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EX-32.2 - EXHIBIT 32.2 - US GEOTHERMAL INCexhibit32-2.htm
EX-32.1 - EXHIBIT 32.1 - US GEOTHERMAL INCexhibit32-1.htm
EX-31.2 - EXHIBIT 31.2 - US GEOTHERMAL INCexhibit31-2.htm
EX-31.1 - EXHIBIT 31.1 - US GEOTHERMAL INCexhibit31-1.htm
EX-10.13 - EXHIBIT 10.13 - US GEOTHERMAL INCexhibit10-13.htm

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

FORM 10-Q

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

For the quarterly period ended June 30, 2017

or

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

For the transition period from ____________ to ___________

Commission File Number: 001-34023

U.S. GEOTHERMAL INC.
(Exact Name of Registrant as Specified in Its Charter)

Delaware 84-1472231
(State or Other Jurisdiction of (I.R.S. Employer
Incorporation or Organization) Identification No.)
   
390 E. Parkcenter Blvd., Suite 250  
Boise, Idaho 83706
(Address of Principal Executive Offices) (Zip Code)

208-424-1027
(Registrant’s Telephone Number, Including Area Code)

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 the past 90 days.
Yes [X]        No [   ]

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation 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).
Yes [X]        No [   ]

-1-


Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an 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 Exchange Act).
Yes [   ]        No [X]

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

Class   Shares Outstanding as of August 8, 2017
Common stock, par value   19,239,685
$ 0.001 per share    

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U.S. Geothermal Inc.
Form 10-Q
For the Three and Six Months Ended June 30, 2017

INDEX

PART I – Financial Information
     
Item 1 – Consolidated Financial Statements (Unaudited)
Consolidated Balance Sheets at June 30, 2017 and December 31, 2016 4
Consolidated Statements of Operations – Three and Six Months Ended June 30, 2017 and 2016 5
Consolidated Statements of Cash Flows – Six Months Ended June 30, 2017 and 2016 6
Consolidated Statements of Changes in Stockholders’ Equity – Six Months Ended June 30, 2017 and Year Ended December 31, 2016 7
Notes to Consolidated Financial Statements 8
   
Item 2 - Management’s Discussion and Analysis of Financial Condition and Results of Operations 25
-        General Background and Discussion 26
          •      Projects in Operation 27
          •      Projects Under Development/Exploration 29
  -        Operating Results 34
-        Off Balance Sheet Arrangements 44
-        Liquidity and Capital Resources 44
-        Potential Acquisitions 45
-        Critical Accounting Policies 45
Item 3 – Quantitative and Qualitative Disclosures about Market Risk 46
Item 4 - Controls and Procedures 46
  
PART II – Other Information
     
Item 1 - Legal Proceedings 47
Item 1A - Risk Factors 47
Item 2 - Unregistered Sales of Equity Securities and Use of Proceeds 47
Item 3 - Defaults Upon Senior Securities 47
Item 4 – Mine Safety Disclosures 47
Item 5 - Other Information 47
Item 6 - Exhibits 47

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PART I – FINANCIAL INFORMATION

Item 1 – Consolidated Financial Statements

U.S. GEOTHERMAL INC.
CONSOLIDATED BALANCE SHEETS

    (Unaudited)        
    June 30,     December 31,  
    2017     2016  
             
ASSETS            
             
Current:            
     Cash and cash equivalents $  13,452,975   $  15,287,144  
     Restricted cash and security bonds   8,848,221     8,527,462  
     Trade accounts receivable   3,646,988     4,102,018  
     Other current assets   1,672,316     1,664,866  
              Total current assets   27,620,500     29,581,490  
             
Restricted cash and security bond reserves   19,650,455     20,111,350  
Property, plant and equipment, net   169,328,095     170,301,349  
Intangible assets, net   14,993,301     15,084,143  
Net deferred income tax asset   8,309,000     8,346,000  
                     Total assets $  239,901,351   $  243,424,332  
             
LIABILITIES AND STOCKHOLDERS’ EQUITY            
             
Current Liabilities:            
     Accounts payable and accrued liabilities $  1,976,577   $  2,255,710  
     Current portion of notes payable   4,212,109     4,259,595  
              Total current liabilities   6,188,686     6,515,305  
             
Long-term Liabilities:            
     Asset retirement obligations   1,219,903     1,219,903  
     Notes payable, less current portion   101,817,016     104,131,086  
              Total long-term liabilities   103,036,919     105,350,989  
             
                     Total liabilities   109,225,605     111,866,294  
             
Commitments and Contingencies (note 10)            
             
STOCKHOLDERS’ EQUITY            
             
Capital stock (authorized: 250,000,000 common shares with a $0.001 par
   value; issued and outstanding shares at June 30, 2017 and December 31, 2016
   were: 19,123,018 and 18,970,445; respectively)
  19,123     18,970  
Additional paid-in capital   122,861,067     121,933,378  
Accumulated deficit   (17,155,264 )   (16,974,300 )
    105,724,926     104,978,048  
             
Non-controlling interests   24,950,820     26,579,990  
                     Total stockholders’ equity   130,675,746     131,558,038  
             
                             Total liabilities and stockholders’ equity $  239,901,351   $  243,424,332  

The accompanying notes are an integral part of these consolidated financial statements.
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U.S. GEOTHERMAL INC.
CONSOLIDATED STATEMENTS OF OPERATIONS

    (Unaudited)     (Unaudited)  
    For the Three Months Ended     For the Six Months Ended  
    June 30,     June 30,  
    2017     2016     2017     2016  
                         
Plant Revenues:                        
       Energy sales $  6,213,808   $  5,589,924   $  14,548,258   $  14,000,746  
       Energy credit sales   97,304     74,356     199,923     166,810  
            Total plant operating revenues   6,311,112     5,664,280     14,748,181     14,167,556  
                         
Plant Expenses:                        
       Plant production expenses   2,865,354     2,217,418     5,811,426     4,616,134  
       Depreciation and amortization   1,631,596     1,584,426     3,264,344     3,165,289  
            Total plant operating expenses   4,496,950     3,801,844     9,075,770     7,781,423  
                         
Gross Profit   1,814,162     1,862,436     5,672,411     6,386,133  
Operating Expenses:                        
       Corporate administration   409,290     299,658     712,996     653,704  
       Professional and management fees   148,584     155,651     294,349     1,212,160  
       Employee compensation   677,570     875,327     1,589,304     1,681,996  
       Travel and promotion   74,302     180,485     111,137     263,897  
       Exploration costs   6,445     6,329     34,635     27,595  
Operating Income   497,971     344,986     2,929,990     2,546,781  
                         
Other (income) expense:                        
       Interest expense   1,208,057     1,042,803     2,396,328     1,976,495  
       Other (income) expense   (16,917 )   (13,150 )   (31,655 )   (22,842 )
Income (Loss) Before Income Tax                        
   Expense (Benefit)   (693,169 )   (684,667 )   565,317     593,128  
       Income Tax Expense (Benefit)   (98,000 )   (296,000 )   37,000     (206,000 )
                         
Net Income (Loss)   (595,169 )   (388,667 )   528,317     799,128  
         Net (income) loss attributable to the non-
            controlling interests
  153,315     (105,050 )   (709,281 )   (1,141,453 )
                         
Net Loss Attributable to U.S. Geothermal Inc. $  (441,854 ) $  (493,717 ) $  (180,964 ) $  (342,325 )
                         
Net Loss Per Share Attributable to U.S. Geothermal Inc.:                
           Basic $  (0.02 )   (0.03 ) $  (0.01 ) $  (0.02 )
           Diluted $  (0.02 )   (0.03 ) $  (0.01 ) $  (0.02 )
                         
Shares used in the calculation of income per share:                
         Basic   19,048,353     18,630,441     19,000,178     18,423,146  
         Diluted   19,048,353     18,630,441     19,000,178     18,423,146  

The accompanying notes are an integral part of these consolidated financial statements.
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U.S. GEOTHERMAL INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS

    (Unaudited)  
    For the Six Months Ended June 30,  
    2017     2016  
             
Operating Activities:            
Net Income $  528,317   $  799,128  
Adjustments to reconcile net income to total cash provided by operating activities:        
           Depreciation and amortization   3,376,149     3,223,160  
           Stock based compensation   513,913     619,521  
           Change in deferred income taxes   37,000     (206,000 )
 Net changes in:            
           Trade accounts receivable   455,030     1,882,088  
           Accounts payable and accrued liabilities   69,411     (584,843 )
           Prepaid expenses and other   (7,450 )   11,270  
              Total cash provided by operating activities   4,972,370     5,744,324  
             
Investing Activities:            
     Purchases of property, plant and equipment   (3,241,975 )   (2,378,055 )
     Grant reimbursements on construction   640,026     -  
     Net proceeds from (funding of) restricted cash reserves and bonds   140,136     (8,138,125 )
           Total cash used by investing activities   (2,461,813 )   (10,516,180 )
             
