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

FORM 10-Q

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

For the quarterly period ended March 31, 2017

or

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

For the transition period from ____________ to ___________

Commission File Number: 001-34023

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

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

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

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

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

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

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

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

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

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

Class	Shares Outstanding as of May 5, 2017
Common stock, par value	19,039,435
$ 0.001 per share

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U.S. Geothermal Inc.
Form 10-Q
For the Three Months Ended March 31, 2017

INDEX

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PART I – FINANCIAL INFORMATION

Item 1 – Consolidated Financial Statements

U.S. GEOTHERMAL INC.
CONSOLIDATED BALANCE SHEETS

		(Unaudited)
		March 31,			December 31,
		2017			2016
ASSETS
Current:
Cash and cash equivalents	$	13,068,978		$	15,287,144
Restricted cash and security bonds		9,815,136			8,527,462
Trade accounts receivable		4,469,804			4,102,018
Other current assets		1,668,734			1,664,866
Total current assets		29,022,652			29,581,490
Restricted cash and security bond reserves		18,605,059			20,111,350
Property, plant and equipment, net		169,622,415			170,301,349
Intangible assets, net		15,038,722			15,084,143
Net deferred income tax asset		8,211,000			8,346,000
Total assets	$	240,499,848		$	243,424,332
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts payable and accrued liabilities	$	2,232,844		$	2,255,710
Current portion of notes payable		3,892,026			4,259,595
Total current liabilities		6,124,870			6,515,305
Long-term Liabilities:
Asset retirement obligations		1,219,903			1,219,903
Notes payable, less current portion		102,279,570			104,131,086
Total long-term liabilities		103,499,473			105,350,989
Total liabilities		109,624,343			111,866,294
Commitments and Contingencies (note 10)
STOCKHOLDERS’ EQUITY
Capital stock (authorized: 250,000,000 common shares with a $0.001 par value; issued and outstanding shares at March 31, 2017 and December 31, 2016 were: 19,039,435and 18,970,445; respectively)		19,039			18,970
Additional paid-in capital		122,448,633			121,933,378
Accumulated deficit		(16,713,410	)		(16,974,300	)
		105,754,262			104,978,048
Non-controlling interests		25,121,243			26,579,990
Total stockholders’ equity		130,875,505			131,558,038
Total liabilities and stockholders’ equity	$	240,499,848		$	243,424,332

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

		(Unaudited)
		For the Three Months Ended March 31,
		2017			2016
Plant Revenues:
Energy sales	$	8,334,450		$	8,410,822
Energy credit sales		102,619			92,454
Total plant operating revenues		8,437,069			8,503,276
Plant Expenses:
Plant production expenses		2,946,072			2,398,716
Depreciation and amortization		1,632,748			1,580,863
Total plant operating expenses		4,578,820			3,979,579
Gross Profit		3,858,249			4,523,697
Operating Expenses:
Corporate administration		303,706			354,046
Professional and management fees		145,765			1,056,509
Employee compensation		911,734			806,669
Promotion		36,835			83,412
Exploration		28,190			21,266
Operating Income		2,432,019			2,201,795
Other (income) expenses:
Interest expense		1,188,271			933,692
Other (income) expense		(14,738	)		(9,692	)
Income Before Income Tax Expense		1,258,486			1,277,795
Income tax expense		135,000			90,000
Net Income		1,123,486			1,187,795
Net income attributable to the non-controlling interests		(862,596	)		(1,036,403	)
Net Income Attributable to U.S. Geothermal Inc.	$	260,890		$	151,392
Net Earnings Per Share Attributable to U.S. Geothermal Inc.:
Basic	$	0.01		$	0.01
Diluted		0.01			0.01
Weighted average number of shares used in the calculation of income per share:
Basic		18,951,468			18,233,778
Diluted		19,285,288			18,547,035

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

		(Unaudited)
		For the Three Months Ended March 31,
		2017			2016
Operating Activities:
Net Income	$	1,123,486		$	1,187,795
Adjustments to reconcile net income to total cash provided by operating activities:
Depreciation and amortization		1,689,173			1,613,521
Stock based compensation		324,690			277,315
Change in deferred income taxes		135,000			90,000
Net changes in:
Trade accounts receivable		(367,786	)		1,407,371
Accounts payable and accrued liabilities		40,533			478,507
Prepaid expenses and other		(3,868	)		(50,810	)
Total cash provided by operating activities		2,941,228			5,003,699
Investing Activities:
Purchases of property, plant and equipment		(1,269,749	)		(1,501,101	)
Grant reimbursement on construction		270,856			-
Net proceeds from (funding of) restricted cash reserves and bonds		218,617			(110,955	)
Total cash used by investing activities		(780,276	)		(1,612,056	)
Financing Activities:
Issuance of common stock		190,634			1,258,385
Distributions to non-controlling interest		(2,321,343	)		(2,451,484	)
Principal payments on notes payable and other obligations		(2,248,409	)		(3,421,317	)
Total cash used by financing activities		(4,379,118	)		(4,614,416	)
Decrease in Cash and Cash Equivalents		(2,218,166	)		(1,222,773	)
Cash and Cash Equivalents, Beginning of Year		15,287,144			8,654,375
Cash and Cash Equivalents, End of Year	$	13,068,978		$	7,431,602
Supplemental Disclosures:
Non-cash investing and financing activities:
Accrual for purchases of property and equipment	$	63,399		$	803,144
Other Items:
Interest paid		1,855,640			1,361,349

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

The accompanying notes are an integral part of these consolidated financial statements.
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U.S. GEOTHERMAL INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Unaudited
March 31, 2017

NOTE 1 - ORGANIZATION AND DESCRIPTION OF BUSINESS

U.S. Geothermal Inc. (“the Company”) was incorporated on March 10, 2000 in the State of Delaware. U.S. Geothermal Inc. – Idaho was formed in February 2002, and is the primary subsidiary through which the Company conducts its operations. The Company constructs, owns, manages and operates power plants that utilize geothermal resources to produce renewable energy. The Company’s operations have been, primarily, focused in the United States and Central America.

Basis of Presentation

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 March 31, 2017 and our operating results and cash flows for the three months ended March 31, 2017 and 2016. The accompanying financial information as of December 31, 2016, is derived from audited financial statements. Interim results are not necessarily indicative of results for a full year. The information included in this Quarterly Report on Form 10-Q should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2016.

The Company consolidates subsidiaries that it controls (more-than-50% owned) and entities over which control is achieved through means other than voting rights. These consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries, as well as three controlling interests. The accounts of the following companies are consolidated in these financial statements:

	i)	U.S. Geothermal Inc. (incorporated in the State of Delaware);
	ii)	U.S. Geothermal Inc. (incorporated in the State of Idaho);
	iii)	U.S. Geothermal Services, LLC (organized in the State of Delaware);
	iv)	Nevada USG Holdings, LLC (organized in the State of Delaware);
	v)	USG Nevada LLC (organized in the State of Delaware);
	vi)	Nevada North USG Holdings, LLC (organized in the State of Delaware);
	vii)	USG Nevada North, LLC (organized in the State of Delaware);
	viii)	Oregon USG Holdings, LLC (organized in the State of Delaware);
	ix)	USG Oregon LLC (organized in the State of Delaware);
	x)	Raft River Energy I LLC (organized in the State of Delaware);
	xi)	Gerlach Geothermal LLC (organized in the State of Delaware);
	xii)	USG Gerlach LLC (organized in the State of Delaware);
	xiii)	U.S. Geothermal Guatemala, S.A. (organized in Guatemala);
	xiv)	Geysers USG Holdings Inc. (incorporated in the State of Delaware);
	xv)	Western GeoPower, Inc. (incorporated in the State of California);
	xvi)	USG Mayacamas Inc. (incorporated in the State of Delaware));
	xvii)	Mayacamas Energy LLC (organized in the State of California);
	xviii)	Skyline Geothermal LLC (organized in the State of Delaware);
	xix)	Skyline Geothermal Holding, Inc. (incorporated in the State of Delaware);
	xx)	Earth Power Resources Inc. (incorporated in Delaware); and
	xxi)	Idaho USG Holdings LLC (organized in the State of Delaware).

