Us Geothermal 10-Q 2016 Q3 Quarterly report

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 endedSeptember 30, 2015

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 or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

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

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, 2015
Common stock, par value	107,601,425
$ 0.001 per share

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U.S. Geothermal Inc.
Form 10-Q
For the Third Quarter Ended September 30, 2015

INDEX

PART I – Financial Information
Item 1	Consolidated Financial Statements
	Consolidated Balance Sheet at September 30, 2015 (unaudited) and Consolidated Balance Sheet at December 31, 2014	4
	Unaudited Consolidated Statements of Comprehensive Income – Three and Nine Months Ended September 30, 2015 and 2014 (unaudited)	5
	Unaudited Consolidated Statements of Cash Flow – Nine Months Ended September 30, 2015 and 2014 (unaudited)	6
	Consolidated Statement of Stockholders’ Equity – Year Ended December 31, 2014 and Nine Months Ended September 30, 2015 (unaudited)	7
	Notes to Consolidated Financial Statements	8
Item 2	Management’s Discussion and Analysis of Financial Condition and Results of Operations	24
	General Background and Discussion	25
	Operating Results	32
	Off Balance Sheet Arrangements	43
	Liquidity and Capital Resources	43
	Potential Acquisitions	43
	Critical Accounting Policies	43
Item 3	Quantitative and Qualitative Disclosures about Market Risk	44
Item 4	Controls and Procedures	44
PART II – Other Information
Item 1	Legal Proceedings	45
Item 1A	Risk Factors	45
Item 2	Unregistered Sales of Equity Securities and Use of Proceeds	45
Item 3	Defaults Upon Senior Securities	45
Item 4	Mine Safety Disclosures	45
Item 5	Other Information	45
Item 6	Exhibits	45

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U.S. GEOTHERMAL INC.
CONSOLIDATED BALANCE SHEETS

		(Unaudited)
		September 30, 2015			December 31, 2014
ASSETS
Current:
Cash and cash equivalents	$	11,172,575		$	12,994,975
Restricted cash and bonds		3,559,327			3,320,781
Trade accounts receivable		2,460,551			3,774,133
Deferred income tax asset		1,803,000			1,803,000
Other current assets		1,569,744			1,550,359
Total current assets		20,565,197			23,443,248
Restricted cash and bond reserves		17,467,052			18,690,096
Property, plant and equipment, net of depreciation		166,693,491			166,859,446
Intangible assets, net of amortization		15,311,250			15,417,514
Net deferred income tax asset		8,031,000			8,504,000
Total assets	$	228,067,990		$	232,914,304
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts payable and accrued liabilities	$	1,693,360		$	1,886,947
Related party accounts payable		3,598			5,195
Current portion of capital lease obligations		-			20,919
Current portion of notes payable		4,381,600			4,336,271
Total current liabilities		6,078,558			6,249,332
Long-term Liabilities:
Asset retirement obligations		1,400,000			1,400,000
Notes payable, less current portion		90,349,251			94,376,351
Total long-term liabilities		91,749,251			95,776,351
Total liabilities		97,827,809			102,025,683
Commitments and Contingencies (note 10)
STOCKHOLDERS’ EQUITY
Capital stock (authorized: 250,000,000 common shares with a $0.001 par       value; issued and outstanding shares at September 30, 2015 and       December 31, 2014 were: 107,601,425 and 107,018,029; respectively)		107,601			107,018
Additional paid-in capital		104,696,824			103,669,371
Accumulated deficit		(18,503,681	)		(19,284,860	)
		86,300,744			84,491,529
Non-controlling interests		43,939,437			46,397,092
Total stockholders’ equity		130,240,181			130,888,621
Total liabilities and stockholders’ equity	$	228,067,990		$	232,914,304

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

		(Unaudited)						(Unaudited)
		For the Three Months Ended						For the Nine Months Ended
		September 30,						September 30,
		2015			2014			2015			2014
Plant Revenues:
Energy sales	$	6,854,109		$	6,649,120		$	21,009,178		$	20,810,254
Energy credit sales		75,738			87,885			255,710			274,590
Total plant operating revenues		6,929,847			6,737,005			21,264,888			21,084,844
Plant Expenses:
Plant production expenses		2,532,780			2,246,034			7,307,590			7,115,530
Depreciation and amortization		1,577,622			1,551,299			4,720,220			4,674,605
Total plant operating expenses		4,110,402			3,797,333			12,027,810			11,790,135
Gross Profit		2,819,445			2,939,672			9,237,078			9,294,709
Operating Expenses:
Corporate administration		263,301			216,386			886,485			808,489
Professional and management fees		185,005			186,849			818,697			754,796
Salaries and wages		388,125			400,950			1,324,920			1,473,006
Stock based compensation		282,815			321,306			978,487			1,098,771
Travel and promotion		74,358			60,362			148,866			160,356
Exploration costs		3,826			27,221			72,557			70,709
Operating Income		1,622,015			1,726,598			5,007,066			4,928,582
Interest Expense		927,730			1,089,686			2,855,816			3,079,415
Other (income) expense		(70,794	)		(58,905	)		(131,863	)		(85,412	)
Income Before Income Tax Expense		765,079			695,817			2,283,113			1,934,579
Income Tax Expense		170,000			-			473,000			-
Net Income		595,079			695,817			1,810,113			1,934,579
Net income attributable to the non- controlling interests		(314,215	)		(614,037	)		(1,028,934	)		(1,666,191	)
Net Income Attributable to U.S.Geothermal Inc.		280,864			81,780			781,179			268,388
Other Comprehensive Income:
Unrealized income on investment in equity securities		-			-			-			27,321
Comprehensive Income Attributable toU.S. Geothermal Inc.	$	280,864		$	81,780		$	781,179		$	295,709
Basic Earnings Per Share Attributable toU.S. Geothermal Inc.	$	0.00			0.00		$	0.01		$	0.00
Diluted Earnings Per Share Attributable toU.S. Geothermal Inc.	$	0.00			0.00		$	0.01		$	0.00
Shares used in the calculation of incomeper share:
Basic		107,164,333			104,028,476			106,902,666			103,050,740
Diluted		108,359,065			106,650,359			108,584,804			105,854,992

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

		(Unaudited)
		For the Nine Months Ended September 30,
		2015			2014
Operating Activities:
Net Income	$	1,810,113		$	1,934,579
Adjustments to reconcile net income to total cash provided by operating activities:
Depreciation and amortization		4,809,489			4,772,192
Stock based compensation		978,487			1,098,771
Loss on sale of securities		-			27,967
Gain on software refund		-			(13,239	)
Change in deferred income taxes		473,000			-
Net changes in:
Trade accounts receivable		1,313,582			1,588,546
Accounts payable and accrued liabilities		(227,414	)		(1,320,909	)
Prepaid expenses and other		(19,385	)		(284,157	)
Total cash provided by operating activities		9,137,872			7,803,750
Investing Activities:
Purchases of property, plant and equipment		(4,529,040	)		(2,874,316	)
Acquisition of subsidiaries		-			(6,782,445	)
Deposits on costs related to acquisition		-			(187,794	)
Proceeds from sale of equities held for investment		-			41,528
Proceeds from software refund		-			31,120
Net release (funding) of restricted cash reserves and bonds		984,498			1,051,844
Total cash used by investing activities		(3,544,542	)		(8,720,063	)
Financing Activities:
Issuance of common stock		49,549			1,634,918
Contributions from non-controlling interest		-			7,360
Distributions to non-controlling interest		(3,462,589	)		(15,048,334	)
Principal payments on notes payable and other obligations		(3,981,771	)		(3,683,631	)
Principal payments on capital leases		(20,919	)		(35,812	)
Total cash used by financing activities		(7,415,730	)		(17,125,499	)
Increase (Decrease) in Cash and Cash Equivalents		(1,822,400	)		(18,041,812	)
Cash and Cash Equivalents, Beginning of Period		12,994,975			28,736,934
Cash and Cash Equivalents, End of Period	$	11,172,575		$	10,695,122
Supplemental Disclosures:
Non-cash investing and financing activities:
Accrual for purchases of property and equipment	$	8,230		$	425,529
Non-cash distributions to non-controlling interest		24,000			-
Other Items:
Interest paid		3,305,363			3,538,629

The accompanying notes are an integral part of these interim consolidated financial statements.
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U.S.GEOTHERMAL INC.
CONSOLIDATEDSTATEMENTS OFCHANGES INSTOCKHOLDERS’EQUITY -Unaudited
For the NineMonths EndedSeptember 30, 2015 and Year EndedDecember 31, 2014

					Additional					Accumulated			Non-
	Number of		Common		Paid-In		Accumulated			Comprehensive			controlling
	Shares		Shares		Capital		Deficit			Income (Loss)			Interest			Totals
Balance at December 31, 2013	102,094,542	$	102,094	$	100,381,207	$	(30,898,571	)	$	(27,321	)	$	58,155,480		$	127,712,889
Distributions to non-controlling interest entities	-		-		-		-			-			(15,048,334	)		(15,048,334	)
Non-controlling equity contributions	-		-		-		-			-			7,360			7,360
Stock issued to shareholders of acquired company	692,769		693		317,981		-			-			-			318,674
Stock issued by the exercise of employee stock options	1,077,000		1,077		336,544		-			-			-			337,621
Stock issued by the exercise of stock purchase warrants	2,594,596		2,595		1,294,703		-			-			-			1,297,298
Stock compensation	559,122		559		1,338,936		-			-			-			1,339,495
Unrealized loss and reclassification to net income	-		-		-		-			27,321			-			27,321
Net income	-		-		-		11,613,711			-			3,282,586			14,896,297
Balance at December 31, 2014	107,018,029		107,018		103,669,371		(19,284,860	)		-			46,397,092			130,888,621
Distributions to non-controlling interest entities	-		-		-		-			-			(3,486,589	)		(3,486,589	)
Stock issued by the exercise of employee stock options	155,000		155		49,394		-			-			-			49,549
Stock compensation	428,396		428		978,059		-			-			-			978,487
Net income	-		-		-		781,179			-			1,028,934			1,810,113
Balance at September 30, 2015	107,601,425	$	107,601	$	104,696,824	$	(18,503,681	)	$	-		$	43,939,437		$	130,240,181

The accompanying notes are an integral part of these interim consolidated financial statements.
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U.S. GEOTHERMAL INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Unaudited
September 30, 2015

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, 2015 and our operating results and cash flows for the nine months ended September 30, 2015 and 2014. The accompanying financial information as of December 31, 2014 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, 2014 (our “Annual Report”).

