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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 September 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 [  ]

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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 November 6, 2017
Common stock, par value	19,276,558
$ 0.001 per share

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

INDEX

PART I – Financial Information
Item 1 – Consolidated Financial Statements (Unaudited)
	Consolidated Balance Sheets at September 30, 2017 and December 31, 2016			4
	Consolidated Statements of Operations – Three and Nine Months Ended September 30, 2017 and 2016			5
	Consolidated Statements of Cash Flows – Nine Months Ended September 30, 2017 and 2016			6
	Consolidated Statements of Changes in Stockholders’ Equity – Nine Months Ended September 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				26
	-	General Background and Discussion		27
		•	Projects in Operation	28
		•	Projects Under Development/Exploration	30
	-	Operating Results		35
	-	Off Balance Sheet Arrangements		47
	-	Liquidity and Capital Resources		47
	-	Potential Acquisitions		48
	-	Critical Accounting Policies		48
Item 3 – Quantitative and Qualitative Disclosures about Market Risk				49
Item 4 – Controls and Procedures				49
PART II – Other Information
Item 1 – Legal Proceedings				50
Item 1A – Risk Factors				50
Item 2 – Unregistered Sales of Equity Securities and Use of Proceeds				50
Item 3 – Defaults Upon Senior Securities				50
Item 4 – Mine Safety Disclosures				50
Item 5 – Other Information				50
Item 6 – Exhibits				50

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PART I – FINANCIAL INFORMATION

Item 1 – Consolidated Financial Statements

U.S. GEOTHERMAL INC.
CONSOLIDATED BALANCE SHEETS

		(Unaudited)
		September 30,			December 31,
		2017			2016
ASSETS
Current:
Cash and cash equivalents	$	10,549,769		$	15,287,144
Restricted cash and security bonds		8,428,376			8,527,462
Trade accounts receivable		3,428,901			4,102,018
Other current assets		1,644,412			1,664,866
Total current assets		24,051,458			29,581,490
Restricted cash and security bond reserves		20,607,970			20,111,350
Property, plant and equipment, net		169,602,460			170,301,349
Intangible assets, net		14,947,879			15,084,143
Net deferred income tax asset		8,495,000			8,346,000
Total assets	$	237,704,767		$	243,424,332
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts payable and accrued liabilities	$	2,921,045		$	2,255,710
Current portion of notes payable		4,168,799			4,259,595
Total current liabilities		7,089,844			6,515,305
Long-term Liabilities:
Asset retirement obligations		1,219,903			1,219,903
Notes payable, less current portion		100,104,235			104,131,086
Total long-term liabilities		101,324,138			105,350,989
Total liabilities		108,413,982			111,866,294
Commitments and Contingencies (note 11)
STOCKHOLDERS’ EQUITY
Capital stock (authorized: 250,000,000 common shares with a $0.001 par value; issued and outstanding shares at September 30, 2017 and December 31, 2016 were: 19,274,683 and 18,970,445; respectively)		19,275			18,970
Additional paid-in capital		123,432,266			121,933,378
Accumulated deficit		(18,982,090	)		(16,974,300	)
		104,469,451			104,978,048
Non-controlling interests		24,821,334			26,579,990
Total stockholders’ equity		129,290,785			131,558,038
Total liabilities and stockholders’ equity	$	237,704,767		$	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 Nine Months Ended
		September 30,						September 30,
		2017			2016			2017			2016
Plant Revenues:
Energy sales	$	6,713,995		$	6,654,363		$	21,262,253		$	20,655,109
Energy credit sales		97,893			78,931			297,816			245,741
Total plant operating revenues		6,811,888			6,733,294			21,560,069			20,900,850
Plant Expenses:
Plant production expenses		2,801,431			2,276,969			8,612,857			6,893,103
Depreciation and amortization		1,631,464			1,586,903			4,895,808			4,752,192
Total plant operating expenses		4,432,895			3,863,872			13,508,665			11,645,295
Gross Profit		2,378,993			2,869,422			8,051,404			9,255,555
Operating Expenses (Income):
Corporate administration		274,870			406,513			987,866			1,060,217
Professional and management fees		370,667			168,489			665,016			1,380,649
Employee compensation		1,847,953			699,554			3,437,257			2,381,550
Travel and promotion		48,944			66,590			160,081			330,487
Exploration costs		7,540			3,826			42,175			31,421
Operating Income (Loss)		(170,981	)		1,524,450			2,759,009			4,071,231
Other (income) expense:
Interest expense		1,173,893			1,241,454			3,570,221			3,217,949
Other (income) expense		(24,728	)		104,766			(56,383	)		81,924
Income (Loss) Before Income Tax
Benefit		(1,320,146	)		178,230			(754,829	)		771,358
Income Tax Benefit		186,000			90,000			149,000			296,000
Net Income (Loss)		(1,134,146	)		268,230			(605,829	)		1,067,358
Net income attributable to the non- controlling interests		(692,680	)		(418,728	)		(1,401,961	)		(1,560,181	)
Net Loss Attributable to U.S. Geothermal Inc.	$	(1,826,826	)	$	(150,498	)	$	(2,007,790	)	$	(492,823	)
Net Loss Per Share Attributable to U.S. Geothermal Inc.:
Basic	$	(0.09	)		(0.01	)	$	(0.11	)	$	(0.03	)
Diluted	$	(0.09	)		(0.01	)	$	(0.11	)	$	(0.03	)
Shares used in the calculation of loss per share:
Basic		19,244,467			18,882,166			19,082,502			18,577,269
Diluted		19,244,467			18,882,166			19,082,502			18,577,269

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 Nine Months Ended September 30,
		2017			2016
Operating Activities:
Net Income (Loss)	$	(605,829	)	$	1,067,358
Adjustments to reconcile net income to total cash provided by operating activities:
Depreciation and amortization		5,061,532			4,842,857
Loss on disposal of equipment		-			124,930
Stock based compensation		668,666			865,461
Change in deferred income taxes/benefit		(149,000	)		(296,000	)
Net changes in:
Trade accounts receivable		673,117			1,465,042
Accounts payable and accrued liabilities		643,392			(545,207	)
Prepaid expenses and other		20,454			(4,372	)
Total cash provided by operating activities		6,312,332			7,520,069
Investing Activities:
Purchases of property, plant and equipment		(4,756,490	)		(7,711,706	)
Grant reimbursements on construction		640,026			-
Net funding of restricted cash reserves and bonds		(397,534	)		(6,464,185	)
Total cash used by investing activities		(4,513,998	)		(14,175,891	)
Financing Activities:
Issuance of common stock		830,527			2,484,121
Distributions to non-controlling interest		(3,160,617	)		(4,153,951	)
Proceeds from notes payable, net of issuance costs		-			19,185,986
Principal payments on notes payable and other obligations		(4,205,619	)		(6,451,727	)
Total cash provided (used) by financing activities		(6,535,709	)		11,064,429
Increase (Decrease) in Cash and Cash Equivalents		(4,737,375	)		4,408,607
Cash and Cash Equivalents, Beginning of Year		15,287,144			8,654,375
Cash and Cash Equivalents, End of Year	$	10,549,769		$	13,062,982
Supplemental Disclosures:
Non-cash investing and financing activities:
Accrual for purchases of property and equipment	$	21,943		$	618,494
Other Items:
Interest paid		4,176,742			3,585,942