Financing Activities:            
     Issuance of common stock   413,929     2,298,215  
     Distributions to non-controlling interest   (2,338,451 )   (2,511,484 )
     Proceeds from notes payable, net of issuance costs   -     19,178,930  
     Principal payments on notes payable and other obligations   (2,420,204 )   (4,542,643 )
           Total cash provided (used) by financing activities   (4,344,726 )   14,423,018  
             
Increase (Decrease) in Cash and Cash Equivalents   (1,834,169 )   9,651,162  
             
Cash and Cash Equivalents, Beginning of Year   15,287,144     8,654,375  
             
Cash and Cash Equivalents, End of Year $  13,452,975   $  18,305,537  
             
Supplemental Disclosures:            
Non-cash investing and financing activities:            
     Accrual for purchases of property and equipment $  348,544   $  135,075  
             
Other Items:            
     Interest paid   2,375,681     1,888,827  

The accompanying notes are an integral part of these consolidated financial statements.
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U.S. GEOTHERMALINC.
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY - Unaudited
For the Six Months Ended June 30, 2017 and Year Ended December 31, 2016

                  Additional           Non-        
    Number of     Common     Paid-In     Accumulated     controlling        
    Shares     Shares     Capital     Deficit     Interest     Totals  
                                     
                                     
Balance at January 1, 2016   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     411     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     75     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   -     -     -     -     (2,338,451 )   (2,338,451 )
Stock issued by the exercise of employee stock options   58,582     58     128,733     -     -     128,791  
Stock issued by the exercise of stock purchase warrants   95,046     95     285,043     -     -     285,138  
Stock compensation   (1,055 )   -     513,913     -     -     513,913  
Net income (loss)   -     -     -     (180,964 )   709,281     528,317  
Balance at June 30, 2017   19,123,018   $  19,123   $  122,861,067   $  (17,155,264 ) $  24,950,820   $  130,675,746  

The accompanying notes are an integral part of these consolidated financial statements.
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U.S. GEOTHERMAL INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Unaudited
June 30, 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

These unaudited interim consolidated financial statements of the Company and its subsidiaries have been prepared in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) for interim financial reporting. Certain information and footnote disclosures normally included in the annual consolidated financial statements prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) have been condensed or omitted pursuant to such rules and regulations. In our opinion, the unaudited consolidated financial statements include all material adjustments, all of which are of a normal and recurring nature, necessary to present fairly our financial position as of June 30, 2017 and our operating results and cash flows for the three and six months ended June 30, 2017 and 2016. The accompanying financial information as of December 31, 2016, is derived from audited financial statements. Interim results are not necessarily indicative of results for a full year. The information included in this Quarterly Report on Form 10-Q should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2016.

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).

-8-


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 operations will consolidate the subsidiary’s full operations, and will separately disclose the elimination of the non-controlling interest’s allocation of profits and losses.

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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 June 30, 2017 and December 31, 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 June 30, 2017, the Company’s total cash balance, excluding money market funds, was $5,833,491 and bank deposits amounted to $6,384,917. The primary difference was due to outstanding checks and deposits. Of the bank deposits, $4,985,752 was not covered by or was in excess of FDIC insurance guaranteed limits. At June 30, 2017, the Company’s money market funds invested, primarily, in government backed securities totaled $34,645,563 and were not subject to deposit insurance. A contracted power purchaser held a security bond for the Company that totaled $1,468,898 at June 30, 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.

-9-


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

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.

Earnings 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.

-10-


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 (“RREI”), 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 statements of income.

Revenue Source

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

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, the 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. Early adoption is permitted, including adoption in an interim period. 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.

-11-


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, with early adoption permitted for public companies effective from annual and interim reporting periods beginning after December 31, 2016. 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 financial statements, and has not determined a method of adoption.

Leases
In February 2016, 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 would 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.

-12-


NOTE 3 – RESTRICTED CASH AND BOND RESERVES

Under the terms of the loan agreements with the U.S. Department of Energy (“DOE”) 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:

      June 30,     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     269,443     284,621  
Prudential Capital Group, Debt Service Reserves (USG Nevada LLC)     1,604,428     1,600,597  
Bureau of Land Management , Geothermal Rights Lease Bond     10,000     10,000  
U.S. Department of Energy, Debt Service Reserve     1,983,332     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)     1,755,776     1,755,776  
Prudential Capital Group, Revenue Reserves (Idaho USG Holdings LLC)     360,059     -  
CAISO, Transmission Interconnection Escrow Deposits     1,895,183     1,895,023  
               
    $  8,848,221   $  8,527,462  

-13-


Long-term restricted cash and bond reserves:

      June 30,     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)     1,109,809     1,081,744  
Prudential Capital Group, Well Reserves (USG Nevada LLC)     1,271,074     951,486  
Prudential Capital Group, Maintenance Reserves (Idaho USG Holdings LLC)     1,807,890     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     2,380,247     2,413,951  
U.S. Department of Energy, Short Term Well Field Reserves     4,509,468     4,508,650  
U.S. Department of Energy, Long-Term Well Field Reserves     4,543,950     5,175,777  
U.S. Department of Energy, Capital Expenditure Reserves     2,285,323     2,429,158  
               
    $  19,650,455   $  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 June 30, 2017 and December 31, 2016.

NOTE 4 – TRADE RECEIVABLES/INSURANCE PROCEEDS

The Company’s receivables are summarized as follows:

      June 30,     December 31,  
      2017     2016  
Trade receivables   $  2,411,654   $  4,100,747  
Insurance proceeds receivable     1,232,288     -  
Other receivables     3,046     1,271  
               
    $  3,646,988   $  4,102,018  

On January 5, 2017, Unit I of the USG Oregon LLC plant experienced mechanical failures, primarily due to extreme cold temperatures, that resulted in an outage and the loss of a substantial amount of the plant’s refrigerant. The initial repairs to identify and plug the damaged tubes were completed on February 12, 2017 and the Unit was returned to service. The repair costs and lost revenue were covered by property and business interruption insurance, subject to deductibles and other terms of the policy. The deductibles were $50,000 for property loss and a 30-day period for business interruption coverage. The lost revenue associated with that 30-day deductible period is estimated at $833,000. At June 30, 2017, the total submitted claims that are expected to be recovered after deductibles were $1,232,288. The Company estimates that the full amount of the property loss expenses, less the $50,000 deductible, will be collected. The Company received partial insurance reimbursements of $1,050,000 and $520,000 in April 2017 and July 2017; respectively. For the six months ended June 30, 2017, insurance recovery amounts of $1,956,882 for plant production expenses and $325,406 for energy sales were accrued.

-14-


NOTE 5 - PROPERTY, PLANT AND EQUIPMENT

During the three months ended June 30, 2017, the Company focused on development activities at Raft River Energy I, San Emidio Phase II and WGP Geysers projects. 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 $396,100 in the current quarter. Grant proceeds totaling $196,000 ($640,026 for the six months ended June 30, 2017) offset the majority of the total costs of the seismic studies. Costs during the quarter that totaled $429,738 were capitalized at WGP Geysers for plant engineering and design. At Raft River, additional costs were incurred for the new production well at total costs of approximately $400,100.

During the three months ended March 31, 2017, the Company focused on development activities at Raft River Energy I, San Emidio Phase II and WGP Geysers projects. At Raft River, a new production well was connected to the plant and placed into operation on March 21, 2017 at a cost of approximately $507,000. At San Emidio Phase II and Crescent Valley projects, seismic studies were conducted and capitalized that cost approximately $322,000 in the prior quarter. Grant proceeds totaling $444,026 offset the majority of the total costs of the studies. Costs during the quarter that totaled $400,338 were capitalized at WGP Geysers for plant engineering and interconnection costs.

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

    June 30,     December 31,  
    2017     2016  
Land $  3,116,262   $  3,116,262  
Power production plant   159,876,162     159,876,162  
Grant proceeds for power plants   (52,965,236 )   (52,965,236 )
Wells   71,273,114     71,340,305  
Grant proceeds for wells   (3,464,555 )   (3,464,555 )
Furniture and equipment   4,551,486     4,491,058  
    182,387,233     182,393,996  
             
           Less: accumulated depreciation   (40,443,044 )   (37,216,385 )
    141,944,189     145,177,611  
Construction in progress   27,383,906     25,123,738  
             
  $  169,328,095   $  170,301,349  

Depreciation expense was charged to plant operations and general expenses for the following periods:

    June 30,  
    2017     2016  
             
Three months ended $  1,612,231   $  1,544,669  
Six months ended   3,226,659     3,112,769  

-15-


Changes in construction in progress are summarized as follows:

      For the Six Months     For the Year  
      Ended June 30,     Ended December  
      2017     31, 2016  
  Beginning balances $  25,123,738   $  21,022,981  
       Development/construction   2,971,715     8,116,725  
       Grant reimbursement   (640,026 )   -  
       Placed into operation   (71,521 )   (4,015,968 )
  Ending balances $  27,383,906   $  25,123,738  