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); and
xx)	Earth Power Resources Inc. (incorporated in in the State of Delaware).

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

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Cash and Cash Equivalents

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

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, 2015 and December 31, 2014, 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, 2015, the Company’s total cash balance, excluding money market funds, was $3,198,731 and bank deposits amounted to $3,269,799. The primary difference was due to outstanding checks and deposits. Of the bank deposits, $1,682,177 was not covered by or was in excess of FDIC insurance guaranteed limits. At September 30, 2015, the Company’s money market funds invested, primarily, in government backed securities totaled $28,996,523 and were not subject to deposit insurance.

Property, Plant and Equipment

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

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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:

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

Stock Compensation

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

Earnings Per Share

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

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Common stock purchase warrants, broker warrants and options not used in the diluted share calculations were as follows:

	September 30,
	2015	2014
Three Months Ended	10,684,542	10,007,292
Nine Months Ended	11,134,542	10,007,292

Foreign Currency Translation

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

Revenue

Revenue Recognition

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

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

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

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Recent Accounting Pronouncements

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

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

Business Combinations
In September 2015, FASB issued Accounting Standards Update No. 2015-16 (“Update 2015-16”),Business Combinations (Topic 805), Simplifying the Accounting Measurement-Period Adjustments. Update 2015-16 provides additional guidance on how to account for provisional costs of business combinations that are incomplete at the end of a reporting period. The amendment to this Update is effective for public business entities for fiscal years beginning after December 15, 2015, including interim periods within those fiscal years. The specific circumstances addressed in this Update do not currently apply to the Company. However, the Company may engage in transactions subject to the guidance of this Update in future periods. Management will continue to evaluate the possible impact that this guidance may have on future consolidated financial statements.

Presentation of Debt Issuance Costs
In April 2015, FASB issued Accounting Standards Update No. 2015-03,Simplifying the Presentation of Debt Issuance Costs, Interest-Imputation of Interest (Subtopic 835-30).In August 2015, FASB issued Accounting Standards Update No. 2015-15,Interest – Imputation of Interest, Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements(Topic 835-35).These Updates require that debt issuance costs related to a recognized debt liability, including some costs related to line of credit arrangements, be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability. For public business entities, the Updates are effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. Early adoption is permitted for financial statements that have not been previously issued. Management is still evaluating the impact and the timing of adoption of these Updates.

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 August 2015, FASB issued Accounting Standards Update No. 2015-14 (“Update 2015-14”),Revenue from Contracts with Customers (Topic 606), Deferral of the Effective Date.Update 2015-14 extends the effective date of this guidance for annual and interim reporting periods beginning after December 15, 2017, with early adoption permitted for public companies effective for annual and interim reporting periods beginning after December 15, 2016. Management is currently evaluating the impact the guidance defined by Update 2014-09 will have on our consolidated financial statements.

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NOTE 3 – RESTRICTED CASH AND BOND RESERVES

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

Current restricted cash and bond reserves:

		September 30,		December 31,
Restricting Entities/Purpose		2015		2014
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, Revenue Account		560,461		188,930
Prudential Capital Group, Debt Service Reserves		1,595,225		-
Bureau of Land Management, Geothermal Rights Lease Bond		10,000		10,000
U.S. Department of Energy, Debt Service Payment Account		423,641		2,151,851
State of California Division of Oil, Gas and Geothermal Resources, Well Cash Bond		100,000		100,000
	$	3,559,327	$	3,320,781

Long-term restricted cash and bond reserves:

		September 30,		December 31,
Restricting Entities/Purpose		2015		2014
Nevada Energy, PPA Security Bond	$	1,468,898	$	1,468,898
Prudential Capital Group, Debt Service Reserves		-		1,594,605
Prudential Capital Group, Maintenance Reserves		586,218		604,529
Prudential Capital Group, Well Reserves		155,402		212,298
U.S. Department of Energy, Operations Reserves		270,000		270,000
U.S. Department of Energy, Debt Service Reserves		2,541,868		2,582,606
U.S. Department of Energy, Short Term Well Field Reserves		4,506,774		4,505,150
U.S. Department of Energy, Long-Term Well Field Reserves		4,966,171		4,761,927
U.S. Department of Energy, Capital Expenditure Reserves		2,971,721		2,690,083
	$	17,467,052	$	18,690,096

The well bonding requirements ensure that the Company has sufficient financial resources to construct, operate and maintain geothermal wells while safeguarding subsurface, surface and atmospheric resources from unreasonable degradation, and to protect ground water aquifers and surface water sources from contamination. Other future costs of environmental remediation cannot be reasonably estimated and have not been recorded. The debt service reserves are required to provide assurance that the Company will have sufficient funds to meet its debt payment obligations for the terms specified by the loan agreements. The maintenance and capital expenditure reserves are required by the lending entities to ensure that funds are available to acquire and maintain critical components of power plants and related supporting structures to enable the plants to operate according to expectations. Except for the PPA Security Bond, all of the restricted funds consisted of cash deposits or money market accounts held in commercial banks. Portions of the cash deposits are subject to FDIC insurance. See note 2 for details. The PPA Security Bond is held by the power purchaser. All of the reserve accounts were considered to be fully funded at September 30, 2015 and December 31, 2014.

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NOTE 4 - PROPERTY, PLANT AND EQUIPMENT

During the quarter ended September 30, 2015, the Company focused development activities on the San Emidio Phase II; Guatemala and WGP Geysers projects with development spending totaling approximately $1,365,000 for the quarter. Drilling and testing costs of approximately $508,000 were incurred on the San Emidio Phase II. Drilling costs exceeded $603,000 in Guatemala. Costs were incurred at WGP Geysers for site preparation, an interconnection study and well field testing that totaled approximately $253,000. In September 2015, the Company disposed of the fully depreciated old power plant located in San Emidio, Nevada at its historical cost of $2,275,475.

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

		September 30,			December 31,
		2015			2014
Land	$	3,275,122		$	3,211,010
Power production plant		159,800,893			162,076,367
Grant proceeds for power plants		(52,965,236	)		(52,965,236	)
Wells		67,621,167			67,621,167
Grant proceeds for wells		(3,464,555	)		(3,464,555	)
Furniture and equipment		2,058,951			1,796,807
		176,326,342			178,275,560
Less: accumulated depreciation		(29,466,586	)		(27,068,836	)
		146,859,756			151,206,724
Construction in progress		19,833,735			15,652,722
	$	166,693,491		$	166,859,446

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

		September 30,
		2015		2014
Three months ended	$	1,562,860	$	1,538,721
Nine months ended		4,673,225		4,635,928

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Changes in construction in progress are summarized as follows:

		For the Nine
		Months Ended		For the Year
		September 30,		Ended December
		2015		31, 2014
Beginning balances	$	15,652,722	$	6,354,503
Development/construction		4,181,013		3,730,371
Grant reimbursements and rebates		-		(632,210	)
Acquisitions		-		6,200,058
Ending balances	$	19,833,735	$	15,652,722

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

		September 30,		December 31,
		2015		2014
Raft River, Idaho:
Unit I, well improvements	$	104,960	$	-
Unit II, power plant, substation and transmission lines		750,493		750,493
Unit II, well construction		2,133,064		2,127,547
		2,988,517		2,878,040
San Emidio, Nevada:
Unit II, power plant, substation and transmission lines		423,536		383,536
Unit II, well construction		3,751,446		3,133,873
		4,174,982		3,517,409
Neal Hot Springs, Oregon:
Power plant and facilities		12,853		6,477
Well construction		231,193		-
		244,046		6,477
WGP Geysers, California:
Power plant and facilities		319,988		319,988
Well construction		7,554,832		6,139,421
		7,874,820		6,459,409
Crescent Valley, Nevada:
Well construction		1,132,569		133,058
El Ceibillo, Republic of Guatemala:
Well construction		3,410,301		2,649,829
Plant and facilities		8,500		8,500
		3,418,801		2,658,329
	$	19,833,735	$	15,652,722

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NOTE 5 – INCOME TAXES

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

	For the Nine Months Ended
	September 30,
	2015		2014
U.S. Federal statutory rate	34.0%		34.0%
Average State and foreign income tax, net of federal tax effect	3.7		3.7
Valuation allowance	-		(37.7	)
Consolidated tax rate before non-controlling interest	37.7		-
Tax effect of non-controlling interests	(17.0	)	-
Net effective tax rate	20.7%		-%

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, 2015, reflects a reported effective tax rate of 20.7% which differs from the statutory federal income tax rate of 34.0% primarily due to the impact of the non-controlling interest and state income taxes.