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

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U.S. GEOTHERMAL INC.
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY - Unaudited
For the Nine Months Ended September 30, 2017 and Year Ended December 31, 2016

														Non-
		Number of			Common			Additional Paid-			Accumulated			controlling
		Shares			Shares			In 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			410			1,188,224			-			-			1,188,634
Stock issued by the exercise of employee stock options		342,082			342			882,961			-			-			883,303
Stock issued by the exercise of broker and stock purchase warrants		209,240			209			587,806									588,015
Stock compensation		74,918			76			1,053,706			-			-			1,053,782
Net income		-			-			-			463,331			3,122,017			3,585,348
Balance at December 31, 2016		18,970,445			18,970			121,933,378			(16,974,300	)		26,579,990			131,558,038
Distributions to non-controlling interest entities		-			-			-			-			(3,160,617	)		(3,160,617	)
Stock issued by the exercise of employee stock options		93,580			93			195,295			-			-			195,388
Stock issued by the exercise of stock purchase warrants		211,713			212			634,927			-			-			635,139
Stock compensation		(1,055	)		-			668,666			-			-			668,666
Net income (loss)		-			-			-			(2,007,790	)		1,401,961			(605,829	)
Balance at September 30, 2017		19,274,683		$	19,275		$	123,432,266		$	(18,982,090	)	$	24,821,334		$	129,290,785

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
September 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 September 30, 2017 and our operating results and cash flows for the nine months ended September 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

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xxi)

Idaho USG Holdings LLC (organized in the State of Delaware).

All intercompany transactions are eliminated upon consolidation.

In cases where the Company owns a majority interest in an entity but does not own 100% of the interest in the entity, it recognizes a non-controlling interest attributed to the interest controlled by outside third parties. The Company will recognize 100% of the assets and liabilities of the entity, and disclose the non-controlling interest. The consolidated statements of 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 September 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 September 30, 2017, the Company’s total cash balance, excluding money market funds, was $6,253,682 and bank deposits amounted to $6,881,620. The primary difference was due to outstanding checks and deposits. Of the bank deposits, $5,588,765 was not covered by or was in excess of FDIC insurance guaranteed limits. At September 30, 2017, the Company’s money market funds invested, primarily, in government backed securities totaled $31,859,835 and were not subject to deposit insurance. A contracted power purchaser held a security bond for the Company that totaled $1,468,898 at September 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.

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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:

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.

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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.

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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 has elected the modified retrospective method of adoption. Management does not expect a material impact on the consolidated statements of operations as a result of adopting these Updates.

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 in the first quarter of 2017 with minimal impact on the financial presentation of the Company’s consolidated financial statements.

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NOTE 3 – RESTRICTED CASH AND BOND RESERVES

Under the terms of the loan agreements with the U.S. Department of Energy and Prudential Capital Group, various bond and cash reserves are required to provide assurances that the power plants will have the necessary funds to maintain expected operations and meet loan payment obligations. Restricted cash balances and bond reserves are summarized as follows:

Current restricted cash and bond reserves:

		September 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		186			284,621
Prudential Capital Group, Debt Service Reserves (USG Nevada LLC)		1,520,874			1,600,597
Bureau of Land Management , Geothermal Rights Lease Bond		10,000			10,000
U.S. Department of Energy, Debt Service Reserve		793,085			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)		1,483,272			-
CAISO, Transmission Interconnection Escrow Deposits		1,895,183			1,895,023
	$	8,428,376		$	8,527,462

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Long-term restricted cash and bond reserves:

		September 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)		1,102,140			1,081,744
Prudential Capital Group, Well Reserves (USG Nevada LLC)		1,273,093			951,486
Prudential Capital Group, Maintenance Reserves (Idaho USG Holdings LLC)		1,882,470			1,807,890
Prudential Capital Group, Capital Expenditure Reserves (Raft River Energy I LLC)		3,796			3,796
U.S. Department of Energy, Operations Reserves		270,000			270,000
U.S. Department of Energy, Debt Service Reserves		2,379,263			2,413,951
U.S. Department of Energy, Short Term Well Field Reserves		4,509,923			4,508,650
U.S. Department of Energy, Long-Term Well Field Reserves		5,389,155			5,175,777
U.S. Department of Energy, Capital Expenditure Reserves		2,329,232			2,429,158
	$	20,607,970		$	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 September 30, 2017 and December 31, 2016.

NOTE 4 – TRADE RECEIVABLES/INSURANCE PROCEEDS

The Company’s receivables are summarized as follows:

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 was $693,953. At September 30, 2017, the total submitted claims that are expected to be recovered after deductibles were $897,150. The Company estimates that the full amount of the property loss expenses, less the $50,000 deductible, will be collected. The Company received partial reimbursement of repair costs in April 2017 and August 2017 that totaled $1,050,000 and $520,000; respectively. For the nine months ended September 30, 2017, insurance recovery amounts of $1,739,915 for plant production expenses and $727,235 for energy sales were accrued. On October 1, 2017, the Company collected insurance proceeds of $897,150. The overall calculated loss from the mechanical failure totaled $3,211,103 and the loss covered by insurance totaled $2,467,150.

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NOTE 5 - PROPERTY, PLANT AND EQUIPMENT

During the three months ended September 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 $958,000 in the current quarter. Costs during the quarter that totaled $271,836 were capitalized at WGP Geysers for plant engineering and design. At Neal Hot Spring, Oregon, additional costs were incurred for the new cooling water well and a plant programming upgrade that totaled approximately $351,000.

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 $492,800 in the second quarter. Grant proceeds totaling $292,730 ($640,026 for the nine months ended June 30, 2017) offset the majority of the total costs of the seismic studies. Costs during the second 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 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 first quarter. Grant proceeds totaling $444,026 offset the majority of the total costs of the studies. Costs during the first 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:

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

Changes in construction in progress are summarized as follows:

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

NOTE 6 – ACCOUNTS PAYABLE/ACCRUED LIABILITIES

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

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

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NOTE 7 – INCOME TAXES

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

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 nine months ended September 30, 2017, reflects a reported effective tax rate of 19.7%, 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 8 – 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 September 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 $654,901 ($821,070, less amortized costs of $166,169).