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

      June 30,     December 31,  
      2017     2016  
  Raft River, Idaho:            
          Unit I, well improvements $  905,313   $  5,377  
          Unit I, plant improvements   109,444     108,555  
          Unit II, power plant, substation and transmission lines   751,678     751,618  
          Unit II, well construction   2,150,568     2,149,835  
      3,917,003     3,015,385  
  San Emidio, Nevada:            
           Unit II, power plant, substation and transmission lines   444,644     426,941  
           Unit II, well construction   4,867,818     4,748,924  
      5,312,462     5,175,865  
  Neal Hot Springs, Oregon:            
           Power plant and facilities   73,980     73,761  
          Well construction   608,520     378,098  
      682,500     451,859  
               
  WGP Geysers, California:            
         Power plant and facilities   325,989     325,989  
         Well construction   9,695,168     8,865,093  
      10,021,157     9,191,082  
  Crescent Valley, Nevada:            
          Well construction   1,614,890     1,655,653  
               
  El Ceibillo, Republic of Guatemala:            
         Well construction   5,827,394     5,625,394  
         Plant and facilities   8,500     8,500  
      5,835,894     5,633,894  
               
    $  27,383,906   $  25,123,738  

-16-


NOTE 6 – INCOME TAXES

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

      For the Six Months Ended  
      June 30,  
      2017     2016  
  U.S. Federal statutory rate   34.0%     34.0%  
  Average State and foreign income tax, net of federal tax effect   2.8     3.5  
  Impact of state deferred rate decrease         -  
  Stock based compensation   (9.2)   -  
  Other   (1.3)   -  
           Consolidated tax rate before non-controlling interest   29.0     37.5  
  Tax effect of non-controlling interests   (22.5)   (37.5)
           Net effective tax rate   6.5%     0.0%  

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 six months ended June 30, 2017, reflects a reported effective tax rate of 6.5%, which differs from the statutory federal income tax rate of 34.0% primarily due to the impact of the non-controlling interest, stock compensation and state income taxes.

NOTE 7 – 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 June 30, 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 $684,225 ($821,070, less amortized costs of $136,845).

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 maybe 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 June 30, 2017 totaled $58,545,023 (current portion $3,252,501).

-17-


Loan advances/tranches and effective annual interest rates are detailed 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 June 30, 2017     (24,512,942 )      
               
Loan balance at June 30, 2017   $  58,545,023        

* - 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 June 30, 2017, the balance of the loan was $28,867,644 (current portion $563,068).

Auto Loan – U.S. Geothermal Services, LLC
On July 28, 2016, the Company’s wholly owned subsidiary (U.S. Geothermal Services, LLC) 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 June 30, 2017, the loan balance totaled $4,207 (current portion $3,585).

-18-


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  
June 30,     Payments  
         
2018   $ 4,212,109  
2019     4,465,939  
2020     4,657,596  
2021     5,099,553  
2022     5,272,176  
Thereafter     83,005,976  
         
    $ 106,713,349  

NOTE 8 - 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 June 30, 2017, the Company can issue stock option grants totaling up to 2,845,566 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.

The following table reflects the summary of stock options outstanding at January 1, 2017 and changes for the six months ended June 30, 2017:

          Weighted        
          Average        
    Number of     Exercise     Aggregate  
    shares under     Price Per     Intrinsic  
    options     Share     Value  
                   
Balance outstanding, January 1, 2017   1,824,664   $  3.38   $  3,186,265  
     Forfeited/Expired   (11,583 )   4.34     -  
     Exercised   (58,582 )   2.20     -  
     Granted   375,136     4.10     -  
                   
Balance outstanding, June 30, 2017   2,129,635   $  3.53   $  3,883,974  

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

-19-


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.

During the three months ended June 30, 2017, 33,583 stock options exercisable at prices between $1.86 and $3.78 were exercised by employees and former employees. During the three months ended March 31, 2017, 24,999 stock options exercisable at prices between $1.86 and $2.76 were exercised by employees and former employees.

On May 1, 2017, the Company granted 12,500 stock options to an employee exercisable at a price of $4.18 that expire on May 1, 2022. On February 1, 2017, the Company granted 16,666 stock options to an employee exercisable at a price of $4.42 that expire on February 1, 2022. On March 28, 2017, the Company granted 345,970 stock options to employees exercisable at a price of $4.08 that expire on March 28, 2022.

During the three months ended June 30, 2017, 11,583 stock options exercisable at prices between $3.78 and $4.44 were forfeited due to termination of employment.

As of June 30, 2017, there was $452,709 of total unrecognized compensation cost related to non-vested stock option compensation arrangements granted under the Plan. That cost is expected to be recognized over a weighted-average period of 1.5 years.

Stock Purchase Warrants

At June 30, 2017, the outstanding share purchase warrants totaled 290,093 (385,139 warrants at December 31, 2016) with a warrant exercise price of $3.00 per warrant and expire December 26, 2017.

On June 27, 2017, broker warrants that totaled 50,000 were exercised by an investor at the warrant exercise price of $3.00. On January 19, 2017, broker warrants that totaled 45,046 were exercised by an investor at the warrant exercise price of $3.00.

NOTE 9 – 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.

-20-


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 June 30, 2017:

      Total     Level 1     Level 2     Level 3  
  Assets:                        
  Money market accounts * $  34,645,563   $  34,645,563   $  -   $  -  

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.

NOTE 10 - COMMITMENTS AND CONTINGENCIES

The Company’s total lease costs are summarized as follows:

    For the Six Months Ended,  
    June 30,  
    2017     2016  
             
Minimum lease payments $  196,703   $  246,964  
Royalty based contingent lease payments   153,678     162,663  
  $  350,381   $  409,627  

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  
         
2017   $  554,843  
2018     1,015,397  
2019     901,791  
2020     881,712  
2021     810,726  
Thereafter     12,714,238  

-21-


NOTE 11 – JOINT VENTURES/NON-CONTROLLING INTERESTS

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

    June 30,     December 31,  
    2017     2016  
             
Gerlach Geothermal LLC interest held by Gerlach Green Energy, LLC $ 201,682   $  207,217  
Oregon USG Holdings LLC interest held by Enbridge Inc.   24,218,670     25,361,410  
Raft River Energy I LLC interest held by Goldman Sachs   530,468     1,011,363  
  $ 24,950,820   $  26,579,990  

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. Initially, the Company contributed $757,190 in cash and $300,000 for a geothermal lease and mineral rights, and GGE contributed $704,460 of geothermal lease, mineral rights and exploration data. From November 18, 2014 to June 30, 2017 the Company has contributed $537,042 for the project’s drilling costs and other costs that were not proportionally matched by GGE. These contributions effectively increased the Company’s ownership interest to 69.28% and 68.99% at June 30, 2017 and December 31, 2016; respectively.

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 income and comprehensive income with the elimination of the non-controlling interest identified.

Oregon USG Holdings LLC
In September 2010, the Company’s subsidiary, Oregon USG Holdings LLC (“Oregon Holdings”), signed an Operating Agreement with Enbridge Inc. (“Enbridge”) for the right to participate in the Company’s Neal Hot Springs project located in Malheur County, Oregon. On February 20, 2014, a new determination under the existing agreement was reached with Enbridge that established their ownership interest percentage at 40% and the Company’s at 60%, effective January 1, 2013. Oregon Holdings has a 100% ownership interest in USG Oregon LLC. Enbridge has contributed a total of $32,801,000, including the debt conversion, to Oregon Holdings in exchange for a direct ownership interest. During the six months ended June 30, 2017 and the year ended December 31, 2016, distributions were made to the Company that totaled $3,482,015 and $6,107,217; respectively. During the six months ended June 30, 2017 and the year ended December 31, 2016, distributions were made to Enbridge that totaled $2,321,343 and $4,071,478; 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 income and comprehensive income with the elimination of the non-controlling interest identified.

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Raft River Energy I LLC (“RREI”)

RREI is a joint venture between the Company and The Goldman Sachs Group. An Operating Agreement governs the rights and responsibilities of both parties. At December 31, 2016, 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 operating 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 six months ended June 30, 2017, RREI distributed funds to the Company and Goldman Sachs of $325,059 and $17,108; respectively. During the year ended December 31, 2016, RREI distributed funds to the Company and Goldman Sachs of $1,203,349 and $82,473; respectively. During the six months ended June 30, 2017 and the year ended December 31, 2016, the Company made contributions of $905,289 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 six months ended June 30, 2017, a new production well that was contributed to the project by the Company produced incremental net profits of $189,422.

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 income and comprehensive income with the elimination of the non-controlling interest identified.

NOTE 12 – ASSET RETIRMENT 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 at $606,000. These obligations are initially estimated based upon discounted cash flows estimates and are accreted to full value over time. At June 30, 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. The obligation balances at June 30, 2017 and December 31, 2016 totaled $1,219,903. All of the obligations were considered to be long-term at June 30, 2017.

Raft River Energy I LLC, USG Nevada LLC, and USG Oregon LLC
These Companies operate in Idaho, Nevada and Oregon and are subject to environmental laws and regulations of these states. The plants, wells, pipelines and transmission lines are expected to have long useful lives. Generally, these assets will require funds for retirement or reclamation. However, these estimated obligations are believed to be less than or not significantly more than the assets’ estimated salvage values. Therefore, as of June 30, 2017 and December 31, 2016, no retirement obligations have been recognized.