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

NOTE 6 – NOTES PAYABLE

U.S. Department of Energy
On August 31, 2011, USG Oregon LLC (“USG Oregon”), a subsidiary of the Company, completed the first funding drawdown associated with the U.S. Department of Energy (“DOE”) $96.8 million loan guarantee (“Loan Guarantee”) to construct its power plant at Neal Hot Springs in Eastern Oregon (the “Project”). All loan advances covered by the Loan Guarantee have been made under the Future Advance Promissory Note (the “Note”) dated February 23, 2011. Upon the occurrence and continuation of an event of default under the transaction documents, all amounts payable under the Note may be accelerated. In connection with the Loan Guarantee, the DOE has been granted a security interest in all of the equity interests of USG Oregon, as well as in the assets of USG Oregon, including a mortgage on real property interests relating to the Project site. 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 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 are scheduled to be reduced to $1,626,251 on February 10, 2017 and continue through February 12, 2035. The loan balance at September 30, 2015 totaled $63,546,722 (current portion $3,375,448).

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

				Annual Interest
Description		Amount		Rate %
Advances by date:
August 31, 2011*	$	2,328,422		2.997
September 28, 2011		10,043,467		2.755
October 27, 2011		3,600,026		2.918
December 2, 2011		4,377,079		2.795
December 21, 2011		2,313,322		2.608
January 25, 2012		8,968,019		2.772
April 26, 2012		13,029,325		2.695
May 30, 2012		19,497,204		2.408
August 27, 2012		7,709,454		2.360
December 28, 2012		2,567,121		2.396
June 10, 2013		2,355,316		2.830
July 3, 2013*		2,242,628		3.073
July 31, 2013*		4,026,582		3.214
		83,057,965
Principal paid through September 30, 2015		(19,511,243	)
Loan balance at September 30, 2015	$	63,546,722

* - Individual tranches have been fully extinguished.

SAIC Constructors LLC
Effective August 27, 2010, the Company’s wholly owned subsidiary (USG Nevada LLC) signed a construction loan agreement with SAIC Constructors LLC (“SAIC”). The new 10.0 net megawatt power plant was considered complete and operational for financial reporting purposes on September 1, 2012. On February 15, 2013, USG Nevada LLC signed a settlement agreement with SAIC that defined the terms of three separate debt components to settle the obligations incurred under the construction loan agreement. As of December 31, 2013, two components of the settlement agreement were paid in full. On April 30, 2013, SAIC signed a loan agreement with Nevada USG Holdings LLC (parent company of USG Nevada LLC and wholly owned subsidiary of the Company), that further defined the terms of the remaining debt component of $2 million. This remaining obligation will be repaid in quarterly installments of $119,382, including interest at 7.0% per annum that began on July 31, 2013 and is scheduled to be repaid by September 2018. The loan balance at September 30, 2015 totaled $1,198,223 (current portion $406,341).

Prudential Capital Group
On September 26, 2013, the Company’s wholly owned subsidiary (USG Nevada LLC) entered into a note purchase agreement with the Prudential Capital Group’s related entities (“Prudential”) to finance the Phase I San Emidio geothermal project located in northwest Nevada. The term of the note is approximately 24 years, and bears interest at fixed rate of 6.75% per annum. Interest payments are due quarterly. Principal payments are due quarterly based upon minimum debt service coverage ratios established according to projected operating results made at the loan origination date and available cash balances. All amounts owing under the notes and the note purchase agreement or any related financing document are secured by USG Nevada LLC’s right, title and interest in and to its real and personal property, including the San Emidio project and the equity interests in USG Nevada LLC. At September 30, 2015, the balance of the loan was $29,946,751 (current portion $592,969).

Auto Loans
On August 21, 2014, the Company’s wholly owned subsidiaries (U.S. Geothermal Services, LLC, USG Nevada LLC and Raft River Energy I, Inc.) purchased three trucks with down payments that totaled $47,000 and three separate loan agreements with Chrysler Capital. The U.S. Geothermal Services, LLC loan was paid in full on September 30, 2015. The remaining two loans require total monthly payments of $764, including interest at an average rate of 6.39% per annum until September 2020. The notes are secured by the vehicles. At September 30, 2015, the loan balances totaled $39,155 (current portion $6,842).

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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:

For the Year Ended		Principal
September 30,		Payments
2016	$	4,381,600
2017		4,084,376
2018		3,828,444
2019		3,683,130
2020		3,727,606
Thereafter		75,025,695
	$	94,730,851

NOTE 7 – COMMON STOCK

On May 21, 2012, the Company entered into a purchase agreement with Lincoln Park Capital Fund, LLC (“LPC”), pursuant to which the Company has the right to sell to LPC up to $10,750,000 in shares of the Company’s common stock, subject to certain limitations and conditions set forth in the Purchase Agreement and imposed by the Company’s Board of Directors and pricing committee. On December 21, 2012, the Company and LPC entered into an Amendment to the Purchase Agreement to reduce the total amount that could be purchased, including the amounts already purchased, from $10,750,000 to $6,500,000. As of May 21, 2015, the Company had sold LPC an aggregate of 4,625,506 shares of common stock for net proceeds of approximately $1,343,639 (net of $86,911 broker fees). The Purchase Agreement was allowed to expire on May 21, 2015.

On September 18, 2015, the Company issued 10,000 shares of common stock as a result of an employee exercising stock options priced at $0.46 per share.

NOTE 8 - STOCK BASED COMPENSATION

The Company has a stock incentive plan (the “Stock Incentive Plan”) for the purpose of attracting and motivating directors, officers, employees and consultants of the Company and advancing the interests of the Company. The Stock Incentive Plan is a 15% rolling plan approved by shareholders in September 2013, whereby the Company can grant options to the extent of 15% of the current outstanding common shares. Under the plan, all forfeited and exercised options can be replaced with new offerings. As of September 30, 2015, the Company can issue stock option grants totaling up to 16,140,214 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.

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The following table reflects the summary of stock options outstanding at December 31, 2014 and changes for the nine months ended September 30, 2015:

				Weighted	Weighted
				Average	Average
	Number of			Exercise	Remaining		Aggregate
	shares under			Price Per	Contract		Intrinsic
	options			Share	Term		Value
Balance outstanding, December 31, 2014	11,808,500		$	0.62	3.52	$	4,264,270
Forfeited/Expired	(1,550,000	)		0.86	0.18		(845,500	)
Exercised	(155,000	)		0.32	2.19		(23,889	)
Granted	2,510,000			0.49	4.89		536,207
Balance outstanding, September 30,  2015	12,613,500		$	0.57	2.75	$	3,931,088

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

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

	For the Nine
	Months Ended	For the Year
	September 30,	Ended December
	2015	31, 2014
Dividend yield	0	0
Expected volatility	65%	81-100%
Risk free interest rate	0.58%	0.69-0.82%
Expected life (years)	3.26	2.94

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.

On September 18, 2015, 10,000 stock options exercisable at the price of $0.46 were exercised by an employee.

On September 10, 2015, 1,100,000 stock options exercisable at a price of $0.86 expired without exercise.

As of September 30, 2015, there was $215,804 of total unrecognized compensation cost related to nonvested share-based compensation arrangements granted under the Plan. That cost is expected to be recognized over the next 1.25 years.

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Common Stock Compensation Plan (Restricted Shares)

Restricted shares are issued to the recipients when granted and held by the Company until vested. The recipients meet the vesting requirements by maintaining employment and good standing with the Company through the vesting period. After vesting, there are no restrictions on the shares.

Stock Purchase Warrants

At September 30, 2015, the outstanding broker warrants and share purchase warrants consisted of the following:

			Broker
			Warrant	Share		Warrant
	Broker		Exercise	Purchase		Exercise
Expiration Date	Warrants		Price	Warrants		Price
May 23, 2017	255,721	$	0.44	-	$	-
December 21, 2017	-		-	3,310,812		0.50

NOTE 9 – FAIR VALUE MEASUREMENT

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

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

Level 1 – Quoted prices are available in active markets for identical assets or liabilities.
Level 2 – Directly or indirectly market based inputs or observable inputs used in models or other valuation methodologies.
Level 3 – Unobservable inputs that are not corroborated by market data. The inputs require significant management judgement or estimation.

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

At September 30, 2015:

		Total		Level 1		Level 2		Level 3
Assets:
Money market accounts *	$	28,996,523	$	28,996,523	$	-	$	-

At December 31, 2014:

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

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

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NOTE 10 - COMMITMENTS AND CONTINGENCIES

Operating Lease Agreements

The Company has entered into several lease agreements with terms expiring up to December 1, 2034 for geothermal properties in Neal Hot Springs, Oregon; Washoe County, Nevada; Eureka County, Nevada; The Geysers, California; Raft River, Idaho and the Republic of Guatemala. The Company incurred total lease expenses for the nine months ended September 30, 2015 and 2014, of $418,813 and $408,429; respectively.

