Us Geothermal 10-Q 2015 Q2 Quarterly report

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

FORM 10-Q

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

For the quarterly period ended June 30, 2014

or

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

For the transition period from ____________ to ___________

Commission File Number:001-34023

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

Delaware	84-1472231
(State or Other Jurisdiction of	(I.R.S. Employer
Incorporation or Organization)	Identification No.)

390 E. Parkcenter Blvd., Suite 250
Boise, Idaho	83706
(Address of Principal Executive Offices)	(Zip Code)

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

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

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

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

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

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

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

Class	Shares Outstanding as of August 12, 2014
Common stock, par value	103,865,800
$ 0.001 per share

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U.S. Geothermal Inc.

Form 10-Q

For the Second Quarter Ended June 30, 2014

INDEX

PART I – Financial Information
Item 1 - Financial Statements (Unaudited)	5
Interim Consolidated Balance Sheet at June 30, 2014 and Consolidated Balance Sheet at December 31, 2013	6
Interim Consolidated Statements of Operations – Three Months Ended and Six Months Ended June 30, 2014 and 2013	7
Interim Consolidated Statements of Cash Flow – Six Months Ended June 30, 2014 and 2013	8
Interim Consolidated Statement of Stockholders’ Equity – Year Ended December 31, 2013 and Three Months Ended June 30, 2014	9
Notes to Interim Consolidated Financial Statements	10
Item 2 - Management’s Discussion and Analysis of Financial Condition and Results of Operations	36
- General Background and Discussion	37
- Operating Results	43
- Off Balance Sheet Arrangements	54
- Liquidity and Capital Resources	54
- Potential Acquisitions	57
- Critical Accounting Policies	57
Item 3 - Quantitative and Qualitative Disclosures about Market Risk	57
Item 4 - Controls and Procedures	58
PART II – Other Information
Item 1 - Legal Proceedings	59
Item 1A - Risk Factors	59
Item 2 - Unregistered Sales of Equity Securities and Use of Proceeds	59
Item 3 - Defaults Upon Senior Securities	59
Item 4 – Mine Safety Disclosures	59
Item 5 - Other Information	59
Item 6 - Exhibits	59

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Part I - Financial Information

Item 1 - Financial Statements

The financial statements included herein have been prepared by U.S. Geothermal Inc. (the “Company”), without audit, pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles may have been condensed or omitted. However, in the opinion of management, all adjustments (which include only normal recurring accruals) necessary to present fairly the financial position and results of operations for the periods presented have been made. These financial statements should be read in conjunction with the accompanying notes, and with the audited financial statements and notes to the financial statements included in the Company’s report on Form 10-K for the year ended December 31, 2013. The results of operations for the six months ended June 30, 2014 are not necessarily indicative of the results to be expected for the year ending December 31, 2014.

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U.S. GEOTHERMAL INC.

________

Consolidated Financial Statements
June 30, 2014

U.S. GEOTHERMAL INC.

CONSOLIDATED BALANCE SHEETS

		(Unaudited)
		June 30, 2014			December 31, 2013
ASSETS
Current:
Cash and cash equivalents (note 2)	$	11,607,953		$	28,736,934
Restricted cash and bonds (note 3)		3,376,183			3,081,020
Trade accounts receivable		2,517,053			4,106,806
Other current assets		1,267,392			1,079,262
Total current assets		18,768,581			37,004,022
Investment in equity securities (note 4)		-			42,174
Costs on acquisition		136,546			-
Restricted cash and bond reserves (note 3)		18,781,360			18,815,145
Property, plant and equipment, net of accumulateddepreciation (note 5)		167,741,928			161,583,938
Intangible assets, net of accumulated amortization (note 6)		15,508,047			15,320,018
Total assets	$	220,936,462		$	232,765,297
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts payable and accrued liabilities	$	1,220,700		$	1,626,687
Related party accounts payable		1,409			3,089
Current portion of capital lease obligations (note 8)		45,343			48,118
Current portion of notes payable (note 9)		4,128,722			4,127,170
Total current liabilities		5,396,174			5,805,064
Long-term Liabilities:
Long-term portion of capital lease obligations (note 8)		-			20,921
Asset retirement obligations (note 14)		1,400,000			-
Notes payable, less current portion (note 9)		97,307,611			99,226,423
Total long-term liabilities		98,707,611			99,247,344
Total liabilities		104,103,785			105,052,408
Commitments and Contingencies (note 14)		-			-
STOCKHOLDERS’ EQUITY
Capital stock (authorized: 250,000,000 common shares with a $0.001 par      value; issued and outstanding shares at June 30, 2014 and December      31, 2013 were: 103,865,800 and 102,094,542; respectively)		103,866			102,094
Additional paid-in capital		101,562,089			100,381,207
Accumulated other comprehensive loss		-			(27,321	)
Accumulated deficit		(30,711,964	)		(30,898,571	)
		70,953,991			69,557,409
Non-controlling interests (note 15)		45,878,686			58,155,480
Total stockholders’ equity		116,832,677			127,712,889
Total liabilities and stockholders’ equity	$	220,936,462		$	232,765,297

The accompanying notes are an integral part of these interim consolidated financial statements.
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U.S. GEOTHERMAL INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

