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, 2017

[ ] 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 American LLC

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

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

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

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

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

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

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

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

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act [ ]

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

The aggregate market value of the voting and non-voting common equity held by non-affiliates as of the end of the registrant’s most recent second quarter based upon the closing sale price of the registrant’s common stock as reported by the NYSE American LLC on June 30, 2017, was $72,659,755.

The number of shares outstanding of the registrant’s common stock as of March 1, 2018 was 19,494,566.

DOCUMENTS INCORPORATED BY REFERENCE

None

U.S. Geothermal Inc.
Form 10-K
INDEX
For the Year Ended December 31, 2017

		Page
PART I

Item 1	Business	5
	Development of Business	6
	History	6
	Plan of Operations	6
	Project Overview	10
	Projects in Operation	11
	Material Projects Under Development/Exploration	13
	Employees	22
	Principal Products	22
	Sources and Availability of Raw Materials	23
	Significant Government Permits	23
	Seasonality of Business	24
	Industry Practices/Needs for Working Capital	25
	Dependence on a Few Customers	25
	Competitive Conditions	25
	Environmental Compliance	26
	Financial Information about Geographic Areas	29
	Financial Information about Business Segments	29
	Available Information	29
	Governmental Approvals and Regulations	30
Item 1A	Risk Factors	34
	Risks Related to Our Business	34
	Risks Related to Our Growth	40
	Risks Related to Our Power Purchase Agreements	46
	Risks Related to Our Liquidity and Capital Resources	48
	Risks Related to Government Regulation	51
	Risks Related to Ownership of Our Common Stock	53
	Risks Related to the Merger	56
Item 1B	Unresolved Staff Comments	58
Item 2	Property	59
	Land and Leases	69
Item 3	Legal Proceedings	71
Item 4	Mine Safety Disclosures	72

PART II

Item 5	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	73
Item 6	Selected Financial Data	74
Item 7	Management’s Discussion and Analysis of Financial Condition and Results of Operations	75

U.S. Geothermal Inc.
Form 10-K
INDEX
For the Year Ended December 31, 2017

		Page
	Historical Overview	75
	Factors Affecting Our Results of Operations	76
	Operating Results	78
	Non-Controlling Interests	93
	Liquidity and Capital Resources	95
	Potential Acquisitions	96
	Critical Accounting Policies	96
	Contractual Obligations	98
	Off Balance Sheet Arrangements	98
Item 7A	Quantitative and Qualitative Disclosures about Market Risk	98
Item 8	Financial Statements and Supplementary Data	98
Item 9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	99
Item 9A	Controls and Procedures	99
	Report of Independent Registered Public Accounting Firm	100
Item 9B	Other Information	102

PART III

Item 10	Directors, Executive Officers and Corporate Governance	103
Item 11	Executive Compensation	107
	Summary Compensation Table	114
	Grants of Plan-Based Awards Table	115
	Options Exercises and Stock Vested Table	115
	Outstanding Equity Awards at Fiscal Year-End	116
	Potential Payments Upon Termination or Change-in-Control	116
	Director Compensation	118
	CEO Pay Ratio	118
Item 12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	120
	Securities Authorized for Issuance under Equity Compensation Plans	120
	Security Ownership of Certain Beneficial Owners and Management	121

Item 13	Certain Relationships and Related Transactions, and Director Independence	122
Item 14	Principal Accountant Fees and Services	123

PART IV

Item 15	Exhibits and Financial Statement Schedules	124

Item 16	Form 10-K Summary	124

Introduction

On January 24, 2018, the Company announced that it had entered into a Merger Agreement, as defined below, with a wholly-owned subsidiary of Ormat Technologies, Inc., a public company incorporated under the laws of the State of Delaware. Unless stated otherwise, all forward-looking information contained in this report does not take into account or give any effect to the impact of the Merger, as defined below. For additional details regarding the Merger, see “Development of the Business” contained in Part I, Item 1, of this report, “Risk Factors”contained in Part I, Item 1A, of this report, and Note 17 to the Company’s consolidated financial statements, contained in Part II, Item 8, of this report.

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. 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.

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.

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 originally incorporated on March 10, 2000 in the State of Delaware. The Company constructs, manages and operates power plants that utilize geothermal resources to produce electricity. 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 identify, evaluate, acquire, develop, and operate 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 through 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. 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 help offset the high upfront project capital cost by enhancing the project economics and attracting 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 is to structure project ownership to optimize project economics. Under current legislation, a company may elect to take 30% ITC for certain qualified investments (or the PTC) provided construction of the project was started prior to the end of 2017. 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.

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•

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.

For the year ended December 31, 2017, the Company was focused on:

	•	operating and optimizing the Neal Hot Springs, San Emidio and Raft River power plants;
	•	continuing detailed engineering and pursuing PPA opportunities for the WGP Geysers project;
	•	continuing permitting and engineering for the San Emidio II project;
	•	continuing the advanced resource evaluation portion of the $1.5 million SubTER grant from the Department of Energy at San Emidio and Crescent Valley;
	•	continuing engineering for the Neal Hot Springs hybrid cooling system and injection pump system; and
	•	evaluating potential new geothermal projects and acquisition opportunities.

The Board of Directors is focused on the strategic direction of the Company, including review of the Company’s overall development plan as well as reviewing strategic alternatives. The Board has established committees to assist the Board with this process. There can be no assurance that this ongoing strategic review will result in any specific action or transaction or that any action taken or transaction we may enter into will prove to be beneficial to stockholders.

On January 24, 2018, U.S. Geothermal Inc. (the “Company”) entered into an Agreement and Plan of Merger (the “Merger Agreement”) by and among Ormat Nevada Inc., a Delaware corporation (“Ormat”), OGP Holding Corp., a Delaware corporation and a wholly-owned subsidiary of Ormat (“Merger Sub”) and the Company. Pursuant to the Merger Agreement, Merger Sub will be merged with and into the Company (the “Merger”), the separate corporate existence of Merger Sub will cease and the Company will continue its corporate existence under the Delaware General Corporation Law as the surviving company in the Merger and a subsidiary of Ormat.

Subject to the terms and conditions set forth in the Merger Agreement, at the effective time of the Merger (the “Effective Time”), each share of common stock, par value $0.001, of the Company (“Company Shares”) issued and outstanding immediately prior to the Effective Time of the Merger (other than Company Shares owned by Ormat, Merger Sub or the Company (as treasury stock or otherwise), or any of their respective direct or indirect wholly-owned subsidiaries, in each case, not Company Shares owned by shareholders who have exercised their rights as dissenting owners under Delaware law) will be automatically converted into the right to receive $5.45 per Company Share in cash, without interest.

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The Merger Agreement provides that, at the Effective Time, each of the Company’s then outstanding stock options will be treated as follows: (i) the accelerated vesting and settlement of all then-outstanding Options immediately prior to and contingent on the closing of the Merger, (ii) the cash-out of such Options providing for payment of an amount equal to the excess, if any,of the Merger Consideration per Company Share over the exercise price of such Options and (iii) the cancellation, as of the Effective Time, of each Option that is outstanding and unexercised as of immediately prior to the Effective Time. Certain optionholders, such as directors and officers, will be required to sign an Option Holder Acknowledgement Form, attached as an exhibit to the Merger Agreement, in order to be automatically cashed-out as noted above in subsection (ii).

The Merger Agreement contains customary representations and warranties of the Company, Ormat and Merger Sub relating to their respective businesses and organizations, in appropriate cases subject to materiality qualifiers. Additionally, the Merger Agreement provides forcustomary pre-closing covenants of the Company, including covenants relating to conducting its business in the ordinary course consistent with past practice and refraining from taking certain actions without Ormat’s consent, covenants not to solicit proposals relating to alternative transactions or, subject to certain exceptions, enter into discussions concerning or provide information in connection with alternative transactions and covenants requiring the Company’s board of directors (the “Board”), subject to certain exceptions, to recommend that the Company's shareholders approve the Merger Agreement. In the event that the Board receives an alternative acquisition proposal that it determines is a Superior Proposal (as defined in the Merger Agreement) in accordance with the terms of the Merger Agreement, the Company may, subject to compliance with requirements to provide notice to and a period for Ormat to match such proposal, and subject to payment of the termination fee payable by the Company to Ormat and other conditions and requirements set forth in the Merger Agreement, terminate the Merger Agreement to accept the applicable Superior Proposal.

The Company, Ormat and Merger Sub have agreed to use their respective commercially reasonable efforts, subject to certain exceptions, to, among other things, consummate the transactions contemplated by the Merger Agreement as promptly as reasonably practicable and make all required filings and obtain all required consents, permits, regulatory approvals and expirations or terminations of waiting periods. None of the Company, Ormat or Merger Sub is required to divest any of its businesses, product lines or assets, or to take or agree to take any other action or to agree to any limitation or restriction of any kind on its business, operations, properties or assets.

Consummation of the Merger is subject to various conditions, including, among others, customary conditions relating to the approval of the Merger Agreement by the requisite vote of the Company's shareholders, expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, and any other applicable antitrust laws, any required approvals from the Federal Energy Regulatory Commission and any other applicable filings with or authorizations, consents or waivers from third parties. The obligation of each party to consummate the Merger is also conditioned on the other parties’ representations and warranties being true and correct (subject to certain materiality exceptions) and the other parties having performed in all material respects its obligations and complied in all material respects with the agreements and covenants under the Merger Agreement. The transaction is not conditioned on Ormat’s receipt of financing.

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The Merger Agreement contains termination rights for each of the Company and Ormat, including, among others, if the Merger has not been consummated by May 24, 2018. Either party may also terminate the Merger Agreement if the Company's stockholder approval has not been obtained at a duly convened meeting of the Company's stockholders or an order permanently restraining, enjoining, or otherwise prohibiting consummation of the Merger becomes final and non-appealable. Upon termination of the Merger Agreement under specified circumstances, generally relating to alternative acquisition proposals, an adverse change in the Board’s recommendation in favor of the Merger, a knowing and intentional breach of the Company representations or warranties, or a failure by the Company to consummate the Merger when required to do so pursuant to the terms of the Merger Agreement, the Company would be required to pay Ormat a termination fee equal to 3% of the Merger Consideration (approximately $3.2 million). Upon termination of the Merger Agreement under specified circumstances, generally relating to a knowing and intentional breach of Ormat’s representations or warranties, or a failure by Ormat to consummate the Merger when required to do so pursuant to the terms of the Merger Agreement, Ormat would be required to pay the Company a reverse termination fee equal to 3% of the Merger Consideration (approximately $3.2 million).

The foregoing description of the Merger Agreement is qualified in its entirety by the full text of the Merger Agreement, which is attached as Exhibit 2.1 to the Company’s Current Report on Form 8-K filed with the U.S. Securities and Exchange Commission (“SEC”) on January 25, 2018, which is incorporated by reference herein.

Project Overview

The following is a list of projects that are in operation, under development or under exploration. Projects in operation currently have producing geothermal power plants. Projects under development have 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 provided for project development costs could understate actual costs.

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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:

Projects in Operation

Generation

Ownership

(Ave. Net

PPA Limit

Power

Contract

Project

Location

MWs)⁽³⁾

(megawatts)

Purchaser

Expiration

Neal Hot Springs

Oregon

60⁽¹⁾

21.2

25.0

Idaho Power

2036

San Emidio (Unit I)

Nevada

100

8.4

9.9⁽⁴⁾

NV Energy

2038

Raft River (Unit I)

Idaho

95⁽²⁾

9.4

13.0

Idaho Power

2032

⁽¹⁾	Neal Hot Springs is a joint venture with a 40% interest held by Enbridge.
⁽²⁾	Raft River is a joint venture with a subsidiary of Goldman Sachs as the tax equity partner owning a 5% interest. On January 2, 2018, US Geothermal acquired the remaining 5% interest and now owns 100% of the project.
⁽³⁾	Average of 3 years generation.
⁽⁴⁾	Generation eligible for full PPA price. Generation from 9.9 MW up to 14.7 MW is eligible for excess energy payment of $50 per megawatt-hour within the terms of the PPA.

Facility Generation

Generation from all facilities totaled 323,832 megawatt hours for 2017. For 2016, the total generation was 326,601 megawatt hours. For the fourth quarter of 2017, generation from all facilities totaled 95,417 megawatt hours compared to 97,879 megawatt hours during the same period in 2016.

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.

For the fourth quarter of 2017, generation was 56,100 megawatt-hours with an average of 25.6 net megawatts per hour of operation and plant availability was 99.3% . For the same period in 2016, the plant generated 57,038 megawatt-hours with an average of 26.3 net megawatts per hour and plant availability was 98.2% . Warmer winter temperatures reduced generation during the fourth quarter of 2017.

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 annual 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 annual average price paid under the PPA for 2017 is $111.83 per megawatt-hour. For 2018, the average price will increase to $114.49 per megawatt-hour.

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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.

For the fourth quarter of 2017, generation was 18,097 megawatt-hours with an average of 8.2 net megawatts per hour of operation and plant availability was 89.3% . For the same period in 2016, the plant generated 20,803 megawatt-hours with an average of 9.4 net megawatts per hour and plant availability was 98.2% .

In mid-December 2017, the plant was shut down for 7 days to repair leaks that were found in the vaporizer tubes. The damaged tubes were plugged and will be replaced during the spring 2018 scheduled maintenance outage. The pump in production well 75B-16 was shut down on December 29, 2017 after 7.8 years in service. The pump was replaced and returned to service. Standby production well 75-16 was brought on line to supplement brine flow to the plant while 75B-16 was off line.

On May 31, 2011, an amended and restated PPA was signed with Sierra Pacific Power Company d/b/a NV Energy for the sale of up to 10 megawatts annual average. The PPA has a 25-year term with an annual escalation rate of 1 percent. The annual average price paid under the PPA for 2017 is $93.94 per megawatt-hour. For 2018, the price will increase to $94.88 per megawatt-hour.

Raft River, Idaho

Raft River Energy 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.

For the fourth quarter of 2017, generation was 21,220 megawatt-hours with an average of 10.8 net megawatts per hour of operation and plant availability was 100%. For the same period in 2016, the plant generated 20,039 megawatt-hours with an average of 9.2 net megawatt hours and plant availability was 100%.

Production pump RRG-7 was off line for 79 days to replace the pump, build a new pump support structure and make a repair to the surface casing. The well was shut down in late September 2017 when the pump failed after 8 years in service and was restarted in mid-December 2017.

Subsequent to the end of the year, the remaining 5% of the project owned by GFSF Investments I Corp, a wholly owned subsidiary of Goldman Sachs, was purchased on January 2, 2018. The purchase price was $350,000. U.S. Geothermal Inc. now owns 100% of the project.

Well RRG-9, which was used as part of an $11.4 million thermal stimulation grant funded primarily by the DOE, has increased injection capacity to a current level of over 1,450 gpm. This injection capacity is sufficient to provide all of the additional volume needed to accept the flow from well RRG-5 without requiring any new drilling.

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The PPA for the project was signed on September 24, 2007 with the Idaho Power Company and allows for the sale of up to 13 megawatts of electricity on an annual average basis. 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 annual average price paid under the PPA for 2017 is $64.63 per megawatt-hour. The average price for 2018, including the project’s share of the REC value, will be $74.32 per megawatt-hour.

In addition to the price paid for energy by Idaho Power, Raft River Unit I used to receive $4.75 per megawatt-hour under a separate contract for the sale of RECs to Holy Cross Energy, a Colorado electric cooperative. As of January 2018, a new, 10-year REC contract with the Public Utility District No. 1 of Clallam County, Washington has replaced the Holy Cross Energy contract. This REC contract only includes the sale of the RECs owned by the Raft River project. Under the terms of our PPA, starting in 2018, 49% of the RECs produced will be owned by the Raft River Project, and the Idaho Power Company will own the remaining 51%.

Material Projects Under Development/Exploration

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:

Development Projects

Target

Projected

Estimated

Development

Commercial

Capital Required

Power

Project

Ownership

(Megawatts)

Operation Date

($million)

Purchaser

Neal Hot Springs - upgrade

60%

1-2

4^thQuarter 2018

1.6

Idaho Power

San Emidio I - upgrade

100%

1-2

3^rdQuarter 2018

NV Energy

Raft River – upgrade

100%

0.5

3^rdQuarter 2018

Idaho Power

WGP Geysers

100%

4^thQuarter 2022

148

TBD

San Emidio Phase II

100%

25-35

4^thQuarter 2020

126-168

TBD

El Ceibillo Phase I

100%

TBD

140

TBD

Crescent Valley Phase I

100%

TBD

130

TBD

- Commercial operation dates are projections only. The actual commercial operation date can only be provided after a PPA has been obtained for the project.

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	Exploration Properties
			Target Development
Project	Location	Ownership	*(Megawatts)
Gerlach	Nevada	67.4%	10
Vale	Oregon	100%	15
El Ceibillo Phase II	Guatemala	100%	25
Neal Hot Springs II	Oregon	100%	10
Raft River Phase II	Idaho	100%	13
Crescent Valley Phase II	Nevada	100%	25
Crescent Valley Phase III	Nevada	100%	25
Lee Hot Springs	Nevada	100%	20

- Target development sizes are predevelopment estimates of resource potential of unproven resources. The estimates are based on our evaluation of available information regarding temperature, and where available, flow.

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/Flash
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
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.

Neal Hot Springs – Upgrade Projects

At our operating Neal Hot Springs project, there are approximately 3.9 megawatts of annual average generation that are available under the terms of the PPA. Each megawatt of increased generation is worth approximately $990,000 per year at the 2019 contract price of $116.45.

The decision was made to delay the hybrid cooling system until 2019 to allow additional time to firm up the water supply and complete the final design of the cooling system. The updated design for the hybrid system would have a single cooling tower with heat exchangers located at all three units. Cooling water would come from both fresh groundwater wells and treated geothermal water. The engineering for the hybrid system is completed to the bid level and will be further refined during the year. Water cooling will increase the efficiency of the plant during the summer period when generation is suppressed by high ambient temperatures.

A second upgrade project under evaluation and engineering is the addition of two injection pumps that would both reduce the parasitic load in the plant, and allow an increase in the pumping capacity of the production pumps that feed hot fluid to the plant. The estimated capital costs is $1.6 million and the system could be on-line by the 4^th quarter 2018.

San Emidio I, Nevada – Upgrade Project

At our operating San Emidio I project, we will move forward with an enhancement program to increase generation from the power plant by drilling a new production well in the Southwest Zone and delivering that fluid to the San Emidio I plant. There are approximately 1.5 megawatts annual average that remains available under the terms of the PPA at full price, and several more megawatts that could be sold at the excess energy price. One megawatt at full contract price is worth approximately $800,000 in additional annual revenue and each megawatt of excess energy generated above 10 megawatts, but below 14.7 megawatts is worth approximately $425,000.

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The drilling permit was received from the Bureau of Land Management (“BLM”) in January 2018 to drill production well 25A-21. A permit from the State of Nevada is pending. The new production well will twin observation well 25-21, which intersected a high temperature, high permeability structure in the Southwest Zone. The well will be connected to the Phase I plant with a new pipeline, and is now planned to provide up to 2,000 gallons per minute of 320°F fluid. Starting production from the Southwest Zone in 2018 will provide a long-term flow test of the Southwest Zone that will be critical to understand its full development potential.

Raft River, Idaho – Upgrade Project

The addition of production well RRG-5 increased the average generation from the Raft River plant by 1.6 net megawatts in 2017. Due to the positive response from the wellfield, which showed a minimal decrease in fluid levels, a study to increase the capacity of production pump RRG-4 in 2018 was completed. The upgrade project would consist of adding additional bowls to the pump and setting the pump deeper in the well to produce approximately 400-500 gpm more fluid to the plant. The pump in RRG-4 has been in service for 10 years and was already scheduled for replacement in 2018.

This upgrade would result in an estimated generation increase of approximately 0.5 net megawatts annual average. In 2019, the first full year of production, the energy plus renewable energy credit value will be $75.71 per megawatt hour. If the full amount of new generation is realized, it would result in approximately $600,000 of additional annual revenue. Approximately half of this revenue is expected to be realized in 2018.

WGP Geysers, California – Development Project

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. We expect that approximately 75% of the development may be funded by non-recourse project debt, with the remainder funded through equity financing. Due to the lapse in the Federal Investment Tax Credit program for geothermal power generation and the delay for start of construction, we do not believe that the project currently qualifies for the 30% ITC or PTC. Several bills have been introduced in Congress that could reauthorize the ITC/PTC for geothermal power generation, but it is unknown when that action might take place.

Detailed engineering of the 28.8 net megawatt power plant is nearly complete. Our engineers and consultants are working in concert with our EPC contractors to examine all aspects of the construction cycle with a focus on reducing construction costs. The hybrid cooling design will dramatically increase the volume of water available for injection back into the reservoir, which will result in increased power generation over the life of the project. Traditional water cooled geothermal steam plants re-inject approximately 20 to 25% of the water that is extracted from the steam, while our current hybrid design may re-inject approximately 80% more of the water. This higher injection rate will provide long term, stable steam production, and will result in increased power generation over the life of the project.

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The Conditional Use Permit from Sonoma County, which approves the construction plan for the WGP Geysers power plant, was received on December 16, 2016 and is active for 10 years. Combined with the Large Generator Interconnection Agreement (“LGIA”) that was received from the California Independent System Operator and Pacific Gas & Electric, this completes the long lead permits and agreements that are needed for the project. Once final engineering design is finished, and a PPA is executed, an air quality permit and building permit will be needed before on site construction will begin.

We terminated the LGIA the project had with the California Independent System Operator and Pacific Gas & Electric (PG&E). The termination was driven by various milestone dates that were not achievable because of the lack of a PPA and the lack of an easement for the 1.7 mile long transmission line from the plant to the substation. This LGIA allowed the project to connect to the transmission grid and deliver up to 35 megawatts of energy. The Company paid the total interconnection cost of $1.9 million to the grid operator for their substation work. After termination, the remaining balance of the interconnection cost is expected to be reimbursed to the Company during the first quarter of 2018.

We are now considering an alternative interconnection method which will trigger additional interconnection studies and extend the time required for interconnection into the transmission grid. A “ring bus” type substation located on the plant site will be required if the easement cannot be acquired. The additional cost associated with the ring bus type substation is currently included in the estimated capital cost for the project.

Based on flow test data generated from well flow testing performed in mid-2015, a third party expert reported in September 2015, that the four production wells already drilled are capable of delivering an initial capacity of 28.1 MW (gross) or 25.4 MW (net) based on current power plant steam conversion rates from a detailed design for a 28.8 MW (net) power plant. These tests show the wells would initially produce a combined total of 458,000 pounds per hour. Using the average steam production rate from these wells and an assumed interference factor of 30%, the third party expert estimates that an additional two to three production wells would be needed to support the long-term operation of a 28.8 MW (net) plant. Using the large data base from the surrounding Geysers geothermal field, the historic WGP well production data, and the 2015 flow test information, a numerical reservoir model has been developed to provide the final well requirements and targeting for injection sites.

We continue to submit proposals when Request for Offers are released by organizations seeking renewable energy and have continued bilateral discussions with several potential purchasers. In Fall 2017, we adopted a revised, more aggressive pricing structure when submitting bids. Despite the new pricing structure, to date, the WGP Geysers project has not been selected to negotiate a PPA. Purchasers have expressed interest in renewable, base load power to replace fossil fuel based power generation that is being phased out of some of their portfolios and to stabilize and balance intermittent resources already in their portfolios.

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San Emidio Phase II, Nevada – Development Project

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 non-recourse project debt, with the remainder funded through equity financing. We believe the project qualifies for the 30% Federal Investment Tax Credit (or Production Tax Credit) which, when monetized, can meet most of the equity financing requirements.

A power plant development permit application for the San Emidio Phase II project was submitted to the BLM on March 29, 2017. The application provides for the installation of three power plant units and up to 20 wells and related infrastructure needed to develop the project. It is expected that the evaluation by the BLM will take 12 months or longer to complete. All of the required cultural and biological surveys were completed for the plant and wellfield area during the second quarter, with no unique or notable sites or species identified. Archeological surveys of the power line that will interconnect the plant to the NV Energy substation were conducted during the 4^th quarter 2017.

During September 2017, a 59-hour, multi-well flow test was conducted using three of the recently drilled Southwest Zone wells. Total flow from the wells was approximately 1,590 gpm. Testing included a step rate program with four-hour increments, whereby one well, then two wells, and finally all three wells were flowed for the 51-hour duration of the test. Flowing temperature from the three wells ranged from 319°F to 325°F. Pressure was also monitored on the flowing wells, which experienced pressure drawdown from 7.7 psi to 43.0 psi. A monitoring well in the Southwest Zone, located 1,700 feet from the nearest flowing well, had a pressure drawdown of 4.3 psi. Five additional monitoring wells located in the Phase I reservoir area recorded pressure changes of 0.9 psi to 3.2 psi.