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

Years Ending
December 31,		Amount
2015	$	224,895
2016		930,463
2017		900,124
2018		865,753
2019		742,547
Thereafter		13,273,471

NOTE 11 – 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,
		2015		2014
Gerlach Geothermal LLC interest held by Gerlach Green Energy, LLC	$	215,238	$	230,539
Oregon USG Holdings LLC interest held by Enbridge Inc.		23,628,343		24,818,443
Raft River Energy I LLC interest held by Raft River I Holdings, LLC		20,095,856		21,348,110
	$	43,939,437	$	46,397,092

Gerlach Geothermal LLC
On April 28, 2008, the Companyformed Gerlach Geothermal, LLC (“Gerlach”) with our partner,Gerlach Green Energy, LLC (“GGE”). The purpose of the joint venture is the exploration of the Gerlach geothermal system, which is located in northwestern Nevada, near the town of Gerlach. Based upon the terms of the members’ agreement, the Company owned a 60% interest and GGE owned a 40% interest in Gerlach Geothermal, LLC. The agreement gives GGE an option to maintain its 40% ownership interest as additional capital contributions are required. If GGE dilutes to below a 10% interest, their ownership position in the joint venture would be converted to a 10% net profits interest. The Company has contributed $757,190 in cash and $300,000 for a geothermal lease and mineral rights; and the GGE has contributed $704,460 of geothermal lease, mineral rights and exploration data. During the first nine months of the year ended December 31, 2014, contributions were made to Gerlach by the Company and GGE that totaled $11,040 and $7,360; respectively. These contributions maintained the existing ownership interests of the two partners in Gerlach. During the fourth quarter of the year ended December 31, 2014, the Company contributed $400,000 for the project’s drilling costs that were not proportionally matched by GGE. These contributions effectively reduced GGE’s ownership interest to 32.65%, and increased the Company’s interest to 67.35% as of December 31, 2014. On June 16, 2015, the Company contributed $6,000 for the project’s costs that were not proportionally matched by GGE. These contributions effectively further reduced GGE’s ownership interest to 32.56%, and increased the Company’s interest to 67.44% .

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

Oregon USG Holdings LLC
In September 2010, the Company’s subsidiary, Oregon USG Holdings LLC (“Oregon Holdings”), signed an Operating Agreement with Enbridge Inc. (“Enbridge”) for the right to participate in the Company’s Neal Hot Springs project located in Malheur County, Oregon. On February 20, 2014, a new determination under the existing agreement was reached with Enbridge that established their ownership interest percentage at 40% and the Company’s at 60%, effective January 1, 2013. Oregon Holdings has a 100% ownership interest in USG Oregon LLC. Enbridge has contributed a total of $32,801,000, including the debt conversion, to Oregon Holdings in exchange for a direct ownership interest. During the nine months ended September 30, 2015, distributions were made to the Company and Enbridge that totaled $5,193,882 and $3,462,588; respectively.

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

Raft River Energy I LLC (“RREI”)
Raft River Energy I is a joint venture between the Company and Raft River I Holdings, LLC a subsidiary of the Goldman Sachs Group, Inc. An Operating Agreement governs the rights and responsibilities of both parties. At September 30, 2015, the Company had contributed approximately $17.9 million in cash and property, and Raft River I Holdings, LLC has contributed approximately $34.1 million in cash. Profits and losses are allocated to the members based upon contractual terms. For income tax purposes, Raft River I Holdings, LLC receives a greater proportion of the share of losses and other income tax benefits. This includes the allocation of production tax credits, which will be distributed 99% to Raft River I Holdings, LLC and 1% to the Company during the first 10 years of production. During the initial years of operations, Raft River I Holdings, LLC will receive a larger allocation of cash distributions.

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

Effective May 17, 2011, a repair services agreement (“RSA”) was executed between RREI and U.S. Geothermal Services, LLC for the purpose of funding repairs of two underperforming wells. The agreement defined terms of the RSA repair costs and RSA repair management fees that would be funded by the loan. The outstanding loan balance will accrue interest at 12.0% per annum. The RSA payments will be made preferentially from project cash flow at a rate of 90% of increased cash created by the repairs and cash availability on a quarterly basis. The repairs were completed in January 2012. During the nine months ended September 30, 2015 and the year ended December 31, 2014, RREI made principal payments on the loan of $0 and $1,012,613; respectively. The balance of the loan, excluding accrued interest, at September 30, 2015 and December 31, 2014 was $368,249. The loan balance and related interest effects are fully eliminated during the consolidation process. On October 19, 2015, the RSA loan was paid in full.

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NOTE 12 – SUBSEQUENT EVENTS

The Company has evaluated events and transactions that have occurred after the balance sheet date through November 9, 2015, which is considered to be the issuance date. The following event was identified for disclosure:

Equipment Purchase
Subsequent to September 30, 2015, the Company entered into an agreement to acquire all of the major and long lead equipment for the construction of three binary geothermal power plants. The equipment was part of an order for six plant units by a geothermal developer, but only three had been installed. The components for the remaining three units have been held in storage and upon closing of the transaction will be moved to a Company owned site. The equipment is from the same manufacturers, and is of a similar size and design, to that installed at the Company’s Neal Hot Springs and San Emidio power plants. The design output of the acquired units totals approximately 35 megawatts. The Company will pay $1.5 million for the equipment.

-23-

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

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;
•	availability and costs of drilling rigs and field services;
•	our liquidity and ability to finance our exploration and development activities;
•	our working capital requirements and availability;
•	our illustrative plant economics;
•	market conditions in the geothermal energy industry; and
•	the impact of environmental and other governmental regulation.

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

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

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

• incorrect estimates of required capital expenditures;

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

• the enforceability of the power purchase agreements 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;

-24-

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

• our dependence on key personnel;

• the potential for claims arising from geothermal plant operations;

• general competitive conditions within the geothermal energy industry; and

• financial market conditions.

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

The U.S. dollar is the Company’s functional currency. 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 quarter ended September 30, 2015 and notes thereto included in this quarterly report and our filed Annual Report.

U.S. Geothermal Inc. (“the Company”) is a Delaware corporation. The Company’s common stock trades on the NYSE MKT LLC under the trade symbol “HTM” and on the Toronto Stock Exchange under the symbol “GTH”.

For the quarter ended September 30, 2015, the Company was focused on:

• operating and optimizing the Neal Hot Springs, San Emidio and Raft River power plants;

• drilling temperature gradient wells at San Emidio;

• completing a reservoir report, optimizing power plant design, working on permitting, and pursuing PPA and steam sale opportunities at the WGP Geysers project;

• drilling and testing a cooling water supply well at Neal Hot Springs;

• drilling a resource well at El Ceibillo and finalizing approval to incorporate the modified construction schedule in the concession agreement;

• supporting the Special Committee of the Board in their process to evaluate strategic alternatives to increase shareholder value; and

• evaluating potential new geothermal projects and acquisition opportunities.

Project Overview

The following is a list of projects that are in operation, under development or under exploration. Projects in operation currently have producing geothermal power plants. Projects under development have a geothermal resource discovery or may have wells in place, but require the drilling of new or additional production and injection wells in order to supply enough geothermal fluid sufficient to operate a commercial power plant. Projects under exploration do not have a geothermal resource discovery occurrence yet, but have significant thermal and other physical evidence that warrants the expenditure of capital in search of the discovery of a geothermal resource. Due to inflation and marketplace increases in the costs of labor and construction materials, estimates provided for project development costs could understate actual costs.

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

(1)	In September 2010, the Company’s wholly owned subsidiary (Oregon USG Holdings LLC) entered into agreements that formulated a strategic partnership with Enbridge (U.S.) Inc. (“Enbridge”). Enbridge contributed approximately $32.8 million to the Neal Hot Springs geothermal project. The Company’s equity interest in the project is 60% and Enbridge’s equity interest is 40%.
(2)	As part of the financing package for Unit I of the Raft River project, the Company contributed $16.5 million in cash and approximately $1.4 million in property to Raft River Energy I LLC, the Unit I project joint venture company. Raft River I Holdings, LLC, a subsidiary of The Goldman Sachs Group, contributed $34 million to finance the construction of the project.
(3)	Based on the designed annual average net output. The output of the Raft River Unit I plant currently is approximately 9.4 megawatts annual average.

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

Generation from the facility during the third quarter of 2015 totaled 33,497 megawatt-hours with an average of 15.4 net megawatts per hour of operation. Generation for the first three quarters of 2015 was 124,229 megawatt-hours. Plant availability was 98.5% during the quarter, and 97.6% for the nine months. A 2.5 day maintenance outage was taken on Unit 3 to replace to a high pressure feed pump under the terms of the Equipment Supply Agreement (“ESA”).

A settlement was reached with Turbine Air Systems under the terms of the ESA, and five of their key equipment suppliers on July 16, 2015. The settlement agreement provided a cash payment to the project company, USG Oregon LLC, a commitment to finalize equipment repairs and upgrades, and an extended warranty for equipment that is repaired or replaced.

A second water supply exploration well was drilled during the quarter seeking groundwater for a potential water cooling project to increase summer power generation at the project. The first well was drilled in May and found water, but was proven to be connected to nearby surface water and cannot be used due to State of Oregon regulations. The second well drilled also encountered water and was flow tested for a period of six weeks, was not connected to surface waters, and achieved steady state production at approximately 170 gpm. The minimum amount of water needed for a hybrid cooling system is approximately 200 gpm per module. Additional studies are being conducted to develop new fresh water drilling targets so we can continue exploring for a reliable water source to satisfy all three modules. A purchase or long term lease of existing surface water or groundwater rights is also being studied. An initial study of various hybrid cooling methods was completed by Power Engineers which confirms the economic viability of hybrid cooling if enough water can be found.