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 September 30, 2017 totaled $56,918,773 (current portion $3,252,501).

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

* - 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 September 30, 2017, the balance of the loan was $28,709,646 (current portion $520,301).

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 September 30, 2017, the loan balance totaled $3,042 (current portion $3,042).

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

NOTE 9 - 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 September 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 nine months ended September 30, 2017:

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.

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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 September 30, 2017, 34,998 stock options exercisable at prices between $1.86 and $2.76 were exercised by directors, employees and former employees. 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 September 30, 2017, 7,499 options were forfeited due to termination of employment. 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 September 30, 2017, there was $297,957 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 September 30, 2017, the outstanding share purchase warrants totaled 173,426 (385,139 warrants at December 31, 2016) with a warrant exercise price of $3.00 per warrant and expire December 26, 2017.

On July 6, 2017, broker warrants that totaled 50,000 were exercised by an investor at the warrant exercise price of $3.00. On July 14, 2017, broker warrants that totaled 66,667 were exercised by an investor at the warrant exercise price of $3.00.

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 10 – 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.

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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 September 30, 2017:

		Total			Level 1			Level 2			Level 3
Assets:
Money market accounts *	$	31,859,835		$	31,859,835		$	-		$	-

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 11 - COMMITMENTS AND CONTINGENCIES

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

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:

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NOTE 12 – JOINT VENTURES/NON-CONTROLLING INTERESTS

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

		September 30,			December 31,
		2017			2016
Gerlach Geothermal LLC interest held by Gerlach Green Energy, LLC	$	201,665		$	207,217
Oregon USG Holdings LLC interest held by Enbridge Inc.		24,218,250			25,361,410
Raft River Energy I LLC interest held by Goldman Sachs		401,419			1,011,363
	$	24,821,334		$	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 September 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 September 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 statements of operations with the elimination of the non-controlling interest identified.

Oregon USG Holdings LLC
In September 2010, the Company’s subsidiary, Oregon USG Holdings LLC (“Oregon Holdings”), signed an Operating Agreement with Enbridge Inc. (“Enbridge”) for the right to participate in the Company’s Neal Hot Springs project located in Malheur County, Oregon. On February 20, 2014, a new determination under the existing agreement was reached with Enbridge that established their ownership interest percentage at 40% and the Company’s at 60%, effective January 1, 2013. Oregon Holdings has a 100% ownership interest in USG Oregon LLC. Enbridge has contributed a total of $32,801,000, including the debt conversion, to Oregon Holdings in exchange for a direct ownership interest. During the nine months ended September 30, 2017 and the year ended December 31, 2016, distributions were made to the Company that totaled $4,702,100 and $6,107,217; respectively. During the nine months ended September 30, 2017 and the year ended December 31, 2016, distributions were made to Enbridge that totaled $3,134,734 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 operations 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 nine months ended September 30, 2017, RREI distributed funds to the Company and Goldman Sachs of $879,864 and $25,884; 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 nine months ended September 30, 2017 and the year ended December 31, 2016, the Company made contributions of $1,053,680 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 nine months ended September 30, 2017, a new production well that was contributed to the project by the Company produced incremental net profits of $440,221.

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 statements of operations with the elimination of the non-controlling interest identified.

NOTE 13 – 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 September 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 September 30, 2017 and December 31, 2016 totaled $1,219,903. All of the obligations were considered to be long-term at September 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 September 30, 2017 and December 31, 2016, no retirement obligations have been recognized.

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NOTE 14 – 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:
September 30, 2017	$	178,886,815		$	58,817,952		$	237,704,767
December 31, 2016		188,682,162			54,742,170			243,424,332
For the Nine Months Ended September 30, 2017:
Operating Revenues	$	21,560,069		$	-		$	21,560,069
Net Income (Loss)		4,890,859			(5,496,688	)		(605,829	)
2016:
Operating Revenues		20,900,850			-			20,900,850
Net Income (Loss)		5,917,713			(4,850,355	)		1,067,358
For the Three Months Ended September 30, 2017:
Operating Revenues	$	6,811,888		$	-		$	6,811,888
Net Income (Loss)		1,342,204			(2,476,350	)		(1,134,146	)
2016:
Operating Revenues		6,733,294			-			6,733,294
Net Income (Loss)		1,644,485			(1,376,255	)		268,230

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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;
	•	the continued availability of tax incentive programs for development of geothermal projects;
	•	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;

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	•	the enforceability of the power purchase agreements for our projects;
	•	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, including tax incentive programs for the development of geothermal projects;
	•	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 nine months ended September 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 September 30, 2017, the Company was focused on:

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

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

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

Generation

Ownership

(Ave. Net

PPA Limit

Power

Contract

Project

Location

%

MWs)(3)

(megawatts)

Purchaser

Expiration

Neal Hot Springs

Oregon

60(1)

21.2

25.0

Idaho Power

2036

San Emidio (Unit I)

Nevada

100

8.4

9.9(4)

NV Energy

2038

Raft River (Unit I)

Idaho

95(2)

9.4

13.0

Idaho Power

2032

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

Facility Generation
Generation from all facilities totaled 228,415 megawatt hours for the first nine months of 2017. For the same period in 2016, the total generation was 228,722 megawatt hours. For the third quarter of 2017, generation from all facilities totaled 62,701 megawatt hours compared to 66,055 megawatt hours during the same period in 2016.

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

For the third quarter of 2017, generation was 30,800 megawatt-hours with an average of 14.1 net megawatts per hour of operation and plant availability was 99.1% . For the same period in 2016, the plant generated 29,758 megawatt-hours with an average of 13.5 net megawatts per hour and plant availability was 99.5% excluding scheduled maintenance.

A final payment of $897,150 was received on October 1, 2017 from the insurance company for the property damage and business interruption (lost generation revenue) incurred for the damage sustained on Unit 1 in January.

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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 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 third quarter of 2017, generation was 11,299 megawatt-hours with an average of 8.6 net megawatts per hour of operation and plant availability was 59.2% . For the same period in 2016, the plant generated 19,675 megawatt-hours with an average of 9.0 net megawatts per hour and plant availability was 99.2% .

On July 21, 2017, refrigerant leaks were identified in a number of vaporizer tubes, and the facility was shut down. Repairs were completed on August 18, 2017, and the plant restarted after being down for 29 days. After the repairs, the plant is operating at budgeted generation levels. The damaged tubes will be replaced during the spring 2018 scheduled maintenance outage.