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NOTE 13 – 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:                    
           June 30, 2017   $  181,871,880   $  58,029,471   $  239,901,351  
           December 31, 2016     188,682,162     54,742,170     243,424,332  
                     
For the Six Months Ended June 30,                    
     2017:                    
           Operating Revenues   $  14,748,181   $  -   $  14,748,181  
           Net Income (Loss)     3,548,654     (3,020,337 )   528,317  
     2016:                    
           Operating Revenues     14,000,746     -     14,000,746  
           Net Income (Loss)     4,273,228     (3,474,100 )   799,128  
                     
For the Three Months Ended June 30,                    
     2017:                    
           Operating Revenues   $  6,311,112   $  -   $  6,311,112  
           Net Income (Loss)     722,768     (1,317,937 )   (595,169 )
     2016:                    
           Operating Revenues     8,503,276     -     8,503,276  
           Net Income (Loss)     779,538     (1,168,205 )   (388,667 )

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Item 2 - Management’s Discussion and Analysis of Financial Condition and Results of Operations

INFORMATION REGARDING FORWARD LOOKING STATEMENTS

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

  • our business and growth strategies;

  • our future results of operations;

  • anticipated trends in our business;

  • the capacity and utilization of our geothermal resources;

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

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

  • the fulfillment of the respective parties’ rights and obligations under our joint ventures, leases, permits and all other agreements;

  • availability and costs of drilling rigs and field services;

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

  • our working capital requirements and availability;

  • our illustrative plant economics;

  • our illustrative growth goals and development and acquisition projections;

  • market conditions in the geothermal energy industry; and

  • the impact of environmental and other governmental regulation.

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

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

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

  • incorrect estimates of required capital expenditures;

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

  • ability to obtain a power purchase agreement for a new project;

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

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  • impact of environmental and other governmental regulation, including delays in obtaining permits or ongoing impacts of the sequester;

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

  • our ability to successfully identify and integrate acquisitions;

  • the failure of the geothermal resource to support the anticipated power capacity;

  • our dependence on key personnel;

  • changes in applicable laws, rules or regulations;

  • the potential for claims arising from geothermal plant operations;

  • general competitive conditions within the geothermal energy industry; and

  • financial market conditions.

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

The U.S. dollar is the Company’s functional currency. All references to “dollars” or “$” are to United States dollars.

General Background and Discussion

The following discussion should be read in conjunction with our unaudited consolidated financial statements for the three and six months ended June 30, 2017 and notes thereto included in this quarterly report and our Annual Report for the year ended December 31, 2016 filed with the SEC on March 9, 2017.

The Company is a Delaware corporation. The Company’s common stock trades on the NYSE American Exchange under the symbol “HTM”.

For the quarter ended June 30, 2017, the Company was focused on:

  • operating and optimizing the Neal Hot Springs, San Emidio and Raft River power plants;
  • completing the deepening of three additional temperature gradient wells and planning for flow testing at San Emidio II;
  • 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 detailed engineering and pursuing PPA opportunities for the WGP Geysers project;
  • commencing engineering for the Neal Hot Springs hybrid cooling system and preparing for water well testing; and
  • evaluating potential new geothermal projects and acquisition opportunities.

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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.

Projects in Operation

  Projects in Operation  
            Generating       Contract
                   Project   Location   Ownership   Capacity (megawatts)   Power Purchaser   Expiration
Neal Hot Springs   Oregon   JV(1)   22.0   Idaho Power   2036
San Emidio (Unit I)   Nevada   100%   10.0   Sierra Pacific   2038
Raft River (Unit I)   Idaho   JV(2)   13.0(3)   Idaho Power   2032
                     
  (1)

The Company’s equity interest in the project is 60% and Enbridge’s equity interest is 40%.

  (2)

The Company’s membership interest in the project is 95% and Goldman Sachs’ membership interest is 5% as the tax equity partner.

  (3)

The annual average net output design for the plant is 13 megawatts. The current average net output of the Raft River Unit I plant is approximately 10.1 megawatts.

Facility Generation
Generation from all facilities totaled 165,715 megawatt hours for the first six months of 2017. For the same period in 2016, the total generation was 162,667 megawatt hours. For the second quarter of 2017, generation from all facilities totaled 76,101 megawatt hours compared to 68,879 megawatt hours during the same period in 2016, which was a 10.4% increase.

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 second quarter of 2017, generation was 37,727 megawatt-hours with an average of 20.4 net megawatts per hour of operation and plant availability was 91.6% . For the same period in 2016, the plant generated 39,094 megawatt-hours with an average of 18.8 net megawatts per hour and plant availability was 99.0% excluding scheduled maintenance.

During the quarter, all three units underwent their scheduled annual maintenance outages. The outage for Unit 1 included replacement and repair of the vaporizer tubes that were damaged in January 2017. Unit 1 is back up to full production. A final settlement is pending with the insurance company on property damage costs and lost generation revenue.

An engineering firm has been contracted and is preparing the bid level design for a hybrid cooling system. Cooling water well CWW#1 has had a pump installed and is being prepared for a flow test. When drilled, it was estimated that the well was capable of 80 gallons per minute, bringing the total amount of water available from two wells to 250 gpm, enough for one unit to be converted to hybrid cooling. Discussions are underway to lease or purchase private surface water rights in the area and to determine the amount of water that would be available on a continuous basis. The option of treating geothermal brine to produce water for the hybrid cooling system is still being investigated. A pilot plant brine treatment system operating at the site is successfully producing high quality water that could be used if other water sources are not identified.

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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 ($109.27 for 2016) per megawatt-hour.

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 second quarter of 2017, generation was 17,695 megawatt-hours with an average of 9.1 net megawatts per hour of operation and plant availability was 97.9% . For the same period in 2016, the plant generated 14,139 megawatt-hours with an average of 8.15 net megawatts per hour and plant availability was 84.7% . San Emidio completed its annual scheduled maintenance outage from April 2 to April 10, 2017. Subsequent to the end of the current quarter on July 21, 2017, a small refrigerant leak was identified in the vaporizers. The facility was shut down, several pin-hole leaks were found and it is undergoing repairs.

On June 1, 2011, an amended and restated PPA was signed with Sierra Pacific Power Company d/b/a NV Energy for the sale of up to 19.9 megawatts of electricity on an annual average basis from two units. The option for the second unit expired in December 2015. The PPA has a 25-year term with a base price of $89.75 per megawatt-hour, and an annual escalation rate of 1 percent. The annual average price paid under the PPA for 2017 is $93.94 ($93.01 for 2016) 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 second quarter of 2017, generation was up 32.2% over the prior year to 20,680 megawatt-hours with an average of 10.2 net megawatts per hour of operation and plant availability was 98.5% . For the same period in 2016, the plant generated 15,647 megawatt-hours with an average of 7.7 net megawatt hours and plant availability was 100%. Raft River completed its annual scheduled maintenance outage from May 15 to May 24, 2017.

The increased generation during the second quarter of 2017 is primarily due to the addition of production well RRG-5, which commenced operation in late March 2017. RRG-5 is continuing to operate at 1,100 gpm with the temperature increasing to 249°F. An upgraded injection pump was ordered during the second quarter and is expected to be installed before the end of the third quarter 2017. Once the new injection pump is installed, an additional increase in generation is expected. After the reservoir is balanced out over several months, other potential changes in the operation that may further increase generation will be evaluated.

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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 1,370 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.

On April 20, 2017 we were awarded a $150,000 Small Business Voucher grant to evaluate the installation of an integrated solar topping turbine at the Raft River project. The total cost of the program is $187,500, with the Company providing $37,500 in cost share. Two DOE national laboratories are working on the solar topping design with the Company; the National Renewable Energy Laboratory (NREL), operated by the Alliance for Sustainable Energy, LLC, and Idaho National Laboratory (INL), which performs work in each of DOE’s strategic goal areas: energy, national security, science and environment, and is operated by Battelle Energy Alliance.

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 ($63.00 for 2016) per megawatt-hour.

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

Projects Under Development/Exploration

  Projects Under Development  
          Estimated  
      Target Projected Capital  
      Development Commercial Required Power
Project Location Ownership (Megawatts)   Operation Date ($million) Purchaser
Raft River Idaho 100% 1-3 3rd Quarter 2017 4 IDPC
Neal Hot Springs Oregon 60% 3 4th Quarter 2018 10 IDPC
San Emidio Phase II Nevada 100% 25-35 4th Quarter 2020* 126-168 TBD
WGP Geysers California 100% 30 3rd Quarter 2019* 148 TBD
El Ceibillo Phase I Guatemala 100% 25 2nd Quarter 2019* 140 TBD
Crescent Valley Phase I Nevada 100% 25 2nd Quarter 2021* 130 TBD
  * - Commercial operation dates are projections only. Actual dates can only be provided after PPAs have been obtained.

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Exploration Properties
            Target Development
Project   Location   Ownership   *(Megawatts)
Gerlach   Nevada   69.3%   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
Ruby Hot Springs Phase I   Nevada   100%   20
  * - Target development sizes are predevelopment estimates of resource potential of unproven
       resources. The estimates are based on our internal evaluation of available information regarding
       temperature, and where available, flow.