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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 income and 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 and short-term deposits, with original maturities of no more than ninety days when acquired to be cash and cash equivalents.

Trade Accounts Receivable Allowance for Doubtful Accounts

Management estimates the amount of trade accounts receivable that may not be collectible and records an allowance for doubtful accounts. The allowance is an estimate based upon aging of receivable balances, historical collection experience, and the periodic credit evaluations of our customers’ financial condition. Receivable balances are written off when we determine that the balance is uncollectible. As of March 31, 2017 and December 31, 2016, there were no balances that were over 90 days past due and no balance in allowance for doubtful accounts was recognized.

Concentration of Credit Risk

The Company’s cash and cash equivalents, including restricted cash, consisted of commercial bank deposits, money market accounts, and petty cash. Cash deposits are held in commercial banks in Boise, Idaho and Portland, Oregon. Deposits are guaranteed by the Federal Deposit Insurance Corporation (“FDIC”) up to $250,000 per legal entity. At March 31, 2017, the Company’s total cash balance, excluding money market funds, was $7,376,783 and bank deposits amounted to $7,830,480. The primary difference was due to outstanding checks and deposits. Of the bank deposits, $6,514,547 was not covered by or was in excess of FDIC insurance guaranteed limits. At March 31, 2017, the Company’s money market funds invested, primarily, in government backed securities totaled $32,639,791 and were not subject to deposit insurance. A contracted power purchaser held a security bond for the Company that totaled $1,468,898 at March 31, 2017.

Property, Plant and Equipment

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

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Direct labor costs, incurred for specific major projects expected to have long-term benefits will be capitalized. Direct labor costs subject to capitalization include employee salaries, as well as, related payroll taxes and benefits. With respect to the allocation of salaries to projects, salaries are allocated based on the percentage of hours that our key managers, engineers and scientists work on each project and are invoiced to the project each month. These individuals track their time worked at each project. Major projects are, generally, defined as projects expected to exceed $500,000. Direct labor includes all of the time incurred by employees directly involved with construction and development activities. General and/or indirect management time and time spent evaluating the feasibility of potential projects is expensed when incurred. Employee training time is expensed when incurred.

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

Stock Compensation

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

Earnings Per Share

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

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Revenue

Revenue Recognition

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

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

Revenue Source

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

Recent Accounting Pronouncements

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

Statement of Cash Flows
In August 2016, FASB issued Accounting Standards Update No. 2016-15 (“Update 2016-15”), Statement of Cash Flows (Topic 230), Classification of Certain Cash Receipts and Cash Payments. In November 2016, FASB issued Accounting Standards Update No. 2016-18 (“Update 2016-18”), Statement of Cash Flows (Topic 230), Restricted Cash. Update 2016-15 provides guidance on how certain cash receipts and cash payments are presented and classified in the statement of cash flows. Update 2016-18 provides guidance on how to classify and present changes in restricted cash or restricted cash equivalents that occur when there are direct cash receipts into restricted cash or restricted cash equivalents or direct cash payments made from restricted cash or restricted cash equivalents. These Updates are effective for annual periods beginning after December 15, 2017, and interim periods within those fiscal years. Early adoption is permitted, including adoption in an interim period. It is likely that some of the provisions of Update 2016-15 will apply to certain transactions our Company may engage in. The Company holds restricted cash and restricted cash equivalents that are addressed in Update 2016-18. Management is currently evaluating the possible impact these Updates may have on the presentation of the Company’s consolidated statements of cash flows.

Revenue Recognition
In May 2014, FASB issued Accounting Standards Update No. 2014-09 (“Update 2014-09”), Revenue from Contracts with Customers (Topic 606). Update 2014-09 amends the revenue recognition guidance and requires more detailed disclosures to enable financial statement users to understand the nature, amount, timing and uncertainties of revenue and cash flows arising from contracts with customers. In April 2016, FASB issued Accounting Standards Update No. 2016-10 (“Update 2016-10”), Revenue from Contracts with Customers (Topic 606), Identify Performance Obligations and Licensing. In March 2016, FASB issued Accounting Standards Update No. 2016-08 (“Update 2016-08”), Revenue from Contracts with Customers (Topic 606), Principal versus Agent Considerations (Reporting Revenue Gross versus Net). In May 2016, FASB issued Accounting Standards Update No. 2016-12 (“Updated 2016-12”), Revenue from Contracts with Customers (Topic 606), Narrow-Scope Improvements and Practical Expedients. Both Update 2016-10 and 2016-08 provide additional guidance on how an entity should recognize revenue when depicting the transfer of promised goods or services. These Updates provide more guidance on identifying performance obligations and licensing. Update 2016-12 provides additional clarification to the steps an entity should follow to achieve the core principle of Topic 606. The guidance, as amended, is effective for annual and interim reporting periods beginning after December 15, 2017, with early adoption permitted for public companies effective from annual and interim reporting periods beginning after December 31, 2016. Management has reviewed the essential provisions of all of our major revenue contracts and our revenue recognition practices. As a result of this review, Management does not expect a material impact on the consolidated statement of income.

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

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

NOTE 3 – RESTRICTED CASH AND BOND RESERVES

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

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Current restricted cash and bond reserves:

			March 31,			December 31,
Restricting Entities/Purpose			2017			2016
Idaho Department of Water Resources, Geothermal Well Bond		$	260,000		$	260,000
Bureau of Land Management, Geothermal Lease Bond- Gerlach			10,000			10,000
State of Nevada Division of Minerals, Statewide Drilling Bond			50,000			50,000
Bureau of Land Management, Geothermal Lease Bonds- USG Nevada			150,000			150,000
Oregon Department of Geology and Mineral Industries, Mineral Land and Reclamation Program			400,000			400,000
Prudential Capital Group, Cash Reserves			502,994			284,621
Prudential Capital Group, Debt Service Reserves (USG Nevada LLC)			1,602,032			1,600,597
Bureau of Land Management , Geothermal Rights Lease Bond			10,000			10,000
U.S. Department of Energy, Debt Service Reserve			793,314			2,011,445
State of California Division of Oil, Gas and Geothermal Resources, Well Cash Bond			100,000			100,000
Prudential Capital Group, Debt Service Reserves (Idaho USG Holdings LLC)			1,755,776			1,755,776
Prudential Capital Group, Revenue Reserves (Idaho USG Holdings LLC)			2,285,836			-
CAISO, Transmission Interconnection Escrow Deposits			1,895,184			1,895,023
		$	9,815,136		$	8,527,462