These results continue to support the previously announced Probability Power Density model resource estimate of 25.9 megawatts at a 90% probability. The 50% probability level estimate of 47 megawatts remains unchanged because all of these wells are inside the originally defined Southwest Zone resource area. Future drilling to expand the resource beyond the currently defined area is planned but cannot be implemented until the Environmental Assessment for the Phase II power plant development is approved by the BLM.

An application for a LGIA was filed with NV Energy on June 26, 2017. The LGIA would provide for the interconnection of 45 megawatts of generation capacity. Permitting for the transmission line, which is approximately 57 miles long, may extend the time required to interconnect the project and could impact the currently projected commercial operation date. The LGIA was accepted as complete by NV Energy and entered the first step in the FERC mandated evaluation process on October 1, 2017. The first phase study, a System Impact Study (“SIS”), was received on January 29, 2018. The SIS that was presented indicated potentially higher transmission costs, but did not study the correct interconnection parameters and is currently undergoing a re-study by NV Energy. A second phase study, the Facilities Study, will be required to be completed before an interconnection agreement can be reached.

The three power plant equipment packages that were purchased in 2016 are available to provide this project with the major, long lead equipment requirements for 25-35 net megawatts annual average (depending upon cooling system used). The increased San Emidio II reservoir capacity with a 320°F+ temperature fits the design range of the equipment. These new, unused components represent approximately 70% of the equipment needed for a complete facility similar to the Company’s Neal Hot Springs operation.

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In July 2016, the Company was awarded a $1.5 million DOE cost share grant under the “Development of Technologies for Sensing, Analyzing, and Utilizing Novel Subsurface Signals in Support of the Subsurface Technology and Engineering (“SubTER”) Crosscut Initiative”. The program approved under the grant includes using new subsurface imaging technologies at both San Emidio and Crescent Valley to identify fluid flow paths in the geothermal resource. The primary data collection phase of the program, which included passive seismic and magnetotelluric (MT) stations, was completed at San Emidio in December 2016. A second phase of data collection was required to fill in and replace a limited number of MT stations at San Emidio, and was completed in the third quarter. Final interpretation of the geophysical data is currently underway.

After all data is compiled and interpreted, if viable drilling targets have been identified, DOE may approve a second phase of the grant program to confirm the findings by drilling. There is no assurance the DOE will approve the drilling phase of the grant, even if viable targets are identified. The total program cost is estimated to be $1.9 million and we anticipate the Company cost share would be $400,000.

El Ceibillo, Republic of Guatemala – Development Project

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 agreement contains a schedule that requires the development and construction of a power plant. In July 2015, the Guatemalan Ministry of Energy and Mines approved a modified construction schedule that extended the development and construction period to June 1, 2018. There are 24,710 acres (100 square kilometers) in the concession, which is at the center of the Aqua and Pacaya twin volcano complex.

On September 28, 2017, U.S. Geothermal Guatemala S.A. was notified that it has been awarded a $3.42 (€2.91) million grant from the German Development Facility for Latin America for further development drilling at the El Ceibillo project. The grant represents an approximate 40% cost share for drilling up to three production wells, with a total estimated program cost of $8.81 (€7.486) million. If the GDF funding is used on the project and the power plant is constructed, the grant would be converted into a loan. The German Development Bank may consider financing the entire project if it moves to production. The next phase of work for the project is being considered by the management team as 2018 budgets are being developed.

On December 29, 2017 we were notified that the US Trade Development Agency had approved the grant for a feasibility study at El Ceibillo valued at $825,319. The study is being led by Power Engineers of Hailey, Idaho and a consortium of professional geothermal contractors. It is scheduled to be completed by the end of 2018. All of the proceeds from the grant are paid to the contractors at defined milestones.

A production well, EC-5, was drilled in August 2016 to a depth of 1,450 feet (442 meter and intersected a high permeability zone at 1,299 feet (396 meters). EC-5 underwent a series of flow tests, with field wide monitoring, beginning on September 5, 2016 and ran until September 13, 2016. Data was collected from three monitoring wells during the test (EC-2A, EC-3, and EC-4) to provide pressure data for the reservoir model. Fluid samples taken at the end of the flow test indicate a potential reservoir temperature of 450 to 523°F (232 to 273°C).

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With the shallow, commercial resource now outlined, a deeper well has been sited to test the producing structure down dip from well EC-5 to a projected depth of 1,970 to 2,300 feet (600-800 meters). A deeper intersection in the reservoir could increase the reservoir capacity and production temperature and change the design of the power plant. Well EC-1, which was drilled in 2013 to a depth of 5,650 feet (1,722 meters) found a measured bottom-hole temperature of 526°F (274°C), but did not intersect a commercial zone of permeability. The comparative geology between EC-5 and EC-1 suggests a fault or other structure feeding the reservoir may be located in the area between the two wells.

Expenditures at El Ceibillo are being carefully controlled until we see evidence that the energy market is advancing in Guatemala. On January 10, 2017, the Guatemalan government, through the National Electrical Energy Commission (COMISIÓN NACIONAL DE ENERG¥A ELÉCTRICA–“CNEE”), announced that it is preparing to issue a Request For Proposal (“RFP”) for 420 megawatts of power, of which 40 megawatts is to be reserved specifically for geothermal energy. The RFP was not issued in 2017 and there is still no indication of when that RFP may be issued. When the RFP is issued, we expect to bid the El Ceibillo project into the process.

Raft River Phase II, Idaho

In 2011, the Raft River Phase II project was awarded an $11.4 million cost-shared, thermal stimulation program grant from the DOE with the University of Utah Energy and Geoscience Institute as the project lead. 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 for the program and the first stage of injection into the well began in June 2013.

Initially the well was only capable of receiving 20 gpm of water due to the low permeability of the rock. After several moderate pressure stimulations, the injection of cold power plant discharge fluid first began in June 2015 and has continued to date. The lower temperature fluid causes thermal fracturing within the higher temperature host rock of the reservoir. At the current plant generation level, the flow into the well has continued to increase and is now approximately 1,572 gallons per minute.

Well RRG-9 continues to be used temporarily for injection from the Raft River Energy I power plant as an extension of the DOE EGS program. The Company’s contributions for the thermal stimulation program are made in-kind by the use of the RRG-9 well, well field data provided by the Company, and through ongoing labor for monitoring support.

The development and construction of a Phase II project at Raft River is dependent upon additional drilling and the availability of a PPA.

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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 December 2014.

In light of federal legislation that extended the qualification for the 30% Federal Investment Tax Credit to projects that began construction prior to December 31, 2014, drilling of the first production/injection well CVP-001 (67-3) was initiated in December of 2014, following completion of gravity surveys, and analysis of prior temperature gradient drilling data. Well CVP-001 was completed on March 27, 2015 to a depth of 2,746 feet. The well exhibited modest permeability with a flowing temperature of 213°F, which makes the well suited for duty as an injection well.

The SubTER program, approved under the DOE grant awarded in July 2016, includes using new subsurface technologies at both San Emidio and Crescent Valley to identify fluid flow paths in the geothermal resource. The passive seismic data collection phase of the program was completed at Crescent Valley in December of 2016. A magnetotelluric (MT) survey was completed during the third quarter 2017. The data is being interpreted to develop a 3D map to help identify future drilling targets. The details of this award are discussed in the San Emidio Phase II project discussion above.

Employees

At December 31, 2017, the Company had 48 full-time and one part time employees (14 administrative and project development, and 34 field and plant operations) in the United States, with another 9 employees in Guatemala. 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.

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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.

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 maintains all permits necessary for operating its three plants located in Idaho, Nevada and Oregon. In addition, in December 2016 the Company received the Sonoma County Conditional Use Permit required for construction and operations of the WGP Geysers project.

Neal Hot Springs, Oregon. The Neal Hot Springs project has four primary permits governing power plant operations. The permits include:

	1.	Geothermal Well Permits issued by the Department of Geology.

	2.	A Right-of-Way issued by the Bureau of Land Management.

	3.	A Conditional Use Permit issued by the Malheur County Commission.

	4.	Underground Injection Control Permit issued by the Oregon Department of Environmental Quality.

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San Emidio, Nevada. The San Emidio project has five primary permits governing power plant operations. The permits include:

	1.	Geothermal well permits issued by the Nevada Division of Minerals.

	2.	A Special Use Permit issued by the Washoe County Board of Commissioners.

	3.	An Air Quality Permit to Operate from Washoe County.

	4.	A Surface Discharge Permit from Nevada Division of Environmental Protection.

	5.	An Underground Injection Permit from Nevada Division of Environmental Protection.

Raft River, Idaho. The Raft River project has three primary permits governing power plant operations. The permits include:

	1.	Geothermal well permits issued by the Idaho Department of Water Resources.

	2.	A Conditional Use Permit issued by the Cassia County Planning and Zoning Commission.

	3.	A Wastewater Reuse Permit issued by the Idaho Department of Environmental Quality.

WGP Geysers, California. Western GeoPower had previously been issued all necessary permits for construction and operation of up to a 38.5 megawatt geothermal power plant. The Sonoma County Conditional Use Permit administratively expired in 2015. A new Conditional Use was issued in December 2016 for an initial term of 10 years including administrative extensions of 5 years. The primary permits include:

	1.	Geothermal well permits for production and injection wells issued by the California Department of Oil, Gas, and Geothermal Resources.

	2.	A Conditional Use Permit that has been issued by the Sonoma County.

	3.	Air Quality Permit to Construct issued by the Northern Sonoma Air Quality Board.

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. 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. 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.

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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 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. As of January 2018, energy credits earned by Raft River plant are sold to the Public Utility District No. 1 of Clallam County, Washington. Under the current PPAs, energy credits that are earned by USG Oregon LLC and USG Nevada LLC plants are bundled with energy sales. Based upon current operations and expected project completions, it is expected that the Company will have a small number of direct customers that may amount to less than 10 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 and retail sellers of electricity to purchase a minimum percentage of their power from renewable sources. For example, RPS statutes in California require 50% by 2030, Oregon requires 50% by 2040 and Nevada requires 25% by 2015. 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.

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

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

Environmental Compliance

Geothermal drilling, construction and power plant operations are subject to federal, state and local environmental requirements and construction oversight. Applicable laws may include but are not limited to 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, state specific geothermal drilling rules, state and federal injection well requirements and standards and local building codes.

Prior to acquiring an existing geothermal development, USG retains an independent, licensed engineer or geologist to conduct an Environmental Site Assessment and evaluate the property for recognized environmental conditions that could result in regulatory and financial liabilities being passed to U.S. Geothermal Inc. or our subsidiaries.

Our geothermal operations involve significant quantities of geothermal brine that is returned to the local subsurface, geologic formation. We also use isopentane and R-134A refrigerant working fluids, and numerous industrial lubricants that are defined by state regulatory agencies as “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 prior to obtaining project financing. Independent legal reviews have verified that USG and our subsidiary companies 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.

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Neal Hot Springs, Oregon

The Neal Hot Springs project is situated approximately 12 miles west of Vale, Oregon. There are two nearby residents; both are family of JR Land & Livestock, our primary lessor. 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. The reports are filed with the Oregon Department of Environmental Quality and Oregon Department of Geology and Mineral Industries. Bi-annual water monitoring has been conducted since 2008 and will continue throughout the life of the project. Energy generation reports are filed with the Federal Energy Regulatory Commission on a quarterly basis. 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.

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 Nevada Department of Environmental Protection and Nevada Department of Water Resources. Similar to other projects San Emidio’s monthly geothermal production and injection volumes are submitted the Nevada Division of Minerals and Nevada Division of Environmental Protection. Water quality reporting is also submitted regularly to the Nevada Division of Environmental Protection.

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 south of Malta, Idaho in a rural agricultural area with the nearest residence approximately two miles from the plant site. There are no unique plants or animal communities in the area and no unique cultural or environmental constraints.

Wastewater reuse requires bi-annual ground water monitoring at six locations, monthly monitoring of the cooling water and annual reporting. Water quality data is collected a minimum of twice annually. Monthly production and injection reports are filed with the Idaho Department of Water Resources, and land application and cooling water quality reports are filed with the Idaho Department of Environmental Quality and Idaho Department of Water Resources annually. The Project’s private lands are managed on an ongoing basis for weed control, water management, irrigation, and fencing infrastructure.

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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.

WGP Geysers, California

The Geysers project is located approximately 30 minutes north-east of the city of Healdsburg, California. The property encompasses a ridgetop and a north facing hillside that has been developed and used for geothermal operations 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, prior to new construction, that WGP submit a plan to remove or reuse existing steam pipelines. The pipelines may contain mineral scale that has arsenic levels that exceed 150 parts per million.

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 Geysers 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.

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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,
		2017		2016		2015

USG Oregon LLC located in Eastern Oregon	$	19,941,366	$	19,561,718	$	18,823,799
USG Nevada LLC located in Northwestern Nevada		6,255,599		6,980,358		7,324,484
Raft River Energy I LLC located in Southeastern Idaho		5,859,822		4,939,599		5,051,815
Total energy and energy
credits sales	$	32,056,787	$	31,481,675	$	31,200,098

Financial Information about Business Segments

The Company has two reporting segments: operating plants and corporate and development. For more information about the business segments, please see Note 16 to our consolidated financial statements.

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.

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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 through 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”).

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.

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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.

Our power plants are Qualifying Facilities that make only wholesale sales of electricity and are not subject to rate, financial and organizational regulations that are otherwise applicable to electric utilities in those states. The power plants each sell their electrical output under power purchase agreements to an electric utility company. 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.

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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.

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.

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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. Facilities that begin construction after December 31, 2016 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 2016, 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 average over the year) through the year 2017. Holy Cross Energy began purchasing the renewable energy credits associated with the RREI power production on October 2007, and continued 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%.

On December 15, 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; and
	•	Risks Related to the Merger.

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

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Our geothermal reserves could decline in the future. Declines greater than those that we expect would reduce our electricity production levels, which could have a material adverse effect on our 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:

	•	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 corresponding 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 results of operations are subject to seasonal variations. This is primarily because some of our power plants receive higher energy payments during certain summer and winter months. Some of our air cooled power plants may also experience reduced generation during hot summer months due to the lower differential between the temperature of the geothermal fluid and the ambient surroundings. Such seasonal variations could materially and adversely affect our business, financial condition, and cash flow. If our operating results fall below the public’s or analysts’ expectations, the market price of our common stock can fall in such periods.

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

	•	well blowouts;
	•	casing deformation;
	•	casing corrosion;
	•	uncontrollable flows of steam and hot water;
	•	spills, releases, and other accidental environmental impacts; 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.

Threats of terrorism and cyber-attacks could impact our operations and could adversely affect our business and operating revenues. We are subject to the potentially adverse operating and financial effects of terrorist acts and threats, as well as cyberattacks. Our generation and transmission facilities, information technology systems and other infrastructure facilities could be directly or indirectly affected by such activities. Terrorist acts or other similar events could harm our business by limiting our ability to generate or transmit power and by delaying the development of new generating facilities. These events could result in a material decrease in revenues and significant additional costs to repair and insure our assets. We operate in an industry that requires the continued operation of sophisticated information technology systems vulnerable to security breaches, and failures. Those breaches and events may result from acts of our employees, contractors, or third parties. If our technology systems were to be breached and we were unable to recover in a timely way, we would be unable to fulfill critical business functions, which could adversely affect our business.

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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 may terminate. In the event that we determine that a terminated lease is subsequently required for a project, we would need to enter into one or more new leases in order to develop and exploit these geothermal resources. It may not be possible to enter into new leases or these new leases could be on less favorable financial terms than the prior leases, which could materially and adversely affect our ability to achieve commercial success on the applicable project.

Pursuant to the terms of our leases with the 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 may cause seismic activity and related property damage. There are approximately two-dozen steam geothermal plants operating within a fifty-square-mile region known as “The Geysers” located near the community 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 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. 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. 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.

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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. 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.

Our participation in joint ventures is subject to risks relating to working with a co-venture partner. We are subject to risks in working with a co-venture partner that could adversely impact our current projects as well as anticipated development of expansion projects. Involving a joint venture partner 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.

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

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

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

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

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We depend on our senior management, geothermal resource and other technical employees. The loss of these employees could harm our business. Our future operating results depend to a large extent upon the continued contribution of key senior managers and personnel.

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 material adverse effect upon us. As of the date of this report, the Company has executed employment agreements with key senior managers, but does not have key-man insurance on any of them.

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;

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	•	obtain appropriate governmental permits;
	•	maintain cost controls during construction;
	•	identify, hire and retain a qualified work force;
	•	obtaining Power Purchase Agreements; and
	•	negotiating engineering, construction, and procurement agreements.

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

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

We may decide not to implement, or may not be successful in implementing, our 5 year strategic plan for the growth of the Company. There are uncertainties and risks associated with the achieving our 5 year growth target. It is possible that we may not be successful in implementing one or more elements of the plan. It is also possible that we may decide to change, or not implement, one or more elements of the plan. The growth goals are provided as a target only, as we do not have direct control over the timing associated with the solicitation for power purchase agreements, transmission interconnection agreements, or use permits allowing for the building of a new power plant. These or other factors could mean that we decide to change or even abandon, or are otherwise unable to implement, one or more elements of the plan. Early stage project development costs may not be recovered, in whole or in part, if one or more elements of the plan are not successfully implemented. These costs could materially and adversely affect our business, financial condition, and cash flow and the price at which our common stock is traded.

Our business development activities may not be successful and our projects under construction may not commence operation as scheduled. We are in the process of developing and constructing a number of new power plants. Our success in developing a particular project is contingent upon successfully obtaining Power Purchase Agreements, satisfactorily negotiating engineering, procurement, and construction agreements, obtaining required permits, and securing adequate financing. These are followed by the satisfactory completion of the power plant construction and commissioning. We may be unsuccessful in accomplishing any of these tasks on a timely basis. Though we try to minimize our expenses before we can determine whether a project is feasible, we may incur significant expense prior for preliminary engineering, permitting and legal support prior to securing financing.

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Actual costs of construction or operation of a power plant may exceed estimates used in negotiation of power purchase and power financing agreements. If the actual costs of construction or operations exceed the costs used in our economic model, the Company may not be able to build the contemplated power plants, or if constructed, may not be able to operate profitably. The Company’s financing agreements may provide for a priority payback to our lender or partner. If the actual costs of construction or operations exceed the anticipated costs, we may not be able to operate profitably or receive the planned share of cash flow and proceeds from the project.

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

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

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

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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.

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.

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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.

The power generation industry is characterized by intense competition, and we encounter pricing pressure from electric utilities, community choice aggregators and other power producers and power marketers, that could materially and adversely affect our growth plans.

The power generation industry is characterized by intense competition. In recent years, there has been increasing competition in the sale of electricity, in part due to excess capacity in a number of U.S. markets and an emphasis on short duration contracts or “spot” market power. This increased competition has contributed to a reduction in electricity prices. We expect that power purchasers interested in long-term power purchase agreements will engage in “competitive bid” solicitations to satisfy their demands. This competition could adversely affect our ability to obtain PPAs and the price paid for electricity by the relevant power purchasers. There is also increasing competition between electric utilities, municipal power companies, and community choice aggregators that is putting further pressure on power purchasers to reduce the prices at which they purchase electricity from us.

Natural gas prices and oil prices are volatile, and lower prices for these commodities could affect 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 associated with both the demand for renewable energy, as well as the prices and demand for natural gas in the United States markets and the price of oil in our Central American markets. The markets for these commodities are volatile, and modest drops in prices can affect significantly price levels obtainable on new PPA contracts. Prices 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;

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	•	political conditions in or affecting other oil producing and gas producing countries, including conflicts in the Middle East and conditions in South America and Russia;
	•	weather conditions, as evidenced by recent hurricanes;
	•	technological advances affecting oil and gas consumption;
	•	overall U.S. and global economic conditions; and
	•	price and availability of alternative fuels.

Further, oil 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.

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 short term prices than our geothermal plants. In addition, there are other technologies that can produce electricity at competitive prices, most notably fossil fuel power systems, hydroelectric systems, wind-turbines and photovoltaic (solar) cells. 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 below that of most geothermal power generation technologies such that the competitive advantage of our projects may be significantly impaired. Intermittent renewable energy sources such as solar and wind, have already seen such cost reductions allowing them to offer their intermittent power and substantially lower prices.

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 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. Additionally, the credit quality of newly formed power purchasers may negatively impact our ability to finance our power purchase projects and may negatively impact their ability to pay for the contracted power in the future.

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Changes in costs and technology of other baseload renewable electricity sources may significantly impact our business by making our power plants less competitive. A basic premise of our business model is that our geothermal power plants generate baseload power at a competitive price. While there are other renewable energy technologies that can also produce baseload electricity, such as biomass, fuel cell, and hydroelectric systems, most 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 may gradually decline. 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 power plants may be significantly impaired.

Risks Related to Our Liquidity and Capital Resources

Substantial leverage and debt service obligations may adversely affect our cash flows, liquidity and operations. We 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.

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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 and any future financing we receive may be less favorable to us than our current financing arrangements, either of which may adversely affect our ability to expand our operations. Our geothermal power plants generally have been financed using leveraged financing structures, consisting of non-recourse debt obligations and partnership arrangements. Each of our projects under development and those projects and businesses we may seek to acquire will require substantial capital investment. Our continued access to capital with acceptable terms is necessary for the success of our growth strategy. Our attempts to obtain future financings may not be successful or on favorable terms, and 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. Market conditions and other factors may not permit future project and acquisition financings on terms similar to those previously received. If we are not able to obtain financing for our power plants on a non-recourse basis, we may have to finance them using direct equity investments, which may have a dilutive effect on our common stock or incur additional recourse debt.

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.

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Our debt instruments impose significant operating and financial restrictions on us; any failure to comply with these restrictions could have a material adverse effect on our liquidity and our operations. The instruments governing our outstanding debt impose significant operating and financial restrictions on our geothermal operating subsidiaries. These restrictions could adversely affect us by limiting our ability to plan for or react to market conditions or to meet our capital needs. These restrictions limit our ability to, among other things:

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

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.

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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.

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.

Rules 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.

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In the states of Idaho, Nevada California, 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); in California by the Division of Oil, Gas, and Geothermal Resources (Public Resources Code Title 14 Chapter 4); 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.

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 or bonding requirements, 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.

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The reduction or elimination of government incentives could adversely affect our business, financial condition, future results and cash flows. Construction and operation of our geothermal power plants have benefited, and may benefit in the future, from public policies and government incentives that support renewable energy and enhance the economic feasibility of these projects. The most important tax rule that affects our business is the Production Tax Credit (“PTC”) or Investment Tax Credit (“ITC”), which is available to encourage the development of new geothermal plants. Legislation enacted as part of the 2016 “Fiscal Cliff” efforts resulted in the extension of the 30% PTC or ITC with eligibility for projects that started construction before December 31, 2016. 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 the development of new projects uneconomic. Additionally, current IRS guidance states that projects that are placed into service by December 31, 2018 do not have to show continuous construction. Projects placed into service after that date could have some or all of their tax credit eligibility challenged. Additional policies and incentives include accelerated depreciation tax benefits, renewable portfolio standards, carbon trading mechanisms, and rebates. Some of these measures have been implemented at the federal level, while others have been implemented by different states. The availability and continuation of these public policies and government incentives have a significant effect on the economics and viability of our development. Any changes to such public policies, or any reduction in or elimination of such Government incentives could affect us negatively.

Risks Related to Ownership of Our Common Stock

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

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

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	•	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 American LLC (“NYSE American”) is subject to fluctuations in response to, among other things, quarterly variations in operating and financial results, and general economic and market conditions. In addition, statements or changes in opinions, ratings, or earnings estimates made by brokerage firms or industry analysts relating to our market or relating to our company could result in an immediate and adverse effect on the market price of our common stock. The highly volatile nature of our stock price may cause investment losses for our shareholders.

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

Failure to comply with regulatory requirements may adversely affect our stock price and business. As a public company, we are subject to numerous governmental and stock exchange requirements, with which we believe we are in compliance. The Sarbanes-Oxley Act of 2002 (“SOX”) and the 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 we fail to achieve and maintain the adequacy of our internal controls, as such standards are modified, supplemented or amended from time to time, we may not be able to ensure that we can conclude on an ongoing basis that we have effective internal controls over financial reporting in accordance with Section 404 of SOX. Moreover, effective internal controls are necessary for us to produce reliable financial reports and are important to help prevent financial fraud. If we cannot provide reliable financial reports or prevent fraud, our business and operating results could be harmed, investors could lose confidence in our reported financial information, and the trading price of our stock could drop significantly. Our failure to meet regulatory requirements and exchange listing standards may result in actions such as the delisting of our stock impacting our stock’s liquidity; SEC enforcement actions; and securities claims and litigation.