WGP Geysers, California
The WGP Geysers project is located in the broader Geysers geothermal field located approximately 75 miles north of San Francisco, California. The broader Geysers geothermal field is the largest producing geothermal field in the world generating more than 850 megawatts of power for more than 30 years. Acquisition of the WGP Geysers Project from Ram Power was completed on April 22, 2014 for $6.4 million. We expect that approximately 75% of the development may be funded by non-recourse project debt, with the remainder funded through equity financing. We anticipate the project qualifying for the 30% Federal Investment Tax Credit, which when monetized can meet most of the equity financing requirements.

Detailed engineering of the new, hybrid power plant design is continuing and final quotes for the turbine-generator have been received. Our engineers and consultants are working in concert with our EPC contractors to examine all aspects of the construction cycle with a focus further on reducing construction costs. The hybrid 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.

The Conditional Use Permit from Sonoma County, which approves the construction plan for the WGP Geysers power plant, was received on December 16, 2016. Combined with the Large Generator Interconnection Agreement 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 received the signed Large Generator Interconnection Agreement for the project on March 6, 2016 with the California Independent System Operator and Pacific Gas & Electric (PG&E). This agreement allows the project to connect to the transmission grid and deliver up to 35 megawatts of energy. The Company has paid the total interconnection cost of $1.9 million for the grid operator’s portion of the work in the substation. An additional 1.7 mile long transmission line will be required to connect from the plant to the substation and discussions are ongoing with the landowners to acquire a right-of-way. If the right-of-way cannot be secured, an alternative interconnection method will be required that may trigger additional studies and extend the time required for interconnection into the transmission grid. The LGIA issued in 2009, which preceded the new LGIA, utilized a more expensive “ring bus” type substation and could be adopted for the current facility. The additional cost associated with the “ring bus” configuration is currently included in the estimated project capital requirements.

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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 is being prepared to provide the final well requirements and targeting for injection sites.

Bilateral discussions are being held with several potential California based power purchasers for the generation from the WGP Geysers plant. The potential power 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. A number of community choice aggregators are also expected to issue renewable energy Requests for Proposals (RFP) for the purchase of renewable energy during 2017. The San Francisco Public Utilities Commission issued a renewable energy Request For Offers on June 22, 2017, and subsequent to the end of the quarter on July 26, 2017, a proposal was submitted for 30 megawatts from the WGP Geysers project.

San Emidio Phase II, Nevada
The Phase II expansion is dependent on successful development of additional production and injection well capacity. We expect that approximately 75% of the Phase II development may be funded by non-recourse project debt, with the remainder funded through equity financing. We anticipate the project qualifying 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 during the second quarter, with no unique or notable sites or species identified.

Permits to deepen three temperature gradient wells were received from the BLM in December 2016. Drilling began on June 1, 2017 and the three wells were deepened based on their high thermal gradient and bottom hole temperature. Well 78-20 was drilled to 2,387 feet deep, intersected the geothermal resource at 2,314 feet, and has a measured flowing temperature of 324°F. Well 18-21 was drilled to 2,177 feet deep, intersected the geothermal resource at 1,874 feet, and has a measured flowing temperature of 325°F. The third well (28-21) was drilled to 2,799 feet deep, intersected the geothermal resource at 1,900 feet, and though less permeable than the other two, has a measured flowing temperature of 321°F. For comparison purposes, the wellfield at our San Emidio I project is currently producing at an average temperature of 278°F.

The three newly completed wells extend the proven portion of the Southwest Zone approximately 1,000 feet further south and are expected to increase the P90 (90% probability) reservoir estimate of 18.7 net megawatts, announced in January, toward the 47 net megawatt P50 (50% probability) level. A long-term flow test is in the planning stages. This test will provide more detailed information about the generation capacity of the reservoir, so that an updated model can be developed to determine the maximum level of generation.

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An application for a Large Generator Interconnection Agreement (“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.

Bilateral discussions are being held with several potential California based power purchasers for the generation from the SE II plant. The potential power purchasers have expressed interest in renewable, base load power including that generated in Nevada. NV Energy, the Nevada publically owned electric utility, issued a renewable energy Request For Proposal on June 14, 2016. Subsequent to the end of the quarter, on July 6, 2017, a proposal was submitted to NV Energy in response to their Request For Proposal for a 25 megawatt PURPA PPA.

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.

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. Based on data collected to date, it was determined that a second phase of data collection was required to fill in and replace a limited number of MT stations at San Emidio, which is planned for the third quarter. Data integration and interpretation is nearly complete, pending the new information that will be generated in the third quarter. After all data is compiled and interpreted, if viable targets have been identified, DOE may approve a second phase of the grant program to confirm the findings by drilling, but there is no assurance the DOE will approve a second phase, even if viable targets are identified. The total program cost is $1.9 million with the Company providing $400,000 in cost share.

El Ceibillo, Republic of Guatemala
A geothermal energy rights concession, located 14 kilometers southwest of Guatemala City, was awarded to U.S. Geothermal Guatemala S.A., a wholly owned subsidiary of the Company in April 2010. The concession 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.

Production well EC-5 was completed to a depth of 1,450 feet (442 meters) on August 20, 2016 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).

With the shallow, commercial resource now indicated, a deep well is planned in 2017 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 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. A site has been constructed to drill well EC-6 to test this area.

-32-


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 an RFP later this year for 420 megawatts of power, of which 40 megawatts is to be reserved specifically for geothermal energy. When the RFP is issued, the El Ceibillo project will be bid 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 was started 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 1,370 gpm.

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.

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 is planned for the third quarter. 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.

-33-


Operating Results

For the six months ended June 30, 2017, the Company reported net loss attributable to the Company of $180,964 ($0.01 loss per share) which represented a favorable decrease of $161,361 (47.1% decrease) from net loss attributable to the Company of $342,325 ($0.02 loss per share) reported in the same period ended 2016. For the three months ended June 30, 2017, the Company reported net loss attributable to the Company of $441,854 ($0.02 loss per share) which represented a favorable decrease of $51,863 (10.5% decrease) from net loss attributable to the Company of $493,717 ($0.03 loss per share) reported in the same period ended 2016. Both favorable and unfavorable variances were reported in areas related to the operations of the Company’s three power plants. Notable favorable variances were reported for professional fees and promotion expenses. Notable unfavorable variances were noted for interest and income tax expenses.

Plant Operations

A summary of energy sales by plant location is as follows:

    For the Six Months Ended June 30,  
    2017     2016  
    $     %     $     %  
Neal Hot Springs, Oregon   8,659,958     59.5     8,811,326     62.9  
San Emidio, Nevada   3,494,135     24.0     3,215,516     23.0  
Raft River, Idaho   2,394,165     16.5     1,973,904     14.1  
    14,548,258     100.0     14,000,746     100.0  

% - represents the percentage of total Company energy sales.

    For the Three Months Ended June 30,  
    2017     2016  
    $     %     $     %  
Neal Hot Springs, Oregon   3,449,403     55.5     3,445,321     61.7  
San Emidio, Nevada   1,662,245     26.8     1,315,049     23.5  
Raft River, Idaho   1,102,160     17.7     829,554     14.8  
    6,213,808     100.0     5,589,924     100.0  

% - represents the percentage of total Company energy sales.

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

    For the Quarter Ended,  
    June 30,     September 30,     December 31,     March 31,     June 30,  
    2016     2016     2016     2017     2017  
Neal Hot Springs, Oregon   39,094     29,758     57,036     48,178     37,727  
San Emidio, Nevada   14,139     19,675     20,803     19,501     17,695  
Raft River, Idaho   15,647     16,622     20,039     21,934     20,679  
    68,880     66,055     97,878     89,613     76,101  

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

For the six months ended June 30, 2017, the Neal Hot Springs plant reported subsidiary net income of $2,987,887 which was a decrease of $1,482,559 (33.2% decrease) from subsidiary net income of $4,470,446 reported in the same period ended 2016. For the three months ended June 30, 2017, the Neal Hot Springs plant reported subsidiary net income of $642,313 which was a decrease of $601,393 (48.4% decrease) from subsidiary net income of $1,243,706 reported in the same period ended 2016.

-34-


Energy sales for the six months ended June 30, 2017, decreased 1.7% (decreased 0.1% for the three months ended June 30, 2017) from the same periods ended 2016. 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. 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 $325,406 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 period ended 2016. In the second quarter of 2017, the annual planned maintenance was completed on Units 1 and 2. The annual maintenance resulted in a total of 393 lost production hours. Also in April and May 2017, Unit 1 experienced a number of forced outages due to the plugging of the feed pump suction strainer on multiple occasions caused by debris in the refrigerant system from the vaporizer failure and other minor mechanical issues that resulted in approximately 352 lost production hours. In the second quarter of 2016, the annual maintenance resulted in approximately 239 lost production hours.

Plant operating expenses, excluding depreciation, increased $1,332,917 (70.1% increase) for the six months ended June 30, 2017 from the same period ended 2016. Plant operating expenses, excluding depreciation, increased $590,887 (60.1% increase) for the three months ended June 30, 2017 from the same period ended 2016. During the current periods, there were notable cost increases in field maintenance, chemicals and taxes.