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 average price paid under the PPA for September 2015 was $106.79 per megawatt-hour.

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San Emidio Unit I, Nevada
The Unit I power plant at San Emidio is located approximately 100 miles north-east of Reno, Nevada near the town of Gerlach, and achieved commercial operation on May 25, 2012. The San Emidio facility is a single 14.7 megawatt (gross) module, with a design output of 9 megawatts (net) annual average based on a specific flow and temperature of geothermal brine.

Generation from the facility during the third quarter 2015 totaled 18,924 megawatt-hours, with an average of 8.7 net megawatts per hour of operation. Generation for the first three quarters of 2015 was 59,170 megawatt-hours. Plant availability was 98.9% during the quarter, and 99.6% for the nine months.

On June 1, 2011, an amended and restated PPA was signed with Sierra Pacific Power Company d/b/a NV Energy for the sale of up to 19.9 megawatts of electricity on an annual average basis. The PPA has a 25 year term with a base price of $89.75 per megawatt-hour, and an annual escalation rate of 1 percent. The average price paid under the PPA for 2015 is $92.08 per megawatt-hour.

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

Generation from the facility during the third quarter 2015 totaled 15,950 megawatt-hours, with an average of 8.7 net megawatts per hour of operation. Generation for the first three quarters of 2015 was 53,845 megawatt-hours. Plant availability was 82.7% during the quarter, which includes a 12.5 day unplanned maintenance outage in August that was required to replace the bearings on the two facility turbines. Availability for the first nine months averaged 93.8% .

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 average price paid under the PPA for 2015 is $62.00 per megawatt-hour.

In addition to the price paid for energy by Idaho Power, Raft River Unit I currently receives $4.75 per megawatt-hour under a separate contract for the sale of Renewable Energy Credits (“RECs”) to Holy Cross Energy, a Colorado electric cooperative. Starting in calendar year 2018, 51% of the RECs produced by the project will be owned by the Idaho Power Company and 49% by the project. For the 49% of RECs owned by the Raft River project, a new, 10 year REC contract with the Public Utility District No. 1 of Clallam County, Washington will replace the current contract. The Company currently receives 70% of the REC income during the term of the Holy Cross contract and will receive 50% of the REC income due to Raft River during the term of the Clallam County contract.

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Projects Under Development/Exploration

Projects Under Development
					Estimated
			Target	Projected	Capital
			Development	Commercial	Required	Power
Project	Location	Ownership	(Megawatts)	Operation Date	($million)	Purchaser
El Ceibillo Phase I	Guatemala	100%	25	2ndQuarter 2018	138	TBD
San Emidio Phase II	Nevada	100%	11	3rdQuarter 2017	65	TBD
WGP Geysers	California	100%	30	3rdQuarter 2017	160	TBD
Crescent Valley Phase I	Nevada	100%	25	1stQuarter 2018	141	TBD

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

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

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

Equipment Purchase
Subsequent to September 30, 2015, the Company entered into an agreement to acquire all of the major and long lead equipment for the construction of three binary geothermal power plants. The equipment was part of an order for six plant units by a geothermal developer, but only three had been installed. The components for the remaining three units have been held in storage and upon closing of the transaction will be moved to a Company owned site. The equipment is from the samemanufacturers, and is of a similar size and design, to that installed at the Company’s Neal Hot Springs and San Emidio power plants. The design output of the acquired units totals approximately 35 megawatts. The Company will pay $1.5 million for the equipment, which is approximately 5% of what the equipment originally cost, a saving of roughly over $28 million.

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

An extended flow test program of the three new wells with the highest production rate was completed in June 2015 confirming that the three largest wells were still open and ready for production. The fourth production well was used to inject the produced fluid and was not tested. GeothermEx Inc. (a Schlumberger company) designed the isochronal (step rate) flow test program and monitored the testing of the wells. A step rate test is designed such that each well is flowed at different rates through a fixed orifice, and the resulting pressure in the reservoir is measured both before, during and after the test. This data is used to determine the reservoirs potential size and production characteristics.

Based on this data, GeothermEx reported in September that the four production wells 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 longer term tests show the wells would initially produce a combined total of 458,000 pounds per hour of steam compared to 462,000 pounds per hour of steam from short term tests performed when the wells were first drilled, demonstrating that the capacity of the wells is virtually unchanged. Using the average steam production rate from these wells and an assumed interference factor of 30%, GeothermEx 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.

Two methods were used to estimate the long term capacity of the WGP project, and both support a high probability that a 28.8 MW (net) plant can be operated for 25 years, given the modern plant design and the available productive area. The first is the p/z method, an established natural gas reservoir engineering calculation that is routinely used at The Geysers. Based on the plant design and the increase in available injection that would result from WGP’s planned hybrid cooling system, GeothermEx estimates that the reservoir could support the 28.8 MW (net) plant for up to 54 years. The second method, which is an empirical approach based on GeothermEx’s extensive experience at The Geysers, was used to estimate the steam production capacity per acre within the productive area of a geothermal leasehold. On this basis, it was determined that the productive acreage within the WGP leasehold has steam reserves sufficient to supply up to 44 MW (net) with a conventional injection level of 25%, and potentially more at the higher injection levels associated with the planned hybrid cooling system.

Engineering optimization of the power plant design is continuing with a focus on the new hybrid plant design that includes both water and air cooling. This design will dramatically increase the volume of water available for injection back into the reservoir. Traditional water cooled steam plants re-inject approximately 20 to 25% of the water that is removed during power generation, while a hybrid design may re-inject 65% or more of the water. This higher injection rate will provide longer term, stable steam production, and will result in increased power generation over the life of the project.

Our transmission interconnection application is proceeding under the Independent Study Process that is being conducted by the California Independent System Operator. The first phase study, the Interconnection System Impact and Facilities Study Report was completed on October 8, 2015. The study shows that the interconnection is feasible and that the preliminary cost is estimated at $1.9 million. A new conditional use permit application was submitted to Sonoma County in June, which will replace the original conditional use permit that expired in July.

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El Ceibillo, Republic of Guatemala
A geothermal energy rights concession, located 14 kilometers southwest of Guatemala City, was awarded to U.S. Geothermal Guatemala S.A., a wholly owned subsidiary of the Company in April 2010. The concession has a five year term for the development and construction of a power plant. There are 24,710 acres (100 square kilometers) in the concession which is at the center of the Aqua and Pacaya twin volcano complex.

The modified development schedule was formally approved and signed by the Minister of the Guatemalan Ministry of Energy and Mines on July 21, 2015. A second step required for the change was completed on October 13, 2015 when the modified development schedule was formally incorporated into to the concession agreement. With the schedule modification and updated concession agreement now in place that provides a Commercial Operation Date during the second quarter of 2018, we will reestablish our discussions and negotiations for a Power Purchase Agreement.

A nine hole temperature gradient drilling program completed in 2014 outlined a high temperature anomaly in which two of the shallow wells intersected high temperature fluid, but not in commercial quantity. As a follow up to that program, well EC-2 was started on August 6, 2015, and after drilling to a depth of 667 feet (203 meters) the drill bit assembly became stuck and could not be retrieved. The hole was abandoned and replacement well EC-2A was started on September 3, 2015. Well EC-2A intersected a zone of high permeability at a depth of 1,300 feet (396 meters). Flow testing of EC-2A confirmed that a commercial resource has been discovered with a flowing temperature of 398°F (198.5°C) .

Based on the discovery at EC-2A, two additional wells have been sited to further extend the resource area to the south and west of the known high temperature permeability, and to test a deeper horizon in the system. Drill pads are being constructed and drilling of the next well is expected to begin within the next few weeks as weather allows. Pending the results of these two wells, a decision will be made on the location for a full production size well to fully test the resource to determine its size and production characteristics.

San Emidio, Nevada
The Phase II expansion is dependent on successful development of additional production and injection well capacity. We expect that approximately 75% of the Phase II development may be funded by project loans, with the remainder funded through equity financing. We anticipate the project qualifying for the 30% Federal investment tax credit.

Permits were received for a five hole temperature gradient drilling program in June, which was designed to follow up on past drilling activities and geophysical/structural models. A driller was mobilized to the site, and drilling started on July 27, 2015. Five 1,000 feet deep temperature gradient wells were completed. All of the wells encountered high bottom hole temperatures and anomalously high temperature gradients. Bottom hole temperatures ranged from 224°F to 274°F and temperature gradients in four of the wells ranged from 12.4°F/100’ in the hole with the highest bottom hole temperature to 14.9°F/100’ . These results are considered to be indicative of a nearby, active geothermal system at depth. A second phase program to deepen the two most prospective wells is being permitted with the Bureau of Land Management and is expected to be carried out during the fourth quarter, weather permitting. Additional temperature gradient wells to further expand the anomaly are also under consideration, but will have to be permitted separately after additional cultural surveys are done.