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Long-term restricted cash and bond reserves:

			March 31,			December 31,
Restricting Entities/Purpose			2017			2016
Nevada Energy, PPA Security Bond		$	1,468,898		$	1,468,898
Prudential Capital Group, Maintenance Reserves (USG Nevada LLC)			1,063,147			1,081,744
Prudential Capital Group, Well Reserves (USG Nevada LLC)			1,111,017			951,486
Prudential Capital Group, Maintenance Reserves (Idaho USG Holdings LLC)			1,807,890			1,807,890
Prudential Capital Group, Capital Expenditure Reserves (Raft River Energy I LLC)			3,796			3,796
U.S. Department of Energy, Operations Reserves			270,000			270,000
U.S. Department of Energy, Debt Service Reserves			2,380,007			2,413,951
U.S. Department of Energy, Short Term Well Field Reserves			4,509,013			4,508,650
U.S. Department of Energy, Long-Term Well Field Reserves			3,533,621			5,175,777
U.S. Department of Energy, Capital Expenditure Reserves			2,457,670			2,429,158
		$	18,605,059		$	20,111,350

The well bonding requirements ensure that the Company has sufficient financial resources to construct, operate and maintain geothermal wells while safeguarding subsurface, surface and atmospheric resources from unreasonable degradation, and to protect ground water aquifers and surface water sources from contamination. The debt service reserves are required to provide assurance that the Company will have sufficient funds to meet its debt payment obligations for the terms specified by the loan agreements. The maintenance and capital expenditure reserves are required by the lending entities to ensure that funds are available to acquire and maintain critical components of power plants and related supporting structures to enable the plants to operate according to expectations. Except for the PPA Security Bond, all of the restricted funds consisted of cash deposits or money market accounts held in commercial banks. Portions of the cash deposits are subject to FDIC insurance (see note 2 for details). The PPA Security Bond is held by the power purchaser. All of the reserve accounts were considered to be fully funded at March 31, 2017 and December 31, 2016.

NOTE 4 – TRADE RECEIVABLES/INSURANCE PROCEEDS

The Company’s receivables are summarized as follows:

On January 5, 2017, Unit I of the USG Oregon LLC plant experienced mechanical failures, primarily due to extreme cold temperatures, that resulted in an outage and the loss of a substantial amount of the plant’s refrigerant. The initial repairs to identify and plug the damaged tubes were completed on February 12, 2017 and the Unit was returned to service. Unit I is operating at a reduced level until the plugged heat exchanger tubes can be replaced during the annual maintenance outage scheduled for May 2017. The repair costs and lost revenue were covered by property and business interruption insurance, subject to deductibles and other terms of the policy. The deductibles were $50,000 for property loss and a 30 day period for business interruption coverage. The lost revenue associated with that 30 day deductible period is estimated at $833,000. At March 31, 2017, the total submitted claims that are expected to be recovered after deductibles were $2,037,409. The Company estimates that the full amount of the property loss expenses, less the $50,000 deductible, will be collected. The Company received partial reimbursement of repair costs that totaled $1,050,000 in April 2017. For the three months ended March 31, 2017, insurance recovery amounts of $1,712,003 for plant production expenses and $325,406 for energy sales were accrued.

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NOTE 5 - PROPERTY, PLANT AND EQUIPMENT

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

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

Depreciation expense charged to plant operations and administrative costs for the three months ended March 31, 2017 and 2016, was $1,614,428 and $1,568,100; respectively.

Changes in construction in progress are summarized as follows:

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

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NOTE 6 – INCOME TAXES

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

The provision for income taxes reflects an estimated effective income tax rate attributable to U.S. Geothermal Inc.’s share of income. Our provision for income taxes for the three months ended March 31, 2017, reflects a reported effective tax rate of 10.7%, which differs from the statutory federal income tax rate of 34.0% primarily due to the impact of the non-controlling interest, stock compensation and state income taxes.

NOTE 7 – NOTES PAYABLE

Prudential Capital Group – Idaho USG Holdings LLC
In May 2016, the Company’s wholly owned subsidiary (Idaho USG Holdings LLC) entered into a loan agreement with the Prudential Capital Group to finance the Company’s development activities. The original principal totaled $20 million and included the option to issue additional debt up to $50 million within the next two years. The original $20 million loan amount bears interest at a fixed interest rate of 5.8% per annum. The principal and interest payments are due semi-annually at amounts based upon a 20-year amortization period and the scheduled remaining balance of $16,009,495 is due in full at the end of the 7 year term. The loan is secured by the Company’s ownership interests in the Neal Hot Springs (Oregon USG Holdings LLC and USG Oregon LLC) and the Raft River (Raft River Energy I LLC) projects. At March 31, 2017, the balance of the loan was $19,296,475 and the net unamortized debt issuance costs associated with this loan totaled $713,549 ($821,070, less amortized costs of $107,521).

U.S. Department of Energy – USG Oregon LLC
On August 31, 2011, USG Oregon LLC (“USG Oregon”), a subsidiary of the Company, completed the first funding drawdown associated with the U.S. Department of Energy (“DOE”) $96.8 million loan guarantee (“Loan Guarantee”) to construct its power plant at Neal Hot Springs in Eastern Oregon (the “Project”). All loan advances covered by the Loan Guarantee have been made under the Future Advance Promissory Note (the “Note”) dated February 23, 2011. Upon the occurrence and continuation of an event of default under the transaction documents, all amounts payable under the Note maybe accelerated. In connection with the Loan Guarantee, the DOE has been granted a security interest in all of the equity interests of USG Oregon, as well as in the assets of USG Oregon, including a mortgage on real property interests relating to the Project site. No additional advances are allowed under the terms of the loan. A total of 13 draws were taken and each individual draw or tranche is considered to be a separate loan. The loan principal is scheduled to be paid over 21.5 years from the first scheduled payment date with semi-annual installments including interest calculated at an aggregate fixed interest rate of 2.598%. The principal payment amounts are calculated on a straight-line basis according to the life of the loans and the original loan principal amounts. The principal portion of the aggregate loan payment is adjusted as individual tranches are extinguished. The principal payments started at $1,709,963 on February 10, 2014 and were reduced to $1,626,251 on February 10, 2017 and continue through February 12, 2035. The loan balance at March 31, 2017 totaled $58,545,023 (current portion $3,252,501).

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

* - Individual tranches have been fully extinguished.

Prudential Capital Group – USG Nevada LLC
On September 26, 2013, the Company’s wholly owned subsidiary (USG Nevada LLC) entered into a note purchase agreement with the Prudential Capital Group to finance the Phase I San Emidio geothermal project located in northwest Nevada. The term of the note is approximately 24 years, and bears interest at fixed rate of 6.75% per annum. Interest payments are due quarterly. Principal payments are due quarterly based upon minimum debt service coverage ratios established according to projected operating results made at the loan origination date and available cash balances. The loan agreement is secured by USG Nevada LLC’s right, title and interest in and to its real and personal property, including the San Emidio project and the equity interests in USG Nevada LLC. At March 31, 2017, the balance of the loan was $29,038,580 (current portion $635,999).

Auto Loan – U.S. Geothermal Services
On July 28, 2016, the Company’s wholly owned subsidiary (U.S. Geothermal Services) purchased a truck with down payments that totaled $39,496 and a loan agreement with Chrysler Capital. The loan requires total monthly payments of $313, including interest at an average rate of 6.74% per annum until July 2018. The note is secured by the vehicle. At March 31, 2017, the loan balance totaled $5,067 (current portion $3,526).