During the six months ended June 30, 2017, field maintenance costs increased $484,370 ($339,142 increase for the three months ended June 30, 2017) from the same periods ended 2016. For the current six month period, over $573,000 in costs were incurred, after insurance recoveries, needed 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.

During the six months ended June 30, 2017, chemical and lubricant costs increased 377.2% (672.6% increase for the three months ended June 30, 2017) from the same periods ended 2016. Significant repair and refrigerant replacement costs totaling $1.7 million were required in the first quarter of 2017 for Unit 1, of which the refrigerant replacement costs alone exceeded $758,000. Property Loss insurance covered all of those costs except for a $50,000 deductible.

For the six months ended June 30, 2017, the Company incurred property taxes of $704,093. For the first 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.

-35-


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

    Six Months Ended June 30,  
    2017     2016     Variance  
    $     %     $     %     $     %*  
Plant revenues:                                    
       Energy sales   8,659,958     100.0     8,811,326     100.0     (151,368 )   (1.7 )
                                     
Plant expenses:                                    
       General operations   3,233,886     37.3     1,900,969     21.6     (1,332,917 )   (70.1 )
       Depreciation and amortization   1,652,774     19.1     1,638,125     18.6     (14,649 )   (0.9 )
    4,886,660     56.4     3,539,094     40.2     (1,347,599 )   (38.1 )
                                     
                   Gross Profit   3,773,298     43.6     5,272,232     59.8     (1,498,934 )   (28.4 )
                                     
Other income (expense):                                    
       Interest expense   (788,903 )   (9.1 )   (805,688 )   (9.1 )   16,785     2.1  
       Other and interest income   3,492     0.0     3,902     0.0     (410 )   (10.5 )
    (785,411 )   (9.1 )   (801,786 )   (9.1 )   16,375     2.0  
                                     
                   Subsidiary Net Income   2,987,887     34.5     4,470,446     50.7     (1,482,559 )   (33.2 )

  % -

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

    Three Months Ended June 30,  
    2017     2016     Variance  
    $     %     $     %         %*  
Plant revenues:                                    
       Energy sales   3,449,403     100.0     3,445,321     100.0     4,082     0.1  
                                     
Plant expenses:                                    
       General operations   1,574,007     45.6     983,120     28.5     (590,887 )   (60.1 )
       Depreciation and amortization   826,026     23.9     820,063     23.8     (5,963 )   (0.7 )
    2,400,033     69.6     1,803,183     52.3     (596,850 )   (33.1 )
                                     
                   Gross Profit   1,049,370     30.4     1,642,138     47.7     (592,768 )   (36.1 )
                                     
Other income (expense):                                    
       Interest expense   (408,846 )   (11.9 )   (400,372 )   (11.6 )   (8,474 )   (2.1 )
       Other and interest income   1,789     0.1     1,940     0.0     (151 )   (7.8 )
    (407,057 )   (11.8 )   (398,432 )   (11.6 )   (8,625 )   (2.2 )
                                     
                   Subsidiary Net Income   642,313     18.6     1,243,706     36.1     (601,393 )   (48.4 )

  % -

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

-36-


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

     Mega-       Ave. Rate       Depreciation
    watt   Energy   per    Subsidiary   &
     Hours   Sales   Megawatt   Net Income*   Amortization
Quarter Ended:   Produced   ($)   Hour ($)   ($)   ($)
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

 

* -

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

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

For the six months ended June 30, 2017, the San Emidio plant reported subsidiary net income of $667,020 which was an increase of $383,846 (135.6% increase) from $283,174 subsidiary net income reported in the same period ended 2016. For the three months ended June 30, 2017, the San Emidio plant reported subsidiary net income of $241,949 which was an increase of $384,222 (270.1% increase) from $142,273 subsidiary net loss reported in the same period ended 2016.

Energy sales for the six months ended June 30, 2017, increased 8.7% (26.4% increase for the three months ended June 30, 2017) from the same periods ended 2016. For the current three months, the plant produced 17,695 megawatt hours, which was a 25.1% increase from the same period in the prior year. During the current quarter, the plant experienced a planned outage for annual maintenance that resulted in a total 243 lost production hours. In the second quarter of the prior year, the plant lost over 450 hours of production. In addition to 138 hours lost due to the prior year annual maintenance, 312 hours were lost due to a forced outage needed to replace the refrigerant pump and the failure of a vaporizer bypass valve.

Plant operating costs, excluding depreciation, decreased $76,163 for the six months ended June 30, 2017 ($16,910 for the three months ended June 30, 2017), which was a 5.9% decrease (2.7% decreased for the three months ended June 30, 2017) from the same periods ended 2016. The notable decrease in operating expenses was related to taxes and licenses. During the first quarter 2016, the Company was required to pay additional minerals proceeds tax of $70,747 after an examination by the State of Nevada. Similar tax assessments have been significantly less in the current six months.

-37-


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

    Six Months Ended June 30,  
    2017     2016     Variance  
    $     %     $     %     $     %*  
Plant revenues:                                    
       Energy sales   3,494,135     100.0     3,215,516     100.0     278,619     8.7  
                                     
Plant expenses:                                    
       Operations   1,216,957     34.8     1,293,120     40.2     76,163     5.9  
       Depreciation and amortization   640,681     18.3     637,970     19.8     (2,711 )   (0.4 )
    1,857,638     53.2     1,931,090     60.1     73,452     3.8  
                                     
             Gross Profit   1,636,497     46.8     1,284,426     39.9     352,071     27.4  
                                     
Other income (expense):                                    
       Interest expense   (980,102 )   (28.0 )   (1,006,493 )   (31.3 )   26,391     2.6  
       Other income   10,625     0.3     5,241     0.2     5,384     102.7  
    (969,477 )   (27.7 )   (1,001,252 )   (31.1 )   31,775     3.2  
                                     
             Subsidiary Net Income   667,020     19.1     283,174     8.8     383,846     135.6  

  % - 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 are not incorporated into the presentation of the subsidiary’s net operating income/loss.

    Three Months Ended June 30,  
    2017     2016     Variance  
    $     %     $     %     $     %*  
Plant revenues:                                    
       Energy sales   1,662,245     100.0     1,315,049     100.0     347,196     26.4  
                                     
Plant expenses:                                    
       Operations   618,162     37.2     635,072     48.3     16,910     2.7  
       Depreciation and amortization   319,629     19.2     319,756     24.3     127     0.0  
    937,791     56.4     954,828     72.6     17,037     1.8  
                                     
             Gross Profit   724,454     43.6     360,221     27.4     364,233     101.1  
                                     
Other income (expense):                                    
       Interest expense   (490,026 )   (29.5 )   (505,880 )   (38.5 )   15,854     3.1  
       Other income   7,521     0.5     3,386     0.3     4,135     122.1  
    (482,505 )   (29.0 )   (502,494 )   (38.2 )   19,989     4.0  
                                     
             Subsidiary Net Income   241,949     14.6     (142,273 )   (10.8 )   384,222     270.1  

  % - 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 are not incorporated into the presentation of the subsidiary’s net operating income/loss.

-38-


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

     Mega-       Ave. Rate   Subsidiary   Depreciation
    watt   Energy        per   Net Income   &
     Hours   Sales   Megawatt      (Loss)*   Amortization
Quarter Ended:   Produced   ($)   Hour ($)   ($)   ($)
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

  * - 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 Unit I (Raft River Energy I LLC) Plant Operations

For the six months ended June 30, 2017, the Raft River plant reported subsidiary net loss of $106,253 which was a favorable decrease of $374,139 (77.9% decrease) from the $480,392 subsidiary net loss reported in the same period ended 2016. For the three months ended June 30, 2017, the Raft River plant reported subsidiary net loss of $161,494 which was a favorable decrease of $160,401 (49.8% decrease) from the $321,895 subsidiary net loss reported in the same period ended 2016.

Energy sales, for the six months ended June 30, 2017 increased 21.3% (32.9% increase for the three months ended June 30, 2016) from the same periods ended 2016. During the three months ended June 30, 2017, the plant produced 20,680 megawatts, which was a 32.2% increase from the same period ended 2016. In the current quarter, the plant lost a total of 150 hours (138 hours lost in the second quarter of 2016) related to annual maintenance. 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. 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.

Plant operating costs, excluding depreciation, increased $93,932 for the three months ended June 30, 2017 ($2,584 decrease for the six months ended June 30, 2017), which was a 12.0% increase (0.1% decrease for the six months) from the same periods ended 2016. During the current quarter, electricity purchases increased 28.6% (16.1% for the six months) from the same periods in 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. A portion of the increase in electricity purchases related to adding an additional production well pump in March 2017.