A Small Generator Interconnection Agreement for 16 megawatts of transmission capacity was executed with Sierra Pacific Power Company on December 28, 2010. An application to increase the interconnection agreement by 3.9 megawatts, to a total of 19.9 megawatts was submitted to NV Energy on January 9, 2014. Results from the System Impact Study, which is the first step in the interconnection process were received on December 24, 2014. The second phase interconnection study, called the Facilities Study, was started in January 2015 and was completed in June pending a decision by NV Energy on funding upgrades to the system. NV Energy decided not to fund the upgrades and completed the Interconnection System Impact Restudy on September 28. The Restudy determined that the interconnection is feasible, but with a significant increase in the estimated cost, due to a change in cost allocation by NV Energy. A meeting was held with NV Energy to discuss the results and anticipated costs in late October.

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Raft River, Idaho
The Raft River project was awarded an $11.4 million cost-shared, thermal stimulation program grant from the Department of Energy in 2011. The goal of the project is to create an Enhanced Geothermal System (“EGS”) by creating thermal fractures and developing a corresponding increase in permeability in the low permeability rock. Well RRG-9 was made available, and after installing four, 300 foot deep monitoring wells with seismic geophones to allow for seismic monitoring, the first stage of injection into the well began in June 2013. Initially the well was only capable of receiving 20 gallons per minute (“gpm”) of water due to the low permeability of the rock. After several moderate pressure stimulations, injection of power plant injectate has continued through the quarter, with flow into the well seeing a continuing increase from its initial 20 gpm to currently over 785 gpm, indicating a tremendous success.

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

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

In light of federal legislation that extended the qualification for the 30% Investment Tax Credit to projects that began construction prior to December 31, 2014, drilling of the first production/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 27th 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 next phase of development work is in the planning stages and will be dependent upon market conditions.

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Operating Results

For the nine months ended September 30, 2015, the Company reported net income attributable to the Company of $781,179 ($0.01 income per share) which represented an increase $512,791 (191.1% increase) from net income attributable to the Company of $268,388 reported in the same period ended 2014 ($0.00 income per share). For the three months ended September 30, 2015, the Company reported net income attributable to the Company of $280,864 ($0.00 income per share) which represented an increase of $199,084 (243.4% increase) from net income attributable to the Company of $81,780 reported in the same period ended 2014 ($0.00 income per share). Both favorable and unfavorable variances were reported related to the operations of the Company’s three power plants. Favorable variances were noted for salary and wages, stock based compensation and net income/loss attributable to non-controlling interests. A notable unfavorable variance was reported in income tax expense.

Plant Operations

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

	For the Nine Months Ended September 30,
	2015		2014
	$	%	$	%
Energy sales by plant:
Neal Hot Springs, Oregon	12,400,157	59.0	12,381,761	59.5
San Emidio, Nevada	5,448,729	25.9	5,048,736	24.3
Raft River, Idaho	3,160,292	15.1	3,379,757	16.2
	21,009,178	100.0	20,810,254	100.0

%- represents the percentage of total Company energy sales.

	For the Three Months Ended September 30,
	2015		2014
	$	%	$	%
Energy sales by plant:
Neal Hot Springs, Oregon	4,004,715	58.5	3,712,988	55.9
San Emidio, Nevada	1,742,750	25.4	1,663,119	25.0
Raft River, Idaho	1,106,643	16.1	1,273,013	19.1
	6,854,108	100.0	6,649,120	100.0

%- represents the percentage of total Company energy sales.

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

		For the Quarter Ended,
	September 30,	December 31,	March 31,	June 30,	September 30,
	2014	2014	2015	2015	2015
Neal Hot Spring, Oregon	32,246	54,472	53,500	37,232	33,498
San Emidio, Nevada	18,240	21,745	21,754	18,492	18,924
Raft River, Idaho	18,501	20,614	20,672	17,223	15,950
	68,987	96,831	95,926	72,947	68,372

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

For the nine months ended September 30, 2015, subsidiary net income was $5,689,221 which was an increase of $10,344 (0.2% increase) from subsidiary net income of $5,678,877 from the same period ended 2014. For the three months ended September 30, 2015, subsidiary net income was $1,651,029 which was an increase of $238,905 (16.9% increase) from subsidiary net income of $1,412,124 from the same period ended 2014.

Overall, energy sales for the nine months ended September 30, 2015 was consistent with the same period ended 2014. The contracted rate increase offset the decrease in energy production that occurred in the first and second quarter 2015. In quarter ended March 31, 2015, the plant’s three units experienced a total of 192 hours of lost production. The two primary causes for the outages were plugged vaporizers and a generator re-alignment needed at Unit 3. In the quarter ended June 30, 2015, the plant experienced 424 hours of planned lost production for general repairs and inspections. In the quarter ended September 30, 2015, the plant’s production increased 3.88% compared to the same quarter in 2014. In the current quarter, the three units lost a total of 104 hours of production. The largest losses were incurred at Unit 3 (73 total lost hours), which experienced difficulties with the refrigerant feed pumps.

Plant operating costs, excluding depreciation and amortization, for the nine months ended September 30, 2015, increased $162,418 which was a 5.7% ($161,985, which was a 17.0% increase for the three months ended September 30, 2015) from the same period ended 2014. For the current nine months, salaries and related costs increased $167,952 ($1,873 increase for the current three months). The compensation increases were due to the employee bonuses, wage increases and increases in workers’ compensation premiums. On March 31, 2015, the plant employees were awarded a bonus that totaled $83,179. Average wage increases of 2.5% were awarded to plant employees in April 2015. The additional time and increases in workers’ compensation costs resulted in increases of approximately $24,700 for the nine months ended September 30, 2015 ($227 for the three months ended September 30, 2015). In addition to compensation increases, a major planned purchase of refrigerant was made for $91,505 in the current quarter.

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

			Nine Months Ended September 30,
	2015				2014				Variance
	$		%		$		%		$		%*
Plant revenues:
Energy sales	12,400,157		100.0		12,381,760		100.0		18,397		0.1
Plant expenses:
General operations	3,000,677		24.2		2,838,259		22.9		(162,418	)	(5.7	)
Depreciation and amortization	2,458,942		19.8		2,443,525		19.8		(15,417	)	(0.6	)
	5,459,619		44.0		5,281,784		42.7		(177,835	)	(3.4	)
Gross Profit	6,940,538		56.0		7,099,976		57.3		(159,438	)	(2.2	)
Other income (expense):
Interest expense	(1,258,480	)	(10.1	)	(1,436,902	)	(11.6	)	178,422		12.4
Other and interest income	7,163		0.0		15,803		0.1		(8,640	)	(54.7	)
	(1,251,317	)	(10.1	)	(1,421,099	)	(11.5	)	169,782		11.9
Subsidiary Net Income	5,689,221		45.9		5,678,877		45.8		10,344		0.2

%- represents the percentage of total plant operating revenues.
%*- represents the percentage of change from 2014 to 2015.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,
	2015				2014				Variance
	$		%		$		%		$		%*
Plant revenues:
Energy sales	4,004,715		100.0		3,712,988		100.0		291,727		7.9
Plant expenses:
General operations	1,115,298		27.8		953,313		25.7		(161,985	)	(17.0	)
Depreciation and amortization	819,450		20.5		805,497		21.7		(13,953	)	(1.7	)
	1,934,748		48.3		1,758,810		47.4		(175,938	)	(10.0	)
Gross Profit	2,069,967		51.7		1,954,178		52.6		115,789		5.9
Other income (expense):
Interest expense	(421,050	)	(10.5	)	(546,676	)	(14.7	)	125,626		23.0
Other and interest income	2,112		0.0		4,622		0.1		(2,510	)	(54.3	)
	(418,938	)	(10.5	)	(542,054	)	(14.6	)	123,116		22.7
Subsidiary Net Income	1,651,029		41.2		1,412,124		38.0		238,905		16.9

%- represents the percentage of total plant operating revenues.
%*- represents the percentage of change from 2014 to 2015.Increases in revenues and decreases in expenses from the prior period to the current period are considered to be favorable and are presented as positive figures.

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

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Key quarterly production data for 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, 2013	25,832	2,875,686	110.9	829,374	810,573
December 31, 2013	53,445	6,058,169	113.3	3,644,359	812,766
March 31, 2014	56,047	5,266,454	93.8	3,070,349	817,503
June 30, 2014	40,629	3,403,812	83.7	1,196,404	820,526
September 30, 2014	32,246	3,717,609	115.0	1,412,124	805,497
December 31, 2014	54,472	6,378,488	117.1	4,147,356	819,924
March 31, 2015	53,500	5,207,350	97.3	3,010,263	819,708
June 30, 2015	37,232	3,188,091	85.6	1,027,928	819,785
September 30, 2015	33,498	4,004,715	119.3	1,651,029	819,450

* - 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, 2015, the San Emidio plant reported subsidiary net income of $1,206,744 which was an increase of $877,303 (266.3% increase) from the $329,411 in subsidiary net income reported in the same period ended 2014. For the three months ended September 30, 2015, the San Emidio plant reported subsidiary net income of $386,033 which was an increase of $276,518 (252.5% increase) from the $109,515 in subsidiary net income reported in the same period ended 2014.

During the current nine months, the plant produced 59,171 megawatt hours (18,924 megawatt hours current three months), which was a 7.3% increase (3.8% current three month increase) from the same periods ended 2014. The increase production levels reported in the current periods were due to the lower production in the prior year (primarily the second quarter 2014). In April 2014, the plant lost 415 hours of production during the planned shutdown which was more than the 120 hours (71.1% decrease) needed for the planned shut down in April 2015. The 2014 outage had required additional time to perform turbine warranty modifications. In the current quarter, the plant lost a total of 21 hours of production as opposed to 87 hours lost in the same quarter in 2014.