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 10 megawatts annual average. The PPA has a 25-year term with an annual escalation rate of 1 percent. The annual average price paid under the PPA for 2017 is $93.94 per megawatt-hour.

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 third quarter of 2017, generation was 20,602 megawatt-hours with an average of 9.3 net megawatts per hour of operation and plant availability was 100%. For the same period in 2016, the plant generated 16,622 megawatt-hours with an average of 7.5 net megawatt hours and plant availability was 100%.

The increased generation during the third quarter of 2017 is due to the addition of production well RRG-5, which commenced operation in late March 2017 at 1,000 gpm. The flow rate from RRG-5 was increased to 1,400 gpm after installation of a new, upgraded injection pump. The new injection pump was installed on August 25, 2017, and allows the plant to inject over 6,000 gpm into the injection field. These improvements have increased the annual average generation of the plant by 1.6 net megawatts. Further improvements to the plant and wellfield are being analyzed and will be considered in the future.

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

The PPA for the project was signed on September 24, 2007 with the Idaho Power Company and allows for the sale of up to 13 megawatts of electricity on an annual average basis. The PPA has a 25 year term with a starting average price for the year 2007 of $52.50 that escalates at 2.1% per year through 2020 and then at 0.6% per year until the end of the contract in 2034. The Idaho Power PPA has a seasonal pricing structure that pays 120% of the average price for four months (July, August, November, December), 100% of the average price for five months (January, February, June, September, October) and 73.5% of the average price for three months (March, April, May). The annual average price paid under the PPA for 2017 is $64.63 per megawatt-hour.

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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 January 2018, a new, 10 year REC contract with the Public Utility District No. 1 of Clallam County, Washington will replace the current contract. This REC contract only includes the sale of the RECs owned by the Raft River project. Under the terms of our PPA, starting in 2018, 49% of the RECs produced will be owned by the Raft River Project, and the Idaho Power Company will own the remaining 51%.

Projects Under Development and Exploration

Development Projects

Target

Projected

Estimated

Development

Commercial

Capital Required

Power

Project

Ownership

(Megawatts)

Operation Date

($million)

Purchaser

Neal Hot Springs - upgrade

60%

1-2

4th Quarter 2018

5

Idaho Power

San Emidio I - upgrade

100%

1-2

3rd Quarter 2018

4

NV Energy

Raft River – upgrade

100%

0.5

3rd Quarter 2018

1

Idaho Power

WGP Geysers

100%

30

4th Quarter 2019*

148

TBD

San Emidio Phase II

100%

25-35

4th Quarter 2020*

126-168

TBD

El Ceibillo Phase I

100%

25

TBD

140

TBD

Crescent Valley Phase I

100%

25

TBD

130

TBD

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

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

* - Target development sizes are predevelopment estimates of unproven resources. The estimates are based             on third-party, Monte Carlo heat-in-place calculations or our internal evaluation of available information             regarding resource temperature, and flow data from wells, where available.

Neal Hot Springs – Upgrade Project
The engineering is continuing to complete the design for a hybrid cooling system that will add water cooling to the existing air cooled system now in place. Water cooling will increase the efficiency of the plant during the summer period when generation is suppressed by high ambient temperatures. There are approximately 3.9 megawatts of annual average generation that are available under the terms of the PPA.

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Each megawatt of increased generation is worth approximately $990,000 at the 2019 contract price of $116.45.

Construction of the first phase of the hybrid cooling system is planned for 2018. Testing of cooling water well #1 showed that while it produced over 100 gpm of water, it is connected to surface water and is not useable under Oregon law. A combined water supply system will be used that utilizes both fresh water and treated geothermal water to provide the 250 gpm of water for the cooling tower. An idle well, NHS-12, is also being evaluated to provide additional cooling water to the system.

San Emidio I, Nevada – Upgrade Project
At our operating San Emidio I project, we are evaluating an enhancement program to increase generation from the power plant. There are approximately 1.5 megawatts annual average that remains available under the terms of the PPA at full price, and several more megawatts that could be sold at the excess energy price. One megawatt at full contract price is worth approximately $800,000 in additional annual revenue and each megawatt of excess energy generated above 10 megawatts, but below 14.7 megawatts is worth approximately $425,000.

A permit has been filed with the Bureau of Land Management (BLM) in order to drill a full-sized twin of observation well 25-21 in the Southwest Zone. The new production well would be connected to the Phase I plant and provide 1,200 to 1,500 gpm of 320°F fluid. Developing production from the Southwest Zone in 2018 would provide a long-term flow test of the Southwest Zone that will be critical to understand its full development potential and would result in an increase in revenue.

Raft River, Idaho – Upgrade Project
The addition of production well RRG-5 increased the average generation from the Raft River plant by 1.6 net megawatts in 2017. Due to the positive response from the wellfield, which showed a minimal decrease in fluid levels, a study to increase the capacity of production pump RRG-4 in 2018 is being analyzed. The upgrade project would consist of increasing the capacity of the pump to produce approximately 400-500 gpm more fluid to the plant.

This upgrade would result in an estimated generation increase of approximately 0.5 net megawatts annual average. In 2019, the first full year of production, the energy plus renewable energy credit value will be $75.71 per megawatt hour, resulting in approximately $630,000 of additional revenue. Approximately half of this revenue would be realized in 2018.

WGP Geysers, California – Development Project
The WGP Geysers project is located in the broader Geysers geothermal field located approximately 75 miles north of San Francisco, California. The broader Geysers geothermal field is the largest producing geothermal field in the world generating more than 850 megawatts of power for more than 30 years. Acquisition of the WGP Geysers Project from Ram Power was completed on April 22, 2014 for $6.4 million. We expect that approximately 75% of the development may be funded by non-recourse project debt, with the remainder funded through equity financing. 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 28.8 net megawatt power plant is continuing. Our engineers and consultants are working in concert with our EPC contractors to examine all aspects of the construction cycle with a focus on reducing construction costs. The hybrid cooling design will dramatically increase the volume of water available for injection back into the reservoir, which will result in increased power generation over the life of the project. Traditional water cooled geothermal steam plants re-inject approximately 20 to 25% of the water that is extracted from the steam, while our current hybrid design may re-inject approximately 80% more of the water. This higher injection rate will provide long term, stable steam production, and will result in increased power generation over the life of the project.

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

We received the signed LGIA 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. A previous LGIA was issued for the WGP Geysers project in 2009 (now terminated), which utilized a “ring bus” type substation that was located on the plant site. The additional cost associated with this substation configuration is currently included in the estimated capital cost for the project.