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

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

A substantial percentage of our shares are held by a small group of stockholders whose interests may conflict with the interests of our other stockholders. As of December 31, 2017, our largest three shareholders consisted of JCP Investment Management, LLC beneficially owning 2,871,448 shares (14.8%), Bradley Louis Radoff beneficially owning 1,923,000 shares (9.9%), and Private Management Group, Inc. beneficially owning 1,818,042 shares (9.4%), collectively totaling approximately 34.0% of our outstanding common stock. As a result of these stockholders’ beneficial ownership of our outstanding common stock, they could exert significant influence on the election of our directors and decisions on matters submitted to a vote of our shareholders, including mergers, consolidations and the sale of all or substantially all of our assets. This concentration of ownership of our shares could delay or prevent proxy contests, mergers, tender offers, or other purchases of our shares that might otherwise give our stockholders the opportunity to realize a premium over the then-prevailing market price for our shares. This concentration of ownership may also adversely affect our stock price. Future sales of common stock by these stockholders could cause our stock price to decline.

Future sales of common stock by some of our insider stockholders could cause our stock price to decline. As of the date of this report, our directors and officers collectively held 4,060,809 shares of and options for our common stock, representing approximately 16.9% of issued and outstanding common stock. Sales of such shares in the public market, as well as shares we may issue upon exercise of outstanding options, could cause the market price of our common stock to decline.

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.

Risks Related to the Merger

There are a variety of risks, contingencies and other uncertainties associated with the Merger that could result in the delay or the failure of the Merger to be completed. The Company’s ability to complete the Merger is subject to risks and uncertainties, including, but not limited to, failure to satisfy required closing conditions to the Merger, including the failure to obtain necessary shareholder, regulatory or other approvals, or complete the Merger in a timely manner or at all. No assurance can be given that the required approvals will be obtained and, even if all such approvals are obtained, no assurance can be given as to the terms, conditions and timing of the approvals or that they will satisfy the terms of the Merger Agreement. Even if certain necessary approvals are obtained, the Company may still be subjected to conditions that could result in a material delay in, or the abandonment of, the Merger or otherwise have an adverse effect on the Company. More generally, the occurrence of any event, change or other circumstances that could give rise to the right of a party to terminate the Merger Agreement, including such a circumstance where the Company would be required to pay Ormat a termination fee equal to 3% of the Merger Consideration (approximately $3.2 million). As a result, one or more conditions to closing of the Merger may not be satisfied and the Merger may not be completed.

Any delay in completing the Merger may adversely affect the Company or shareholders, including but not limited to delaying the time at which shareholders may receive consideration for their shares of the Company and further subjecting the Merger to the occurrence of any other event, change or circumstance that may lead to the abandonment of the Merger.

The Company is subject to certain risks during the pendency of the Merger that may have an adverse effect on the Company’s business. During the pendency of the Merger, the Company and its subsidiaries may be subject to business uncertainties, merger-related costs and certain operating restrictions. For instance, the Merger Agreement restricts the Company from taking certain specified actions while the Merger is pending without first obtaining Ormat’s prior written consent. These restrictions may limit the Company from pursuing attractive business opportunities, change or prevent certain strategic decisions from being made or cause or prevent any other changes to the Company’s business prior to completion of the Merger or termination of the Merger Agreement.

Additionally, the ability of the Company or its subsidiaries to retain customers, retain and hire key personnel and maintain relationships with vendors and suppliers may be subject to disruption due to uncertainty associated with the Merger, which could have an adverse effect on the results of operations, cash flows and financial position of the Company and its operating subsidiaries. The Company’s management may also be distracted from ongoing business operations due to the Merger.

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Further, the Company’s directors and executive officers may have interests in the Merger that are different from, or in addition to, the interests of the Company shareholders generally. These interests may cause the Company’s directors and executive officers to view the Merger differently and more favorably than the Company shareholders may view it.

Failure to complete the Merger and/or the restrictions on the Company from pursuing alternatives to the Merger could negatively affect the Company’s share price, future business and financial results. Completion of the Merger is not assured and is subject to risks, including the risks that approval of the transaction by our shareholders or by governmental agencies will not be obtained or that certain other closing conditions will not be satisfied. If the Merger is not completed, the Company’s ongoing business and financial results may be adversely affected and the Company will be subject to several risks, including:

	•	having to pay certain significant transaction costs relating to the Merger without receiving the benefits of the Merger;
	•	the trading price of the Company’s shares changing, to the extent that the current trading price of the Company’s shares reflects an assumption that the Merger will be completed;
	•	potentially having to pay Ormat up to 3% of the Merger Consideration (approximately$3.2 million) in specific circumstances, including without limitation, a change in or withdrawal of our board of directors’ recommendation to our shareholders or termination to accept an alternative takeover proposal;
	•	litigation related to any failure to complete the Merger;
	•	potential reduction of value offered by others to the Company in any future business combination; and
	•	erosion of customer, vendor, supplier and employee confidence in the Company.

Further, the Company’s legal remedy in the event of breach of the Merger Agreement (whether willfully, intentionally, unintentionally or otherwise) by Ormat or Merger Sub is limited to receipt of the Ormat termination fee, equal to 3% of the Merger Consideration (approximately $3.2 million), and the Company may not be entitled to such fee at all in certain circumstances.

Pursuant to the terms of the Merger Agreement, the Company is restricted from pursuing alternative takeover proposals to the Merger. Should the Company pursue an alternative takeover proposal instead of the Merger, there can be no guarantee that such a pursuit would be more successful or favorable to the Company or its shareholders, either in terms of the costs and expenses to pursue an alternative takeover proposal, the type or amount of consideration that may be received by shareholders, the likelihood or time it takes to complete an alternative takeover proposal, or for any other reason. Restrictions on the Company pursuing alternative takeover proposals may also deter and/or make it difficult for an otherwise interested third party to acquire or propose to acquire the Company prior to the completion of the Merger, even one that may be deemed of greater value to the Company’s shareholders than the current offer by Ormat. Furthermore, the concept of a termination fee may result in that third party’s offering a lower value to the Company’s shareholders than such third party might otherwise have offered.

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The nature of the all-cash Merger Consideration prevents the Company’s shareholders from participating in future growth. The Company’s shareholders will be receiving a fixed amount of cash for their stock and will not be compensated for any increase in the value of the Company or Ormat during the pre-closing period or following the closing, which may prevent the Company’s shareholders from realizing any further upside to the Merger.

Legal claims or investigations could result in an injunction preventing completion of the Merger, the payment of damages in the event the Merger is completed and/or may otherwise adversely affect the Company’s business, financial condition or results of operations.

Transactions such as the Merger are often subject to shareholder lawsuits and other legal claims or investigations by regulators, legislators and law enforcement officials, and the Company cannot guarantee the success in responding or defending against any such lawsuits, claims or investigations. Further, responding or defending to these lawsuits, claims and investigations, regardless of the merits, can incur additional time and expenses, which may have an adverse effect on the Company’s business, financial condition or results of operations.

Item 1B.

Unresolved Staff Comments

None.

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Item 2.

Property

The Company has interests in nine 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 (5) and California (1). The properties include the Raft River area located in southeastern Idaho, the two properties located in southeastern Oregon, and four 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 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 wells 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 included 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 4830 acres; 720 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.

A private geothermal unit was established for the operating project in December 2015. The Unit establishes the geologic production area. A Participating Area of 1640 was established in May 2015. The Participating Area is that area that is reasonably expected to contribute to power production. Production is allocated based on the percentage of each property in relation to the entire Participating Area.

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El Ceibillo, Republic of Guatemala

The Company successfully acquired a geothermal energy rights concession in the Republic of Guatemala, which was granted by the Guatemalan government. It consists of 24,710 acres (100 square kilometers) and is located 14 miles southwest of Guatemala City, the capital. The concession provides sub-surface geothermal rights only, and does not provide access to the surface that is owned by private landowners. The concession had an initial five year term for the development and construction of a power plant, which was extended by three years in 2015. There are no royalties due to the government for use of the geothermal resource.

The primary area of interest within the concession is the El Ceibillo project, 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 80 acres of surface land within the concession area is under lease.

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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 our first 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 property includes surface and geothermal rights that consist of federal geothermal lease CA-51000 and one private geothermal lease with no expiration. The total project acreage is 2,267 acres. The site has been re-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 and Lake 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 royalty for the 421 acre private parcel owned by WGP. The Abril Ranch mineral lease payment for an additional 410 acres of geothermal rights is $10,500 annually. The Filly-Brown properties include 214 acres of surface access rights and 50% of the mineral rights owned by Western GeoPower. During production, the geothermal royalty payment for Abril Ranch is 4.25% of gross revenue at a power price of $100/MW or less and is consistent with market conditions.

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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 311ºF to 320ºF and historical drilling in the area has encountered ground (rock) temperatures in excess of 300°F. 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 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 2,536 acres of surface rights and 2,539 acres of geothermal rights 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 27 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 on federal lands 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.

Typical BLM leases 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.

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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 geothermal rights through leases with 73 individuals and companies. The leases authorize geothermal development and operations on privately owned geothermal estates. 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, and established milestones for development and production. The Company has negotiated and acquired a surface lease from one landowner and controls 80 acres enabling geothermal development. The lease is similar in term and conditions to our leases with private landowners in the United States for surface fee land.

Item 3.

Legal Proceedings

As of March 8, 2018, 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.

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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 American

The following table sets forth information relating to the trading of our common stock from January 1, 2015 through December 31, 2017, as adjusted for the 1-for-6 share consolidation described in Note 9 of the consolidated financial statements, for the Company’s common stock trading on the NYSE American, under the trade symbol “HTM”:

Sale Prices on the NYSE American
	High	Low
Year Ended December 31, 2017	($)	($)
First Quarter	4.92	3.99
Second Quarter	4.53	3.67
Third Quarter	4.63	3.80
Fourth Quarter	4.08	3.31

Year Ended December 31, 2016
First Quarter	4.08	3.12
Second Quarter	5.16	4.08
Third Quarter	5.34	4.20
Fourth Quarter	4.33	3.72

As of March 1, 2018, we had approximately 12,400 beneficial 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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Item 6.

Selected Financial Data

		For the Years Ended December 31,
	2017	2016	2015	2014	2013
Operating Revenues	$ 32,056,787	$ 31,481,675	$ 31,200,098	$ 30,968,782	$ 27,370,934
Operating Expenses	19,618,439	16,447,329	21,207,738	21,972,764	23,240,285
Income from Continuing Operations	1,411,561	4,160,348	6,336,498	4,589,297	4,130,649
Income (Loss) attributable to U.S. Geothermal Inc.	(2,267,981)	463,331	1,847,229	11,613,711	1,946,579
* Income (Loss) per share attributable to U.S. Geothermal Inc.	(0.12)	0.02	0.10	0.67	0.11
Cash dividends declared and paid per common share	-	-	-	-	-

* - Adjusted for the 1-for-6 share consolidation described in Note 9 of the consolidated financial statements.

	As of December 31,
	2017	2016	2015	2014	2013
Total Assets	$ 235,742,998	$ 243,424,332	$ 228,217,127 $	232,914,304	$ 232,765,297
Total Long-term Obligations	98,732,843	105,350,989	91,091,982	95,776,351	99,247,344

	* Income (loss) per share attributable to U.S. Geothermal Inc.	Operating Revenues	Gross Profit	Income (Loss) from Operations	Net Income (Loss) Attributable to U.S. Geothermal, Inc.
Year Ended December 31, 2014
1^stQuarter	0.08	8,501,965	4,783,941	2,547,091	1,339,420
2^ndQuarter	(0.07)	5,845,874	1,571,096	(1,308,330)	(1,152,813)
3^rdQuarter	0.00	6,737,005	2,939,672	695,817	81,780
4^thQuarter	0.64	9,883,938	5,731,213	2,654,719	11,345,324
Year Ended December 31, 2015
1^stQuarter	0.04	8,473,861	4,615,637	1,763,381	734,135
2^ndQuarter	(0.01)	5,861,180	1,801,996	(548,347)	(233,820)
3^rdQuarter	0.02	6,929,847	2,819,445	595,079	280,864
4^thQuarter	0.05	9,935,210	6,090,908	3,140,385	1,066,050
Year Ended December 31, 2016
1^stQuarter	0.01	8,503,276	4,523,697	1,277,795	151,392
2^ndQuarter	(0.03)	5,664,280	1,862,436	(684,667)	(493,717)
3^rdQuarter	(0.01)	6,733,294	2,869,422	178,230	(150,498)
4^thQuarter	0.05	10,580,825	5,778,791	2,813,990	956,154
Year Ended December 31, 2017
1^stQuarter	0.01	8,437,069	3,858,249	1,258,486	260,890
2^ndQuarter	(0.02)	6,311,112	1,811,162	(693,169)	(441,854)
3^rdQuarter	(0.09)	6,811,888	2,378,993	(1,320,146)	(1,826,826)
4^thQuarter	(0.02)	10,496,718	4,386,944	2,166,390	(260,191)

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* - Adjusted for the 1-for-6 share consolidation described in Note 9 of the consolidated financial statements.

Item 7.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Historical Overview

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

The Company signed a 20 year 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.

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.

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In April 2010, the Company was granted a geothermal energy rights concession in the Republic of Guatemala located in Central America. Geophysics activities and the drilling of the first exploration well occurred during 2013. A 25 megawatt flash steam plant is planned.

On April 22, 2014, the Company acquired all of the ownership shares of a group of companies owned by Ram Power Corp. (“Ram”) that held 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, geothermal water rights, and an inventory of new drill casing.

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).

Factors Affecting Our Results of Operations

Raft River Operating Agreement/Ownership

Original Agreement

Originally, the Raft River Energy I LLC (“RREI”) issued two classes of member units, (Class A and Class B). Each class of ownership gives the owner participating rights in the business and results in equity ownership risks. The rights attached to the different classes will vary over time, in accordance with the terms of the Membership Admission Agreement. The agreement required RREI to track separately the capital accounts of the members after November 24, 2006. For income tax purposes, the Class A units received a greater proportion of the share of losses and other income tax benefits. This includes the allocation of production tax credits, which was distributed 99% to the Class A units and 1% to the Class B units during the first 10 years of production.

Purchase Agreement of Member Interest

On December 16, 2015, the U.S. Geothermal Inc. (holder of all Class B units) signed a purchase agreement with Goldman Sachs for the acquisition of 450 Class A units of the 500 Class A units held by Goldman Sachs. The terms of the agreement specified the conversion of 450 A units to 450 C units. All of the C units were acquired by U.S. Geothermal Inc. The remaining 50 A units held by Goldman Sachs retain all of the benefits for income tax purposes that were held by the original 500 A units. Effective December 16, 2015, U.S. Geothermal Inc. will receive 95% of the available cash flow from the project for the total purchase price of $5.1 million. The agreement includes an option for U.S. Geothermal Inc. to purchase residual interest in RREI for fair market value in December 2017. Allocations of profits and losses will remain 99% to Goldman Sachs and 1% to the U.S. Geothermal Inc. until December 31, 2017, after which the U.S. Geothermal Inc. would receive 95% of the allocation of profits and losses and Goldman Sachs will receive 5%.

On December 13, 2017, the Company entered into an agreement to acquire the remaining interest of RREI from Goldman Sachs. The acquisition was effective January 2, 2018, at which time RREI became a wholly-owned subsidiary. As a result, the Company now owns 100% of the income and 100% of available cash.

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Power Purchase Agreements

Prior to the construction of a geothermal project, we typically enter into a Power Purchase Agreement (“PPA”) with a utility, which fixes the price of energy produced at a project for a 20 to 30 year period. Such PPAs are typically negotiated with a utility company and approved by a state utility commission or similar regulating body, or other major retail electric service provider, or with a large industrial consumer.

Our power purchase agreements generally provide for energy payments only and can include the “green” attributes for geothermal energy since geothermal energy is a source of renewable energy. 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 or subject to preset annual adjustments. Some PPAs provide for 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 up to 3.9% in the initial years and to as low as 1.0% during the last 10 years of the agreement. The approximate 25 year levelized price is $117.65 per megawatt hour.

San Emidio, Nevada

On May 31, 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 was to be sold under the terms of the amended and restated PPA. The PPA required that Phase II had to be on line by December 2015, and since Phase II was not constructed, the option expired. The PPA was approved by the Public Utility Commission of Nevada on December 27, 2011.

Raft River Energy I LLC

Raft River Energy I LLC currently earns revenue from a 25 year, full-output PPA with Idaho Power Company, which allows power sales of up to 13 megawatts annual average. The PPA was signed on September 24, 2007 and expires in January 2033 on the anniversary of its commercial operation date. 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 12 (2020). From years 13 to 25 of the contract the escalation rate will drop to 0.6% per year.

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Operating Results

Comparison of the Year Ended December 31, 2017 and the Year Ended December 31, 2016

For the year ended December 31 2017, the Company reported net loss attributable to U.S. Geothermal Inc. of $2,267,981 ($0.12 loss per share) which represented a $2,731,312 decrease from net income attributable to U.S. Geothermal Inc. of $463,331 reported in the year ended 2016 ($0.02 income per share). Both favorable and unfavorable variances were noted for plant operations. These variances are addressed by each individual plant. Significant favorable variances were reported for professional and management fees, and promotion costs. Notable unfavorable variances were reported for employee compensation and income tax expense.

Comparison of the Year Ended December 31, 2016 and the Year Ended December 31, 2015

For the year ended December 31 2016, the Company reported net income attributable to U.S. Geothermal Inc. of $463,331 ($0.02 income per share) which represented a $1,383,898 decrease from net income attributable to U.S. Geothermal Inc. of $1,847,229 reported in the year ended 2015 ($0.10 income per share). Unfavorable variances were reported in corporate administration, professional and management fees, promotion, and other income/expenses. A notable favorable variance was reported for income tax expense.

Plant Operations

The Company’s energy production revenues and related operating costs originated from its three power plants. The Neal Hot Springs, Oregon (USG Oregon LLC) plant is located in Eastern Oregon and began commercial operations in November 2012. The San Emidio, Nevada (USG Nevada LLC) plant is located in the San Emidio Desert in the northwestern part of the State of Nevada and began operations in May 2012. The Raft River, Idaho (Raft River Energy I LLC) plant is located in South Eastern Idaho and began operations in January of 2008.

A summary of energy sales by plant for the three years are as follows:

	For the Year Ended December 31,
	2017		2016		2015
	$	%*	$	%*	$	%*
Energy sales by plant:
Neal Hot Spring, Oregon	19,941,366	63.0	19,561,718	62.8	18,823,799	61.1
San Emidio, Nevada	6,255,599	19.8	6,980,358	22.4	7,324,484	23.7
Raft River, Idaho	5,463,472	17.3	4,599,936	14.8	4,693,913	15.2
	31,660,437	100.0	31,142,012	100.0	30,842,196	100.0

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

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Neal Hot Springs, Oregon (USG Oregon LLC) Plant Operations

Comparison of the Year Ended December 31, 2017 and the Year Ended December 31, 2016

For the year ended December 31, 2017, the Neal Hot Springs plant reported subsidiary net plant income of $9,244,299, which was a decrease of $977,543 (9.6% decrease) from the net income of $10,221,842 reported in the year ended 2016.

Overall, energy sales for the year ended 2017 increased $379,648 (1.9% increase) from the prior year. The contracted rates effectively increased 2.3% during the year. During the current year the plant produced 172,805 megawatts of power which was a decrease of 6,753 megawatts (3.8% decrease) from the prior year. On January 5, 2017, Unit 1 experienced mechanical failures, primarily due to extreme cold temperatures that resulted in outages and the loss of a substantial amount of that Unit’s refrigerant. The Unit’s complications resulted in a total of 1,025 lost production hours during the first quarter of 2017 (1,146 lost for all three units). The initial repairs to identify and plug the damaged tubes were completed on February 12, 2017, however, Unit 1 operated at a reduced level through May 2017. Business Interruption insurance provided $727,235 of revenue to cover lost energy sales after the first 30 days of lost generation. Without the insurance coverage, energy sales for the first quarter would have decreased 9.0% from the same quarter ended 2016.

Plant operating costs, excluding depreciation, increased $1,442,886, which was a 32.3% increase from the prior year. The largest increases were related to taxes and field maintenance costs. For the year ended December 31, 2017, the Plant incurred property taxes of $1,103,071 which was an increase of $738,482 (202.6% increase) from the year ended 2016. For the first three years of operations, property taxes were abated by the County. The abatement period ended in 2016 and the first property tax payment was made in December 2016. Calendar year 2017 was the first full year of assessed property tax on the Plant.

During the year ended December 31, 2017, total field maintenance costs increased $324,304 (40.2% increase) from the prior year. For the current year, over $761,000 (not covered by insurance) in field maintenance costs were incurred to repair vaporizers, turbines and brine injection systems. Most of the repair costs were needed for Unit 1. Turbine repairs were incurred for both Units 1 and 2. In the fourth quarter of 2017, the plant was charged $250,413 for the rental of replacement pump motors owned by the Parent Company.

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

	Year Ended December 31,
	2017				2016				Variance
	$		%*		$		%*		$		%**
Plant revenues:
Energy sales	19,941,366		100.0		19,561,718		100.0		379,648		1.9

Plant expenses:
Operations	5,909,791		29.7		4,466,905		22.8		(1,442,886	)	(32.3	)
Depreciation and amortization	3,257,304		16.3		3,281,787		16.8		24,483		0.7
	9,167,095		46.0		7,748,692		39.6		(1,418,403	)	(18.3	)

Operating income	10,774271		54.0		11,813,026		60.4		(1,038,755	)	(8.8	)

Other income (expense):
Interest expense	(1,537,040	)	(7.7	)	(1,597,980	)	(8.1	)	60,940		3.8
Interest income/other	7,068		0.0		6,796		0.0		272		4.0
	(1,529,972	)	(7.7	)	(1,591,184	)	(8.1	)	61,212		3.8

Subsidiary net income	9,244,299		46.3		10,221,842		52.3		(977,543	)	(9.6	)

%* - represents the percentage of total plant operating revenues.

%** - represents the percentage of change from 2016 to 2017. 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.

Comparison of the Year Ended December 31, 2016 and the Year Ended December 31, 2015

For the year ended December 31, 2016, the Neal Hot Springs plant reported subsidiary net plant income of $10,221,842, which was an increase of $220,833 (2.2% increase) from the net income of $10,001,009 reported in the year ended December 31, 2015. Overall, energy sales for the year ended 2016 increased $737,919 (3.9% increase) from the year ended 2015. The contracted rates effectively increased 2.4% during the year. During the current year the plant produced 179,558 megawatts of power which was an increase of 2,687 megawatts (1.5% increase) from the prior year. Production hours lost due to both planned and unplanned outages decreased 9.2% from the prior year. In January and May of 2015, approximately 218 hours were lost due to plugged vaporizers in Units 2 and 3.

Plant operating costs, excluding depreciation, increased $588,143, which was a 15.2% increase from the prior year. The largest increases were related to taxes and field maintenance costs. For the current year, the plant incurred County Property taxes of $352,110. These taxes were abated during the initial years of plant operations. The abatement period ended in 2015. Increases in field maintenance expenses were partially offset by decreases in chemical and lubricant costs. Field and maintenance costs for the current year increased $98,374 (13.9% increase) from 2015.

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In the current year, the Company incurred costs that exceeded $233,000 for production pump repairs.

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

	Year Ended December 31,
	2016				2015				Variance
	$		%*		$		%*		$		%**
Plant revenues:
Energy sales	19,561,718		100.0		18,823,799		100.0		737,919		3.9

Plant expenses:
Operations	4,466,905		22.8		3,878,762		20.6		(588,143	)	(15.2	)
Depreciation and amortization	3,281,787		16.8		3,278,114		17.4		(3,673	)	(0.1	)
	7,748,692		39.6		7,156,876		38.0		(591,816	)	(8.3	)

Operating income	11,813,026		60.4		11,666,923		62.0		146,103		1.3

Other income (expense):
Interest expense	(1,597,980	)	(8.1	)	(1,674,411	)	(8.9	)	76,431		4.6
Interest income/other	6,796		0.0		8,497		0.0		(1,701	)	(20.0	)
	(1,591,184	)	(8.1	)	(1,665,914	)	(8.9	)	74,730		4.5

Subsidiary net income	10,221,842		52.3		10,001,009		53.1		220,833		2.2

%* - represents the percentage of total plant operating revenues.