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

NOTE 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 March 31, 2017, the Company can issue stock option grants totaling up to 2,855,915 shares. Options are typically granted for a term of up to five years from the date of grant. Stock options granted generally vest over a period of eighteen months, with 25% vesting on the date of grant and 25% vesting every six months thereafter. The Company recognizes compensation expense using the straight-line method of amortization. Historically, the Company has issued new shares to satisfy exercises of stock options and the Company expects to issue new shares to satisfy any future exercises of stock options.

The following table reflects the summary of stock options outstanding at January 1, 2017 and changes for the three months ended March 31, 2017:

						Weighted
						Average
			Number of			Exercise			Aggregate
			shares under			Price Per			Intrinsic
			options			Share			Value
	Balance outstanding, January 1, 2017		1,824,664		$	3.38		$	3,186,265
	Forfeited/Expired		-			-			-
	Exercised		(24,999	)		2.22			-
	Granted		362,636			4.10			-
	Balance outstanding, March 31, 2017		2,162,301		$	3.52		$	3,932,250

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

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.

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

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

As of March 31, 2017, there was $622,763 of total unrecognized compensation cost related to non-vested stock option compensation arrangements granted under the Plan. That cost is expected to be recognized over a weighted-average period of 1.5 years.

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.

At March 31, 2017, total compensation cost related to restricted stock granted under the Stock Plan but not yet recognized was $3,712 net of estimated forfeitures. This cost will be amortized on the straight-line method over a period of approximately 0.25 years.

Stock Purchase Warrants

At March 31, 2017, the outstanding share purchase warrants totaled 340,093 (385,139 warrants at December 31, 2016) with a warrant exercise price of $3.00 per warrant and expire December 26, 2017.

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

NOTE 9 – FAIR VALUE MEASUREMENT

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

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

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

At March 31, 2017:

		Total			Level 1			Level 2			Level 3
Assets:
Money market accounts *	$	32,639,791		$	32,639,791		$	-		$	-

At December 31, 2016:

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

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

NOTE 10 - COMMITMENTS AND CONTINGENCIES

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

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

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NOTE 11 – JOINT VENTURES/NON-CONTROLLING INTERESTS

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

		March 31,			December 31,
		2017			2016
Gerlach Geothermal LLC interest held by Gerlach Green Energy, LLC	$	204,114		$	207,217
Oregon USG Holdings LLC interest held by Enbridge Inc.		23,967,236			25,361,410
Raft River Energy I LLC interest held by Goldman Sachs		949,893			1,011,363
	$	25,121,243		$	26,579,990

Gerlach Geothermal LLC
On April 28, 2008, the Company formed Gerlach Geothermal, LLC (“Gerlach”) with our partner, Gerlach Green Energy, LLC (“GGE”). The purpose of the joint venture is the exploration of the Gerlach geothermal system, which is located in northwestern Nevada, near the town of Gerlach. Based upon the terms of the members’ agreement, the Company owned a 60% interest and GGE owned a 40% interest in Gerlach Geothermal, LLC. The agreement gives GGE an option to maintain its 40% ownership interest as additional capital contributions are required. If GGE dilutes to below a 10% interest, their ownership position in the joint venture would be converted to a 10% net profits interest. Initially, the Company contributed $757,190 in cash and $300,000 for a geothermal lease and mineral rights, and GGE contributed $704,460 of geothermal lease, mineral rights and exploration data. From November 18, 2014 to March 31, 2017 the Company has contributed $527,042 for the project’s drilling costs and other costs that were not proportionally matched by GGE. These contributions effectively increased the Company’s ownership interest to 69.15% and 68.99% at March 31, 2017 and December 31, 2016; respectively.

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

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

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

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Raft River Energy I LLC (“RREI”)
RREI is a joint venture between the Company and The Goldman Sachs Group. An Operating Agreement governs the rights and responsibilities of both parties. At December 31, 2016, the Company had contributed approximately $17.9 million in cash and property, and Goldman Sachs has contributed approximately $34.1 million in cash. Profits and losses are allocated to the members based upon contractual terms. The initial contracted terms stated that the Company would be allocated 70% of energy credit sales and 1% of the residual income/loss excluding energy credit sales. Under the terms of the amended operating agreement that became effective December 16, 2015, the Company will receive a 95% interest in RREI’s cash flows. Under the terms of both agreements, Goldman Sachs receives a greater proportion of the share of profit or losses for income tax purposes/benefits. This includes the allocation of profits and losses as well as production tax credits, which will be distributed 99% to Goldman Sachs and 1% to the Company during the first 10 years of production, which ends December 31, 2017. No distributions were made for the three months ended March 31, 2017. During the year ended December 31, 2016, RREI distributed funds to the Company and Goldman Sachs of $1,203,349 and $82,473; respectively. During the three months ended March 31, 2017 and the year ended December 31, 2016, the Company made contributions of $260,525 and $3,349,087; respectively.

Under the terms of the December 16, 2015 agreement, the Company is entitled to incremental profits earned as a result of additional contributions made by the Company. During the three months ended March 31, 2017, a new production well that was contributed to the project by the Company produced incremental net profits of $22,471.

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

NOTE 12 – ASSET RETIRMENT OBLIGATIONS

The Geysers, California
On April 22, 2014, the Company completed the acquisition of a group of companies owned by Ram Power Corp.’s (“Ram”) Geysers Project located in Northern California. Two of the acquired companies (Western GeoPower, Inc. and Etoile Holdings, Inc.) contained asset retirement obligations that, primarily, originate with the environmental regulations defined by the laws of the State of California. The liabilities related to the removal and disposal of arsenic impacted soil and existing steam conveyance pipelines are estimated to total $598,930. Obligations related to decommissioning four existing wells were estimated at $606,000. These obligations are initially estimated based upon discounted cash flows estimates and are accreted to full value over time. At March 31, 2017, the Company has not considered it necessary to specifically fund these obligations. Since the Company is still evaluating the development plan for this project that could eliminate or significantly reduce the remaining obligations, no charges directly associated the asset retirement obligations have been charged to operations. The obligation balances at March 31, 2017 and December 31, 2016 totaled $1,219,903. All of the obligations were considered to be long-term at March 31, 2017.

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

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NOTE 13 – BUSINESS SEGMENTS

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

			Operating			Corporate &
			Plants			Development			Consolidated
Total Assets:
March 31, 2017		$	184,028,504		$	56,471,344		$	240,499,848
December 31, 2016			188,682,162			54,742,170			243,424,332
For the Three Months Ended March 31,
2017:
Operating Revenues		$	8,437,069		$	-		$	8,437,069
Net Income (Loss)			2,825,886			(1,702,400	)		1,123,486
2016:
Operating Revenues			8,503,276			-			8,503,276
Net Income (Loss)			3,493,691			(2,305,896	)		1,187,795

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

INFORMATION REGARDING FORWARD LOOKING STATEMENTS

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

• our business and growth strategies;

• our future results of operations;

• anticipated trends in our business;

• the capacity and utilization of our geothermal resources;

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

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

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

• availability and costs of drilling rigs and field services;

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

• our working capital requirements and availability;

• our illustrative plant economics;

• our illustrative growth goals and development and acquisition projections;

• market conditions in the geothermal energy industry; and

• the impact of environmental and other governmental regulation.