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

We continue to submit proposals when Request for Offers are released by organizations seeking renewable energy and have continued bilateral discussions with several potential purchasers. To date, the WGP Geysers project has not been selected to negotiate a PPA. Bilateral discussions are being held with several potential California based power purchasers for the generation from the WGP Geysers plant. 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.

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 believe the project qualifies for the 30% Federal Investment Tax Credit (or Production Tax Credit), which when monetized, can meet most of the equity financing requirements.

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

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

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

An application for a LGIA was filed with NV Energy on June 26, 2017. The LGIA would provide for the interconnection of 45 megawatts of generation capacity. Permitting for the transmission line, which is approximately 57 miles long, may extend the time required to interconnect the project and could impact the currently projected commercial operation date. The LGIA was accepted as complete by NV Energy and entered the first step in the FERC mandated evaluation process on October 1, 2017. Under the structure of the interconnection process, the first phase study is scheduled to be completed in early January 2018.

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. A second phase of data collection was required to fill in and replace a limited number of MT stations at San Emidio, and was completed in the third quarter.

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

El Ceibillo, Republic of Guatemala
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.

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

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

Expenditures at El Ceibillo are being carefully controlled until we see evidence that the energy market is advancing in Guatemala. On January 10, 2017, the Guatemalan government, through the National Electrical Energy Commission (COMISIÓN NACIONAL DE ENERG¥A ELÉCTRICA–“CNEE”), announced that it is preparing to issue a Request For Proposal (“RFP”) later this year for 420 megawatts of power, of which 40 megawatts is to be reserved specifically for geothermal energy. There is still no indication of when that RFP may be issued. When the RFP is issued, we expect 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 1,450 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.

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

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

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

The SubTER program, approved under the DOE grant awarded in July 2016, includes using new subsurface technologies at both San Emidio and Crescent Valley to identify fluid flow paths in the geothermal resource. The passive seismic data collection phase of the program was completed at Crescent Valley in December of 2016. A magnetotelluric (MT) survey was completed during the third quarter. 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.

Operating Results

For the nine months ended September 30, 2017, the Company reported net loss attributable to the Company of $2,007,790 ($0.11 loss per share) which represented an unfavorable increase of $1,514,967 (307.4% increase) from net loss attributable to the Company of $492,823 ($0.03 loss per share) reported in the same period ended 2016. For the three months ended September 30, 2017, the Company reported net loss attributable to the Company of $1,826,826 ($0.09 loss per share) which represented an unfavorable increase of $1,676,328 (1,113.9% increase) from net loss attributable to the Company of $150,498 ($0.01 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, promotion expenses and income tax expense/benefit. An unfavorable variance was noted for employee compensation.

Plant Operations

A summary of energy sales by plant is as follows:

% - represents the percentage of total Company energy sales.

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% - represents the percentage of total Company energy sales.

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

		For the Quarter Ended,
		September 30,			December 31,			March 31,			June 30,			September 30,
		2016			2016			2017			2017			2017
Neal Hot Springs, Oregon		29,758			57,036			48,178			37,727			30,800
San Emidio, Nevada		19,675			20,803			19,501			17,695			11,299
Raft River, Idaho		16,622			20,039			21,934			20,679			20,602
		66,055			97,878			89,613			76,101			62,701

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

For the nine months ended September 30, 2017, the Neal Hot Springs plant reported subsidiary net income of $5,020,316 which was a decrease of $729,657 (12.7% decrease) from subsidiary net income of $5,749,973 reported in the same period ended 2016. For the three months ended September 30, 2017, the Neal Hot Springs plant reported subsidiary net income of $2,032,429 which was an increase of $752,902 (58.8% increase) from subsidiary net income of $1,279,527 reported in the same period ended 2016.

Energy sales for the nine months ended September 30, 2017 increased 2.7% (increased 13.4% for the three months ended September 30, 2017) from the same periods ended 2016. In the current quarter, the plant produced 30,800 net megawatts which was an increase of 3.5% from the same quarter ended 2016. In the third quarter of 2016, annual maintenance for Unit 3 resulted in 252 lost production hours. Few production hours (70 hours for all three units) were lost in the third quarter of 2017. For the nine months ended September 30, 2017, energy production was down 4.8% from the same period 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 $727,235 of revenue to cover lost energy sales after the first 30 days of lost generation. Without the insurance coverage, energy sales for the first quarter would have decreased 9.0% from the same 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 and other minor mechanical issues that resulted in approximately 352 lost production hours.

Plant operating expenses, excluding depreciation, increased $1,084,043 (35.5% increase) for the nine months ended September 30, 2017 from the same period ended 2016. Plant operating expenses, excluding depreciation, decreased $248,875 (21.6% decrease) for the three months ended September 30, 2017 from the same period ended 2016. During the current periods, there were notable cost increases in field maintenance, chemicals and taxes.

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During the nine months ended September 30, 2017, field maintenance costs increased $264,669 ($219,701 decrease for the three months ended September 30, 2017) from the same periods ended 2016. For the current nine month period, over $661,000 in field maintenance costs were incurred to repair vaporizers, turbines and brine injection systems. Most of the repair costs were needed for Unit 1. Turbine repairs were incurred for both Units 1 and 2.

During the nine months ended September 30, 2017, chemical and lubricant costs increased $234,861 ($1,733 for the three months ended September 30, 2017) which was a 238.0% increase (4.7% increase for the three months ended September 30, 2017) from the same periods ended 2016. For the current nine months, purchases were made for additional refrigerant and scale inhibitor fluids of approximately $121,000 and $77,000; respectively.

For the nine months ended September 30, 2017, the Company incurred property taxes of $704,093. For the first three years of operations, property taxes were abated by the County. The abatement period ended in 2016 and the first property tax payment was made in December 2016.