%** - represents the percentage of change from 2015 to 2016. 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:

Quarter Ended:	Mega- watt Hours Produced	Energy Sales ($)	Ave. Rate per Megawatt Hour ($)	Subsidiary Net Income* ($)	Depreciation & Amortization ($)
March 31, 2015	53,500	5,207,350	97.3	3,010,263	819,708
June 30, 2015	37,232	3,188,091	85.6	1,027,928	819,785
September 30, 2015	33,498	4,004,715	119.3	1,651,029	819,450
December 31, 2015	52,642	6,423,643	122.0	4,311,789	819,171
March 31, 2016	53,671	5,366,004	100.0	3,226,740	818,062
June 30, 2016	39,094	3,445,321	88.2	1,243,706	820,063
September 30, 2016	29,758	3,651,073	122.4	1,279,527	820,546
December 31, 2016	57,036	7,099,320	124.5	4,471,869	823,116
March 31, 2017	48,178	5,210,556	101.4	2,345,574	826,748
June 30, 2017	37,727	3,449,403	91.4	642,313	826,026
September 30, 2017	30,800	4,141,284	125.1	2,032,429	827,996
December 31, 2017	56,100	7,139,310	127.3	4,474,396	776,534

* - 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 (USG Nevada LLC) Plant Operations

Comparison of the Year Ended December 31, 2017 and the Year Ended December 31, 2016

For the year ended December 31, 2017, the San Emidio plant reported subsidiary net loss of $312,420 which was a decrease of $1,354,686 (130.0% decrease) from the subsidiary net income of $1,042,266 reported for the year ended 2016.

Energy sales decreased $724,759 (10.4% decreased) from the prior year. During the current year the plant produced 66,591 megawatts of power which was a decrease of 8,458 megawatts (11.3% decrease) from the prior year. The contracted rates effectively increased 1.0% during the year. Production decreases were primarily due to higher levels of down time in the current year. Outages in 2017 resulted in a total 1,890 lost hours which was a 1,367 increase in lost hours from 2016. In the third quarter of 2017, approximately 886 hours were lost due repairs of plugged vaporizer tubes and repairs to a refrigerant pump. In the fourth quarter of 2017, approximately 184 hours were lost due to repairs on the vaporizer tubes.

For the current year, the total operating costs, excluding depreciation, increased $702,843 (26.3% increase) from the prior year. Significant increases were reported in chemicals and field maintenance costs. Chemical costs increased $293,990 (138.2% increase) from 2016. The complications related to the plugged vaporizer tubes resulted in significant losses of the plant’s refrigerant. The refrigerant replacement costs totaled approximately $293,800.

Field maintenance costs increased $473,188 (108.0% increase) from the prior year. As noted above, the plant experienced issues with the vaporizer tubes and refrigerant feed systems during the current year. The repair and replacement costs needed to alleviate these issues and other related issues was approximately $576,000.

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

	Year Ended December 31,
	2017				2016				Variance
	$		%*		$		%*		$		%**
Plant revenues:
Energy sales	6,255,599		100.0		6,980,358		100.0		(724,759	)	(10.4	)

Plant expenses:
Operations	3,370,988		53.9		2,668,145		38.2		(702,843	)	(26.3	)
Depreciation and amortization	1,273,273		20.3		1,280,671		18.3		7,398		0.6
	4,644,261		74.2		3,948,816		56.6		(695,445	)	(17.6	)

Operating income (loss)	1,611,338		25.8		3,031,542		43.4		(1,420,204	)	(46.8	)

Other income (expense):
Interest expense	(1,951,714	)	(31.2	)	(1,999,932	)	(28.7	)	48,218		2.4
Interest income/other income	27,956		0.4		10,656		0.2		17,300		16.3
	(1,923,758	)	(30.8	)	(1,989,276	)	(28.5	)	65,518		3.3

Subsidiary net income	(312,420	)	(5.0	)	1,042,266		14.9		(1,354,686	)	(130.0	)

%*      - represents the percentage of total plant operating revenues.
%**    - represents the percentage of change from 2016 to 2017. Increases in revenues and decreases in expenses from the prior period to the current period are considered to be favorable and are presented as positive figures.
#         - variance percentage that is extremely high or undefined.
The intercompany elimination adjustments for management fees and corporate support are not incorporated into the presentation of the subsidiary’s net operating income/loss.

Comparison of the Year Ended December 31, 2016 and the Year Ended December 31, 2015

For the year ended December 31, 2016, the San Emidio plant reported subsidiary net income of $1,042,266 which was a decrease of $442,931 (29.8% decrease) from the subsidiary net income of $1,485,197 reported for the year ended 2015.

The contracted rates effectively increased 1.0% during the year. During the current year the plant produced 20,803 megawatts of power which was a decrease of 4,489 megawatts (5.6% decrease) from the prior year. Production decreases were primarily due to higher levels of down time in the current year. In April 2016, approximately 107 hours were needed to repair a vaporizer bypass valve. In June 2016, approximately 155 hours were needed to replace a refrigerant pump. Efficiencies gained by the new refrigerant pump have increased production that was realized in the current third quarter and fourth quarters.

For the current year, the total operating costs, excluding depreciation, decreased $63,653 (2.4% decrease) from the prior year. Significant decreases in administration and corporate support were partly offset by increases in field maintenance and taxes. Corporate support and administrative costs decreased $322,337 (61.6% decrease) from 2015. For the current year, the Parent Company elected to forgo its collection of management fees and corporate support costs. In 2015, USG Nevada LLC incurred $206,398 and $117,997 in management fees and corporate support; respectively. Field maintenance costs increased $186,671 (74.2% increase) from the prior year. In the current year, costs that exceeded $147,700 were incurred for production pump repairs and repairs to the condensate/feed system. For the current year, taxes and permit costs increased $51,183 (15.1% increase) from 2015. The mineral proceeds tax for the State of Nevada were significantly lower in 2015 due to an overpayment in 2014 and lower budgeted allowable expenses for 2015. In the second quarter 2016, additional minerals proceeds tax assessment was made for $30,425 after an examination by the State of Nevada.

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

	Year Ended December 31,
	2016				2015				Variance
	$		%*		$		%*		$		%**
Plant revenues:
Energy sales	6,980,358		100.0		7,324,484		100.0		(344,126	)	(4.7	)

Plant expenses:
Operations	2,668,145		38.2		2,604,492		35.6		(63,653	)	(2.4	)
Depreciation and amortization	1,280,671		18.3		1,263,401		17.2		(17,270	)	(1.4	)
	3,948,816		56.6		3,867,893		52.8		(80,923	)	(2.1	)

Operating income (loss)	3,031,542		43.4		3,456,591		47.2		(425,049	)	(12.3	)

Other income (expense):
Interest expense	(1,999,932	)	(28.7	)	(2,032,776	)	(27.7	)	32,844		1.6
Interest income/other income	10,656		0.2		61,382		0.8		(50,726	)	(82.6	)
	(1,989,276	)	(28.5	)	(1,971,394	)	(26.9	)	(17,882	)	(0.9	)

Subsidiary net income	1,042,266		14.9		1,485,197		20.3		(442,931	)	(29.8	)

%*     - represents the percentage of total plant operating revenues.
%**   - represents the percentage of change from 2015 to 2016. Increases in revenues and decreases in expenses from the prior period to the current period are considered to be favorable and are presented as positive figures.
#          - variance percentage that is extremely high or undefined.
The intercompany elimination adjustments for management fees 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 San Emidio, Nevada plant is summarized as follows:

Quarter Ended:	Mega- watt Hours Produced	Energy Sales ($)	Ave. Rate per Megawatt Hour ($)	Subsidiary Net Income (Loss)* ($)		Depreciation & Amortization ($)
March 31, 2015	21,754	2,003,346	92.1	556,301		316,346
June 30, 2015	18,492	1,702,633	92.1	264,410		315,846
September 30, 2015	18,924	1,742,750	92.1	386,033		314,940
December 31, 2015	20,369	1,875,755	92.1	278,453		316,269
March 31, 2016	20,433	1,900,467	93.0	425,447		318,214
June 30, 2016	14,139	1,315,049	93.0	(142,273	)	319,756
September 30, 2016	19,675	1,829,996	93.0	384,018		321,479
December 31, 2016	20,803	1,934,846	93.0	375,074		321,222
March 31, 2017	19,501	1,831,890	93.9	425,071		321,051
June 30, 2017	17,695	1,662,245	93.9	241,949		319,629
September 30, 2017	11,299	1,061,459	93.9	(896,001	)	316,940
December 31, 2017	18,097	1,700,005	93.9	(83,439	)	315,653

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

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

Comparison of the Year Ended December 31, 2017 and the Year Ended December 31, 2016

For the year ended December 31, 2017, Raft River Energy I LLC (“RREI”) reported subsidiary net loss of $925,538, which was an unfavorable increase of $287,316 (45.0% increase) from the loss of $638,222 reported for the year ended 2016.

Energy sales increased $863,536 (18.8% increase) from the prior year. During the current year the plant produced 84,436 megawatts of power which was an increase of 12,445 megawatts (17.3% increase) from the prior year. On March 21, 2017, a new production well (RRG-5) was connected to the plant. The new well addition has increased the net power production of the plant by approximately 0.71 megawatts. In February 2016, a production well (RRG-2) was taken off line in order to facilitate the well expansion project. This well was reconnected to the plant when the project was completed in June 2016. Overall, the plant lost a total of 166 hours and 149 hours in 2017 and 2016; respectively. For both years, the lost hours were primarily due to the noted issues and annual maintenance.

Plant operating costs, excluding depreciation, increased $1,197,694 (32.9% increase) from the year ended 2016. The increases were primarily due to field maintenance costs and electricity purchases. Field maintenance costs increased $860,204 (107.2% increase) from 2016. On September 22, 2017, the production pump for well (RRG-7) was lost when the conductor slipped and lost its cement bond. Repairs involved installing and setting a new conductor, rebuilding the well head and reinstalling a new pump. The cost of these repairs was approximately $1,090,000 and was completed on December 11, 2017.

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During the year ended December 31, 2017, electricity purchases increased $128,431 (18.1% increase) from the prior year. Electricity purchases are incurred for the various pumps utilized by the plant. The increases in electricity purchases are directly related to the increase in energy production. The majority of the increase in electricity purchases is related to the addition of the production well pump in March 2017.

The summarized statements of operations for RREI are as follows:

	Year Ended December 31,
	2017				2016				Variance
	$		%*		$		%*		$		%**
Plant revenues:
Energy sales	5,463,472		93.2		4,599,936		93.1		863,536		18.8
Energy credit sales	396,350		6.8		339,663		6.9		56,667		16.7
	5,859,822		100.0		4,939,599		100.0		920,223		18.6

Plant expenses:
General operations	4,836,192		82.5		3,638,498		73.7		(1,197,694	)	(32.9	)
Depreciation and amortization	1,950,016		33.3		1,814,937		36.7		(135,079	)	(7.4	)
	6,786,208		115.8		5,453,435		110.4		(1,332,773	)	(24.4	)

Operating loss	(926,386	)	(15.8	)	(513,836	)	(10.4	)	(412,550	)	80.3

Other income (expense):
Interest expense	(233	)	(0.0	)	(198	)	(0.0	)	(35	)	(17.7	)
Other and interest income	1,081		(0.0	)	(124,188	)	(2.5	)	125,269		100.9
	848		(0.0	)	(124,386	)	(2.5	)	125,234		100.7

Subsidiary net loss	(925,538	)	(15.8	)	(638,222	)	(12.9	)	(287,316	)	45.0

%* - represents the percentage of total plant operating revenues.

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

Comparison of the Year Ended December 31, 2016 and the Year Ended December 31, 2015

The subsidiary net loss from Raft River Energy I LLC (“RREI”) operations of $638,222 for the year ended December 31, 2016 increased $1,530 (0.2% increase) from the loss of $636,692 reported for the year ended 2015. Energy sales decreased $93,977 (2.0% decrease) from the prior year. Decreases in production were partially offset by contracted rate increases. The contracted rates effectively increased 2.9% during the year. During the current year the plant produced 20,039 megawatts of power which was a decrease of 3,604 megawatts (4.8% decrease) from the prior year. From February through September 2016, the plant lost one of its production wells partially due to the drilling of the new leg on a production well. Also, another well was out of operation from late September through November of the current year.

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Plant operating costs, excluding depreciation, decreased $275,519 for the year ended December 31, 2016, which was a 7.0% decrease from the year ended 2015. The decreases were primarily due to field maintenance costs. Field maintenance costs decreased 12.0% from 2015. In the prior year, costs that exceeded $294,700 were incurred for a scheduled turbine overhaul.

The summarized statements of operations for RREI are as follows:

	Year Ended December 31,
	2016				2015				Variance
	$		%*		$		%*		$		%**
Plant revenues:
Energy sales	4,599,936		93.1		4,693,913		92.9		(93,977	)	(2.0	)
Energy credit sales	339,663		6.9		357,902		7.1		(18,239	)	(5.1	)
	4,939,599		100.0		5,051,815		100.0		(112,216	)	(2.2	)

Plant expenses:
General operations	3,638,498		73.7		3,914,017		77.5		275,519		7.0
Depreciation and amortization	1,814,937		36.7		1,757,891		34.8		(57,046	)	(3.2	)
	5,453,435		110.4		5,671,908		112.3		218,473		3.9

Operating loss	(513,836	)	(10.4	)	(620,093	)	(12.3	)	106,257		17.1

Other income (expense):
Interest expense	(198	)	(0.0	)	(39,064	)	(0.8	)	38,866		99.5
Other and interest income	(124,188	)	(2.5	)	22,465		0.5		(146,653	)	(652.8	)
	(124,386	)	(2.5	)	(16,599	)	(0.3	)	(107,787	)	(649.4	)

Subsidiary net loss	(638,222	)	(12.9	)	(636,692	)	(12.6	)	(1,530	)	0.2

%* - represents the percentage of total plant operating revenues.
%** - represents the percentage of change from 2015 to 2016. 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:

Quarter Ended:	Mega- watt Hours Produced	Energy Sales ($)	Ave. Rate per Megawatt Hour ($)	Subsidiary Net Income (Loss)* ($)		Depreciation & Amortization ($)
March 31, 2015	20,672	1,165,050	56.4	(96,930	)	431,959
June 30, 2015	17,223	888,599	51.6	(668,764	)	438,955
September 30, 2015	15,950	1,106,643	69.4	(296,743	)	443,233
December 31, 2015	21,751	1,533,621	70.5	425,745		443,744
March 31, 2016	19,684	1,144,351	58.2	(158,497	)	444,587
June 30, 2016	15,647	829,554	52.1	(321,895	)	444,608
September 30, 2016	16,622	1,173,294	71.5	(288,634	)	444,878
December 31, 2016	20,039	1,452,737	72.5	130,804		480,864
March 31, 2017	21,934	1,292,005	58.9	55,242		484,948
June 30, 2017	20,680	1,102,160	64.6	(161,494	)	485,940
September 30, 2017	20,602	1,511,251	73.3	205,776		486,530
December 31, 2017	21,220	1,954,406	73.4	(1,025,062	)	492,598

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

Corporate Administration

Comparison of the Year Ended December 31, 2017 and the Year Ended December 31, 2016

For the year ended December 31, 2017, the Company reported $1,252,345 in corporate and administrative expense which was a decrease of $61,179 (4.7% increase) from $1,313,524 reported for the year ended 2016.

Comparison of the Year Ended December 31, 2016 and the Year Ended December 31, 2015

For the year ended December 31, 2016, the Company reported $1,313,524 in corporate and administrative expense which was an increase of $225,849 (20.8% increase) from $1,087,675 reported for the year ended 2015. For the year ended December 31, 2016, rental expenses increased $158,278 (134.9% increase) from the year ended 2015. During the current year, additional rental/storage costs of $152,433 were incurred for storage of power plant components acquired in the fourth quarter 2015. The majority of the power plant components have been moved to a storage facility owned by the Company in the fourth quarter of 2016; therefore, these rental costs will not be incurred in future periods. Director fees increased $49,900 (42.2% increase) from the prior year. In addition to routine rate increases, two additional independent board members were added during the current year.

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Professional and Management Fees

Comparison of the Year Ended December 31, 2017 and the Year Ended December 31, 2016

For the year ended December 31, 2017, the Company reported $895,925 in professional and management fees which was a decrease of $719,845 (44.6% decrease) from $1,615,770 reported in the year ended 2016. In August of 2015, the Company formed a Special Committee of the Board of Directors to thoroughly explore strategic options to maximize shareholder value. The Company ended this process and ended the contract with the primary consultant that was engaged in the examination in March 2016. For the first quarter of 2016, the consultant’s fees associated with this examination totaled approximately $544,000. Legal fees that exceeded $100,000 were incurred in the first quarter of 2016 to support the examination and issuance of common shares. The Company incurred fees of $100,000 for services provided by a new financial advisor hired during the first quarter 2016. These consultant services were discontinued in June 2016.

Comparison of the Year Ended December 31, 2016 and the Year Ended December 31, 2015

For the year ended December 31, 2016, the Company reported $1,615,770 in professional and management fees which was an increase of $547,831 (51.3% increase) from $1,067,939 reported in the year ended 2015. In August of 2015, the Company formed a Special Committee of the Board of Directors to thoroughly explore strategic options to maximize shareholder value. The Company ended this process and ended the contract with the primary consultant that was engaged in the examination in March 2016. For the first quarter of 2016, the consultant’s fees associated with this examination totaled approximately $544,000. During 2016, the Company incurred additional fees of $100,000 for services provided by a new financial advisor.

Employee Compensation

Comparison of the Year Ended December 31, 2017 and the Year Ended December 31, 2016

For the year ended December 31, 2017, the Company reported $3,946,898 in employee compensation which was an increase of $911,824 (30.0% increase) from $3,035,074 reported in the year ended 2016. The Company elected not to renew the CEO’s employment contract, and consequently, on July 18, 2017, the former CEO’s employment contract expired. The severance provisions of the contract entitled the former CEO to 18 months of base salary and targeted bonus, plus 18 months of health insurance premiums. The cost of these provisions totaled approximately $1.25 million.

Comparison of the Year Ended December 31, 2016 and the Year Ended December 31, 2015

For the year ended December 31, 2016, the Company reported $3,035,074 in employee compensation which was an increase of $152,969 (5.3% increase) from $2,882,105 reported in the year ended 2015.

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Promotion

Comparison of the Year Ended December 31, 2017 and the Year Ended December 31, 2016

For the year ended December 31, 2017, the Company reported $204,651 in promotion costs which was a decrease of $171,775 (45.6% decrease) from $376,426 reported in the year ended 2016. In 2016, the Company incurred additional travel costs related to the process of exploring strategic options to maximize shareholder value, attending investment conferences and implementing a new marketing program. The new marketing program included radio spots and regular news article coverage. The costs of the marketing program for the second quarter 2016 totaled $117,650. Also in 2016, the Company continued a contract with an outside investor relations firm for $6,000 per month. This contract ended in June 2016.

Comparison of the Year Ended December 31, 2016 and the Year Ended December 31, 2015

For the year ended December 31, 2016, the Company reported $376,426 in promotion costs which was an increase of $160,835 (74.6% increase) from $215,591 reported in the year ended 2015. During first quarter 2016, the Company incurred additional travel costs related to the process of exploring strategic options to maximize shareholder value and to attend investment conferences. During second quarter 2016, the Company implemented a new marketing program that included radio spots and regular news article coverage. The costs of the marketing program for the second quarter totaled $117,650. The Company continued a contract with an outside investor relations firm for $6,000 per month. This contract ended in June 2016. In the third and fourth quarters of 2016, promotion costs were, primarily, incurred for professional memberships fees and investor conferences.

Other Income/Expenses

Comparison of the Year Ended December 31, 2017 and the Year Ended December 31, 2016

For the year ended December 31, 2017, the Company reported a net gain of $80,324 for other income/expenses which was an increase of $149,270 from the net loss/expense of $68,946 reported the year ended 2016. In September 2016, a production pump was replaced at the Raft River Energy I LLC plant. The book value of the pump was $124,930 ($175,000 cost, less $50,070 accumulated depreciation) at the time of disposal.

Comparison of the Year Ended December 31, 2016 and the Year Ended December 31, 2015

For the year ended December 31, 2016, the Company reported a net loss of $68,946 for other income/expenses which was a decrease of $210,239 from the net gain of $141,293 reported the year ended 2015. In September 2016, a production pump was replaced at the Raft River Energy I LLC plant. The book value of the pump was $124,930 ($175,000 cost, less $50,070 accumulated depreciation) at the time of disposal.

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Income Tax Expense

Comparison of the Year Ended December 31, 2017 and the Year Ended December 31, 2016

For the year ended December 31, 2017, the Company reported net income tax expense of $1,863,000 which was an increase $1,288,000 (224.0% increase) from $575,000 of income tax expense recognized in the prior year. The Tax Cuts and Jobs Act was enacted on December 22, 2017. The Act reduced the U.S. Federal corporate tax rate from 34% to 21% beginning in 2018. The impact of the Act reduced the Company’s net deferred tax asset by approximately $4.1 million.

Comparison of the Year Ended December 31, 2016 and the Year Ended December 31, 2015

For the year ended December 31, 2016, the Company reported net income tax expense of $575,000 which was a decrease of $811,000 (58.5% decrease) from $1,386,000 of net income tax expense recognized in the prior year. Net income attributable to U.S. Geothermal Inc. before income taxes decreased $2,194,898 (67.9% decrease) from the year ended 2015. The decrease was due to the decline in income, which was primarily a result of increases in corporate administration, professional and management fees, and promotion costs as discussed above.

Net Income Attributable to the Non-Controlling Interests

Comparison of the Year Ended December 31, 2017 and the Year Ended December 31, 2016

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 subsidiaries. For the year ended December 31, 2017, the Company reported $1,916,707 in net income attributable to non-controlling interests, which was a decrease of $1,205,310 (38.6% decrease) from $3,122,017 net income reported for the year ended 2016.

The primary components of the variances were the operating results of USG Oregon LLC (wholly owned by Oregon USG Holdings LLC) and Raft River Energy I LLC. USG Oregon reported a subsidiary net profit for the year ended December 31, 2017 of $9,244,299, which was a decrease of $977,543 (9.6% decrease) from $10,221,842 subsidiary net profit reported for the year ended 2016. Raft River reported a subsidiary net loss of $925,538, which was an unfavorable increase of $287,316 (45.0% increase) from the net loss of $638,222 reported for the year ended 2016. The primary conditions for the variances in USG Oregon and Raft River’s operations were discussed above.

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

	For the Year Ended
	December 31,
Subsidiaries and Non-Controlling	2017		2016		Variances
Interest Entities	$		$		$		%
Oregon USG Holdings LLC interest held by Enbridge Inc.	3,671,168		4,079,830		(408,662	)	(10.0	)
Raft River Energy I LLC interest held by Goldman Sachs	(1,847,948	)	(951,148	)	(896,800	)	(94.3	)
Gerlach Geothermal LLC interest held by Gerlach Green Energy, LLC	(6,678	)	(6,665	)	(13	)	(0.2	)
	1,816,542		3,122,017		(1,305,475	)	(41.8	)

% - represents the percentage of change from 2016 to 2017.

Comparison of the Year Ended December 31, 2016 and the Year Ended December 31, 2015

For the year ended December 31, 2016, the Company reported $3,122,017 in net income attributable to non-controlling interests, which was an increase of $18,748 (0.6% increase) from $3,103,269 net income reported for the year ended 2015.

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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, 2017:

							Exploration
							Activities
	Neal Hot		San				and
Statement of	Springs		Emidio		Raft River		Corporate		Consolidated
Operations Element	$		$		$		$		$

Net income from plant operations	10,774,270		1,611,338		(926,386	)	979,126		12,438,348
Expenses/(income)	1,596,352		1,923,758		(848	)	⁽⁴⁾7,507,525		11,026,787
Net income (loss)	9,177,918		(312,420	)	(925,538	)	(6,528,399	)	1,441,561

Income taxes	(1,399,000	)	79,000		(234,000	)	(309,000	)	(1,863,000	)
Non-controlling interests	⁽¹⁾(3,671,167)		-		⁽²⁾1,847,949		⁽³⁾6,676		(1,816,542	)
Net income attributable to U.S. Geothermal	4,107,751		(233,420	)	688,411		(6,830,723	)	(2,267,981	)

	⁽¹⁾	The non-controlling interest for Neal Hot Springs represents a 40% interest for our joint venture partner, Enbridge. Neal Hot Springs includes the operations of both Oregon USG Holdings LLC and USG Oregon LLC.