-39-


The summarized statements of operations for RREI are as follows:

    Six Months Ended June 30,  
    2017     2016     Variance  
    $     %     $     %     $     %*  
Plant revenues:                                    
       Energy sales   2,394,165     92.3     1,973,904     92.2     420,261     21.3  
       Energy credit sales   199,923     7.7     166,811     7.8     33,112     19.9  
    2,594,088     100.0     2,140,715     100.0     453,373     21.2  
                                     
Plant expenses:                                    
       General operations   1,729,811     66.7     1,732,395     80.9     2,584     0.1  
       Depreciation and amortization   970,889     37.4     889,194     41.6     (81,695 )   (9.2 )
    2,700,700     104.1     2,621,589     122.5     (79,111 )   (3.0 )
                                     
             Gross Loss   (106,612 )   (4.1 )   (480,874 )   (22.5 )   374,262     77.8  
                                     
Other income (expense)   359     0.0     482     0.1     (123 )   (25.5 )
                                     
                   Subsidiary Net Loss   (106,253 )   (4.1 )   (480,392 )   (22.4 )   374,139     77.9  

  % - 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 interest expense, management fees and lease costs are not incorporated into the presentation of the subsidiary’s operations.

    Three Months Ended June 30,  
    2017     2016     Variance  
    $     %     $     %     $     %*  
Plant revenues:                                  
       Energy sales   1,102,160     91.9     829,554     91.8     272,606     32.9  
       Energy credit sales   97,304     8.1     74,357     8.2     22,947     30.9  
    1,199,464     100.0     903,911     100.0     295,553     32.7  
                                     
Plant expenses:                                    
       General operations   875,223     73.0     781,291     86.4     (93,932 )   (12.0 )
       Depreciation and amortization   485,940     40.5     444,608     49.2     (41,332 )   (9.3 )
    1,361,163     113.5     1,225,899     135.6     (135,264 )   (11.0 )
                                     
             Gross Loss   (161,699 )   (13.5 )   (321,988 )   (35.6 )   160,289     49.8  
                                     
Other income (expense)   205     0.0     93     0.0     112     120.4  
                                     
                   Subsidiary Net Loss   (161,494 )   (13.5 )   (321,895 )   (35.6 )   160,401     49.8  

  % - 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 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:

     Mega-       Ave. Rate   Subsidiary   Depreciation
    watt   Energy        per   Net Income   &
     Hours   Sales   Megawatt      (Loss)*   Amortization
Quarter Ended:   Produced   ($)   Hour ($)   ($)   ($)
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   1,292,004   58.9     55,241   484,949
June 30, 2017    20,680   1,102,160   64.6   (161,494)   485,940

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

Professional and Management Fees
For the six months ended June 30, 2017, the Company reported $294,349 in professional and management fees which was a decrease of $917,811 (75.7% decrease) from $1,212,160 reported in the same period ended 2016. For the three months ended June 30, 2017, the Company reported $148,584 in professional and management fees which was a decrease of $7,067 (4.5% decrease) from $155,651 reported in the same period ended 2016. During the current first and second quarters, the Company incurred routine professional services and fees. 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 2016, the consultant’s fees associated with this examination exceeded $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.

Travel and Promotion
For the six months ended June 30, 2017, the Company reported $111,137 in travel and promotional costs which was a decrease of $152,760 (57.9% decrease) from $263,897 reported in the same period ended 2016. For the three months ended June 30, 2017, the Company reported $74,302 in travel and promotional costs which were a decrease of $106,183 (58.8% decrease) from $180,485 reported in the same period ended 2016. During the current quarters, the Company incurred routine travel and promotional costs. In the 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 marketing program that included radio spots and regular news article coverage. The costs of the marketing program for the second quarter of 2016 totaled $117,650.

Interest Expense
For the six months ended June 30, 2017, the Company reported $2,396,328 in interest expense which is an increase of $419,833 (21.2% increase) from $1,976,495 reported in the same period ended 2016. For the three months ended June 30, 2017, the Company reported $1,208,057 in interest expense which is an increase of $165,254 (15.8% increase) from $1,042,803 reported in the same period ended 2016. Interest expense increased due to a new loan agreement/balance. The average total monthly loan balance for the six months ended June 30, 2017 was $107.3 million, which was 8.35% higher than the average total monthly loan balances from the same period in 2016. In May 2016, the Company’s wholly owned subsidiary (Idaho USG Holdings LLC) entered into a loan agreement to finance the Company’s development activities. The original principal totaled $20.0 million. The loan amount bears interest at a fixed rate of 5.8% per annum.

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Net Income Tax Expense
For the six months ended June 30, 2017, the Company reported net income tax expense of $37,000, which was an unfavorable increase of $243,000 (118.0% increase) from the income tax benefit of $206,000 reported in the same period ended 2016. For the three months ended June 30, 2017, the Company reported net income tax benefit of $98,000, which was an unfavorable decrease of $198,000 (66.9% decrease) from the income tax benefit of $296,000 reported in the same period ended 2016. A significant factor in the tax variances were attributed to the lower amounts of non-controlling interest income in the current periods. Lower non-controlling interest income reduces the amount of income tax passed through to those entities. The non-controlling interest variance and the other significant variances that impact income tax expense are discussed in other sections of this document.

Net Income Attributable to the Non-Controlling Interests
The net income attributable to the non-controlling interest entities is the line item that removes the portion of the total consolidated operations that are owned by the Company’s subsidiaries. For the six months ended June 30, 2017, the Company reported $709,281 in net income attributable to non-controlling interests, which was a decrease of $432,172 (37.9% decrease) from $1,141,453 net income reported in the same period ended 2016. For the three months ended June 30, 2017, the Company reported $153,315 in net loss attributable to non-controlling interests, which was a decrease of $258,365 (245.9% decrease) from $105,050 net income reported in the same period ended 2016.

The primary component of the variances were the operating results of USG Oregon LLC (wholly owned by Oregon USG Holdings LLC) which reported a subsidiary net profit for the six months ended June 30, 2017 of $2,987,887, which was a decrease of $1,482,559 (33.2% decrease) from $4,470,446 subsidiary net profit reported in the same period ended 2016. USG Oregon LLC reported a subsidiary net profit for the three months ended June 30, 2017 of $642,313, which was a decrease of $601,393 (48.4% decrease) from $1,243,706 subsidiary net profit reported in the same period ended 2016. The primary conditions for the decreases in USG Oregon LLC’s profits were discussed above.

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

    For the Six Months Ended              
    June 30,              
Subsidiaries and Non-Controlling   2017     2016     Variances  
Interest Entities   $     $     $     %  
Oregon USG Holdings LLC interest held by Enbridge Inc.   1,178,603     1,779,335     (600,732 )   (33.8 )
Raft River Energy I LLC interest held by Goldman Sachs   (463,787 )   (632,389 )   168,602     26.7  
Gerlach Geothermal LLC interest held by Gerlach Green Energy, LLC   (5,535 )   (5,493 )   (42 )   (0.8 )
    709,281     1,141,453     (432,172 )   (37.9 )

% - represents the percentage of change from 2016 to 2017.
# - Variance percentage was extremely high or undefined.

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    For the Three Months Ended              
    June 30,              
Subsidiaries and Non-Controlling   2017     2016     Variances  
Interest Entities     $     $      $     %  
Oregon USG Holdings LLC interest held by Enbridge Inc.   251,434     495,249     (243,815 )   (49.2 )
Raft River Energy I LLC interest held by Goldman Sachs   (402,316 )   (388,571 )   (13,745 )   (3.5 )
Gerlach Geothermal LLC interest held by Gerlach Green Energy, LLC   (2,433 )   (1,628 )   (805 )   (49.4 )
    (153,315 )   105,050     (258,365 )   (245.9 )

% - represents the percentage of change from 2016 to 2017.
# - Variance percentage was extremely high or undefined.

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 six months ended June 30, 2017:

                      Exploration        
    Neal Hot                 Activities and     Consolid-  
Statement of   Springs     San Emidio     Raft River     Corporate     ated  
   Operations Element   $     $     $     $     $  
                               
Gross Profit (Loss)   3,773,298     1,636,497     (106,612 )   369,288     5,672,411  
Expenses/(Income)   826,791     969,477     (360 )   (4)3,311,186     5,107,094  
Net Income(Loss) before tax expense   2,946,507     667,020     (106,252 )   (2,941,958 )   565,317  
Income taxes – USG Portion   (663,000 )   (250,000 )   (134,000 )   1,010,000     (37,000 )
Non-controlling interests   (1)(1,178,603)     -     (2)463,788     (3)5,534     (709,281 )
Net income (loss) attributable to U.S. Geothermal   1,104,904     417,020     223,536     (1,926,424 )   (180,964 )

  (1)

The non-controlling interest for Neal Hot Springs represents a 40% interest for our joint venture partner, Enbridge.

  (2)

The non-controlling interest for Raft River represents 5% of REC income and cash flows, and 99% of all remaining profits and losses allocated to the Goldman Sachs Group.

  (3)

The non-controlling interest for our exploration activities represents an approximately 30.7% interest for our joint venture partner at Gerlach, GGE Development.

  (4)

Major costs included in Exploration Activities and Corporate for the six months ended June 30, 2017 included:

  Employee compensation $ 1,589,304  
  Corporate administration 712,996  
  Professional fees 294,349  

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, the costs associated with a project will be capitalized.