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

		Nine Months Ended September 30,
		2017						2016						Variance
		$			%			$			%			$			%*
Plant revenues:
Energy sales		12,801,243			100.0			12,462,399			100.0			338,844			2.7
Plant expenses:
General operations		4,139,038			32.3			3,054,995			24.5			(1,084,043	)		(35.5	)
Depreciation and amortization		2,480,770			19.4			2,458,672			19.7			(22,098	)		(0.9	)
		6,619,808			51.7			5,513,667			44.2			(1,106,141	)		(20.1	)
Gross Profit		6,181,435			48.3			6,948,732			55.8			(767,297	)		(11.0	)
Other income (expense):
Interest expense		(1,166,469	)		(9.1	)		(1,204,256	)		(9.7	)		37,787			3.1
Other and interest income		5,350			0.0			5,497			0.0			(147	)		(2.7	)
		(1,161,119	)		(9.1	)		(1,198,759	)		(9.7	)		37,640			3.1
Subsidiary Net Income		5,020,316			39.2			5,749,973			46.1			(729,657	)		(12.7	)

% - 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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		Three Months Ended September 30,
		2017						2016						Variance
		$			%			$			%			$			%*
Plant revenues:
Energy sales		4,141,284			100.0			3,651,073			100.0			490,211			13.4
Plant expenses:
General operations		905,151			21.9			1,154,026			31.6			248,875			21.6
Depreciation and amortization		827,996			20.0			820,546			22.5			(7,450	)		(0.9	)
		1,733,147			41.9			1,974,572			54.1			241,425			12.2
Gross Profit		2,408,137			58.1			1,676,501			45.9			731,636			43.6
Other income (expense):
Interest expense		(377,566	)		(9.0	)		(398,569	)		(10.9	)		21,003			5.3
Other and interest income		1,858			0.0			1,595			0.0			263			16.5
		(375,708	)		(9.0	)		(396,974	)		(10.9	)		21,266			5.4
Subsidiary Net Income		2,032,429			49.1			1,279,527			35.0			752,902			58.8

% - 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.

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			($)			Hour ($)			($)			($)
September 30, 2015		33,498			4,004,715			119.3			1,651,029			819,450
December 31, 2015		52,642			6,423,643			122.0			4,311,789			819,171
March 31, 2016		53,671			5,366,004			100.0			3,226,740			818,062
June 30, 2016		39,094			3,445,321			88.2			1,243,706			820,063
September 30, 2016		29,758			3,651,073			122.4			1,279,527			820,546
December 31, 2016		57,036			7,099,320			124.5			4,471,869			823,116
March 31, 2017		48,178			5,210,556			101.4			2,345,574			826,748
June 30, 2017		37,727			3,449,403			91.4			642,313			826,026
September 30, 2017		30,800			4,141,284			125.1			2,032,429			827,996

* - 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 nine months ended September 30, 2017, the San Emidio plant reported subsidiary net loss of $228,981 which was a decrease of $896,173 (134.3% decrease) from $667,192 subsidiary net income reported in the same period ended 2016. For the three months ended September 30, 2017, the San Emidio plant reported subsidiary net loss of $896,001 which was a decrease of $1,280,019 (333.3% decrease) from $384,018 subsidiary net income reported in the same period ended 2016.

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Energy sales for the nine months ended September 30, 2017, decreased 9.7% (42.0% decrease for the three months ended September 30, 2017) from the same periods ended 2016. For the current three months, the plant produced 11,299 megawatt hours, which was a 42.6% decrease from the same period in the prior year. The plant experienced several outages in the current quarter that resulted in a total of 903 lost production hours. The largest outages were needed to repair the leaks in the vaporizer tubes (637 lost hours). Other outages were caused by line capacitor fault failures, refrigerant feed pump repairs and transmission pole fires. During the second quarter 2017, 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, increased $455,437 for the nine months ended September 30, 2017 ($531,600 increase for the three months ended September 30, 2017), which was a 23.7% increase (84.3% increase for the three months ended September 30, 2017) from the same periods ended 2016. The notable increase in operating expenses was primarily related to field maintenance costs. In the current quarter, the plant incurred field maintenance costs of $476,275, which was a 327.2% increase in field maintenance costs from the same quarter in the prior year. As noted above, the plant experienced issues with the vaporizer tubes and refrigerant feed systems during the current quarter. The repair and replacement costs needed to alleviate these issues exceeded $509,000.

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

		Nine Months Ended September 30,
		2017						2016						Variance
		$			%			$			%			$			%*
Plant revenues:
Energy sales		4,555,594			100.0			5,045,512			100.0			(489,918	)		(9.7	)
Plant expenses:
Operations		2,378,819			52.2			1,923,382			38.1			(455,437	)		(23.7	)
Depreciation and amortization		957,620			21.0			959,448			19.0			1,828			0.2
		3,336,439			73.2			2,882,830			57.1			(453,609	)		(15.7	)
Gross Profit		1,219,155			26.8			2,162,682			42.9			(943,527	)		(43.6	)
Other income (expense):
Interest expense		(1,467,243	)		(32.2	)		(1,504,587	)		(29.9	)		37,344			2.5
Other income		19,107			0.4			9,097			0.2			10,010			110.0
		(1,448,136	)		(31.8	)		(1,495,490	)		(29.7	)		47,354			3.2
Subsidiary Net Income (Loss)		(228,981	)		(5.0	)		667,192			13.2			(896,173	)		(134.3	)

% - 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.

-39-

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		Three Months Ended September 30,
		2017						2016						Variance
		$			%			$			%			$			%*
Plant revenues:
Energy sales		1,061,459			100.0			1,829,996			100.0			(768,537	)		(42.0	)
Plant expenses:
Operations		1,161,861			109.4			630,261			34.4			(531,600	)		(84.3	)
Depreciation and amortization		316,940			29.9			321,479			17.6			4,539			1.4
		1,478,801			139.3			951,740			52.0			(527,061	)		(55.4	)
Gross Profit (Loss)		(417,342	)		(39.3	)		878,256			48.0			(1,295,598	)		(147.5	)
Other income (expense):
Interest expense		(487,141	)		(45.9	)		(498,094	)		(27.2	)		10,953			2.2
Other income		8,482			0.8			3,856			0.2			4,626			120.0
		(478,659	)		(45.1	)		(494,238	)		(27.0	)		15,579			3.2
Subsidiary Net Income (Loss)		(896,001	)		(84.4	)		384,018			21.0			(1,280,019	)		(333.3	)

% - 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.

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			($)			Hour ($)			($)			($)
September 30, 2015		18,924			1,742,750			92.1			386,033			314,940
December 31, 2015		20,369			1,875,755			92.1			278,453			316,269
March 31, 2016		20,433			1,900,467			93.0			425,447			318,214
June 30, 2016		14,139			1,315,049			93.0			(142,273	)		319,756
September 30, 2016		19,675			1,829,996			93.0			384,018			321,479
December 31, 2016		20,803			1,934,846			93.0			375,074			321,222
March 31, 2017		19,501			1,831,890			93.9			425,071			321,051
June 30, 2017		17,695			1,662,245			93.9			241,949			319,629
September 30, 2017		11,299			1,061,459			93.9			(896,001	)		316,940

* - 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 nine months ended September 30, 2017, the Raft River plant reported subsidiary net income of $99,524 which was an increase of $598,978 (119.9% increase) from the $499,452 subsidiary net loss reported in the same period ended 2016. For the three months ended September 30, 2017, the Raft River plant reported subsidiary net income of $205,776 which was an increase of $224,836 from the $19,060 subsidiary net loss reported in the same period ended 2016.