	⁽²⁾	The non-controlling interest 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 interest for our exploration activities represents a 30.7% 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, 2017 include:

•	Employee compensation	$ 3,946,898
•	Corporate administration	1,252,345
•	Professional fees	895,925
•	Promotion	204,651
•	Exploration costs	47,844

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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Selected balance sheet items affected by non-controlling interests as of December 31, 2017 are detailed as follows:

		Non-	U.S.
		Controlling	Geothermal
	Consolidated	Interests	Inc.
Balance Sheet Items	$	$	$

Unrestricted cash and cash equivalents	16,648,419	2,038,530	14,609,889
Restricted cash and security bonds:
Current	7,532,683	940,044	6,592,639
Long-term	16,028,722	3,991,792	12,036,930

Notes payable:
Current	4,232,534	1,301,001	2,931,533
Long-term	97,993,641	20,508,868	77,484,773

The loans held by the Company at December 31, 2017 are detailed as follows:

					U.S. Geothermal Inc.
	Consolidated			Contracted	Loan
	Total Loan	Remaining	Loan	Interest	Balance	Loan
	Balances	Months to	Maturity	Rate	Portions	Balances
Descriptions	$	Term	End Date	%	%	$

Department of Energy – USG Oregon LLC	54,524,670	206	2/12/35	2.598	60.0	32,714,802
Prudential Group – USG Nevada LLC	28,402,582	240	12/31/37	6.750	100.0	28,402,582
Prudential Group – Idaho USG Holdings LLC	19,296,475	63	3/31/23	5.800	100.0	19,296,475
Chrysler Auto Loan – U.S. Geothermal Services	2,447	7	7/27/18	6.740	100.0	2,447
Totals	102,226,174					80,416,306

Weighted Average Term (Months)		188
Weighted Average Interest Rate				4.356

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Liquidity and Capital Resources

Year Ended December 31, 2017

During the quarter ended December 31, 2017, the Company’s operating projects continued to generate available cash (after debt service and reserves) to fund our development activities and corporate costs. In addition, exercise of options and warrants generated $1,356,200 during the year. We believe our cash and liquid investments at December 31, 2017 are adequate to fund our general operating activities through December 31, 2018.

Year Ended December 31, 2016

During the quarter ended December 31, 2016, the Company’s operating projects continued to generate available cash (after debt service and reserves) to fund our development activities and corporate costs. In addition, exercise of options and warrants generated $1,471,318 during the year.

Year Ended December 31, 2015

During the calendar year ended December 31, 2015, the Company’s operating projects have generated significant available cash (after debt service and reserves) to fund our development activities and corporate costs. Neal Hot Springs has distributed $5.2 million in cash as an equity distribution to U.S. Geothermal; San Emidio has generated $2.7 million in cash provided by operating activities; Raft River has paid $0.2 million in REC income cash to U.S. Geothermal. In addition, cash received by corporate as a result of management fees, royalties and lease income totaled $1.3 million.

The Company’s 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.

Idaho Power Company and Sierra Pacific Power (NV Energy) continue to pay for their power in a timely manner. This power is sold under long-term contracts at fixed prices. 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 May 19, 2016, the Company closed on a $20 million debt facility from Prudential Capital Group. Under terms of the financing agreement, the Company has the option, without obligation, to issue additional debt, up to $50 million in aggregate within the next two years. The initial $20 million loan has a fixed interest rate of 5.8% per annum. The loan principal amortizes over twenty years, with a seven-year term. Principal and interest payments are made semi-annually. The loan is collateralized with the Company’s ownership interest in the Neal Hot Springs and Raft River projects and by virtue of a pledge by the Company’s wholly owned subsidiary, U.S. Geothermal Inc., an Idaho corporation, and sole member of Idaho USG Holdings, of the equity interests in Idaho USG Holdings. The 22 MW Neal Hot Springs project is owned 60% by the Company and 40% by Enbridge. The 13 MW Raft River project is owned 95% by the Company and 5% by Goldman Sachs. As of January 2, 2018, the Company owns 100% of the Raft River project.

-95-

On January 22, 2016, management determined it would be prudent to enter into a new Lincoln Park Capital Fund, LLC (“LPC”) facility and entered into a purchase agreement with LPC (the “Purchase Agreement”) to that effect. The Company’s first Purchase Agreement with LPC was entered into on May 21, 2012 and expired in 2015. Under the 2016 Purchase Agreement, at the Company’s sole discretion, the Company had the right to sell and LPC had the obligation to purchase up to $10 million of equity capital over a 30-month period subject to the conditions in the Purchase Agreement. The Purchase Agreement provided for an initial sale of $650,000 of shares of common stock upon closing. Net proceeds from LPC’s investments were used to cover a portion of the cost of the recent acquisition of the Goldman Sachs ownership interest of the Raft River project, development of our geothermal projects and for general corporate purposes. During the quarter ended March 31, 2016 an additional $571,650 was raised under the LPC facility subsequent to the initial sale. No additional funds were raised since that time. On August 4, 2017, the Company delivered notice to LPC pursuant to the Purchase Agreement terminating the Purchase Agreement. Pursuant to the terms of the Purchase Agreement, termination of the Purchase Agreement became effective August 7, 2017.

Potential Acquisitions

The Company intends to continue its growth through the acquisition of ownership or leasehold interests in properties and/or property rights that it believes will add to the value of the Company’s geothermal resources, and through possible mergers with or acquisitions of operating power plants and geothermal or other renewable energy properties.

Critical Accounting Policies

The discussion and analysis of our financial condition and results of operations are based upon the consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of these financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been made. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for the financial statements.

-96-

Revenue Recognition

Energy sales revenue are 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”) are earned for each megawatt hour produced from the geothermal power plants. 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 San Emidio and Neal Hot Springs, the RECs are owned by our customer and are bundled with energy sales.

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, geothermal water rights and construction in progress. 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.

Stock-Based Compensation

The Company awards stock options to employees for services provide to the Company. 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 shares, the expected life of the options, and the volatility of the stock price. Generally, 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. To date, all costs associated with the stock options have been charged to operations and no costs have been allocated to the construction of property and equipment.

-97-

Contractual Obligations

As of December 31, 2017, the following table denotes contractual obligations by payments due for each period:

	Total	< 1 year	1-3 years	3-5 years	> 5 years
Operating Leases ⁽¹⁾	$ 7,790,138	$ 662,536	$ 1,072,342	$ 911,510	$ 5,143,750
Plant Loan⁽²⁾	28,402,581	584,630	1,504,685	2,436,195	23,877,071
Project Loan ⁽³⁾	19,296,475	392,955	1,385,973	1,508,051	16,009,496
Plant Loan, DOE⁽⁴⁾	54,524,670	3,145,441	6,290,883	6,290,883	38,797,463
Auto Loan	2,447	2,447	-	-	-

	⁽¹⁾	Operating leases does not include costs from royalty based lease contracts. Lease extentions are calculated through the end of the individual plants’ PPA contract periods.
	⁽²⁾	Plant loan with Prudential Capital Group scheduled for to be repaid over the next 21 years.
	⁽³⁾	Project loan with Prudential Capital Group scheduled to be repaid March 2023.
	⁽⁴⁾	Plant loan with the Department of Energy scheduled to be repaid over the next 18 years.

Off Balance Sheet Arrangements

As of December 31, 2017, the Company does not have any off balance sheet arrangements.

Item 7A.

Quantitative and Qualitative Disclosures About Market Risk

Interest Risk on Investments

At December 31, 2017, the Company held investments of $31,656,317 in money market accounts. The money market funds are invested in governmental obligations with minimal fluctuations in interest rates and fixed terms; therefore, the interest rate risk on investments is not significant.

Foreign Currency Risk

The Company is not subject to foreign currency risks as we do not maintain a significant amount of cash deposits in a foreign currency. At fiscal year end, the Company held deposits that amounted to less than $1,000 in U.S. dollar equivalents.

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 signing PPA contracts for 20 to 25 year periods. This type of arrangement will be the model for PPAs planned for future power plants.

Item 8.

Financial Statements and Supplementary Data

The following financial statements and supplementary data should be read in conjunction with “Part II, Item 6: Selected Financial Data” of this Annual Report on Form 10-K.

-98-

U.S. GEOTHERMAL INC.

________

Consolidated Financial Statements
and
Reports of Independent Registered Public Accountants

December 31, 2017, 2016 and 2015

Report of Independent Registered Public Accounting Firm

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

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of U.S. Geothermal Inc. (“the Company”) as of December 31, 2017 and 2016, the related consolidated statements of operations, cash flows, and changes in stockholders’ equity for each of the three years in the period ended December 31, 2017, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of the Company as of December 31, 2017 and 2016, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 8, 2018, expressed an unqualified opinion on the Company’s internal control over financial reporting.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures to respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ Moss Adams LLP

Seattle, Washington
March 8, 2018

We have served as the Company’s auditor since 2015.

U.S. GEOTHERMAL INC.

CONSOLIDATED BALANCE SHEETS

		December 31,
		2017			2016

ASSETS

Current:
Cash and cash equivalents	$	16,648,419		$	15,287,144
Restricted cash and security bonds		7,532,683			8,527,462
Trade accounts receivable		3,861,559			4,102,018
Other current assets		1,595,824			1,664,866
Total current assets		29,638,485			29,581,490

Restricted cash and security bond reserves		16,028,722			20,111,350
Property, plant and equipment, net		168,690,333			170,301,349
Intangible assets, net		14,902,458			15,084,143
Net deferred income tax asset		6,483,000			8,346,000
Total assets	$	235,742,998		$	243,424,332


LIABILITIES AND STOCKHOLDERS’ EQUITY

Current Liabilities:
Accounts payable and accrued liabilities	$	3,985,783		$	2,255,710
Convertible promissory note		-			-
Current portion of notes payable		4,125,474			4,259,595
Total current liabilities		8,111,257			6,515,305

Long-term Liabilities:
Asset retirement obligations		1,257,720			1,219,903
Notes payable, less current portion		97,475,123			104,131,086
Total long-term liabilities		98,732,843			105,350,989

Total liabilities		106,844,100			111,866,294

Commitments and Contingencies (note 13)
STOCKHOLDERS’ EQUITY
Capital stock (authorized: 250,000,000 common shares with a $0.001 par value; issued and outstanding shares at December 31, 2017 and 2016 were: 19,449,984 and 18,970,445; respectively)		19,450			18,970
Additional paid-in capital		124,046,514			121,933,378
Accumulated deficit		(19,242,281	)		(16,974,300	)
		104,823,683			104,978,048

Non-controlling interests		24,075,215			26,579,990
Total stockholders’ equity		128,898,898			131,558,038

Total liabilities and stockholders’ equity	$	235,742,998		$	243,424,332

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

U.S. GEOTHERMAL INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

		For the Year Ended December 31,
		2017			2016			2015

Plant Revenues:
Energy sales	$	31,660,437		$	31,142,012		$	30,842,196
Energy credit sales		396,350			339,663			357,902
Total plant operating revenues		32,056,787			31,481,675			31,200,098

Plant Expenses:
Plant production expenses		13,137,847			10,069,933			9,572,707
Depreciation and amortization		6,480,592			6,377,396			6,299,405
Total plant operating expenses		19,618,439			16,447,329			15,872,112

Gross Profit		12,438,348			15,034,346			15,327,986
Operating Expenses:
Corporate administration		1,252,345			1,313,524			1,087,675
Professional and management fees		895,925			1,615,770			1,067,939
Employee compensation		3,946,898			3,035,074			2,882,105
Promotion		204,651			376,426			215,591
Exploration		47,844			39,091			82,316
Operating Income		6,090,685			8,654,461			9,992,360

Other (income) expenses:
Interest expense		4,759,448			4,425,167			3,797,155
Other (income) expense		(80,324	)		68,946			(141,293	)

Income Before Income Tax Expense		1,411,561			4,160,348			6,336,498
Income tax expense		1,863,000			575,000			1,386,000

Net Income (Loss)		(451,439	)		3,585,348			4,950,498

Net income attributable to the non-controlling interests		(1,816,542	)		(3,122,017	)		(3,103,269	)

Net Income (Loss) Attributable to U.S. Geothermal Inc.	$	(2,267,981	)	$	463,331		$	1,847,229

Net Earnings (Loss) Per Share Attributable to U.S. Geothermal Inc.:
Basic		(0.12	)	$	0.02		$	0.10
Diluted		(0.12	)		0.02			0.10

Weighted average number of shares used in the calculation of income (loss) per share:
Basic		19,135,822			18,665,808			17,828,469
Diluted		19,135,822			19,255,891			18,052,267

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

U.S. GEOTHERMAL INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

		For the Year Ended December 31,
		2017			2016			2015

Operating Activities:
Net Income (Loss)	$	(451,439	)	$	3,585,348		$	4,950,498
Adjustments to reconcile net income (loss) to total cash provided by operating activities:
Depreciation and amortization		6,699,596			6,544,287			6,409,818
Stock based compensation		757,412			1,053,782			1,107,828
Loss on disposal of equipment		-			124,930			-
Change in deferred income taxes		1,863,000			575,000			1,386,000
Net changes in:
Trade accounts receivable		240,459			(335,501	)		7,616
Accounts payable and accrued liabilities		1,879,587			2,826			59,510
Prepaid expenses and other		69,042			15,952			(130,460	)
Total cash provided by operating activities		11,057,657			11,566,624			13,790,810

Investing Activities:
Purchases of property, plant and equipment		(5,677,523	)		(9,409,260	)		(6,602,974	)
Acquisition of additional interests in subsidiaries		-			-			(3,500,000	)
Grant proceeds for capital expenditures		776,226			-			-
Net release (funding) of restricted cash reserves and bonds		5,077,407			(6,447,016	)		(180,919	)
Total cash provided (used) by investing activities		176,110			(15,856,276	)		(10,283,893	)

Financing Activities:
Issuance of common stock		1,356,204			2,659,952			49,549
Proceeds from note payable, net of issuance costs		-			19,185,986			-
Distributions to non-controlling interest		(4,321,317	)		(4,153,951	)		(3,462,589	)
Principal payments on notes payable and other obligations		(6,907,379	)		(6,769,566	)		(4,434,477	)
Total cash (used) provided by financing activities		(9,872,492	)		10,922,421			(7,847,517	)

Increase (Decrease) in Cash and Cash Equivalents		1,361,275			6,632,769			(4,340,600	)

Cash and Cash Equivalents, Beginning of Year		15,287,144			8,654,375			12,994,975

Cash and Cash Equivalents, End of Year	$	16,648,419		$	15,287,144		$	8,654,375

Supplemental Disclosures:
Non-cash investing and financing activities:
Accrual for purchases of property and equipment	$	149,515		$	450,342		$	8,230
Convertible promissory note issued for additional subsidiary interest		-			-			1,597,000
Non-cash distributions to non-controlling interest		-			-			24,000

Other Items:
Interest paid		4,711,120			4,106,537			3,819,585

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

U.S. GEOTHERMAL INC.

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY

For the Years Ended December 31, 2017, 2016 and 2015

											Non-
	Number of			Common		Additional Paid-		Accumulated			controlling
	Shares			Shares		In Capital		Deficit			Interest			Totals

Balance at January 1, 2015	17,836,338		$	17,836	$	103,758,553	$	(19,284,860	)	$	46,397,092		$	130,888,621

Distributions to non-controlling interest entities	-			-		-		-			(3,486,589	)		(3,486,589	)
Acquisition of additional interest in subsidiary	-			-		13,304,848		-			(18,401,848	)		(5,097,000	)
Stock issued by the exercise of employee stock options	25,833			26		49,524		-			-			49,550
Stock compensation	71,399			71		1,107,756		-			-			1,107,827
Net income	-			-		-		1,847,229			3,103,269			4,950,498

Balance at December 31, 2015	17,933,570			17,933		118,220,681		(17,437,631	)		27,611,924			128,412,907

Distributions to non-controlling interest entities	-			-		-		-			(4,153,951	)		(4,153,951	)
Stock issued under At Market Issuance Purchase Agreement net of commitment shares valued at $225,000	410,635			410		1,188,224		-			-			1,188,634
Stock issued by the exercise of employee stock options	342,082			342		882,961		-			-			883,303
Stock issued by the exercise of broker and stock purchase warrants	209,240			209		587,806								588,015
Stock compensation	74,918			76		1,053,706		-			-			1,053,782
Net income	-			-		-		463,331			3,122,017			3,585,348

Balance at December 31, 2016	18,970,445			18,970		121,933,378		(16,974,300	)		26,579,990			131,558,038

Distributions to non-controlling interest entities	-			-		-		-			(4,321,317	)		(4,321,317	)
Stock issued by the exercise of employee stock options	95,455			95		200,692		-			-			200,787
Stock issued by the exercise of stock purchase warrants	385,139			385		1,155,032		-			-			1,155,417
Stock compensation	(1,055	)		-		757,412		-			-			757,412
Net income (loss)	-			-		-		(2,267,981	)		1,816,542			(451,439	)
Balance at December 31, 2017	19,449,984		$	19,450	$	124,046,514	$	(19,242,281	)	$	24,075,215		$	128,898,898

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

U.S. GEOTHERMAL INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2017

NOTE 1 - ORGANIZATION AND DESCRIPTION OF BUSINESS

U.S. Geothermal Inc. (“the Company”) 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, owns, manages and operates power plants that utilize geothermal resources to produce renewable energy. The Company’s operations have been, primarily, focused in the United States and Central 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)	USG Mayacamas Inc. (incorporated in the State of Delaware);
	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);
	xx)	Earth Power Resources Inc. (incorporated in Delaware); and
	xxi)	Idaho USG Holdings LLC (organized in the State of 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 consolidated statements of income will consolidate the subsidiary’s full operations, and will separately disclose the elimination of the non-controlling interest’s allocation of profits and losses.

-F-5-

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

The Company’s consolidated financial statements have been prepared accordance with generally accepted accounting principles in the United States of America (“U.S. GAAP”). The consolidated financial statements include the accounts of U.S. Geothermal and its consolidated subsidiaries.

Share Consolidation (“Reverse Stock Split”)

On November 9, 2016, the Company effected a 1-for-6 share consolidation of its outstanding common stock. All share and per share amounts for all periods presented in these consolidated financial statements and notes have been adjusted retrospectively, where applicable, to reflect this share consolidation.

Use of Estimates

The preparation of consolidated financial statements in accordance with U.S. GAAP requires estimates and assumptions that affect the reported amounts of assets and liabilities, and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements as well as reported amounts of revenues and expenses during the reporting periods. Uncertainties with respect to such estimates and assumptions are inherent in the preparation of the Company’s consolidated financial statements; accordingly, actual results could differ from these estimates.

Cash and Cash Equivalents

The Company considers all unrestricted cash and short-term deposits, with original maturities of no more than ninety days when acquired to be cash and cash equivalents.

Trade Accounts Receivable Allowance for Doubtful Accounts

Management estimates the amount of trade accounts receivable that may not be collectible and records an allowance for doubtful accounts. 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, 2017 and 2016, there were no balances that were over 90 days past due and no balance in allowance for doubtful accounts was recognized.

Concentration of Credit Risk

The Company’s cash and cash equivalents, including restricted cash, consisted of commercial bank deposits, money market accounts, and petty cash. Cash deposits are held in commercial banks in Boise, Idaho and Portland, Oregon. Deposits are guaranteed by the Federal Deposit Insurance Corporation (“FDIC”) up to $250,000 per legal entity. At December 31, 2017, the Company’s total cash balance, excluding money market funds, was $7,080,910 and bank deposits amounted to $7,502,966. The primary difference was due to outstanding checks and deposits. Of the bank deposits, $6,087,518 was not covered by or was in excess of FDIC insurance guaranteed limits. At December 31, 2017, the Company’s money market funds invested, primarily, in government backed securities totaled $31,656,317 and were not subject to deposit insurance. A contracted power purchaser held a security bond for the Company that totaled $1,468,898 at December 31, 2017.

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 typically 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 and are included in construction in progress until the project has been placed into service. If a geothermal project is abandoned, the associated costs that have been capitalized are charged to expense in the year of abandonment. Expenditures for repairs and maintenance are charged to expense as incurred. Interest costs incurred during the construction period of defined major projects from debt that is specifically incurred for those projects are capitalized. Funds received from grants associated with capital projects reduce the cost of the asset directly associated with the individual grants. The offset of the cost of the asset associated with grant proceeds is recorded in the period when the requirements of the grant are substantially complete and the amount can be reasonably estimated.

-F-6-

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.

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:

		Estimated Useful
Asset Categories		Lives in Years

Furniture, vehicle and other equipment		3 to 5
Power plant, buildings and improvements		3 to 30
Wells		30
Well pumps and components		5 to 15
Pipelines		30
Transmission lines		30

Intangible Assets

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

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

-F-7-

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 the carrying value of its long-lived assets for impairment when factors and circumstances indicate that the carrying values may not be recoverable. Factors which could trigger an impairment include, among others, significant underperformance relative to historical or projected future operating results, significant changes in the Company’s use of assets or its overall business strategy, negative industry or economic trends, a determination that a project will not support commercial operations, a determination that a suspended project is not likely to be completed, a significant increase in costs necessary to complete a project, legal factors relating to its business or when it concludes that it is more likely than not that an asset will be disposed of or sold. The Company tests its long-lived assets for impairment at the operating plants or site location. Recoverability of assets held and used is determined by comparison of the carrying amount of an asset to future undiscounted net cash flows expected to be generated by the asset. If such assets are considered impaired, the impairment recognized is measured by the amount in which the carrying amount of the assets exceeds their fair value. The estimate of future cash flows required significant judgments of factors that include future sales, gross profit and operating expenses.

Stock Compensation

The Company accounts for stock based compensation by recording the estimated fair value of stock-based awards granted as compensation expense over the vesting period, net of estimated forfeitures. The fair value of restricted stock awards is determined based on the number of shares granted and the quoted price of the Company’s common stock on the date of grant. The fair value of stock option awards is estimated at the grant date as calculated by the Black-Scholes-Merton option pricing model. Stock-based compensation expense is attributed to earnings for stock options and restricted stock on the straight-line method. The Company estimates forfeitures of stock-based awards based on historical experience and expected future activity.

Income Taxes

The Company uses the asset and liability method of accounting for income taxes. Using this method, deferred tax assets and liabilities are recorded based on the differences between the financial reporting and tax basis of assets and liabilities. The deferred tax assets and liabilities are calculated using the enacted tax rates and laws that are expected to be in effect when the differences are expected to reverse. The Company routinely evaluates the likelihood of realizing the benefit of its deferred tax assets and may record a valuation allowance if, based on all available evidence, it is determined that it is more likely than not that all or some portion of the deferred tax benefit will not to be realized.

The Company regularly evaluates the likelihood of realizing the benefit for income tax positions in various federal, state and foreign filings by considering all relevant facts, circumstances and information available. If the Company believes it is more likely than not that its positions will be sustained, a benefit is recognized at the largest amount that is cumulatively greater than 50% likely to be realized. Interest and penalties related to income tax matters are classified as a component of income tax expense. Unrecognized tax benefits are recorded in other liabilities and long-term debt and other liabilities on the consolidated balance sheets.

-F-8-

Earnings (Loss) Per Share

Basic income or loss per share is computed using the weighted average number of common shares outstanding during the period, and excludes any dilutive effects of common stock equivalent shares, such as options and restricted stock awards. Restricted stock awards (“RSAs”) are considered outstanding and included in the computation of basic income or loss per share when underlying restrictions expire and the awards are no longer forfeitable. Diluted income per share is computed using the weighted average number of common shares outstanding and common stock equivalent shares outstanding during the period using the treasury stock method. Common stock equivalent shares are excluded from the computation if their effect is anti-dilutive.

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.

Foreign Currency Translation

The Company’s functional currency is the U.S. dollar. Monetary items are converted into U.S. dollars at the rate prevailing at the consolidated balance sheet date. Foreign currency transactions are translated into U.S. dollars at the exchange rate in effect at the transaction date. Exchange gains and losses arising from transactions denominated in a currency other than the functional currency are included in other (income) expense.

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 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 consolidated statement of operations.