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

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

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

• incorrect estimates of required capital expenditures;

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

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

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

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

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

• our ability to successfully identify and integrate acquisitions;

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

• our dependence on key personnel;

• changes in applicable laws, rules or regulations;

• the potential for claims arising from geothermal plant operations;

• general competitive conditions within the geothermal energy industry; and

• financial market conditions.

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

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

General Background and Discussion

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

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

For the quarter ended March 31, 2017, the Company was focused on:

• operating and optimizing the Neal Hot Springs, San Emidio and Raft River power plants;
• placing well RRG-5 into production at the Raft River project;
• submitting a power plant development permit to the Bureau of Land Management (“BLM”) for San Emidio Phase II;
• preparing to deepen three additional temperature gradient wells at San Emidio II;
• beginning the advanced resource evaluation portion of the $1.5 million SubTER grant from the Department of Energy at San Emidio and Crescent Valley;
• receiving final turbine and generator bids from vendors, continuing to optimize the power plant/hybrid cooling design, and pursuing PPA opportunities for the WGP Geysers project;
• received a $150,000 Small Business Voucher grant to evaluate the installation of an integrated solar topping cycle at the Raft River project;
• drilling a fourth water well at Neal Hot Springs; and
• evaluating potential new geothermal projects and acquisition opportunities.

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Project Overview

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

Projects in Operation

	(1)	The Company’s equity interest in the project is 60% and Enbridge’s equity interest is 40%.
	(2)	The Company’s membership interest in the project is 95% and Goldman Sachs’ membership interest is 5% as the tax equity partner.
	(3)	The annual average net output design for the plant is 13 megawatts. The current average net output of the Raft River Unit I plant is approximately 10.1 megawatts.

Facility Generation
Generation from all facilities totaled 89,613 megawatt hours for the first quarter of 2017. For the same period in 2016, the total generation was 93,788 megawatt hours.

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

For the first quarter of 2017, generation was 48,178 megawatt-hours with an average of 17.6 net megawatts per hour of operation and plant availability was 82.5%. For the same period in 2016, the plant generated 53,671 megawatt-hours with an average of 25.4 net megawatts per hour and plant availability was 96.7%.

On January 5, 2017 the entire facility tripped off line during extreme cold weather conditions, and due to weather caused delays to restart the facility, vaporizer tubes in Unit 1 froze and split, resulting in loss of refrigerant charge and brine incursion into the refrigerant system. 80 tubes in the vaporizers were found to have either failed or were badly damaged. All of these tubes were plugged, and the unit was restarted on February 12, 2017, and is operating at slightly reduced generation.

Our Property Loss insurance covers the reimbursement of all equipment repair costs, including lost refrigerant, with a deductible level of $50,000. A first insurance claim of $1,024,966 was made to the insurance company and an initial payment of $1,050,000 was received on the claim. A second request for payment of $977,204 was made to the insurance company on March 12, 2017, but has not been received to date. The remainder of the repair costs will be totaled and submitted to the insurance company after Unit I has gone through its annual maintenance outage in the second quarter, and all of the damaged tubes have been replaced.

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Our Business Interruption insurance covers all lost generation, with a 30 day deductible level. The estimated lost generation revenue for the first 30 days of the outage was approximately $833,000. The lost generation revenue after the 30 day deductible period, to the end of the first quarter, is estimated at $325,406. While Unit I has been returned to service, it continues to operate at a reduced output until the damaged tube replacements are able to be manufactured and installed in early May. This additional lost generation will be included in our business interruption insurance claim.

During the first quarter, a significant amount of additional reprogramming and component tuning on all of the three generation units has been accomplished to insure that a similar freezing event will not reoccur in the future.

A third water supply well for the project was drilled in December 2016, but due to extreme winter weather, was not completed until the first quarter. While several small water zones were found, due to multiple sloughing zones in the well, it was abandoned. A fourth well was drilled at a different location and found an estimated 80 gallons per minute (“gpm”) of water, bringing the total amount of water available from two wells to 250 gpm, enough for one unit to be converted to hybrid cooling. Discussions are underway to lease or purchase private surface water rights in the area. The option of treating geothermal brine is still being investigated with a brine treatment system operating at the site that is successfully producing high quality water that could be used in the hybrid system if other water sources are not identified.

Subsequent to the end of the quarter, Neal Hot Springs Unit 3 completed its annual maintenance outage from April 24 to April 28, 2017.

The PPA for the project was signed on December 11, 2009 with the Idaho Power Company. It has a 25-year term, and a variable percentage annual price escalation. The PPA has a seasonal pricing structure that pays 120% of the average price for four months (July, August, November, December), 100% of the average price for five months (January, February, June, September, October) and 73.3% of the average price for three months (March, April, May). The annual average price paid under the PPA for 2017 is $111.83 ($109.27 for 2016) per megawatt-hour.

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

For the first quarter of 2017, generation was 19,501 megawatt-hours with an average of 9.2 net megawatts per hour of operation and plant availability was 98.6%. For the same period in 2016, the plant generated 20,433 megawatt-hours with an average of 9.4 net megawatts per hour and plant availability was 99.4%. The reduced generation was caused by the submersible pump motor in production well 61-21 failing on January 12, 2017. A standby production well with lower temperature was placed in service, which reduced the amount of lost generation. A new motor, which was provided by the manufacturer under warranty, and rebuilt pump were installed, and well 61-21 resumed production on March 3, 2017. Subsequent to the end of the quarter, San Emidio completed its annual maintenance outage from April 2 to April 10, 2017.

On June 1, 2011, an amended and restated PPA was signed with Sierra Pacific Power Company d/b/a NV Energy for the sale of up to 19.9 megawatts of electricity on an annual average basis from two units. The option for the second unit expired in December 2015. The PPA has a 25-year term with a base price of $89.75 per megawatt-hour, and an annual escalation rate of 1 percent. The annual average price paid under the PPA for 2017 is $93.94 ($93.01 for 2016) per megawatt-hour.

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

For the first quarter of 2017, generation was 21,934 megawatt-hours with an average of 10.1 net megawatts per hour of operation and plant availability was 100%. For the same period in 2016, the plant generated 19,684 megawatt-hours with an average of 9.4 net megawatt hours and plant availability was 100.0%. The increased generation in 2017 is primarily due to having all production wells on-line compared to 2016 when production well RRG-2 failed in February 2016 and was off line for the remainder of the first quarter.

Well RRG-5, an idle injection well with significant permeability, was converted to production with piping modifications and the installation of a pump and, commenced operation on March 21, 2017. It is currently operating at the flow rate of 1,100 gpm, with a temperature of just over 247°F. The increased flow to the plant is generating an additional 0.71 megawatts per hour. To date, the reservoir response has been significantly better than projected, with minimal drawdown in well RRG-5 and no impact to water level in the adjoining wells.

The next step to optimize output from the wellfield is to increase the capacity of the injection system by upgrading an injection pump. A further increase in fluid flow to the plant is expected during the third quarter after the injection pump upgrade is completed, which will result in a further increase in generation. The targeted increase for this phase of the program is 1.5 to 2 megawatts, which depends in part on the final temperature that well RRG-5 achieves. Once the upgraded injection pump is in service and the wellfield is rebalanced to maximize output, additional changes will be analyzed to further increase the generation level of the plant. The Raft River PPA allows for 13 megawatts of generation.