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Energy sales for the nine months ended September 30, 2017 increased 24.1% (28.8% increase for the three months ended September 30, 2016) from the same periods ended 2016. During the three months ended September 30, 2017, the plant produced 20,602 megawatts, which was a 24.0% increase from the same period ended 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. The plant experienced less than an hour of lost production in the current quarter and the same quarter of 2016. In the second quarter of 2017, 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.

Plant operating costs, excluding depreciation, increased $212,986 for the nine months ended September 30, 2017 ($215,570 increase for the three months ended September 30, 2017), which was an 8.8% increase (30.7% increase for the three months) from the same periods ended 2016. During the current nine months, electricity purchases increased 21.2% (30.8% increase for the three months) from the same period 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 majority of the increase in electricity purchases is related to adding an additional production well pump in March 2017.

Depreciation expense increased $123,346 for the nine months ended September 30, 2017 ($41,652 increase for the three months ended September 30, 2017) from the same periods ended 2016. In October 2016, the well RRG-2 that cost approximately $3.8 million was placed into operation. The depreciation costs of this well are approximately $10,630 per month ($31,890 per quarter).

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The summarized statements of operations for RREI are as follows:

		Nine Months Ended September 30,
		2017						2016						Variance
		$			%			$			%			$			%*
Plant revenues:
Energy sales		3,905,416			92.9			3,147,199			92.8			758,217			24.1
Energy credit sales		297,816			7.1			245,741			7.2			52,075			21.2
		4,203,232			100.0			3,392,940			100.0			810,292			23.9
Plant expenses:
General operations		2,646,883			63.0			2,433,897			71.7			(212,986	)		(8.8	)
Depreciation and amortization		1,457,418			34.6			1,334,072			39.3			(123,346	)		(9.2	)
		4,104,301			97.6			3,767,969			111.0			(336,332	)		(8.9	)
Gross Profit (Loss)		98,931			2.4			(375,029	)		(11.0	)		473,960			126.4
Other income (expense)		593			0.0			(124,423	)		(3.7	)		125,016			100.5
Subsidiary Net Income (Loss)		99,524			2.4			(499,452	)		(14.7	)		598,976			119.9

% - 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 September 30,
		2017						2016						Variance
		$			%			$			%			$			%*
Plant revenues:
Energy sales		1,511,251			93.9			1,173,294			93.7			337,957			28.8
Energy credit sales		97,893			6.1			78,931			6.3			18,962			24.0
		1,609,144			100.0			1,252,225			100.0			356,919			28.5
Plant expenses:
General operations		917,071			57.0			701,501			56.0			(215,570	)		(30.7	)
Depreciation and amortization		486,530			30.2			444,878			35.5			(41,652	)		(9.4	)
		1,403,601			87.2			1,146,379			91.5			(257,222	)		(22.4	)
Gross Profit		205,543			12.8			105,846			8.5			99,697			94.2
Other income (expense)		233			0.0			(124,906	)		(10.0	)		125,139			100.2
Subsidiary Net Income (Loss)		205,776			12.8			(19,060	)		(1.5	)		224,836			**

% - represents the percentage of total plant operating revenues.
%* - represents the percentage of change from 2016 to 2017. Increases in revenues and decreases in expenses from the prior period to the current period are considered to be favorable and are presented as positive figures.
** - variance was a very large percentage.

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			($)			Hour ($)			($)			($)
September 30, 2015		15,950			1,106,643			69.4			(296,743	)		443,233
December 31, 2015		21,751			1,533,621			70.5			425,745			443,744
March 31, 2016		19,684			1,144,351			58.2			(158,497	)		444,587
June 30, 2016		15,647			829,554			52.1			(321,895	)		444,608
September 30, 2016		16,622			1,173,294			71.5			(288,634	)		444,878
December 31, 2016		20,039			1,452,737			72.5			130,804			480,864
March 31, 2017		21,934			1,292,005			58.9			55,242			484,948
June 30, 2017		20,680			1,102,160			64.6			(161,494	)		485,940
September 30, 2017		20,602			1,511,251			73.3			205,776			486,530

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

Professional and Management Fees
For the nine months ended September 30, 2017, the Company reported $665,016 in professional and management fees which was a decrease of $715,633 (51.8% decrease) from $1,380,649 reported in the same period ended 2016. For the three months ended September 30, 2017, the Company reported $370,667 in professional and management fees which was a increase of $202,178 (120.0% increase) from $168,489 reported in the same period ended 2016. During the nine months ended September 30, 2017, 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.

In the current quarter, the Company incurred legal costs that exceeded $265,000 for services related to executive employment contract issues, a review of the Company’s equity compensation plans and advice to the Board of Directors and its committees.

On July 12, 2017, Dennis Gilles signed a six-month advisory agreement that will pay him $10,000 per month.

Employee Compensation
For the nine months ended September 30, 2017, the Company reported $3,437,257 in employee compensation which was an increase of $1,055,707 (44.3% increase) from $2,381,550 reported in the same period ended 2016. For the three months ended September 30, 2017, the Company reported $1,847,953 in employee compensation which was an increase of $1,148,399 (164.2% increase) from $699,554 reported in the same period ended 2016. The Company chose not to renew the CEO’s employment contract, and consequently, on July 18, 2017, the former CEO’s employment contract expired. The severance provisions of the contract entitled the former CEO to 18 months of base salary and targeted bonus, plus 18 months of health insurance premiums. The cost of these provisions totaled approximately $1.25 million.

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On July 27, 2017, Douglas Glaspey signed an amendment to his employment agreement to serve as interim CEO with an associated pay increase of $5,000 per month.

Travel and Promotion
For the nine months ended September 30, 2017, the Company reported $160,081 in travel and promotional costs which was a decrease of $170,406 (51.6% decrease) from $330,487 reported in the same period ended 2016. For the three months ended September 30, 2017, the Company reported $48,944 in travel and promotional costs which were a decrease of $17,646 (26.5% decrease) from $66,590 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. In the third quarter of 2016, the Company incurred promotional expenses on industry conferences and investor relations services.

Net Income Tax Expense/Benefit
For the nine months ended September 30, 2017, the Company reported net income tax benefit of $149,000, which was a decrease of $147,000 (49.7% decrease) from the income tax benefit of $296,000 reported in the same period ended 2016. For the three months ended September 30, 2017, the Company reported net income tax benefit of $186,000, which was an increase of $96,000 (106.7% increase) from the income tax benefit of $90,000 reported in the same period ended 2016. The increases in the estimated tax benefits were primarily related to decreases in the profitability of plant operations as well as increases in employee compensation as described above.