Revenue Source

All of the Company’s operating revenues (energy sales and renewable energy credit sales) originate from energy production from its interests in three geothermal power plants located in the states of Idaho, Oregon and Nevada. The plants located in Oregon and Idaho sell their energy to the same electric power utility that primarily serves Idaho and eastern Oregon. For the years ended December 31, 2017 and 2016, the percentage of operating revenues from the major customer to total operating revenues was 79.2% and 76.7%; respectively. At December 31, 2017 and 2016, the percentage of trade accounts receivable balance from the major customer was 86.1% and 82.1%; respectively.

-F-9-

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.

Recent Accounting Pronouncements

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

Statement of Cash Flows
In August 2016, Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2016-15 (“Update 2016-15”), Statement of Cash Flows (Topic 230), Classification of Certain Cash Receipts and Cash Payments. In November 2016, FASB issued Accounting Standards Update No. 2016-18 (“Update 2016-18”), Statement of Cash Flows (Topic 230), Restricted Cash. Update 2016-15 provides guidance on how certain cash receipts and cash payments are presented and classified in the statement of cash flows. Update 2016-18 provides guidance on how to classify and present changes in restricted cash or restricted cash equivalents that occur when there are direct cash receipts into restricted cash or restricted cash equivalents or direct cash payments made from restricted cash or restricted cash equivalents. These Updates are effective for annual periods beginning after December 15, 2017, and interim periods within those fiscal years. The Company did not elect early adoption of this Update. It is likely that some of the provisions of Update 2016-15 will apply to certain transactions our Company may engage in. The Company holds restricted cash and restricted cash equivalents that are addressed in Update 2016-18. Management is currently evaluating the possible impact these Updates may have on the presentation of the Company’s consolidated statements of cash flows.

Revenue Recognition
In May 2014, FASB issued Accounting Standards Update No. 2014-09 (“Update 2014-09”), Revenue from Contracts with Customers (Topic 606). Update 2014-09 amends the revenue recognition guidance and requires more detailed disclosures to enable financial statement users to understand the nature, amount, timing and uncertainties of revenue and cash flows arising from contracts with customers. In April 2016, FASB issued Accounting Standards Update No. 2016-10 (“Update 2016-10”), Revenue from Contracts with Customers (Topic 606), Identify Performance Obligations and Licensing. In March 2016, FASB issued Accounting Standards Update No. 2016-08 (“Update 2016-08”), Revenue from Contracts with Customers (Topic 606), Principal versus Agent Considerations (Reporting Revenue Gross versus Net). In May 2016, FASB issued Accounting Standards Update No. 2016-12 (“Updated 2016-12”), Revenue from Contracts with Customers (Topic 606), Narrow-Scope Improvements and Practical Expedients. Both Update 2016-10 and 2016-08 provide additional guidance on how an entity should recognize revenue when depicting the transfer of promised goods or services. These Updates provide more guidance on identifying performance obligations and licensing. Update 2016-12 provides additional clarification to the steps an entity should follow to achieve the core principle of Topic 606. The guidance, as amended, is effective for annual and interim reporting periods beginning after December 15, 2017. The Company did not elect early adoption of these Updates. Management has reviewed the essential provisions of all of our major revenue contracts and our revenue recognition practices. As a result of this review, Management does not expect a material impact on the consolidated statement of income. The Company has elected to adopt these pronouncements using the modified retrospective method effective January 1, 2018.

-F-10-

Leases
In February 2016, the FASB issued Accounting Standards Update No. 2016-02 (“Update 2016-02”), Leases (Topic 842). Update 2016-02 recognizes lease assets and lease liabilities on the balance sheet and requires disclosing key information about leasing arrangements. Under previous standards, assets and liabilities were only recognized for leases that met the definition of a capital lease. Our preliminary review indicates that certain of the Company’s lease contracts would be subject to the reporting requirements defined by Update 2016-02. The Update is effective for public companies with fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early adoption is permitted. In transition, the Company will be required to recognize and measure leases at the beginning of the earliest period being presented using a modified retrospective approach. Management is still evaluating the possible impact this Update may have on the financial presentation of the Company’s consolidated financial statements.

Stock Compensation
In March 2016, FASB issued Accounting Standards Update No. 2016-09 (“Update 2016-09”), Compensation-Stock Compensation (Topic 718), Improvements to Employee Share-Based Payment Accounting. Update 2016-09 is effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Changes related to the timing of when excess tax benefits are recognized, minimum statutory withholding requirements, forfeitures, and intrinsic value should be applied using a modified retrospective transition method by means of cumulative-effect adjustment to equity as of the beginning of the period in which the guidance is adopted. Update 2016-09 was adopted during the first quarter of 2017 with minimal impact on the financial presentation of the Company’s consolidated financial statements.

-F-11-

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		2017		2016
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		81,711		284,621
Prudential Capital Group, Debt Service Reserves (USG Nevada LLC)		1,595,601		1,600,597
Bureau of Land Management , Geothermal Rights Lease Bond		10,000		10,000
U.S. Department of Energy, Debt Service Reserve		1,942,428		2,011,445
State of California Division of Oil, Gas and Geothermal Resources, Well Cash Bond		100,000		100,000
Prudential Capital Group, Debt Service Reserves (Idaho USG Holdings LLC)		952,553		1,755,776
Prudential Capital Group, Revenue Reserves (Idaho USG Holdings LLC)		80,000		-
CAISO, Transmission Interconnection Escrow Deposits		1,900,390		1,895,023

	$	7,532,683	$	8,527,462

-F-12-

Long-term restricted cash and bond reserves:

		December 31,
Restricting Entities/Purpose		2017		2016
Nevada Energy, PPA Security Bond	$	1,468,898	$	1,468,898
Prudential Capital Group, Maintenance Reserves (USG Nevada LLC)		1,100,246		1,081,744
Prudential Capital Group, Well Reserves (USG Nevada LLC)		1,593,832		951,486
Prudential Capital Group, Maintenance Reserves (Idaho USG Holdings LLC)		1,882,470		1,807,890
Prudential Capital Group, Capital Expenditure Reserves (Raft River Energy I LLC)		3,796		3,796
U.S. Department of Energy, Operations Reserves		270,000		270,000
U.S. Department of Energy, Debt Service Reserves		2,379,500		2,413,951
U.S. Department of Energy, Short Term Well Field Reserves		-		4,508,650
U.S. Department of Energy, Long-Term Well Field Reserves		5,389,693		5,175,777
U.S. Department of Energy, Capital Expenditure Reserves		1,940,287		2,429,158

	$	16,028,722	$	20,111,350

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. 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, 2017 and 2016.

NOTE 4 - PROPERTY, PLANT AND EQUIPMENT

During the year ended December 31, 2017, the Company focused on development activities at, San Emidio Phase II, WGP Geysers projects, and Raft River Energy I. At San Emidio Phase II and Crescent Valley projects, three wells were deepened and seismic studies were conducted that were capitalized at costs that totaled approximately $1,807,000. Grant proceeds totaling $776,226 offset the majority of the total costs of the seismic studies for the Nevada projects. Costs during the year that totaled approximately $1,294,000 were capitalized at WGP Geysers for plant engineering and design. During the current year, Raft River Energy I, LLC completed and connected a new production well (RRG-5) at a cost of approximately $1,071,000.

During the year ended December 31, 2016, the Company continued to develop the Raft River Energy I, San Emidio Phase II, Guatemala and the WGP Geysers projects. At Raft River, a new well production leg was completed in September 2016. The well construction and related costs totaled approximately $3,894,000. Drilling and testing costs of approximately $950,000 were capitalized for the San Emidio Phase II project. Drilling and reservoir analysis costs that exceeded $1,448,000 were capitalized in Guatemala. Costs were capitalized at WGP Geysers for permitting and an interconnection study that totaled approximately $1,174,000.

-F-13-

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

		December 31,
		2017			2016
Land	$	3,135,293		$	3,116,262
Power production plant		159,701,163			159,876,162
Grant proceeds for power plants		(52,965,236	)		(52,965,236	)
Wells		72,619,263			71,340,305
Grant proceeds for wells		(3,464,555	)		(3,464,555	)
Furniture and equipment		4,816,900			4,491,058
		183,842,828			182,393,996
Less: accumulated depreciation		(43,529,243	)		(37,216,385	)
		140,313,585			145,177,611
Construction in progress		28,376,748			25,123,738

	$	168,690,333		$	170,301,349

Depreciation expense charged to plant operations and administrative costs for the years ended December 31, 2017, 2016 and 2015, was $6,400,615, $6,284,405 and $6,228,133; respectively.

Changes in construction in progress are summarized as follows:

		For the Year Ended December 31,
		2017			2016
Beginning balances	$	25,123,738		$	21,022,981
Development/construction		5,436,213			8,116,725
Grant reimbursements		(776,226	)		-
Placed into operation		(1,406,977	)		(4,015,968	)
Ending balances	$	28,376,748		$	25,123,738

-F-14-

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

		December 31,
		2017		2016
Raft River, Idaho:
Unit I, well improvements	$	200	$	5,377
Unit I, plant improvements		30,895		108,555
Unit II, power plant, substation and transmission lines		751,678		751,618
Unit II, well construction		2,151,227		2,149,835
		2,934,000		3,015,385
San Emidio, Nevada:
Unit II, power plant, substation and transmission lines		410,665		426,941
Unit II, well construction		5,655,101		4,748,924
		6,065,766		5,175,865
Neal Hot Springs, Oregon:
Power plant and facilities		219,420		73,761
Well construction		854,760		378,098
		1,074,180		451,859

WGP Geysers, California:
Power plant and facilities		325,988		325,989
Well construction		10,177,442		8,865,093
		10,503,430		9,191,082
Crescent Valley, Nevada:
Well construction		1,780,033		1,655,653
El Ceibillo, Republic of Guatemala:
Well construction		6,010,839		5,625,394
Plant and facilities		8,500		8,500
		6,019,339		5,633,894

	$	28,376,748	$	25,123,738

-F-15-

NOTE 5 – INTANGIBLE ASSETS

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

		December 31,
		2017			2016
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		(1,662,489	)		(1,480,804	)
		3,788,068			3,969,753
Inactive:
Raft River, Idaho:
Surface water rights		146,342			146,342
Geothermal water and mineral rights		1,281,540			1,281,540

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		451,608			451,608

The Geysers, California:
Geothermal water rights		278,872			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	)
		11,114,390			11,114,390

	$	14,902,458		$	15,084,143

Amortization expense was charged to plant operations for the years ended December 31, 2017, 2016 and 2015 that amounted to $181,685, $181,685 and $181,685; respectively.

-F-16-

NOTE 6 – ACCOUNTS PAYABLE/ACCRUED LIABILITIES

The Company’s accounts payable and accrued liabilities are summarized as follows:

		December 31,
		2017		2016
Accounts payable and accrued liabilities	$	2,735,035	$	2,255,710
Employee severance liability		1,250,747		-

	$	3,985,782	$	2,255,710

On July 18, 2017, the CEO’s employment contract expired. The employment contract contained a severance provisions that entitled the employee to 18 months base pay, plus 18 months of insurance premium coverage. The liability is non-secured and non-interest bearing and is scheduled to be paid in the first quarter of 2018.

NOTE 7 – INCOME TAXES

The Company’s net deferred tax assets consisted of the following:

		December 31,
		2017			2016
Long-term deferred tax assets:
Net operating loss carry forward	$	25,346,000		$	35,893,000
Stock based compensation		766,000			1,052,000
Tax credit carryforward and other		174,000			156,000

Long-term deferred tax liabilities:
Depreciation and amortization		(19,803,000	)		(28,755,000	)
Total deferred tax assets		6,483,000			8,346,000
Less: valuation allowance		-			-
Net deferred income tax assets	$	6,483,000		$	8,346,000

Income before income taxes consists of the following:

		For the Year ended December 31,
		2017			2016			2015

United States	$	1,577,975		$	4,335,369		$	6,543,299
Foreign		(166,414	)		(175,021	)		(206,801	)
		1,411,561			4,160,348			6,336,498
Income attributable to non-controlling interests		(1,816,542	)		(3,122,017	)		(3,103,269	)
Income (loss) attributable to U.S. Geothermal Inc.	$	(404,981	)	$	1,038,331		$	3,233,229

-F-17-

The Company’s estimated effective income tax rates are as follows:

	For the Year Ended December 31,
	2017		2016		2015
U.S. Federal statutory rate	34.0%		34.0%		34.0%
Average State and foreign income tax, net of federal tax effect	0.8		1.2		3.5
Impact of tax reform	291.5		0.0		0.0
Impact of state deferred rate decrease	(141.9	)	(3.0	)	0.0
Stock based compensation	(16.0	)	7.8		0.0
Other	7.6		(0.6	)	(0.0	)
Consolidated tax rate before non-controlling interest	176.0		39.4		37.5
Tax effect of non-controlling interests	(43.8	)	(25.5	)	(18.4	)
Net effective tax rate	132.2%		13.9%		19.1%

The provision (benefit) for income taxes consists of the following:

		For the Year Ended December 31,
		2017		2016		2015
Current:
United States	$	3,000	$	-	$	-
Foreign		-		-		-
		3,000		-		-
Deferred:
United States		1,860,000		575,000		1,386,000
Foreign		-		-		-
Provision from income taxes	$	1,863,000	$	575,000	$	1,386,000

The Tax Cuts and Jobs Act was enacted on December 22, 2017. The Company’s evaluation of the accounting elements of the Tax Act is complete and its impact is reflected in our 2017 financial statements. The Act reduces the US federal corporate tax rate from 34% to 21% beginning in 2018. The impact of the Act for the Company is $4.1 million reduction in the Company's net deferred tax asset to reflect the new statutory rate.

The provision for income taxes reflects an estimated effective income tax rate attributable to U.S. Geothermal Inc.’s share of income. Our provision for income taxes for the year ended December 31, 2017, reflects a reported effective tax rate of 132.2% which differs from the statutory federal income tax rate of 34.0% primarily due to the impact of the tax reform, non-controlling interest, stock based compensation and state income taxes.

At December 31, 2017, the Company had federal net operating loss carry forwards of approximately $109 million and state net operating loss carry forwards of approximately $44 million, which expire in the years 2023 through 2037. Approximately $104 million of the operating losses were generated by the Company, the residual originated from acquired subsidiaries.

In 2014, the Company purchased a group of companies. Federal and applicable state net operating losses that totalled approximately $5.8 million were included in the acquisition. These NOLs are scheduled to expire in the years ending 2024 through 2034. The use of these net operating losses is restricted by the Company’s basis (acquisition price) 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 $5,189,000 at December 31, 2017.

-F-18-

Accounting for Income Tax Uncertainties and Related Matters
The Company files income tax returns in the U.S. federal jurisdiction and in the States of Idaho, California and Oregon. These filings are generally subject to a three year statute of limitations, but do remain open to Internal Revenue Service adjustments for net operating loss carry forward. No filings are currently under examination.

The Company currently does not have any uncertain tax positions to disclose. In the event that the Company is assessed interest or penalties on uncertain tax positions at some point in the future, it will be classified in the financial statements as tax expense.

NOTE 8 – LONG TERM NOTES PAYABLE

Prudential Capital Group – Idaho USG Holdings LLC
In May 2016, the Company’s wholly owned subsidiary (Idaho USG Holdings LLC) entered into a loan agreement with the Prudential Capital Group to finance the Company’s development activities. The original principal totaled $20 million and included the option to issue additional debt up to $50 million within the next two years. The original $20 million loan amount bears interest at a fixed interest rate of 5.8% per annum. The principal and interest payments are due semi-annually at amounts based upon a 20-year amortization period and the scheduled remaining balance of $16,009,495 is due in full at the end of the 7 year term. The loan is secured by the Company’s ownership interests in the Neal Hot Springs (Oregon USG Holdings LLC and USG Oregon LLC) and the Raft River (Raft River Energy I LLC) projects. At December 31, 2017, the balance of the loan was $19,296,475 (current portion $392,955) and the net unamortized debt issuance costs associated with this loan totaled $625,577 ($821,070, less amortized costs of $195,493).

U.S. Department of Energy – USG Oregon LLC
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”). 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 e 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. 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. The loan principal is scheduled to be paid over 21.5 years from the first scheduled payment date 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 started at $1,709,963 on February 10, 2014 and were reduced to $1,626,251 on February 10, 2017 and continue through February 12, 2035. The loan balance at December 31, 2017 totaled $54,524,670 (current portion $3,145,441).

-F-19-

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, 2017		(28,533,295	)

Loan balance at December 31, 2017	$	54,524,670

* - Individual tranches have been fully extinguished.

Prudential Capital Group – USG Nevada LLC
On September 26, 2013, the Company’s wholly owned subsidiary (USG Nevada LLC) entered into a note purchase agreement with the Prudential Capital Group 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. The loan agreement is 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, 2017, the balance of the loan was $28,402,581 (current portion $584,631).

Auto Loan
On July 28, 2016, the Company’s wholly owned subsidiary (U.S. Geothermal Services) purchased a truck with down payments that totaled $39,496 and a loan agreement with Chrysler Capital. The loan requires total monthly payments of $313, including interest at an average rate of 6.74% per annum until July 2018. The note is secured by the vehicle. At December 31, 2017, the loan balance totaled $2,447 (entire balance is current).

-F-20-

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:

For the Year Ended		Principal
December 31,		Payments
2018	$	4,125,474
2019		4,448,673
2020		4,732,869
2021		5,067,514
2022		5,167,615
Thereafter		78,684,029

	$	102,226,174

NOTE 9 – COMMON STOCK

Stock Purchase Agreement
On January 25, 2016, the Company entered into a Purchase Agreement with Lincoln Park Capital (“LPC”). Under the Purchase Agreement, the Company has the right to sell and LPC has the obligation to purchase up to $10 million of equity capital over a 30-month period. During the quarter ended March 31, 2016, the Company issued 2,463,810 (410,635 adjusted for share consolidation) shares of common stock at prices between $0.58 and $0.61 ($3.48 and $3.66 adjusted for share consolidation) per share under the Purchase Agreement.

Share Consolidation (Reverse Stock Split)
On November 9, 2016, the Company effected a 1-for-6 share consolidation of its outstanding common stock. All share and per share amounts for all periods presented in these consolidated financial statements and notes have been adjusted retrospectively, where applicable, to reflect this share consolidation.

To reflect the reverse stock split on shareholder’s equity, we reclassified an amount equal to the par value of the reduced shares from the common stock par value to additional paid in capital, which had no net impact to shareholders’ equity on our consolidated balance sheet. All per share information in our consolidated financial statements and applicable disclosures have been retroactively adjusted to reflect the reverse stock split. Proportional adjustments were, also, be made to all shares of common stock issuable under the Company’s stock incentive plans and common stock purchase warrants.

NOTE 10 - 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, 2017, the Company can issue stock option grants totaling up to 2,917,497 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.

-F-21-

The following table reflects the summary of stock options outstanding at January 1, 2016 and changes for the years ended December 31, 2017 and 2016:

				Weighted
				Average
	Number of			Exercise		Aggregate
	shares under			Price Per		Intrinsic
	options			Share		Value

Balance outstanding, January 1, 2016	2,102,250		$	3.42	$	3,940,061
Forfeited/Expired	(398,790	)		4.95		-
Exercised	(342,129	)		2.54		-
Granted	463,333			4.04		-
Balance outstanding, December 31, 2016	1,824,664			3.38		3,186,265
Forfeited/Expired	(21,582	)		4.25		-
Exercised	(95,455	)		2.10		-
Granted	375,136			4.10		-

Balance outstanding, December 31, 2017	2,082,763		$	3.56	$	3,519,092
Vested and expected to vest at December 31, 2017	2,082,763		$	3.56	$	3,519,092

The fair value of the stock options granted was estimated using the Black-Scholes-Merton 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,
	2017	2016	2015
Dividend yield	0	0	0
Expected volatility	50%	65%	65%
Risk free interest rate	1.16%	0.58%	0.58%
Expected life (years)	3.26	3.26	3.26

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

-F-22-

The following table summarizes information about the stock options outstanding at December 31, 2017:

OPTIONS OUTSTANDING
			REMAINING	NUMBER OF
	EXERCISE	NUMBER OF	CONTRACTUAL	OPTIONS
	PRICE	OPTIONS	LIFE (YEARS)	EXERCISABLE		INTRINSIC VALUE

$	1.86	38,332	0.17	38,332	$	35,779
	2.76	207,491	0.56	207,491		302,411
	2.10	208,333	5.30	208,333		337,977
	2.46	2,500	0.67	2,500		3,012
	4.44	413,823	1.25	413,823		1,003,242
	2.88	312,910	2.37	312,910		384,343
	3.18	75,000	2.48	75,000		114,522
	3.78	137,575	3.22	137,575		217,486
	4.02	149,998	3.25	149,998		269,612
	4.26	103,333	3.28	103,333		194,694
	4.50	25,000	3.66	18,750		30,576
	4.32	33,332	3.75	24,999		44,148
	4.42	16,666	4.08	8,888		14,309
	4.08	345,970	4.24	172,985		254,893
	4.18	12,500	4.33	6,250		8,989
	3.56	2,082,763	2.76	1,881,167	$	3,215,993

At December 31, 2017, total compensation cost related to stock options granted under the Stock Plan but not yet recognized was $209,211 net of estimated forfeitures.

Common Stock Compensation Plan (Restricted Shares)
Restricted shares are issued to the recipients when granted and held by the Company until vested. The recipients meet 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.

The following table summarizes restricted stock activity under the Stock Plan for 2017 and 2016:

	Shares			Issue Price

Unvested at January 1, 2016	71,399		$	3.02
Granted	60,833			4.07
Vested	(71,399	)		3.02

Unvested at December 31, 2016	60,833			4.07
Granted	-			-
Vested	(60,833	)		4.07

Unvested December 31, 2017	-		$	-

Expected to vest after December 31, 2017	-		$	-

Stock Purchase Warrants

At December 31, 2017, there were no remaining share purchase warrants (385,139 warrants at December 31, 2016).

-F-23-

During the year ended December 31, 2017, stock purchase warrants that totaled 385,139 were exercised by investors at the exercise price of $3.00.

During the year ended December 31, 2016, broker warrants that totaled 42,618 were exercised by a broker at the exercise price of $2.62. Stock purchase warrants that totaled 166,667 were exercised by an investor at the exercise price of $3.00.

NOTE 11 – FAIR VALUE MEASUREMENT

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.
Level 2 – Directly or indirectly market based inputs or observable inputs used in models or other valuation methodologies.
Level 3 – Unobservable inputs that are not corroborated by market data. The inputs require significant management judgement or estimation.

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 at fair value on a recurring basis:

At December 31, 2017:

		Total		Level 1		Level 2		Level 3
Assets:
Money market accounts *	$	31,656,317	$	31,656,317	$	-	$	-

At December 31, 2016:

		Total		Level 1		Level 2		Level 3
Assets:
Money market accounts *	$	37,347,897	$	37,347,897	$	-	$	-

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

-F-24-

NOTE 12 – 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, 2017, the Company had 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.

NOTE 13 - COMMITMENTS AND CONTINGENCIES

Operating Lease Agreements

The Company incurred total geothermal and mineral operating lease expenses for the years ended December 31, 2017, 2016 and 2015 of $711,567, $722,499 and $523,658; respectively. Included in the total lease expense are minimum lease payments of $349,268, $361,513 and $164,405 and royalty based contingent lease expense of $362,299, $360,986 and $359,253 for the years ended December 31, 2017, 2016 and 2015; respectively.

BLM Lease Agreements

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

-F-25-

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 2,986 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.

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.

Raft River Energy I LLC
The Company has entered into several lease contracts for approximately 5,144 acres of land and geothermal water rights located in the Raft River area located in Southern Idaho. Two contracts renew automatically upon receipt of annual payment, the residual have expiration terms from 5 to 30 years with expiration dates that range from January 2016 to December 2034. Six contracts have a royalty rate provision of 10% of net income calculated with specified depreciation methods.

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).

Crescent Valley, Nevada
On December 12, 2014, the Company acquired Earth Power Resources Inc. that held 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 2016 to June 2054.

Office Lease
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 years ended December 31, 2017 and 2016, the annual office lease costs totaled $115,830.

-F-26-

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

Years Ending
December 31,		Amount

2018	$	1,137,143
2019		1,031,409
2020		1,018,638
2021		954,570
2022		1,074550
Thereafter		13,631,298

Parental Guaranty Agreement
Under the terms of PPA, Raft River Energy I, LLC (“RREI”) is required to provide a Seller’s Performance Assurance. On April 29, 2011, U.S. Geothermal Inc. (“Guarantor”) signed a Parental Guaranty Agreement with RREI’s energy purchaser (“Beneficiary”) that extends credit to RREI (“Debtor”). The agreement provides for assurances related to possible obligations related to purchases, exchanges, sales or transportation of energy from contacts entered into by the Beneficiary and Debtor. The agreement insures the Beneficiary for damages up to a maximum of $750,000.