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Selected balance sheet items affected by non-controlling interests as of June 30, 2017 are detailed as follows:

        Non-   U.S.
        Controlling   Geothermal
    Consolidated   Interests   Inc.
Balance Sheet Items   $   $   $
             
Unrestricted cash and cash equivalents   13,452,975   1,171,115   12,281,860
Restricted cash and security bonds:            
         Current   8,848,221   956,418   7,891,803
         Long-term   19,650,455   5,595,595   14,054,860
Notes payable:            
         Current   4,212,109   1,301,001   2,911,108
         Long-term   102,501,240   23,418,009   79,083,231

The loans held by the Company at June 30, 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   58,545,023     212     2/12/35     2.598     60.0     35,127,014  
Prudential Group – USG Nevada LLC   28,867,644     246     12/31/37     6.750     100.0     28,867,644  
Prudential Group – Idaho USG Holdings LLC   19,296,475     69     3/31/23     5.800     100.0     19,296,475  
Chrysler Auto Loan – U.S. Geothermal Services, LLC   4,207     13     7/27/18     6.740     100.0     4,207  
Totals   106,713,349                             83,295,340  
                                     
Weighted Average Term (Months)       195                  
Weighted Average Interest Rate               4.300          

Off Balance Sheet Arrangements

As of June 30, 2017, the Company does not have any off balance sheet arrangements.

Liquidity and Capital Resources

During the quarter ended June 30, 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 $223,295 during the quarter. We believe our cash and liquid investments at June 30, 2017 are adequate to fund our general operating activities through December 31, 2018.

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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.

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 new Purchase Agreement, at the Company’s sole discretion, 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 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. Subsequent to the end of the quarter, 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

Our consolidated financial statements are prepared in accordance with U.S. GAAP. In connection with the preparation of our consolidated financial statements, we are required to make assumptions and estimates about future events and apply judgments that affect the reported amounts of assets, liabilities, revenue, expenses and the related disclosures. We base our assumptions, estimates and judgments on historical experience, current trends and other factors that we believe to be relevant at the time our consolidated financial statements are prepared. On a regular basis, we review the accounting policies, assumptions, estimates and judgments to ensure that our consolidated financial statements are presented fairly and in accordance with U.S. GAAP. However, because future events and their effects cannot be determined with certainty, actual results could differ from our assumptions and estimates, and such differences could be material.

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There have been no significant changes to our critical accounting estimates as discussed in our Annual Report.

Item 3 – Quantitative and Qualitative Disclosures about Market Risk

Interest Risk on Investments
At June 30, 2017, the Company held investments of $34,645,563 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 a PPAs contracts for 20 to 25 year periods. This type of arrangement will be the model for PPAs planned for future power plants.

Item 4 - Controls and Procedures

An evaluation was performed under the supervision and with the participation of our management, including the Interim Chief Executive Officer (“Interim CEO”) and the Chief Financial Officer (“CFO”), of the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) or 15d-15(e) under the Securities Exchange Act of 1934, as amended) as of the end of the period covered by this quarterly report. Based on that evaluation, our management, including the Interim CEO and CFO, concluded that our disclosure controls and procedures were effective at the end of this period covered by this quarterly report to ensure that information we are required to disclose in the reports that we file or submit under the Securities Exchange Act of 1934, is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms relating to us, including our consolidated subsidiaries, and was accumulated and communicated to our management, including our Interim CEO and CFO, as appropriate, to allow timely decisions regarding required disclosure.

There has been no change to our internal control over financial reporting during the six months ended June 30, 2017 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II - OTHER INFORMATION

Item 1 - Legal Proceedings

None.

Item 1A - Risk Factors

None.

Item 2 - Unregistered Sales Of Equity Securities And Use Of Proceeds

None.

Item 3 – Defaults Upon Senior Securities

None.

Item 4 – Mine Safety Disclosures

Not applicable.

Item 5 - Other Information

The information set forth below is included herein for the purpose of providing the disclosure required under “Item 5.02 - Departure of Directors or Certain Officers; Election of Directors; Appointment of Certain Officers; Compensatory Arrangements of Certain Officers” of Form 8-K.

On August 7, 2017, the Company entered into the Second Amendment to Employment Agreement (the “Amendment”) with Douglas J. Glaspey, the Company’s Interim Chief Executive Officer, President and Chief Operating Officer.  The Amendment amends Mr. Glaspey’s employment agreement with the Company, originally effective July 1, 2013 and as further amended as of July 19, 2017. 

The Amendment provides that, if Mr. Glaspey is a “disqualified individual” (as defined in Section 280G(c) of the Internal Revenue Code of 1986, as amended (the “Code”)) and becomes subject to the excise tax under Section 4999 of the Code, including any interest and penalties imposed with respect to such excise tax, then the severance benefits payable to Mr. Glaspey will be reduced such that the excise tax does not apply, unless Mr. Glaspey would be better off on an after-tax basis receiving all such severance benefits.

Item 6 - Exhibits

See the exhibit index to this quarterly report on Form 10-Q.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

  U.S. GEOTHERMAL INC.
  (Registrant)
   
Date: August 10, 2017 By: /s/ Douglas J. Glaspey
  Douglas J. Glaspey
  Interim Chief Executive Officer
   
Date: August 10, 2017  
  By: /s/ Kerry D. Hawkley
  Kerry D. Hawkley
  Chief Financial Officer and Corporate Secretary

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EXHIBIT INDEX

Exhibit
Number
Description
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)

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)

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)

4.1

Form of Stock Certificate (Incorporated by reference to exhibit 4.1 to the registrant’s Form SB-2 registration statement as filed on July 8, 2004)

4.2

Form of Warrant Certificate used in December 2012 registered offering (incorporated by reference to exhibit 4.1 to the Company’s Form 8-K filed on December 21, 2012)

10.1

Employment Agreement dated July 1, 2013with Douglas J. Glaspey (Incorporated by reference to exhibit 10.1 to the registrant’s Form 8-K as filed on July 26, 2013)

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)

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)

10.4

Renewable Energy Credits Purchase and Sales Agreement dated July 29, 2006 between Holy Cross Energy and U.S. Geothermal Inc. (Incorporated by reference to exhibit 10.28 to the registrant’s Form SB-2 as filed on September 29, 2006)

10.5

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)

10.6

Interconnection and Wheeling Agreement dated March 9, 2006 between Raft River Rural Electric Co-op and U.S. Geothermal Inc. (Incorporated by reference to exhibit 10.28 to the registrant’s Form 10-KSB annual report as filed on June 29, 2006)

10.7

Asset Purchase Agreement dated as of March 31, 2008, between U.S. Geothermal Inc., and Empire Geothermal Power LLC and Michael B. Stewart (Incorporated by reference as exhibit 99.1 to the registrant’s Form 8-K current report as filed on April 7, 2008)

10.8

Water Rights Purchase Agreement Michael B. Stewart and U.S. Geothermal Inc. dated March 31, 2008 (Incorporated by reference as exhibit 99.2 to the registrants Form 8-K current report as filed on April 7, 2008).

10.9

Power Purchase Agreement dated as of December 11, 2009, between Idaho Power Company and USG Oregon LLC (Incorporated by reference to Exhibit 10.43 to the Company’s Form 10-Q quarterly report as filed on February 9, 2010)

10.10

Amended and Restated Long-Term Portfolio Energy Credit and Renewable Power Purchase Agreement dated May 31, 2011 between Sierra Pacific Power Company d/b/a NV Energy, and USG Nevada LLC (Incorporated by reference to Exhibit 10.1 to the registrant’s Form 8-K filed on January 4, 2012)

10.11

Amended and Restated Limited Liability Company Agreement made and entered into as of September 7, 2010, by and among Oregon USG Holdings LLC, U.S. Geothermal Inc., and Enbridge (U.S.) Inc. (Incorporated by reference to exhibit 99.4 to the registrant’s Form 8-K as filed on November 8, 2010) *

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10.12

2009 Stock Incentive Plan of the Registrant (Incorporated by reference to Appendix A to the Company’s definitive proxy statement on Schedule 14A as filed on November 6, 2009)

10.13 2009 Stock Incentive Plan Non-Qualified Stock Option Certificate
10.14

Loan Guarantee Agreement dated as of February 23, 2011, among USG Oregon LLC, U.S. Department of Energy, and PNC Bank N.A. (Incorporated by reference to exhibit 99.2 to the registrant’s Form 8-K as filed on August 31, 2011)

10.15

Equity Pledge Agreement dated as of February 23, 2011, among Oregon USG Holdings LLC, USG Oregon LLC, and PNC Bank, N.A. (Incorporated by reference to exhibit 99.3 to the registrant’s Form 8-K as filed on August 31, 2011)

10.16

Note Purchase Agreement dated as of February 23, 2011 among the Federal Financing Bank, USG Oregon LLC, and the Secretary of Energy, acting though the Department of Energy (Incorporated by reference to exhibit 99.2 to the registrant’s Form 8-K as filed on September 15, 2011)

10.17

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)

10.18

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)

10.19

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)

10.20

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)

10.21

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)

10.22

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)

10.23

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)

10.24

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)

10.25

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)

10.26

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)

10.27

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)

10.28

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)

31.1

Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

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

-51-