For the nine months ended September 30, 2015, the total operating costs, excluding depreciation, decreased $393,398 ($105,830 for the three months ended September 30, 2015), which was a 17.9% decrease (14.7% decrease for three months ended September 30, 2015) from the same period ended 2014. Three significant cost component variances were salaries, field maintenance and taxes. On March 31, 2015, the plant employees were awarded a bonus that totaled $62,523. Average wage increases of 2.5% were awarded to plant employees in April 2015. In the nine months ended September 30, 2014, repair costs that exceeded $144,600 were incurred to repair a brine injection pump and to upgrade the well/plant communication software. In the three months ended September 30, 2014, repair costs that exceeded $59,790 were incurred on production pump replacements, cooling system repairs and electrical system upgrades.

The minerals proceeds tax for the State of Nevada decreased approximately $78,000 from the nine months ended September 30, 2014, due to changes in tax calculation methods and the higher operating costs reported in the prior year.

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

			Nine Months Ended September 30,
	2015				2014				Variance
	$		%		$		%		$		%*
Plant revenues:
Energy sales	5,448,729		100.0		5,048,736		100.0		399,993		7.9
Plant expenses:
Operations	1,828,276		33.6		2,226,674		44.1		398,398		17.9
Depreciation and amortization	947,132		17.4		945,828		18.7		(1,304	)	(0.1	)
	2,775,408		51.0		3,172,502		62.8		397,094		12.5
Gross Profit	2,673,321		49.1		1,876,234		37.2		797,087		42.5
Other income (expense):
Interest expense	(1,527,335	)	(28.0	)	(1,546,958	)	(30.6	)	19,623		1.3
Other income	60,758		1.1		165		0.0		60,593		#
	(1,466,577	)	(26.9	)	(1,546,793	)	(30.6	)	80,216		5.2
Subsidiary Net Income	1,206,744		22.1		329,441		6.6		877,303		266.3

%- represents the percentage of total plant operating revenues.
%*- represents the percentage of change from 2014 to 2015.Increases in revenues and decreases in expenses from the prior period to the current period are considered to be favorable and are presented as positive figures.
#- Variance percentage was extremely high or undefined.

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

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			Three Months Ended September 30,
	2015				2014				Variance
	$		%		$		%		$	%*
Plant revenues:
Energy sales	1,742,750		100.0		1,663,119		100.0		79,631	4.8
Plant expenses:
Operations	616,531		35.4		722,361		43.5		105,830	14.7
Depreciation and amortization	314,940		18.0		316,638		19.0		1,698	0.5
	931,471		53.4		1,038,999		62.5		107,528	10.3
Gross Profit	811,279		46.6		624,120		37.5		187,159	30.0
Other income (expense):
Interest expense	(484,849	)	(27.8	)	(514,693	)	(30.9	)	29,844	5.8
Other income	59,603		3.4		88		0.0		59,515	#
	(425,246	)	(24.4	)	(514,605	)	(30.9	)	89,359	17.4
Subsidiary Net Income	386,033		22.2		109,515		6.6		276,518	252.5

%- represents the percentage of total plant operating revenues.
%*- represents the percentage of change from 2014 to 2015.Increases in revenues and decreases in expenses from the prior period to the current period are considered to be favorable and are presented as positive figures.

#- Variance percentage was extremely high or undefined.

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

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

	Mega-		Ave. Rate	Subsidiary		Depreciation
	watt	Energy	per	Net Income		&
	Hours	Sales	Megawatt	(Loss)*		Amortization
Quarter Ended:	Produced	($)	Hour ($)	($)		($)
September 30, 2013	18,317	1,531,260	83.6	355,498		307,854
December 31, 2013	21,112	1,905,813	90.3	180,931		312,273
March 31, 2014	21,223	1,935,091	91.2	423,350		312,908
June 30, 2014	15,686	1,450,526	92.5	(203,424	)	316,283
September 30, 2014	18,240	1,663,119	91.2	109,515		316,638
December 31, 2014	21,745	1,982,709	91.2	158,352		315,609
March 31, 2015	21,754	2,003,346	92.1	556,301		316,346
June 30, 2015	18,492	1,702,633	92.1	264,410		315,846
September 30, 2015	18,924	1,742,750	92.1	386,033		314,940

*-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

The net loss from Raft River Energy I LLC (“RREI”) operations of $1,062,437 for the nine months ended September 30, 2015, unfavorably increased by $661,898 (165.3% increase) from the net loss for the same period ended 2014. The net loss from RREI operations of $296,743 for the three months ended September 30, 2015, decreased by $414,024 (353.0% decrease) from the net profit for the same period ended 2014.

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During the current nine months, the plant produced 53,845 megawatt hours (15,950 megawatt hours current three months), which was a 7.5% decrease (13.8% current three month decrease) from the same periods ended 2014. In August 2015, the plant lost 371 hours during two unplanned outages needed for additional turbine repairs.

Plant operating costs, excluding depreciation, increased $459,045 for the nine months ended September 30, 2015 ($228,417 for the three months ended September 30, 2015), which was a 17.1% increase (28.7% increase for the three months ended September 30, 2015) from the same periods ended 2014. The increases were primarily due to increases in maintenance and salary costs. The scheduled turbine overhaul was completed in June 2015. After the initial overhaul, the turbine coupling insulating kit was compromised which created the need for a second turbine outage for bearing replacement that was completed in August 2015. For the nine months ended September 30, 2015, the turbine repairs exceeded $361,500 ($194,000 for the three months ended September 30, 2015). In the current quarter, repairs of approximately $46,700 were made to the brine injection pump due to a bearing failure.

Salaries and related costs increased $142,300 from the same nine month ($54,681 from the same three month) period ended 2014. In March 2015, the plant employees were awarded a bonus that totaled $55,431. The remaining portion of the salary increase was primarily due to general wage increases awarded in April 2015 that averaged 2.5% .

The summarized statements of operations for RREI are as follows:

			Nine Months Ended September 30,
	2015				2014				Variance
	$		%		$		%		$		%*
Plant revenues:
Energy sales	3,160,292		91.9		3,379,757		92.5		(219,465	)	(6.5	)
Energy credit sales	255,710		8.1		274,590		7.5		(18,880	)	(6.9	)
	3,416,002		100.0		3,654,347		100.0		(238,345	)	(6.5	)
Plant expenses:
General operations	3,150,139		95.2		2,691,094		73.6		(459,045	)	(17.1	)
Depreciation and amortization	1,314,146		39.0		1,285,251		35.2		(28,895	)	(2.2	)
	4,464,285		134.2		3,976,345		108.8		(487,940	)	(12.3	)
Gross Profit (Loss)	(1,048,283	)	(34.2	)	(321,998	)	(8.8	)	(726,285	)	(225.6	)
Other income (expense):
Interest expense	(36,386	)	(1.1	)	(81,557	)	(2.2	)	45,171		55.4
Other and interest income	22,232		1.0		3,016		0.1		19,216		#
	(14,154	)	(0.1	)	(78,541	)	(2.1	)	64,387		82.0
Subsidiary Net Loss	(1,062,437	)	(34.3	)	(400,539	)	(10.9	)	(661,898	)	165.3

%- represents the percentage of total plant operating revenues.
%*- represents the percentage of change from 2014 to 2015.Increases in revenues and decreases in expenses from the prior period to the current period are considered to be favorable and are presented as positive figures.
#- Variance percentage was extremely high or undefined.

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,
	2015				2014				Variance
	$		%		$		%		$		%*
Plant revenues:
Energy sales	1,106,643		93.6		1,273,013		93.5		(166,370	)	(13.1	)
Energy credit sales	75,739		6.4		87,885		6.5		(12,146	)	(13.8	)
	1,182,382		100.0		1,360,898		100.0		(178,516	)	(13.1	)
Plant expenses:
General operations	1,023,589		86.6		795,172		58.5		(228,417	)	(28.7	)
Depreciation and amortization	443,233		37.5		429,164		31.5		(14,069	)	(3.3	)
	1,466,822		124.1		1,224,336		90.0		(242,486	)	(19.8	)
Gross Profit (Loss)	(284,440	)	(24.1	)	136,562		10.0		(421,002	)	(308.3	)
Other income (expense):
Interest expense	(12,590	)	(1.0	)	(21,830	)	(1.6	)	9,240		(42.3	)
Other and interest income	287		0.0		2,549		0.2		(2,262	)	(88.7	)
	(12,303	)	(1.0	)	(19,281	)	(1.4	)	6,978		(36.2	)
Subsidiary Net Loss	(296,743	)	(25.1	)	117,281		8.6		(414,024	)	(353.0	)

%- represents the percentage of total plant operating revenues.
%*- represents the percentage of change from 2014 to 2015.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 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, 2013	18,687	1,260,124	69.5	(1,166	)	450,222
December 31, 2013	21,951	1,479,499	69.0	254,302		450,222
March 31, 2014	21,614	1,199,550	57.9	61,749		427,907
June 30, 2014	18,069	907,194	52.6	(579,569	)	428,180
September 30, 2014	18,501	1,273,013	71.2	117,281		429,164
December 31, 2014	20,614	1,425,811	71.3	203,414		431,214
March 31, 2015	20,672	1,165,050	58.5	(96,930	)	431,959
June 30, 2015	17,223	888,599	54.1	(668,764	)	438,955
September 30, 2015	15,950	1,106,643	71.2	(296,743	)	443,233

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

Salaries and Wages
For the nine months ended September 30, 2015, the Company reported $1,324,920 in salaries and wages which was a $148,086 (10.1%) decrease from $1,473,006 reported in the same period ended in 2014. For the three months ended September 30, 2015, the Company reported $388,125 in salaries and wages which was a $12,825 (3.2% decrease) from $400,950 reported in the same period ended in 2014. Salaries and wages primarily represent the compensation earned by management, administrative and development employees. Both salary levels and number of employees were consistent with the same periods in the prior year; however, more salary costs were allocated to capital projects. For the nine months ended September 30, 2015, over $345,000 in salary costs were allocated to the WGP Geysers, Crescent Valley, and San Emidio Phase II projects. For the nine months ended September 30, 2014, over $252,000 in salary costs were allocated to those projects.