401(k) Plan
The Company offers a defined contribution plan qualified under section 401(k) of the Internal Revenue Code to all its eligible employees. All employees are eligible at the beginning of the quarter after completing 3 months of service. The Company matches 50% 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 $99,672, $101,992 and $100,872 for the years ended December 31, 2017, 2016 and 2015; respectively.

NOTE 14 – ASSET RETIREMENT OBLIGATIONS

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 $598,930. Obligations related to decommissioning four existing wells were estimated to total $606,000. These obligations are initially estimated based upon discounted cash flows estimates and are accreted to full value over time. At December 31, 2017, the Company has not considered it necessary to specifically fund these obligations. Since the Company is still evaluating the development plan for this project that could eliminate or significantly reduce the remaining obligations, no charges directly associated the asset retirement obligations have been charged to operations. All of the obligations were considered to be long-term at December 31, 2017, 2016 and 2015.

-F-27-

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 the assets’ estimated salvage values. Therefore, as of December 31, 2017, 2016 and 2015, no retirement obligations have been recognized.

		For the Year Ended December 31,
		2017		2016		2015

Beginning balance	$	1,219,903	$	1,204,930	$	1,400,000

Soil remediation		-		-		(209,070	)
Accretion		37,817		14,973		14,000

Ending balance	$	1,257,720	$	1,219,903	$	1,204,930

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,
		2017			2016		2015

Gerlach Geothermal LLC interest held by Gerlach Green Energy, LLC	$	200,539		$	207,217	$	213,882
Oregon USG Holdings LLC interest held by Enbridge Inc.		24,737,143			25,361,410		25,353,058
Raft River Energy I LLC interest held by Goldman Sachs		(862,467	)		1,011,363		2,044,984
	$	24,075,215		$	26,579,990	$	27,611,924

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 owned a 60% interest and GGE owned 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 years ended December 31, 2014 through 2017, the Company contributed $537,042 for the project’s drilling costs that were not proportionally matched by GGE. These contributions effectively reduced GGE’s ownership interest to 31.01%, and increased the Company’s interest to 68.99% as of December 31, 2016. During the year ended December 31, 2017, the Company contributed $22,000 to support the project’s operations that were not proportionally matched by GGE. These contributions effectively further reduced GGE’s ownership interest to 30.72%, and increased the Company’s interest to 69.28% .

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.

-F-28-

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 years ended December 31, 2017, 2016 and 2015, distributions were made to the Company that totaled $6,443,151, $6,107,217 and $5,193,883; respectively. During the years ended December 31, 2017, 2016 and 2015, distributions were made to Enbridge that totaled $4,295,434, $4,071,478 and $3,462,588; 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 Goldman Sachs. An Operating Agreement governs the rights and responsibilities of both parties. At December 31, 2017, the Company had contributed approximately $17.9 million in cash and property, and Goldman Sachs has contributed approximately $34.1 million in cash. Profits and losses are allocated to the members based upon contractual terms. The initial contracted terms stated that the Company would be allocated 70% of energy credit sales and 1% of the residual income/loss excluding energy credit sales. Under the terms of the amended agreement that became effective December 16, 2015, the Company will receive a 95% interest in RREI’s cash flows. Under the terms of both agreements, Goldman Sachs receives a greater proportion of the share of profit or losses for income tax purposes/benefits. This includes the allocation of profits and losses as well as production tax credits, which will be distributed 99% to Goldman Sachs and 1% to the Company during the first 10 years of production, which ends December 31, 2017. During the years ended December 31, 2017, 2016 and 2015, RREI distributed funds to the Company of $879,864, $1,203,349 and $165,457; respectively. During the years ended December 31, 2017, 2016 and 2015, RREI distributed funds to Goldman Sachs of $25,884, $82,473 and $24,000; respectively. During the years ended December 31, 2017 and 2016, the Company made contributions to RREI to support well construction of $1,105,494 and $3,349,087; respectively.

Under the terms of the December 16, 2015 agreement, the Company is entitled to incremental profits earned as a result of additional contributions made by the Company. During the year ended December 31, 2017, a new production well that was contributed to the project by the Company produced incremental net profits of $607,801. No incremental cash flows were earned for the years ended December 31, 2016 or 2015.

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

Additional Interest in Raft River Energy I LLC/Promissory Note
On December 16, 2015, the Company signed a purchase agreement with Goldman Sachs for the acquisition of the majority of the cash flow interest in Raft River Energy I LLC (“RREI”) for the total purchase price of $5.1 million. The purchase consisted of a $3.5 million cash payment plus a promissory note of $1.6 million that was paid in full on March 31, 2016. On December 13, 2017, the Company entered into an agreement to acquire the remaining interest of RREI from Goldman Sachs for a cash payment of $350,000. The acquisition was effective January 2, 2018.

-F-29-

NOTE 16 – BUSINESS SEGMENTS

The Company has two reportable segments: Operating Plants, and Corporate and Development. These segments are managed and reported separately due to dissimilar economic characteristics. Operating plants are engaged in the sale of electricity from the power plants pursuant to long-tern PPAs. Corporate and development costs are intended to produce additional revenue generating projects. A summary of financial information concerning the Company’s reportable segments is shown in the following table:

		Operating		Corporate &
		Plants		Development			Consolidated

Total Assets:
December 31, 2017	$	178,258,184	$	57,484,814		$	235,742,998
December 31, 2016		188,682,162		54,742,170			243,424,332

For the Year Ended December 31,
2017:
Operating Revenues	$	32,056,787	$	-		$	32,056,787
Net Income (Loss)		8,006,341		(8,457,780	)		451,439
2016:
Operating Revenues		31,481,675		-			31,481,675
Net Income (Loss)		10,625,887		(7,040,539	)		3,585,348
2015:
Operating Revenues		31,200,098		-			31,200,098
Net Income (Loss)		10,849,514		(5,899,016	)		4,950,498

NOTE 17 – SUBSEQUENT EVENTS

The Company has evaluated events and transactions that have occurred after the balance sheet date through March 8, 2018, which is considered to be the issuance date. The Company noted the following event for disclosure:

Acquisition of Residual Interest in Raft River Energy I LLC (“RREI”)
On December 13, 2017, the Company entered into an agreement to acquire the remaining interest of RREI from Goldman Sachs for a cash payment of $350,000. The acquisition was effective January 2, 2018.

Acquisition of the Company
On January 24, 2018, the Company’s Board of Directors entered into a definitive merger agreement under which a wholly owned subsidiary of Ormat Technologies, Inc. will acquire the Company for $5.45 per share in a cash transaction. The merger agreement will be voted on by the shareholders at a special meeting of the Company’s shareholders on a date to be determined. An affirmative vote of the majority of the outstanding shares of the Company’s common stock must be obtained for approval.

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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, 2017. 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, 2017.

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

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•

provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements.

The Company’s management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2017. 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, 2017, the Company’s internal control over financial reporting is effective based on those criteria.

Our independent registered public accounting firm, Moss Adams LLP, independently assessed the effectiveness of the company’s internal control over financial reporting, as stated in the firm’s attestation report, which is included within Part II, Item 8 of this Form 10-K.

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, 2017, that materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Shareholders U.S. Geothermal Inc.

Opinion on Internal Control over Financial Reporting

We have audited U.S. Geothermal Inc.’s (the “Company”) internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, the Company maintained, in all material respects, effective control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by COSO.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated balance sheets of U.S. Geothermal Inc. as of December 31, 2017 and 2016, the related consolidated statements of operations, cash flows, and changes in stockholders’ equity for each of the three years in the period ended December 31, 2017, and the related notes (collectively referred to as the “consolidated financial statements”) and our report dated March 8, 2018 expressed an unqualified opinion on those consolidated financial statements.

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Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting included in Item 9A. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

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

/s/ Moss Adams LLP

Seattle, Washington
March 8, 2018

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Item 9B.

Other Information

None.

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PART III

Item 10.

Directors, Executive Officers and Corporate Governance

The Board of Directors (the “Board”) of the Company is currently composed of seven directors: Douglas J. Glaspey, Ali G. Hedayat, Randolph J. Hill, Paul A. Larkin, Leland L. Mink, James C. Pappas and John H. Walker. The majority of the Board, made up of Mr. Hedayat, Mr. Hill, Mr. Larkin, Dr. Mink, Mr. Pappas and Mr. Walker, satisfy the applicable independence requirements of the NYSE American, and National Instrument 58-101, Disclosure of Corporate Governance Practices and Multilateral Instrument 52-110, Audit Committees. Mr. Glaspey does not satisfy such independence requirements based on his employment as an executive officer 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.

Douglas J. Glaspey: Age 65, is the co-founder, President and Interim Chief Executive Officer and a director of the Company. He has served as the Interim Chief Executive Officer since July 2017, 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 38 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 38 years of experience in the natural resource industry and his many years of senior management and director experience.

Ali G. Hedayat: Age 43, serves as a director of the Company effective February 1, 2017. Mr. Hedayat is the founder and Managing Director of Maryana Capital in Toronto, Canada. He previously co-founded Edoma Capital in London (2010-2012), was a Partner at Indus Capital in London (2013-2015), and worked for the Goldman Sachs Group (1997-2010) in New York and London as a Managing Director and Co-head of Americas Principal Strategies. Mr. Hedayat currently serves as a Director for Restaurant Brands International Inc. since July 2016, and has previously served as a Director for companies in the cable, pharmaceutical and media industries. Mr. Hedayat holds a Bachelor of Commerce degree, with honors, earning a double major in Finance and Economics from McGill University. His qualifications to serve as a Director of the Company include over 20 years of investment banking experience with an emphasis in power, utilities, and distressed debt and equity in European, North American and Latin American markets.

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Randolph J. Hill: Age 62, serves as a director of the Company effective September 30, 2016. Mr. Hill is a corporate lawyer with Stoel Rives (2016 to present) with significant experience in corporate governance, mergers and acquisitions, energy and infrastructure development, project financing, and EPC, design-build and management and operations contracting, and also serves as Chair of the Idaho Energy Resources Authority and a member of the Board of Governors of the Andrus Center for Public Policy at Boise State University. He has previously worked as Chief Legal Officer for a major division of AECOM (2004-2016; previously Washington Group International and then URS through successive mergers), as General Counsel and then President and CEO for Ida-West Energy (1993-2004), and as a corporate lawyer at a premier Wall Street law firm. He has previously served as a director for the Boise Metro Chamber of Commerce (one year as Chair), the Idaho Association of Commerce and Industry, and the Women’s and Children’s Alliance (four years as President). Mr. Hill holds a law degree from Georgetown University Law Center and a bachelor’s degree from George Washington University. Mr. Hill’s qualifications to serve as a director of the Company include his many years of senior management, legal and energy industry experience.

Paul Larkin: Age 67, 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., Westbridge Energy Corp., and Velocity Minerals Ltd. 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 78, serves as a director of the Company, a position he has held since November 2006. Dr. Mink holds a PhD in Geology from the University of Idaho and is currently self-employed as President of Mink GeoHydro Inc conducting consulting activities in hydrogeology and geothermal resource evaluations. He served as Program Director for the Geothermal Technologies Program at the U.S. Department of Energy (DOE) from February 2003 to October 2006. Prior to working for the DOE, Dr. Mink was the Vice President of Exploration for the Company from June 2002 to February 2003. He has also worked for Morrison-Knudsen Corporation, Idaho Bureau of Mines and Geology and Idaho Water Resources Research Institute. Dr. Mink serves on the Geothermal Resources Board of Directors and is a member of the Geothermal Energy Association. His qualifications to serve as a director of the Company include his many years of senior leadership and management experience in the geothermal energy industry.

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James C. Pappas: Age 36, serves as a director of the Company effective September 30, 2016. Mr. Pappas founded JCP Investment Management in Houston in June 2009 and is the Managing Member and owner of the Firm. Since January 2015, Mr. Pappas has served as a director of Jamba, Inc., a leading health and wellness brand and the leading retailer of freshly squeezed juice, where he is also a member of each of the Nominating and Corporate Governance Committee and the Audit Committee. Mr. Pappas also currently serves as a director of Tandy Leather Factory, Inc., a specialty retailer and wholesale distributor of leather and leather related products. Previously, Mr. Pappas served on the Board of Directors of The Pantry, Inc., has also served as Chairman of the Board of Directors of Morgan’s Foods, and has also served as a director of Samex Mining Corp. From 2005 until 2007, Mr. Pappas worked for The Goldman Sachs Group, Inc. in their Investment Banking / Leveraged Finance Division. As part of the Goldman Sachs Leveraged Finance Group, Mr. Pappas advised private equity groups and corporations on appropriate leveraged buyout, recapitalization and refinancing alternatives. Prior to Goldman Sachs, Mr. Pappas worked at Banc of America Securities, the investment banking arm of Bank of America, where he focused on Consumer and Retail Investment Banking, providing advice on a wide range of transactions including mergers and acquisitions, financings, restructurings and buy-side engagements. Mr. Pappas received a BBA in Information Technology, and a Masters in Finance from Texas A&M University. His qualifications to serve as a director of the Company includes his years of investment banking and director experience.

John H. Walker: Age 69, is a director and the Chairman of the Board of Directors of the Company. He has held that position since December 2003. He was a Managing Director of Kensington Capital Partners Ltd until his retirement in May 2017 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 a 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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Additional Executive Officers Who are Not Directors

Kerry D. Hawkley: Age 64, 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 40 years of experience in all areas of accounting, finance and administration. He holds Bachelor of Business Administration degrees in Accounting and Finance. He started his career as an internal auditor with Union Pacific Corporation and has held various accounting management positions in the oil and gas, truck leasing, mining and energy industries.

Jonathan Zurkoff: Age 61, 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).

Certain Relationships and Related Transactions

There are no family relationships among the members of the Board or the members of seniormanagement of the Company. There are no arrangements or understandings with major shareholders, customers, suppliers or others, pursuant to which any member of the Board or member of senior management was selected or any proposed director to be elected.

None of the nominees for election as a director of the Company is, or was within the ten years prior to the date hereof, a director or executive officer of any company that, while that person was acting in such capacity, or within a year of that person ceasing to act in such capacity, became bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency or was subject to or instituted any proceedings, arrangements or compromise with creditors or had a receiver, receiver manager or trustee appointed to hold its assets.

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, 2017 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, 2017. 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 American 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 Randolph J. Hill, Ali G. Hedayat, 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 American 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 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, 2017, stock option grants to executive officers represented approximately 39% of the total stock option grants to all employees. During the fiscal year ended December 31, 2016, stock option grants to executive officers represented approximately 45% of the total stock option grants to all employees. During the year ended December 31, 2015, stock option grants to executive officers represented approximately 47% 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. In 2017, the percentage of votes cast “For” our advisory “say on pay” resolution to approve our executive compensation was 92.2% . The Board and the Compensation and Benefits Committee considered the results of the advisory vote and no significant changes have been made to the executive compensation programs based on the 2017 “say on pay” results.

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.

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. On July 19, 2017, the company entered into an Amendment to the employment agreement in order for Mr. Glaspey to also serve as Interim Chief Executive Officer.

The Company has agreed to pay to Mr. Glaspey compensation of $284,180 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.

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The employment agreement may be terminated by the Company without notice, payment in lieu of notice, severance payments, benefits, damages or other sums for causes which include failure to perform his duties in a competent and professional manner, appropriation of corporate opportunities or failure to disclose a material conflict of interest, a plea of guilty to, or conviction of, an indictable offense which may not be further appealed, fraud, dishonesty, illegality or gross incompetence, failure to disclose material facts concerning business interests or other employment that are relevant to his employment with the Company, refusal to follow reasonable and lawful directions of the Company, breach of fiduciary duty, and material breach under, or gross negligence in connection with his employment under, the employment agreement. Otherwise, the Company may terminate the employment agreement upon one month’s written notice and Mr. Glaspey may terminate the employment agreement upon 60 days’ written notice.

In the event that Mr. Glaspey’s employment is terminated without “cause” by the Company or for “good reason” by Mr. Glaspey, and in the event that a “change of control” has occurred within the 12 months prior to the termination, Mr. Glaspey is entitled to receive compensation equal to 24 monthly installments of his normal compensation on the 30^th day after the date of termination (which sum would be currently $568,360). The terms “cause”, “good reason” and “change of control” are defined in the employment agreement.

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

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. Effective January 9, 2017, the Company and Dennis Gilles, the Company’s Chief Executive Officer, entered into an amendment (the “Amendment”) to Mr. Gilles’ employment agreement (the “Agreement”) to extend the current term of the Agreement by three months. The initial term of the Agreement was 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 Agreement automatically renewed 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 current term of the Agreement ends on April 18, 2017 (the “Current Term”).

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The Amendment extends the Current Term by three (3) months, such that the Current Term of the Agreement now ends on July 18, 2017. As a result of the extension of the Current Term, any notice of non-renewal delivered pursuant to the Agreement must now be delivered no later than April 19, 2017, which is ninety (90) days prior to the expiration of the Current Term. If a notice of non-renewal is not delivered in accordance with the Agreement, the Agreement shall automatically renew at the end of the Current Term on July 18, 2017, for an additional one (1) year term. Further to the above, on April 19, 2017, the Company determined not to extend the Agreement and delivered a notice of non-renewal to Mr. Gilles. 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. 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. 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 is 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 $35,000.

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.

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 $182,962 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. 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.

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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 $274,443). The terms “cause”, “good reason” and “change of control” are defined in the employment agreement.

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

Zurkoff Employment Agreement

The Company has entered into an amendment to the employment agreement with Jonathan Zurkoff as the Company’s Executive Vice President, Finance. The employment agreement, as amended six times, is effective December 31, 2010, and will remain in effect until July 31, 2018 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 $195,840 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 $293,760). 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 three years awarded to or earned by all individuals who served as the Company’s Chief Executive Officer and Chief Financial Officer during the last completed fiscal year and the Company’s next most highly compensated executive officer at the end of the last completed fiscal year (collectively, our “Named Executive Officers”).

Name and principal position(s)	Year Ended	Salary ⁽¹⁾ ($)	Bonus ⁽²⁾ ($)	Option Awards ⁽³⁾ ($)	Stock Awards ⁽⁴⁾ ($)	All other compensation ⁽⁵⁾ ($)	Total ($)



Dennis J. Gilles, Chief Executive Officer ⁽⁶⁾	12/31/15	410,000	102,500	114,524	156,000	2,750	785,774
	12/31/16	398,961	75,000	194,679	162,500	2,110	833,250
	12/31/17	232,723	0	99,606	0	0	332,329

Douglas J. Glaspey, President and Interim Chief Executive Officer ⁽⁶⁾	12/31/15	220,000	0	85,113	14,000	1,035	320,148
	12/31/16	202,441	9,000	77,888	0	1,035	290,364
	12/31/17	255,093	16,612	66,689	0	1,035	339,429

Kerry D. Hawkley, Chief Financial Officer	12/31/15	179,375	8,969	40,317	11,351	0	240,012
	12/31/16	182,065	10,000	53,923	19,200	0	265,188
	12/31/17	198,595	13,000	43,543	0	0	255,138

Jonathan Zurkoff, Treasurer and Executive Vice President	12/31/15	192,000	9,600	32,754	12,973	0	247,327
	12/31/16	194,880	8,000	47,821	16,800	0	267,501
	12/31/17	209,251	13,000	32,703	0	0	254,954

⁽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 are valued at the grant date in accordance with FASB ASC Topic 718.
⁽⁴⁾	Stock awards (restricted shares) are valued at grant date.
⁽⁵⁾	Other compensation consists of all other compensation not disclosed in another category.
⁽⁶⁾	Mr. Gilles’ employment with the Company ended July 17, 2017, while Mr. Glaspey assumed the position of

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Interim Chief Executive Officer on the same date.

Grants of Plan-Based Awards Table

Name	Grant Date	All Other Option Awards: Number of Securities Under-lying Options (j)	Exercise or Base Price of Option Awards ($/Sh) (k)	Grant Date Fair Value of Stock and Option Awards¹⁸
(a)	(b)		Exercise or Base Price of Option Awards ($/Sh) (k)	(l)
Dennis J. Gilles, Former Chief Executive Officer	3/28/17	55,805	4.08	99,612
Douglas J. Glaspey, Interim Chief Executive Officer	3/28/17	37,363	4.08	66,693
Kerry D. Hawkley, Chief Financial Officer	3/28/17	24,395	4.08	43,545
Jonathan Zurkoff, Treasuer and Executive Vice President	3/28/17	22,195	4.08	32,693

Option Exercises and Stock Vested Table

	Option Awards		Stock Awards
Name (a)	Number of shares acquired on exercise (b)	Value realized on exercise ($) (c)	Number of shares acquired on vesting (d)	Value realized on vesting ($) (e)
Dennis J. Gilles, Former Chief Executive Officer	16,666	37,832	30,833	131,350
Douglas J Glaspey, Interim Chief Executive Officer	15,000	32,700	4,166	16,760
Kerry D. Hawkley, Chief Financial Officer			3,888	15,633
Jonathan Zurkoff, Treasuer and Executive Vice President			3,333	13,400

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Outstanding Equity Awards at Fiscal Year-End

The following table shows the unexercised stock options, unvested restricted stock, and other equity incentive plan awards held at the year ended December 31, 2017 by our Named Executive Officers.

		Option Awards			Stock Awards
	Number of	Number of
	Securities	Securities			Number of	Market Value of
	Underlying	Underlying			Shares or Units	Shares or Units of
	Unexercised	Unexercised	Option	Option	of Stock That	Stock That Have
	Options	Options ⁽¹⁾	Exercise Price	Expiration	Have Not Vested	Not Vested
Name	(#) Exercisable	(#) Unexercisable	($)	Date	(#)	($)
Dennis J. Gilles	208,333	0	2.10	4/19/23	0	0
Douglas J. Glaspey	25,000	0	2.76	7/22/18	0	0
Kerry D. Hawkley	20,833	0	2.76	7/22/18	0	0
Jonathan Zurkoff	20,833	0	2.76	7/22/18	0	0
Dennis J. Gilles	66,666	0	4.44	4/2/19	0	0
Douglas J. Glaspey	36,666	0	4.44	4/2/19	0	0
Kerry D. Hawkley	29,166	0	4.44	4/2/19	0	0
Jonathan Zurkoff	29,166	0	4.44	4/2/19	0	0
Douglas J. Glaspey	63,333	0	2.88	5/15/20	0	0
Kerry D. Hawkley	30,000	0	2.88	5/15/20	0	0
Jonathan Zurkoff	26,666	0	2.88	5/15/20	0	0
Dennis J. Gilles	75,000	0	3.18	6/26/20	0	0
Douglas J. Glaspey	43,333	0	4.02	3/31/21	0	0
Kerry D. Hawkley	30,000	0	4.02	3/31/21	0	0
Jonathan Zurkoff	30,000	0	4.02	3/31/21	0	0
Dennis J. Gilles	103,333	0	4.26	4/11/21	0	0
Dennis J. Gilles	55,805	0	4.08	3/28/22	0	0
Douglas J. Glaspey	18,681	18,682	4.08	3/28/22	0	0
Kerry D. Hawkley	12,197	12,198	4.08	3/28/22	0	0
Jonathan Zurkoff	11,097	11,098	4.08	3/28/22	0	0

⁽¹⁾ The $4.08 options unexercisable at December 31, 2017 will fully vest on September 28, 2018.

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.

Name	Change of Control Salary ($)	Change of Control Benefits ($)	Change of Control Total ($)
Dennis J. Gilles	1,230,000	9,988	1,239,988
Douglas J. Glaspey	568,360	22,519	590,879
Kerry D. Hawkley	274,443	28,712	303,155
Jonathan Zurkoff	293,760	26,193	319,953

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Director Compensation

The following table summarizes the compensation paid to our directors during the year ended December 31, 2017.

Name	Fees earned or paid in cash ($)	Stock awards ($)	Option awards ⁽¹⁾ ($)	Non- equity incentive plan compens- ation ($)	Nonqualified deferred compensa- tion earnings ($)	All other compensa- tion ($)	Total ($)
John H. Walker	43,700	0	24,790	0	0	0	68,490

Paul A. Larkin	75,363	0	24,790	0	0	0	100,153

Leland L. Mink	39,500	0	24,790	0	0	0	64,290

Randolph J. Hill	59,325	0	14,279	0	0	0	73,604

James C. Pappas	50,025	0	14,279	0	0	0	64,304

Ali Hedayat	48,550	0	26,681	0	0	0	75,231

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

Directors who are not otherwise remunerated per an employment agreement are paid $7,500 per quarter, $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.