Well RRG-9, which has been used as part of an $11.4 million thermal stimulation grant funded primarily by the DOE, has continued to increase in injection capacity to a current level of 1,360 gpm. This injection capacity is sufficient to provide all of the additional volume needed to accept the flow from well RRG-5 without requiring any new drilling.

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

The PPA for the project was signed on September 24, 2007 with the Idaho Power Company and allows for the sale of up to 13 megawatts of electricity on an annual average basis. The PPA has a 25 year term with a starting average price for the year 2007 of $52.50 that escalates at 2.1% per year through 2020 and then at 0.6% per year until the end of the contract in 2034. The Idaho Power PPA has a seasonal pricing structure that pays 120% of the average price for four months (July, August, November, December), 100% of the average price for five months (January, February, June, September, October) and 73.5% of the average price for three months (March, April, May). The annual average price paid under the PPA for 2017 is $64.63 ($63.00 for 2016) per megawatt-hour.

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

Projects Under Development/Exploration

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 Phase II		Idaho		100%		13
Crescent Valley Phase II		Nevada		100%		25
Crescent Valley Phase III		Nevada		100%		25
Lee Hot Springs		Nevada		100%		20
Ruby Hot Springs Phase I		Nevada		100%		20

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

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Engineering optimization of the new, hybrid power plant design has been completed and final quotes for the turbine-generator have been received. Our engineers and consultants are working in concert with our EPC contractors to examine all aspects of the construction cycle with a focus further on reducing construction costs. The hybrid design will dramatically increase the volume of water available for injection back into the reservoir, which will result in increased power generation over the life of the project. Traditional water cooled geothermal steam plants re-inject approximately 20 to 25% of the water that is extracted from the steam, while our current hybrid design may re-inject approximately 80% more of the water. This higher injection rate will provide long term, stable steam production, and will result in increased power generation over the life of the project.

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

We received the signed Large Generator Interconnection Agreement for the project on March 6, 2016 with the California Independent System Operator and Pacific Gas & Electric (PG&E). This agreement allows the project to connect to the transmission grid and deliver up to 35 megawatts of energy. The Company has paid the total interconnection cost of $1.9 million for the grid operator’s portion of the work in the substation. An additional 1.7 mile long transmission line will be required to connect from the plant to the substation and discussions are underway with the landowners to acquire a right-of-way.

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

Discussions are being held with several potential California based power purchasers for the generation from the WGP Geysers plant. The potential power purchasers have expressed interest in renewable, base load power, to replace fossil fuel based power generation that is being phased out of some of their portfolios and to stabilize and balance intermittent resources already in their portfolios. A number of community choice aggregators are also expected to issue Requests for Proposals for the purchase of renewable energy during 2017. Bilateral negotiations are continuing with a potential offtaker that had shortlisted our bid in their 2016 solicitation.

El Ceibillo, Republic of Guatemala
A geothermal energy rights concession, located 14 kilometers southwest of Guatemala City, was awarded to U.S. Geothermal Guatemala S.A., a wholly owned subsidiary of the Company in April 2010. The concession agreement contains a schedule that requires the development and construction of a power plant. In July 2015, the Guatemalan Ministry of Energy and Mines approved a modified construction schedule that extended the development and construction period to June 1, 2018. There are 24,710 acres (100 square kilometers) in the concession, which is at the center of the Aqua and Pacaya twin volcano complex.

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Production well EC-5 was completed to a depth of 1,450 feet (442 meters) on August 20, 2016 and intersected a high permeability zone at 1,299 feet (396 meters). EC-5 underwent a series of flow tests, with field wide monitoring, beginning on September 5, 2016 and ran until September 13, 2016. Data was collected from three monitoring wells during the test (EC-2A, EC-3, and EC-4) to provide pressure data for the reservoir model. Fluid samples taken at the end of the flow test indicate a potential reservoir temperature of 450 to 523°F (232 to 273°C).

With the shallow, commercial resource now indicated, a deep well is planned in 2017 to test the producing structure down dip from well EC-5 to a projected depth of 1,970 to 2,300 feet (600-800 meters). A deeper intersection in the reservoir could increase the reservoir capacity and production temperature and change the design of the power plant. Well EC-1, which was drilled in 2013 to a depth of 5,650 feet (1,722 meters) found a measured bottom-hole temperature of 526°F (274°C), but did not intersect permeability. The comparative geology between EC-5 and EC-1 suggests a fault or other structure feeding the reservoir may be located in the area between the two wells. A site has been constructed to drill well EC-6 to test this area.

On January 10, 2017, the Guatemalan government, through the National Electrical Energy Commission (COMISIÓN NACIONAL DE ENERG¥A ELÉCTRICA–“CNEE”), announced that it is preparing to issue an RFP later this year for 420 megawatts of power, of which 40 megawatts is to be reserved specifically for geothermal energy. When the RFP is issued, the El Ceibillo project will be bid into the process.

San Emidio Phase II, Nevada
The Phase II expansion is dependent on successful development of additional production and injection well capacity. We expect that approximately 75% of the Phase II development may be funded by non-recourse project debt, with the remainder funded through equity financing. We anticipate the project qualifying for the 30% Federal Investment Tax Credit (or Production Tax Credit), which when monetized, can meet most of the equity financing requirements.

A power plant development permit application for the San Emidio Phase II project was submitted to the BLM on March 29, 2017. The application provides for the installation of three power plant units, up to 20 wells, and the transmission line needed to develop the project. It is expected that the evaluation by the BLM will take 12 months or longer to complete. Additional cultural and threatened & endangered species surveys will be undertaken during 2017 in support of the permit. Permits to deepen three temperature gradient wells were received from the BLM in December 2016. Drilling will begin as soon as weather permits access to the well pads. These three wells will be deepened to the expected reservoir depth of 1,800 to 2,500 feet deep, to further explore the Southwest Zone. If the wells are successful, the length of the productive reservoir could be extended by 1,000 feet.

The updated reservoir model (announced January 11, 2017) resulted in a significant increase in the potential size of the San Emidio Phase II reservoir of up to 47 net megawatts. Data from flow tests that took place in late 2016 from two observation wells were incorporated into a Probabilistic Power Density model, which estimates the net generation potential of a reservoir. Based on the flow rate and temperature produced by the two observation wells, and by measurement of pressure response both in the wells and across the wellfield, the model estimates that the Most Likely Outcome (50% probability) is 47 net megawatts of generation capacity within a 1.4 square mile area. The Minimum level of generation capacity (90% probability) occurs in a 0.18 square mile area, and has 18.8 net megawatts of generation capacity.

These two observation wells are approximately 1,700 feet apart, along the new structural trend identified in the Southwest Zone, which is still open for expansion. Temperature gradient well data and seismic information indicate a potential strike length for the Southwest Zone of up to 2,700 feet. This compares to a strike length for the primary producing wellfield at San Emidio Phase I of 800 feet, which supports the potential for the larger estimated resource in this Southwest Zone.

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The three power plant units that were previously purchased in 2016 are available to provide this project with the major, long lead equipment requirements for 35-45 net megawatts of power (depending upon cooling system used). The increased San Emidio II reservoir capacity with a 320°F+ temperature fits the design range of the equipment. These new, unused components represent approximately 70% of the equipment needed for a complete facility similar to the Company’s Neal Hot Springs operation.