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 nine months ended September 30, 2017, the Company reported $1,401,961 in net income attributable to non-controlling interests, which was a decrease of $158,220 (10.1% decrease) from $1,560,181 net income reported in the same period ended 2016. For the three months ended September 30, 2017, the Company reported $692,680 net income attributable to non-controlling interests, which was an increase of $273,952 (65.4% increase) from $418,728 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 nine months ended September 30, 2017 of $5,020,316, which was a decrease of $729,657 (12.7% decrease) from $5,749,973 subsidiary net profit reported in the same period ended 2016. USG Oregon LLC reported a subsidiary net profit for the three months ended September 30, 2017 of $2,032,429, which was an increase of $752,902 (58.8% increase) from $1,279,527 subsidiary net profit reported in the same period ended 2016. The primary conditions for the variances in USG Oregon LLC’s profits were discussed above.

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

		For the Nine Months Ended
		September 30,
Subsidiaries and Non-Controlling		2017			2016			Variances
Interest Entities		$			$			$			%
Oregon USG Holdings LLC interest held by Enbridge Inc.		1,991,574			2,291,146			(299,572	)		(13.1	)
Raft River Energy I LLC interest held by Goldman Sachs		(584,061	)		(725,454	)		141,393			19.5
Gerlach Geothermal LLC interest       held by Gerlach Green Energy, LLC		(5,552	)		(5,511	)		(41	)		(0.7	)
		1,401,961			1,560,181			(158,220	)		(10.1	)

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

		For the Three Months Ended
		September 30,
Subsidiaries and Non-Controlling		2017			2016			Variances
Interest Entities		$			$			$			%
Oregon USG Holdings LLC interest held by Enbridge Inc.		812,971			511,811			301,160			58.8
Raft River Energy I LLC interest held by Goldman Sachs		(120,274	)		(93,064	)		(27,210	)		(29.2	)
Gerlach Geothermal LLC interest       held by Gerlach Green Energy, LLC		(17	)		(19	)		2			10.5
		692,680			418,728			273,952			65.4

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

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Non-Controlling Interests
The following is a summarized presentation of select financial line items from the statement of operations by project and the impact of the related non-controlling interests for the nine months ended September 30, 2017:

											Exploration
		Neal Hot									Activities and			Consolid-
Statement of		Springs			San Emidio			Raft River			Corporate			ated
Operations Element		$			$			$			$			$
Gross Profit (Loss)		6,181,435			1,219,155			98,931			551,883			8,051,404
Expenses/(Income)		1,202,499			1,448,136			(593	)		(4)6,156,191			8,806,233
Net Income(Loss) before tax expense		4,978,936			(228,981	)		99,524			(5,604,308	)		(754,829	)
Income taxes – USG Portion		(1,120,000	)		86,000			(256,000	)		1,439,000			149,000
Non-controlling interests		(1)(1,991,574)			-			(2)584,062			(3)5,551			(1,401,961	)
Net income (loss) attributable to U.S. Geothermal		1,867,362			(142,981	)		427,586			(4,159,757	)		(2,007,790	)

	(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 nine months ended September 30, 2017 included:

	•	Employee compensation	$ 3,437,257
	•	Corporate administration	987,866
	•	Professional fees	665,016

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 September 30, 2017 are detailed as follows:

					Non-			U.S.
					Controlling			Geothermal
		Consolidated			Interests			Inc.
Balance Sheet Items		$			$			$
Unrestricted cash and cash equivalents		10,549,769			633,284			9,916,485
Restricted cash and security bonds:
Current		8,428,376			480,319			7,948,057
Long-term		20,607,970			5,951,029			14,656,941
Notes payable*:
Current		4,168,799			1,301,001			2,867,798
Long-term		100,104,235			21,466,508			78,637,727

*–Balances include unamortized loan closing costs.

The loans held by the Company at September 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		56,918,773			209			2/12/35			2.598			60.0			34,151,264
Prudential Group – USG Nevada LLC		28,709,646			243			12/31/37			6.750			100.0			28,709,646
Prudential Group – Idaho USG Holdings LLC		19,296,475			66			3/31/23			5.800			100.0			19,296,475
Chrysler Auto Loan – U.S. Geothermal Services, LLC		3,042			10			7/27/18			6.740			100.0			3,042
Totals		104,927,936															82,160,427
Weighted Average Term (Months)					192
Weighted Average Interest Rate											4.323

Off Balance Sheet Arrangements

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

Liquidity and Capital Resources

During the quarter ended September 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 $413,929 during the quarter. We believe our cash and liquid investments at September 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 2016 Purchase Agreement, at the Company’s sole discretion, the Company had the right to sell and LPC had the obligation to purchase up to $10 million of equity capital over a 30-month period subject to the conditions in the Purchase Agreement. The Purchase Agreement provided for an initial sale of $650,000 of shares of common stock upon closing. Net proceeds from LPC’s investments were used to cover a portion of the cost of the recent acquisition of the Goldman Sachs ownership interest of the Raft River project, development of our geothermal projects and for general corporate purposes. During the quarter ended March 31, 2016 an additional $571,650 was raised under the LPC facility subsequent to the initial sale. No additional funds were raised since that time. On August 4, 2017, the Company delivered notice to LPC pursuant to the Purchase Agreement terminating the Purchase Agreement. Pursuant to the terms of the Purchase Agreement, termination of the Purchase Agreement became effective August 7, 2017.

Potential Acquisitions

The Company’s primary focus is on the development and expansion of its current projects. However, 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 September 30, 2017, the Company held investments of $31,859,835 in money market accounts. The money market funds are invested in governmental obligations with minimal fluctuations in interest rates and fixed terms; therefore, the interest rate risk on investments is not significant.

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

Commodity Price Risk
The Company is exposed to risks surrounding the volatility of energy prices. These risks are impacted by various circumstances surrounding the energy production from natural gas, nuclear, hydro, solar, coal and oil. The Company has been able to mitigate, to a certain extent, this risk by signing PPA contracts for 20 to 25 year periods. This type of arrangement will be the model for PPAs planned for future power plants.

Item 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 nine months ended September 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

None.

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: November 9, 2017	By: /s/ Douglas J. Glaspey
	Douglas J. Glaspey
	Interim Chief Executive Officer
Date: November 9, 2017
	By: /s/ Kerry D. Hawkley
	Kerry D. Hawkley
	Chief Financial Officer and Corporate Secretary

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EXHIBIT INDEX

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

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