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Stock Based Compensation
For the nine months ended September 30, 2015, the Company reported a decrease of $120,284 (10.9% decrease) in stock based compensation from the same period ended 2014. For the three months ended September 30, 2015, the Company reported a decrease of $38,491 (12.0% decrease) from the same period ended 2014. The primary factors for the decreases were the timing of the stock option and the restricted share grants and the lower stock prices. Stock options of 2,060,000 and 450,000 were granted to employees and directors on May 15, 2015, and June 26, 2015; respectively. Restricted shares of 235,000 and 193,396 were granted to employees and directors on May 15, 2015 and June 26, 2015; respectively. In the prior year, the Company awarded employees 2,883,500 stock options and 559,122 restricted shares on April 2, 2014. Since the awards were granted later, the calculated cost of the options and restricted shares were lower than the same periods in 2014. During the nine months ended September 30, 2015, the Company’s common stock closing price reached a high of $0.67 and a low of $0.44 ($0.52 average daily closing price). During the nine months ended September 30, 2014, the Company’s common stock closing price reached a high of $0.95 and a low of $0.38 ($0.62 average daily closing price).

The stock based compensation components are summarized as follows:

	For the Nine Months Ended
	September 30,
	2015	2014	Variances
	$	$	$		%
Total Stock Based Compensation:
Stock option compensation	681,315	911,010	(229,695	)	(25.2	)
Stock compensation (restricted shares)	297,172	187,761	109,411		58.3
	978,487	1,098,771	(120,284	)	(10.9	)

%- represents the percentage of change from 2014 to 2015.

	For the Three Months Ended
	September 30,
	2015	2014	Variances
	$	$	$		%
Total Stock Based Compensation:
Stock option compensation	222,525	248,620	(26,095	)	(10.5	)
Stock compensation (restricted shares)	60,290	72,686	(12,396	)	(17.1	)
	282,815	321,306	(38,491	)	(12.0	)

%- represents the percentage of change from 2014 to 2015.

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Net Income Tax Expense
For the nine months ended September 30, 2015, the Company reported net income taxes of $473,000 ($170,000 for the three months ended September 30, 2015). No income tax expense was recognized in the same period ended 2014. As of December 31, 2014, management believed that the “more likely than not” standard had been met to enable the Company to fully recognize the net deferred tax asset. In the prior periods, including the nine months ended September 30, 2014, the net deferred tax asset was recognized to the extent of current period earnings. The current income tax expense represents the estimated consolidated income tax expense, less the impact of the estimated portion that belongs to the non-controlling interest entities.

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, 2015, the Company reported $1,028,934 in net income attributable to non-controlling interests, which was a decrease of $637,257 (38.2% decrease) from the $1,666,191 net income reported in the same period ended 2014. For the three months ended September 30, 2015, the Company reported $314,215 in net income attributable to non-controlling interests, which was a decrease of $299,822 (48.8% decrease) from the $614,037 net income reported in the same period ended 2014. The primary components of the variances were the operations of Raft River Energy I LLC (“RREI”) which reported a subsidiary net loss for the nine and three months ended September 30, 2015 of $1,062,437 and $296,743, respectively. The losses increased for the nine months and three months ended September 30, 2015 by $661,898 (165.3% increase) and $414,024 (353.0% increase); respectively. RREI’s profits and losses are allocated based upon the terms of the partnership agreement. The primary factors for the RREI loss increases were discussed above.

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

	For the Nine Months Ended
	September 30,
Subsidiaries and Non-Controlling	2015		2014		Variances
Interest Entities	$		$		$		%
Oregon USG Holdings LLC interest held by Enbridge Inc.	2,272,489		2,259,557		12,932		0.6
Raft River Energy I LLC interest held by Raft River I Holdings, LLC	(1,228,253	)	(585,999	)	(642,254	)	(109.6	)
Gerlach Geothermal LLC interest held by Gerlach Green Energy, LLC	(15,302	)	(7,367	)	(7,935	)	(107.7	)
	1,028,934		1,666,191		(637,257	)	(38.2	)

%- represents the percentage of change from 2014 to 2015.
#- Variance percentage was extremely high or undefined.

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	For the Three Months Ended
	September 30,
Subsidiaries and Non-Controlling	2015		2014		Variances
Interest Entities	$		$		$		%
Oregon USG Holdings LLC interest held by Enbridge Inc.	660,412		564,850		95,562		16.9
Raft River Energy I LLC interest held by Raft River I Holdings, LLC	(346,035	)	55,467		(401,502	)	(723.9	)
Gerlach Geothermal LLC interest held by Gerlach Green Energy, LLC	(162	)	(6,280	)	6,118		97.4
	314,215		614,037		(299,822	)	(48.8	)

%- represents the percentage of change from 2014 to 2015.
#- Variance percentage was extremely high or undefined.

Non-Controlling Interests
The following is a summarized presentation of select financial line items from the statement of operations by project and the impact of the related non-controlling interests for the nine months ended September 30, 2015:

							Exploration
	Neal Hot						Activities and		Consolid-
	Springs		San Emidio		Raft River		Corporate		ated
Statement of Operations Element	$		$		$		$		$
Gross Profit (Loss)	6,940,538		2,673,321		(1,048,282	)	671,501		9,237,078
Expenses/(Income)	1,259,317		1,466,577		(21,335	)	(4)4,249,406		6,953,965
Net Income(Loss) before tax expense	5,681,221		1,206,744		(1,026,947	)	(3,577,905	)	2,283,113
Income taxes – USG Portion	(1,285,000	)	(455,000	)	(76,000	)	1,343,000		(473,000	)
Non-controlling interests	(1)(2,272,488)		-		(2)1,228,254		(3)15,300		(1,028,934	)
Net income attributable to U.S. Geothermal	2,123,733		751,744		125,307		(2,219,605	)	781,179

(1)	The non-controlling interests for Neal Hot Springs represent a 40% interest for our joint venture partner, Enbridge.
(2)	The non-controlling interests for Raft River represent 30% of REC income and 99% of all other income/expenses for Raft River I Holdings, a subsidiary of Goldman Sachs Group.
(3)	The non-controlling interests for our exploration activities represents an approximately 33% 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, 2015 included:

•	Salaries and wages	$	1,324,920
•	Stock based compensation		978,487
•	Corporate administration		886,485
•	Professional fees		818,697

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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Off Balance Sheet Arrangements

As of September 30, 2015, the Company does not have any off balance sheet arrangements.

Liquidity and Capital Resources

We believe our cash and liquid investments at September 30, 2015 are adequate to fund our general operating activities through December 31, 2016. Advancement of our projects under development and under exploration may require additional funding. We anticipate that additional funding may be raised through financial and strategic partnerships, market loans, issuance of debt or equity, project refinancing, obtaining letters of credit, and/or through the sale of ownership interest in tax credits and benefits. The Company continues discussions with potential investors/financers to evaluate alternatives for funding at the corporate and project levels.

Our power is sold under long-term contracts at fixed prices to large utilities. The status of the credit and equity markets could delay our project development activities while we seek to obtain economic credit terms or a favorable equity market price to further the drilling and construction activities.

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

On August 10, 2015, the Company announced that its Board of Directors had approved a stock repurchase program, pursuant to which the Company is authorized to repurchase, from time to time, up to $2 million of its outstanding common stock through the end of July 2016. The extent to which the Company repurchases its common stock and the timing of the repurchases will depend upon market conditions and other corporate considerations. The Company intends to pay for any stock repurchased with existing cash balances. To date, the Company has not purchased any shares under this program.

Potential Acquisitions

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

Critical Accounting Policies

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

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

Item 3 – Quantitative and Qualitative Disclosures about Market Risk

Not applicable.

Item 4 - Controls and Procedures

An evaluation was performed under the supervision and with the participation of our management, including the Chief Executive Officer (“CEO”) and 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 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 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 three months ended September 30, 2015 that has materially affected, or is 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

See “Risk Factors” in our Annual Report. There have been no material changes in the risk factors during the three months ended September 30, 2015.

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, 2015	By:/s/ Dennis J. Gilles
	Dennis J. Gilles
	Chief Executive Officer
Date: November 9, 2015
	By:/s/ Kerry D. Hawkley
	Kerry D. Hawkley
	Chief Financial Officer and Corporate Secretary

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EXHIBIT INDEX

Exhibit Number	Description
31.1	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1	Certification of Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2	Certification of Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema Document
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB	XBRL Taxonomy Extension Label Linkbase Document
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

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