Given the larger estimated resource capacity at San Emidio II, we have cancelled our Small Generator Interconnection Agreement with NV Energy that was completed in 2016 and are preparing to apply for a Large Generator Interconnection Agreement with a 45 megawatt capacity in support of the higher expected output. Additionally, transmission studies by an outside engineering firm that include the potential for power sales into Southern California are underway.

In July 2016, the Company was awarded a $1.5 million DOE cost share grant under the “Development of Technologies for Sensing, Analyzing, and Utilizing Novel Subsurface Signals in Support of the Subsurface Technology and Engineering (“SubTER”) Crosscut Initiative”. The program approved under the grant includes using new subsurface technologies at both San Emidio and Crescent Valley to identify fluid flow paths in the geothermal resource. The data collection phase of the program was completed at San Emidio in December. The data is being interpreted to determine whether viable targets have been identified. Upon approval from the DOE, a second phase of the grant program is designed to confirm the findings by drilling. The total program cost is $1.9 million with the Company providing $400,000 in cost share.

Raft River Phase II, Idaho
In 2011, the Raft River Phase II project was awarded an $11.4 million cost-shared, thermal stimulation program grant from the DOE with the University of Utah Energy And Geoscience Institute as the project lead. The goal of the project is to create an Enhanced Geothermal System (“EGS”) by creating thermal fractures and developing a corresponding increase in permeability in the low permeability rock. Well RRG-9 was made available for the program and the first stage of injection into the well began in June 2013.

Initially the well was only capable of receiving 20 gpm of water due to the low permeability of the rock. After several moderate pressure stimulations, the injection of cold power plant discharge fluid was started and has continued to date. The lower temperature fluid causes thermal fracturing within the higher temperature host rock of the reservoir. At the current plant generation level, the flow into the well has continued to increase and is now approximately 1,360 gpm.

Well RRG-9 continues to be used temporarily as an injection well as an extension of the DOE EGS program, which is expected at this time to continue through until mid-2017. The Company’s contributions for the thermal stimulation program are made in-kind by the use of the RRG-9 well, well field data provided by the Company, and through ongoing labor for monitoring support.

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

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

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

Operating Results

For the three months ended March 31, 2017, the Company reported net income attributable to the Company of $260,890 ($0.01 income per share) which represented an increase of $109,498 (72.3% increase) from net income attributable to the Company of $151,392 ($0.01 income per share) reported in the same period ended 2016. Both favorable and unfavorable variances were reported in areas related to the operations of the Company’s three power plants. Notable favorable variances were reported for professional fees and promotion expenses. A notable unfavorable variances were noted for interest expense and income tax expense.

Plant Operations

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

% - represents the percentage of total Company energy sales.

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

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

For the three months ended March 31, 2017, the Neal Hot Springs plant reported subsidiary net income of $2,345,574 which was a decrease of $881,166 (27.3% decrease) from subsidiary net income of $3,226,740 reported in the same period ended 2016.

Energy sales for the three months ended March 31, 2017, decreased 2.9% from the same period ended 2016. On January 5, 2017, Unit 1 experienced mechanical failures, primarily due to extreme cold temperatures that resulted in outages and the loss of a substantial amount of that Unit’s refrigerant. The Unit’s complications resulted in a total of 1,025 lost production hours during the current quarter. The initial repairs to identify and plug the damaged tubes were completed on February 12, 2017; however, Unit 1 will operate at a reduced level until the plugged heat exchanger tubes can be replaced during the annual maintenance outage scheduled for May 2017. Business Interruption insurance, provided $325,406 of revenue to cover lost energy sales after the first 30 days of lost generation. Without the insurance coverage, energy sales for the current quarter would have decreased 9.0% from the same period ended 2016.

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Plant operating expenses, excluding depreciation, increased $742,032 (80.8% increase) for the three months ended March 31, 2017 from the same period ended 2016. The largest increases were in property taxes of $705,193. For the first years of operations, property taxes were abated by the County. The abatement period ended in 2016 and the first property tax payment was made in December 2016.

Significant repair and refrigerant replacement costs totaling estimated to be $1.7 million were required during the current quarter for Unit 1, of which the refrigerant replacement costs alone exceeded $758,000. Property Loss insurance covered all of those costs except for a $50,000 deductible.

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

% - represents the percentage of total plant operating revenues.
%* - represents the percentage of change from 2016 to 2017. Increases in revenues and decreases in expenses from the prior period to the current period are considered 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:

* - 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 three months ended March 31, 2017, the San Emidio plant reported subsidiary net income of $425,071 which was a decrease of $376 (0.1% decrease) from $425,447 subsidiary net income reported in the same period ended 2016.

Energy sales for the three months ended March 31, 2017, decreased 3.6% from the same periods ended 2016. During the current three months, the plant produced 19,501 megawatt hours, which was a 4.6% decrease from the same periods ended 2016. During the current quarter, the plant experienced forced outages when it tripped off-line due a pressure indicating transmitter failure and issues with the power purchaser’s substations. No outages were reported in the first quarter of 2016.

Plant operating costs, excluding depreciation, decreased $59,252 for the three months ended March 31, 2017, which was a 9.0% decrease from the same period ended 2016. A notable decrease in operating expenses was related to taxes and licenses. During the first quarter 2016, the Company was required to pay additional minerals proceeds tax for $70,747 after an examination by the State of Nevada.

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

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

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

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

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

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

For the three months ended March 31, 2017, the Raft River plant reported subsidiary net income of $55,241 which was an increase of $213,738 (134.9% increase) from $158,497 subsidiary net loss reported in the same period ended 2016.

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Energy sales, for the three months ended March 31, 2017 increased 12.9% from the same period ended 2016. During the three months ended March 31, 2017, the plant produced 21,934 megawatts, which was an 11.4% increase from the same period ended 2016. In February 2016, a production well (RRG-2) was taken off line in order to facilitate the well expansion project. This well was reconnected to the plant when the project was completed in June 2016. On March 21, 2017, a new production well (RRG-5) was connected to the plant. The new well addition has increased the net power production of the plant by approximately 0.71 megawatts.

Plant operating costs, excluding depreciation, decreased $96,516 for the three months ended March 31, 2017, which was a 10.1% decrease from the same period ended 2016. During the three months ended March 31, 2016, costs of approximately $96,000 were incurred to pull a production pump for repairs. Unplanned repairs were not needed in the current quarter.

The summarized statements of operations for RREI are as follows:

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

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

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Key quarterly production data for RREI is summarized as follows:

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

Professional and Management Fees
For the three months ended March 31, 2017, the Company reported $145,765 in professional and management fees which was a decrease of $910,744 (86.2% decrease) from $1,056,509 reported in the same period ended 2016. During the current quarter, the Company incurred routine professional services and fees. In August of 2015, the Company formed a Special Committee of the Board of Directors to thoroughly explore strategic options to maximize shareholder value. The Company ended this process and ended the contract with the primary consultant that was engaged in the examination in March 2016. For the first quarter 2016, the consultant’s fees associated with this examination exceeded $544,000. Legal fees that exceeded $100,000 were incurred in the first quarter of 2016 to support the examination and issuance of common shares. The Company incurred fees of $100,000 for services provided by a new financial advisor hired during the first quarter 2016. These consultant services were discontinued in June 2016.