CEO Pay Ratio

The following pay ratio and supporting information compares the annual total compensation of our employees other than our CEO (including full-time, part-time, seasonal and temporary employees) and the annual total compensation of our CEO, as required by Section 953(b) of the Dodd-Frank Act. The pay ratio is a reasonable estimate calculated in a manner consistent with Item 402(u) of Regulation S-K.

For 2017, our last completed fiscal year:

	•	The median of the annual total compensation of all employees of our company (other than our CEO) was $85,632; and
	•	The annual total compensation of our CEO, as reported in the Summary Compensation Table included in this Proxy Statement, was $459,905.

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Based on this information, the ratio of the annual total compensation of our CEO to the median of the annual total compensation of all other employees was 5.4 to 1.

To determine the pay ratio, we took the following steps:

We determined that as of December 31, 2017, the determination date, our employee population consisted of approximately 58 individuals, primarily located in the United States and Guatemala. This population consists of our full-time, part-time, temporary and seasonal employees.

To identify the median employee, we compared the W-2 wages (or equivalent information for our employees in Guatemala) and options value over a period of 12 months ending December 31, 2017. We selected the determination date and measurement period because they are recent periods for which employee census and compensation information are readily available. We selected W-2 wages because the information can be gathered for each employee from existing payroll systems in a timely and reliable manner, and because the measure is a reasonable reflection of total compensation for purposes of identifying the median employee. To the W-2 wages, we added the value of stock options granted during 2017 to our employee base. Once we identified our median employee, we calculated such employee’s annual total compensation for 2017 in accordance with the requirements of Item 402(c)(2)(x) of Regulation S-K, resulting in annual total compensation of $85,632.

With respect to the CEO, we used the amounts reported as total compensation in the Summary Compensation Table included in this Proxy Statement for Dennis Gilles for the period January 1 to July 18, 2017, adding the amounts reported for Douglas Glaspey for the period July 19 to December 31, 2017. Any adjustments, estimates and assumptions used to calculate total annual compensation are described in footnotes to the Summary Compensation Table.

The pay ratio includes compensation that is not necessarily comparable to that of the CEO, including non-annualized compensation for part-time, seasonal and temporary employees.

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Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Securities Authorized for Issuance under Equity Compensation Plans

The following table sets forth the number of securities authorized for issuance under the Company’s equity compensation plans as of December 31, 2017.

Equity Compensation Plan Information
Plan category	Number of securities to be issued upon exercise of outstanding options, warrants and rights (a)	Weighted-average exercise price of outstanding options, warrants and rights (b)	Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (c)
Equity compensation plans approved by security holders	2,082,763	$3.56	834,734
Equity compensation plans not approved by security holders	Nil	Nil	Nil
Total	2,082,763	$3.56	834,734

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 1, 2018 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 19,494,566 shares of the Company’s common stock outstanding as of March 1, 2018.

Name and Address of Beneficial Owner	Amount and Nature of Beneficial Ownership	Percent of Class
JCP Investment Management, LLC 1177 West Loop South, Suite 1650 Houston, TX 77027	2,871,448⁽¹⁾	14.73%
Bradley Louis Radoff 1177 West Loop South, Suite 1625 Houston, TX 77027	1,923,000⁽²⁾	9.86%
Private Management Group, Inc. 15635 Alton Parkway, Suite 400 Irvine, CA 92618	1,818,042⁽³⁾	9.33%

⁽¹⁾

As of December 31, 2017, based on information set forth in a Schedule 13D filed with the SEC on January 24, 2018 by JCP Investment Management, LLC. Each of the persons listed may be deemed to be a member of a Section 13(d) group that collectively beneficially owns more than 10% of the Issuer’s outstanding shares of Common Stock, and each such person disclaims beneficial ownership of the shares of Common Stock reported herein except to the extent of his or its pecuniary interest therein. Includes 938,360 shares of Common Stock owned directly by JCP Investment Partnership, LP (“JCP Partnership”). Also includes 1,916,588 shares of Common Stock owned directly by JCP Drawdown Partnership III, LP (“JCP Drawdown III”). JCP Partners, as the general partner of each of JCP Partnership and JCP Drawdown III, may be deemed the beneficial owner of the (i) 938,360 shares owned by JCP Partnership and (ii) 1,916,588 shares owned by JCP Drawdown III. JCP Investment Holdings, LLC (“JCP Holdings”), as the general partner of each of JCP Partners, may be deemed the beneficial owner of the (i) 938,360 shares owned by JCP Partnership and (ii) 1,916,588 shares owned by JCP Drawdown III. JCP Investment Holdings, LLC (“JCP Holdings”), as the general partner of JCP Partners, may be deemed the beneficial owner of the (i) 938,360 shares owned by JCP Partnership and (ii) 1,916,588 shares owned by JCP Drawdown III. JCP Investment Management, LLC (“JCP Management”), as the investment manager of each of JCP Partnership and JCP Drawdown III, may be deemed the beneficial owner of the (i) 938,360 shares owned by JCP Partnership and (ii) 1,916,588 shares owned by JCP Drawdown III. James C. Pappas, as the managing member of JCP Management and sole member of JCP Holdings, may be deemed the beneficial owner of the (i) 938,360 shares owned by JCP Partnership and (ii) 1,916,588 shares owned by JCP Drawdown III and (iii) 16,500 shares beneficially owned directly by Mr. Pappas consisting of shares underlying certain options awarded to Mr. Pappas in his capacity as a director of the Issuer.

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⁽²⁾	As of December 31, 2016, based on information set forth in a Schedule 13G/A filed with the SEC on February 14, 2018 by Bradley Louis Radoff, who has sole voting and dispositive power over 91,125 shares of the Company’s common stock and shared dispositive power over 1,831,875 shares under FMLP, Inc.

⁽³⁾	As of December 31, 2017, based on information set forth in a Schedule 13G filed with the SEC on February 8, 2018 by Private Management Group, Inc., which has sole voting and dispositive power over 1,818,042 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 March 1, 2018, by each of our directors, Named Executive Officers, and directors and executive officers as a group. The percentage of beneficial ownership is based on 19,494,566 shares of the Company’s common stock outstanding as of March 1, 2018.

	Amount and
	Nature
Name of Beneficial Owner	of Beneficial	Percent of
	Ownership	Class
Dennis J. Gilles	722,846⁽¹⁾	3.71%
Douglas J. Glaspey	318,627⁽²⁾	1.64%
Kerry D. Hawkley	157,525⁽³⁾	*
Ali Hedayat	138,333⁽⁴⁾
Randolph J. Hill	20,666⁽⁵⁾	*
Paul A. Larkin	141,078⁽⁶⁾	*
Leland L. Mink	91,671⁽⁷⁾	*
James C. Pappas	2,875,614⁽⁸⁾	14.78%
John H. Walker	90,883⁽⁹⁾	*
Jonathan Zurkoff	147,266⁽¹⁰⁾	*

All directors and executive officers as a group (9 persons)	3,981,663⁽¹¹⁾	20.47%

* Less than 1% of the Company’s outstanding common stock

	⁽¹⁾	Includes 481,235 options exercisable within 60 days of March 1, 2018.
	⁽²⁾	Includes 187,013 options exercisable within 60 days of March 1, 2018
	⁽³⁾	Includes 122,196 options exercisable within 60 days of March 1, 2018.
	⁽⁴⁾	Includes 8,333 options exercisable within 60 days of March 1, 2018.
	⁽⁵⁾	Includes 20,666 options exercisable within 60 days of March 1, 2018.

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	⁽⁶⁾	Includes 73,608 options exercisable within 60 days of March 1, 2018.
	⁽⁷⁾	Includes 66,942 options exercisable within 60 days of March 1, 2018.
	⁽⁸⁾	Includes 20,666 options exercisable within 60 days of March 1, 2018.
	⁽⁹⁾	Includes 73,608 options exercisable within 60 days of March 1, 2018.
	⁽¹⁰⁾	Includes 117,762 options exercisable within 60 days of March 1, 2018.
	⁽¹¹⁾	Includes 690,794 options exercisable within 60 days of March 1, 2018.

Item 13.

Certain Relationships and Related Transactions, and Director Independence

Related Person Transactions

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 $120,000, 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 seven directors: Douglas J. Glaspey, Ali G. Hedayat, Randolph J. Hill, Paul A. Larkin, Leland L. Mink, James C. Pappas and John H. Walker. A majority of the Board, made up of Mr. Hedayat, Mr. Hill, Mr. Larkin, Dr. Mink, Mr. Pappas and Mr. Walker, satisfy the applicable independence requirements of the NYSE American. Mr. Glaspey does not satisfy such independence requirements based on his employment as executive officer 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 American.

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 American 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 American listing standards), or any entity with which the director or any of his or her immediate family members is affiliated by reason of being a partner, officer or a significant shareholder thereof.

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

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Item 14.

Principal Accountant Fees and Services

Audit Fees

The aggregate fees billed to the Company by Moss Adams LLP for the year ended December 31, 2017 and 2016 for annual financial statements and reviews of financial statements included in the Company’s Quarterly Report on Forms 10-Q totaled $321,154 and $298,228; respectively.

Audit-Related Fees

The fees billed to the Company by Moss Adams LLP for the financial statement audits of the Company’s five subsidiaries (three in 2015) Idaho USG Holdings LLC and Oregon USG Holdings LLC, USG Oregon LLC, USG Nevada LLC and Raft River Energy I LLC and the due diligence process related to the merger agreement for the years ended December 31, 2017 and 2016 were $102,935 and $76,000; respectively.

Tax Fees

The fees billed to the Company by Moss Adams LLP for tax preparation and planning services during years ended December 31, 2017 and 2016 amounted to $68,135 and $92,611; respectively.

All Other Fees

The Company was billed by Moss Adams LLP for any other services during year ended December 31, 2016 amounted to $9,885.

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, 2017 and 2016, including services related to the Audit-Related Fees and Tax Fees described above, were approved by the Audit Committee under its pre-approval policies.

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PART IV

Item 15.

Exhibits and Financial Statement Schedules

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

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

EXHIBIT INDEX

Exhibit Number	Description
2.1	Agreement and Plan of Merger, dated January 24, 2018, by and among Ormat Nevada Inc., OGP Holding Corp. and U.S. Geothermal (Incorporated by reference to exhibit 2.1 to the registrant's Form 8-K filed on January 25, 2018)† (https://www.sec.gov/Archives/edgar/data/1172136/000106299318000321/exhibit 2-1.htm)
3.1	Amended Certificate of Incorporation of U.S. Geothermal Inc. (Incorporated by reference to exhibit 3.1 to the registrant’s Form S-3 filed on March 20, 2015) (https://www.sec.gov/Archives/edgar/data/1172136/000106299315001431/exhibit 3-1.htm)
3.2	Third Amended and Restated Bylaws of U.S. Geothermal Inc. (Incorporated by reference to exhibit 99.2 to the registrant’s Form 8-K as filed on March 10, 2016) (https://www.sec.gov/Archives/edgar/data/1172136/000106299316008264/exhibit 99-2.htm)
3.3	Certificate of Amendment to Certificate of Incorporation of U.S. Geothermal Inc. (incorporated by reference to exhibit 3.1 to the registrant’s Form 8-K filed on November 9, 2016) (https://www.sec.gov/Archives/edgar/data/1172136/000091228216000898/ex3_1. htm)
4.1	Form of Stock Certificate (Incorporated by reference to exhibit 4.1 to the registrant’s Form SB-2 registration statement as filed on July 8, 2004) (https://www.sec.gov/Archives/edgar/data/1172136/000106299304001072/exhibit 4-1.htm)
10.1	Employment Agreement dated July 1, 2013 with Douglas J. Glaspey (Incorporated by reference to exhibit 10.1 to the registrant’s Form 8-K as filed on July 26, 2013) (https://www.sec.gov/Archives/edgar/data/1172136/000106299313003607/exhibit 10-1.htm)
10.2	Employment Agreement dated July 1, 2013 with Kerry D. Hawkley (Incorporated by reference to exhibit 10.2 to the registrant’s Form 8-K as filed on July 26, 2013) (https://www.sec.gov/Archives/edgar/data/1172136/000106299313003607/exhibit 10-2.htm)

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10.3	Power Purchase Agreement dated December 29, 2004 between U.S. Geothermal Inc. and Idaho Power Company (Incorporated by reference to exhibit 10.19 to the registrant’s Amendment No. 2 to Form SB-2 registration statement as filed on January 10, 2005) (https://www.sec.gov/Archives/edgar/data/1172136/000106299305000746/exhibit10-19.htm)
10.4	Service Agreement for Point-to-Point Transmission Service dated June 24, 2005 between Department of Energy’s Bonneville Power Administration - Transmission Business Line and U.S. Geothermal Inc. (Incorporated by reference to exhibit 10.27 to the registrant’s Form 10-QSB quarterly report as filed on July 13, 2005) (https://www.sec.gov/Archives/edgar/data/1172136/000106299305001630/exhibit10-27.htm)
10.5	Interconnection and Wheeling Agreement dated March 9, 2006 between Raft River Rural Electric Co-op and Raft River Energy I LLC (Incorporated by reference to exhibit 10.28 to the registrant’s Form 10-KSB annual report as filed on June 29, 2006) (https://www.sec.gov/Archives/edgar/data/1172136/000106299306001879/exhibit10-28.htm)
10.6	Asset Purchase Agreement dated as of March 31, 2008, between U.S. Geothermal Inc., and Empire Geothermal Power LLC and Michael B. Stewart (Incorporated by reference as exhibit 99.1 to the registrant’s Form 8-K current report as filed on April 7, 2008) (https://www.sec.gov/Archives/edgar/data/1172136/000091228208000501/ex99_1.htm)
10.7	Water Rights Purchase Agreement between Michael B. Stewart and U.S. Geothermal Inc. dated March 31, 2008 (Incorporated by reference as exhibit 99.2 to the registrants Form 8-K current report as filed on April 7, 2008) (https://www.sec.gov/Archives/edgar/data/1172136/000091228208000501/ex99_2.htm)
10.8	Power Purchase Agreement dated as of December 11, 2009, between Idaho Power Company and USG Oregon LLC (Incorporated by reference to Exhibit 10.43 to the Company’s Form 10-Q quarterly report as filed on February 9, 2010) (https://www.sec.gov/Archives/edgar/data/1172136/000120445910000264/exhibit10-43.htm)
10.9	Amended and Restated Long-Term Portfolio Energy Credit and Renewable Power Purchase Agreement dated May 31, 2011 between Sierra Pacific Power Company d/b/a NV Energy, and USG Nevada LLC (Incorporated by reference to Exhibit 10.1 to the registrant’s Form 8-K filed on January 4, 2012) (https://www.sec.gov/Archives/edgar/data/1172136/000120445912000014/exhibit10-1.htm)
10.10	Amended and Restated Limited Liability Company Agreement made and entered into as of September 7, 2010, by and among Oregon USG Holdings LLC, U.S. Geothermal Inc., and Enbridge (U.S.) Inc. (Incorporated by reference to exhibit 99.4 to the registrant’s Form 8-K as filed on November 8, 2010) * (https://www.sec.gov/Archives/edgar/data/1172136/000120445910002672/exhibit99-4.htm)

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10.11	2009 Stock Incentive Plan of the Registrant (Incorporated by reference to Appendix A to the Company’s definitive proxy statement on Schedule 14A as filed on November 6, 2009) (https://www.sec.gov/Archives/edgar/data/1172136/000120445909002032/usgeodef14a.htm)
10.12	2009 Stock Incentive Plan Non-Qualified Stock Option Certificate (Incorporated by reference to Exhibit 10.13 to the registrant’s Form 10-Q filed on August 10, 2017) (https://www.sec.gov/Archives/edgar/data/1172136/000106299317003663/exhibit10-13.htm)
10.13	Loan Guarantee Agreement dated as of February 23, 2011, among USG Oregon LLC, U.S. Department of Energy, and PNC Bank N.A. (Incorporated by reference to exhibit 99.2 to the registrant’s Form 8-K as filed on August 31, 2011) (https://www.sec.gov/Archives/edgar/data/1172136/000106299311003532/exhibit99-2.htm)
10.14	Equity Pledge Agreement dated as of February 23, 2011, among Oregon USG Holdings LLC, USG Oregon LLC, and PNC Bank, N.A. (Incorporated by reference to exhibit 99.3 to the registrant’s Form 8-K as filed on August 31, 2011) (https://www.sec.gov/Archives/edgar/data/1172136/000106299311003532/exhibit99-3.htm)
10.15	Note Purchase Agreement dated as of February 23, 2011 among the Federal Financing Bank, USG Oregon LLC, and the Secretary of Energy, acting though the Department of Energy (Incorporated by reference to exhibit 99.2 to the registrant’s Form 8-K as filed on September 15, 2011) (https://www.sec.gov/Archives/edgar/data/1172136/000120445911002531/exhibit 99-2.htm)
10.16	Purchase Agreement dated January 22, 2016, between U.S. Geothermal Inc. and Lincoln Park Capital Fund, LLC ( incorporated by reference to Exhibit 10.1 to the Registrant’s From 8-K as filed on January 25, 2016) (https://www.sec.gov/Archives/edgar/data/1172136/000106299316007274/exhibit10-1.htm)
10.17	Purchase and Sale Agreement dated as of December 14, 2015, among Idaho USG Holdings, LLC, Raft River I Holdings, LLC, Goldman, Sachs & Co., and U.S. Geothermal Inc. (Incorporated by reference to exhibit 10.1 to the registrant’s Form 8-K as filed on December 18, 2015) (https://www.sec.gov/Archives/edgar/data/1172136/000106299315006741/exhibit10-1.htm)
10.18	Second Amended and Restated Operating Agreement of Raft River Energy I LLC, dated as of December 14, 2015, among Idaho USG Holdings, LLC, and Raft River I Holdings, LLC (Incorporated by reference to exhibit 3.1 to the registrant’s Form 8-K as filed on December 18, 2015) (https://www.sec.gov/Archives/edgar/data/1172136/000106299315006741/exhibit 3-1.htm)

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10.19	Employment Agreement dated April 19, 2013 with Dennis J. Gilles (Incorporated by reference to exhibit 10.1 to the registrant’s Form 8-K as filed on April 23, 2013) (https://www.sec.gov/Archives/edgar/data/1172136/000106299313002082/exhibit 10-1.htm)
10.20	Amendment No. 1 to the Employment Agreement dated January 9, 2017 with Dennis J. Gilles (Incorporated by reference to exhibit 10.1 to the registrant’s Form 10-Q as filed on May 10, 2017) (https://www.sec.gov/Archives/edgar/data/1172136/000106299317002338/exhibit 10-1.htm)
10.21	Employment Agreement dated December 31, 2010 with Jonathan Zurkoff (Incorporated by reference to exhibit 10.3 to the registrant’s Form 8-K as filed on July 26, 2013) (https://www.sec.gov/Archives/edgar/data/1172136/000106299313003607/exhibit 10-3.htm)
10.22	Amendment No. 1 to the Employment Agreement dated July 26, 2013 with Jonathan Zurkoff (Incorporated by reference to exhibit 10.3 to the registrant’s Form 8-K as filed on July 26, 2013) (https://www.sec.gov/Archives/edgar/data/1172136/000106299313003607/exhibit 10-3.htm)
10.23	Amendment No. 2 to the Employment Agreement dated April 7, 2014 with Jonathan Zurkoff (Incorporated by reference to exhibit 10.2 to the registrant’s Form 8-K as filed on April 11, 2014) (https://www.sec.gov/Archives/edgar/data/1172136/000106299314002086/exhibit 10-2.htm)
10.24	Amendment No. 3 to the Employment Agreement dated May 1, 2015 with Jonathan Zurkoff (Incorporated by reference to exhibit 10.2 to the registrant’s Form 8-K as filed on May 5, 2015) (https://www.sec.gov/Archives/edgar/data/1172136/000106299315002389/exhibit 10-2.htm)
10.25	Amendment No. 4 to the Employment Agreement dated February 3, 2016 with Jonathan Zurkoff (Incorporated by reference to exhibit 10.4 to the registrant’s Form 8-K as filed on February 4, 2016) (https://www.sec.gov/Archives/edgar/data/1172136/000106299316007449/exhibit 10-4.htm)
10.26	Amendment No. 5 to the Employment Agreement dated February 10, 2017 with Jonathan Zurkoff (Incorporated by reference to exhibit 10.5 to the registrant’s Form 8-K as filed on February 16, 2017) (https://www.sec.gov/Archives/edgar/data/1172136/000091228217000058/ex10_5.htm)

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10.27	Note Purchase Agreement dated May 19, 2016 among Idaho USG Holdings, LLC, The Prudential Insurance Company of America and Prudential Annuities Life Assurance Corporation relating to $20,000,000, 5.80% Senior Secured Notes due March 31, 2023 (Incorporated by reference to exhibit 10.1 to the registrant’s Form 10-Q as filed on August 9, 2016) (https://www.sec.gov/Archives/edgar/data/1172136/000106299316010892/exhibit 10-1.htm)
10.28	Engagement Agreement for Executive Management Advisory Services, dated July 12, 2017, between the Company and Dennis J. Gilles (Incorporated by reference to exhibit 10.29 to the registrant’s Form 10-Q as filed on November 9, 2017) (https://www.sec.gov/Archives/edgar/data/1172136/000106299317004757/exhibit10-29.htm)
10.29	Amendment No. 1 to the Employment Agreement, dated July 27, 2017, between the Company and Douglas J. Glaspey (Incorporated by reference to exhibit 10.30 to the registrant’s Form 10-Q as filed on November 9, 2017) (https://www.sec.gov/Archives/edgar/data/1172136/000106299317004757/exhibit10-30.htm)
10.30	Amendment No. 2 to the Employment Agreement, dated August 7, 2017, between the Company and Douglas J. Glaspey (Incorporated by reference to exhibit 10.31 to the registrant’s Form 10-Q as filed on November 9, 2017) (https://www.sec.gov/Archives/edgar/data/1172136/000106299317004757/exhibit10-31.htm)
10.31	Amendment No. 6 to the Employment Agreement, dated January 8, 2018, with Jonathan Zurkoff (Incorporated by reference to exhibit 10.7 to the registrant’s Form 8-K as filed on January 11, 2018) (https://www.sec.gov/Archives/edgar/data/1172136/000091228218000007/ex10_7.htm)
10.32	Renewable Energy Certificate Purchase and Sale Agreement, dated December 15, 2010, between Raft River Energy I LLC and Public Utility District No. 1 of Clallam County, Washington
21.1	Subsidiaries of the Registrant (Incorporated by reference to exhibit 21.1 to the registrant’s Form 10-K as filed on March 9, 2017) (https://www.sec.gov/Archives/edgar/data/1172136/000106299317001274/exhibit21-1.htm)
23.1	Consent of Moss Adams LLP, Independent Registered Public Accounting Firm
31.1	Certification of Interim Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes- Oxley Act of 2002
32.1	Certification of Interim Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

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32.2	Certification of Chief Financial Officer Pursuant to Section 906 of the Sarbanes- Oxley Act of 2002
101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema Document
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB	XBRL Taxonomy Extension Label Linkbase Document
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

† Schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K. The Company hereby undertakes to furnish supplementally copies of any of the omitted schedules upon request by the U.S. Securities and Exchange Commission; provided, however, that the Company may request confidential treatment pursuant to Rule 24b-2 of the Securities Exchange Act of 1934, as amended, for any schedules so furnished.

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

Item 16

Form 10-K Summary

None.

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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 8, 2018
	By:	/s/ Douglas J. Glaspey
Date		Douglas J. Glaspey
		Interim 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


	Interim Chief Executive Officer, President, Chief Operating
/s/ Douglas J. Glaspey	Officer and Director (Principal Executive Officer)	March 8, 2018
Douglas J. Glaspey

	Chief Financial Officer (Principal Financial and Accounting
/s/ Kerry Hawkley	Officer)	March 8, 2018
Kerry Hawkley


/s/ John H. Walker	Chairman and Director	March 8, 2018
John H. Walker


/s/ Paul A. Larkin	Director	March 8, 2018
Paul A. Larkin

/s/ Leland L. Mink	Director	March 8, 2018
Leland R. Mink


/s/ Ali G. Hedayat	Director	March 8, 2018
Ali G. Hedayat


/s/ Randolph J. Hill	Director	March 8, 2018
Randolph J. Hill


/s/ James C. Pappas	Director	March 8, 2018
James C. Pappas

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US GEOTHERMAL INC 10-K