Travel and Promotion
For the three months ended March 31, 2017, the Company reported $36,835 in travel and promotional costs which were a decrease of $46,577 (55.8% decrease) from $83,412 reported in the same period ended 2016. During the current quarter, the Company incurred routine travel and promotional costs. During first quarter 2016, the Company incurred additional travel costs related to the process of exploring strategic options to maximize shareholder value and to attend investment conferences.

Interest Expense
For the three months ended March 31, 2017, the Company reported $1,188,271 in interest expense which is an increase of $254,579 (27.3% increase) from $933,692 reported in the same period ended 2016. Interest expense increased due to a new loan agreement/balance. In May 2016, the Company’s wholly owned subsidiary (Idaho USG Holdings LLC) entered into a loan agreement to finance the Company’s development activities. The original principal totaled $20.0 million and the principal at March 31, 2017 was $19.3 million. The loan amount bears interest at a fixed rate of 5.8% per annum.

Net Income Tax Expense
For the three months ended March 31, 2017, the Company reported net income tax expense of $153,000, which was an increase of $45,000 (50.0% decrease) from the income tax expense of $90,000 reported in the same period ended 2016. A significant factor in the tax variance was attributed to the lower amount of non-controlling interest income. Lower non-controlling interest income reduces the amount of income tax passed through to those entities. The non-controlling interest variance and the other significant variances that impact income tax expense are discussed in other sections of this document.

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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 three months ended March 31, 2017, the Company reported $862,596 in net income attributable to non-controlling interests, which was a decrease of $173,807 (16.8% decrease) from $1,036,403 net income reported in the same period ended 2016. The primary component of the variances were the operating results of USG Oregon LLC which reported a subsidiary net profit for the three months ended March 31, 2017 of $2,345,574, which was a decrease of $881,166 (27.3% decrease) from $3,226,740 subsidiary net profit reported in the same period ended 2016. The primary conditions for the decreases in USG Oregon LLC’s profits were discussed above.

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

		For the Three Months Ended
		March 31,
Subsidiaries and Non-Controlling		2017			2016			Variances
Interest Entities		$			$			$			%
Oregon USG Holdings LLC interest held by Enbridge Inc.		927,170			1,284,086			(356,916	)		(27.8	)
Raft River Energy I LLC interest held by Goldman Sachs		(61,471	)		(243,819	)		182,348			74.8
Gerlach Geothermal LLC interest held by Gerlach Green Energy, LLC		(3,103	)		(3,864	)		761			19.7
		862,596			1,036,403			(173,807	)		(16.8	)

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

Non-Controlling Interests
The following is a summarized presentation of select financial line items from the statement of operations by project and the impact of the related non-controlling interests for the three months ended March 31, 2017:

	(1)	The non-controlling interest for Neal Hot Springs represents a 40% interest for our joint venture partner, Enbridge.
	(2)	The non-controlling interest for Raft River represents 5% of REC income and cash flows, and 99% of all remaining profits and losses allocated to the Goldman Sachs Group.

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	(3)	The non-controlling interest for our exploration activities represents an approximately 31% interest for our joint venture partner at Gerlach, GGE Development.
	(4)	Major costs included in Exploration Activities and Corporate for the three months ended March 31, 2017 included:

	•	Employee compensation	$   911,734
	•	Corporate administration	303,706
	•	Professional fees	145,765

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.

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

				Non-		U.S.
				Controlling		Geothermal
		Consolidated		Interests		Inc.
Balance Sheet Items		$		$		$
Unrestricted cash and cash equivalents		13,068,978		914,468		12,154,510
Restricted cash and security bonds:
Current		9,815,136		480,411		9,334,725
Long-term		18,605,059		5,260,125		13,344,934
Notes payable:
Current		3,892,026		1,301,000		2,591,026
Long-term		102,279,570		22,117,008		80,162,562

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

Off Balance Sheet Arrangements

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

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Liquidity and Capital Resources

During the quarter ended March 31, 2017, the Company’s operating projects continued to generate significant available cash (after debt service and reserves) to fund our development activities and corporate costs. In addition, exercise of options and warrants generated $190,634 during the quarter. We believe our cash and liquid investments at March 31, 2017 are adequate to fund our general operating activities through December 31, 2018.

The Company’s projects under development and under exploration may require additional funding. In addition to government loans and grants discussed below, we anticipate that additional funding may be raised through financial and strategic partnerships, market loans, issuance of debt or equity, and/or through the sale of ownership interest in tax credits and benefits. The Company continues discussions with potential investors to evaluate alternatives for funding at the corporate and project levels.

Idaho Power Company and Sierra Pacific Power (NV Energy), continue to pay for their power in a timely manner. This power is sold under long-term contracts at fixed prices. The status of the credit and equity markets could delay our project development activities while we seek to obtain economic credit terms or a favorable equity market price to further the drilling and construction activities.

On May 19, 2016, the Company closed on a $20 million debt facility from Prudential Capital Group. Under terms of the financing agreement, the Company has the option, without obligation, to issue additional debt, up to $50 million in aggregate within the next two years. The initial $20 million loan has a fixed interest rate of 5.8% per annum. The loan principal amortizes over twenty years, with a seven-year term. Principal and interest payments are made semi-annually. The loan is collateralized with the Company’s ownership interest in the Neal Hot Springs and Raft River projects and by virtue of a pledge by the Company’s wholly owned subsidiary, U.S. Geothermal Inc., an Idaho corporation, and sole member of Idaho USG Holdings, of the equity interests in Idaho USG Holdings. The 22 MW Neal Hot Springs project is owned 60% by the Company and 40% by Enbridge. The 13 MW Raft River project is owned 95% by the Company and 5% by Goldman Sachs.

On January 25, 2016, management determined it would be prudent to enter into a new Lincoln Park Capital (“LPC”) facility. The Company’s first Purchase Agreement with LPC, was entered into on May 21, 2012 and expired in 2015. Under the new Purchase Agreement, at the company’s sole discretion, the Company has the right to sell and LPC has the obligation to purchase up to $10 million of equity capital over a 30-month period subject to the conditions in the Purchase Agreement. The agreement provided for an initial sale of $650,000 of shares of common stock upon closing. Net proceeds from LPC’s investments were used to cover a portion of the cost of the recent acquisition of the Goldman Sachs ownership interest of the Raft River project, development of our geothermal projects and for general corporate purposes. During the quarter ended March 31, 2016 an additional $571,650 was raised under the At the Market (“ATM”) subsequent to the initial sale. No additional funds were raised since that time.

Potential Acquisitions

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

Critical Accounting Policies

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

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

Item 3 – Quantitative and Qualitative Disclosures about Market Risk

Interest Risk on Investments
At March 31, 2017, the Company held investments of $32,639,791 in money market accounts. The money market funds are invested in governmental obligations with minimal fluctuations in interest rates and fixed terms; therefore, the interest rate risk on investments is not significant.

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

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

Item 4 - Controls and Procedures

An evaluation was performed under the supervision and with the participation of our management, including the 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 March 31, 2017 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

Not applicable.

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: May 10, 2017	By: /s/ Dennis J. Gilles
	Dennis J. Gilles
	Chief Executive Officer
Date: May 10, 2017
	By: /s/ Kerry D. Hawkley
	Kerry D. Hawkley
	Chief Financial Officer and Corporate Secretary

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EXHIBIT INDEX

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