		(Unaudited)						(Unaudited)
		For the Three Months Ended						For the Six Months Ended
		June 30,						June 30,
		2014			2013			2014			2013
Plant Revenues:
Energy sales	$	5,760,037		$	4,886,839		$	14,161,134		$	11,875,498
Energy credit sales		85,837			86,237			186,705			184,567
Total plant operating revenues		5,845,874			4,973,076			14,347,839			12,060,065
Plant Expenses:
Plant production expenses		2,709,790			2,309,007			4,869,496			3,634,963
Depreciation and amortization		1,564,988			1,651,842			3,123,306			3,310,242
Total plant operating expenses		4,274,778			3,960,849			7,992,802			6,945,205
Net Income (Loss) from Plant Operations		1,571,096			1,012,227			6,355,037			5,114,860
Expenses (Income):
Corporate administration		299,797			204,557			592,103			496,868
Professional and management fees		197,964			432,190			567,947			731,350
Salaries and wages		677,343			553,655			1,072,056			1,118,143
Stock based compensation		630,153			204,390			777,465			263,753
Travel and promotion		65,271			68,559			99,994			119,214
Leases and well testing		19,402			414,377			43,488			576,386
Interest expense		1,008,737			1,123,883			1,989,729			1,604,185
Other (income) expenses		(19,241	)		(22,757	)		(26,506	)		(63,492	)
Total expenses (income)		2,879,426			2,978,854			5,116,276			4,846,407
Net Income (Loss) Before Income Tax Expense		(1,308,330	)		(1,966,627	)		1,238,761			268,453
Net Income Tax Expense (note 7):
Income taxes		-			-			473,000			102,500
Effect of net deferred tax assets		-			-			(473,000	)		(102,500	)
Net income tax expense		-			-			-			-
Net Income (Loss)		(1,308,330	)		(1,966,627	)		1,238,761			268,453
Net (income) loss attributable to the non- controlling interests		155,517			590,268			(1,052,154	)		(256,288	)
Net Income (Loss) Attributable to U.S.Geothermal Inc.		(1,152,813	)		(1,376,359	)		186,607			12,165
Other Comprehensive Income (Loss):
Unrealized income (loss) on investment in equity securities		-			(882	)		27,321			(20,547	)
Comprehensive Income (Loss) Attributable toU.S. Geothermal Inc.	$	(1,152,813	)	$	(1,377,241	)	$	213,928		$	(8,382	)
Basic Net Income (Loss) Per Share Attributableto U.S. Geothermal Inc.	$	(0.01	)	$	(0.01	)	$	0.00		$	0.00
Diluted Net Income (Loss) Per Share Attributableto U.S. Geothermal Inc.	$	(0.01	)	$	(0.01	)	$	0.00		$	0.00
Weighted Average Number of SharesOutstanding for Basic Calculations		103,710,490			101,516,764			103,009,360			101,516,764
Weighted Average Number of Shares, StockOptions and Warrants Outstanding for DilutedCalculations		103,710,490			101,516,764			125,833,000			122,611,539

The accompanying notes are an integral part of these interim consolidated financial statements.
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U.S. GEOTHERMAL INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

		(Unaudited)
		For the Six Months Ended June 30,
		2014			2013
Operating Activities:
Net Income	$	1,238,761		$	268,453
Adjustments to reconcile net income to total cash provided by operating activities:
Depreciation and amortization		3,188,050			3,371,177
Stock based compensation		777,465			263,753
Loss on sale of securities		27,967			-
Net changes in:
Trade accounts receivable, operating		1,589,753			1,372,348
Accounts payable and accrued liabilities		1,229,413			(284,230	)
Prepaid expenses and other		(188,130	)		(62,664	)
Total cash provided by operating activities		7,863,279			4,928,837
Investing Activities:
Purchases of property, plant and equipment		(1,150,022	)		(618,662	)
Acquisition of subsidiaries (note 16)		(6,782,445	)		-
Deposit costs related to acquisition		(136,546	)		-
Proceeds from ITC cash grants receivable		-			33,800,784
Proceeds from sale of equities held for investment		41,528			-
Release of restricted cash reserves and bonds		(161,378	)		-
Total cash provided (used) by investing activities		(8,188,863	)		33,182,122
Financing Activities:
Issuance of share capital		405,189			-
Contributions from non-controlling interest		-			7,460
Distributions to non-controlling interest		(13,328,948	)		(63,348	)
Principal payments on notes payable and other obligations		(3,855,942	)		(2,658,892	)
Principal payments on capital lease		(23,696	)		(22,303	)
Total cash used by financing activities		(16,803,397	)		(2,737,083	)
Increase (Decrease) in Cash and Cash Equivalents		(17,128,981	)		35,373,876
Cash and Cash Equivalents, Beginning of Period		28,736,934			12,908,779
Cash and Cash Equivalents, End of Period	$	11,607,953		$	48,282,655
Supplemental Disclosures:
Non-cash investing and financing activities:
Purchase of property and equipment on account	$	301,602		$	1,956,976
Construction and development paid directly with construction loans		-			2,355,316
Property and equipment costs reduced by settlement agreements		-			2,142,658
Grants receivable used to decrease construction costs		-			1,719,216
Other Items:
Interest paid		2,002,894			1,105,950

The accompanying notes are an integral part of these interim consolidated financial statements.
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U.S. GEOTHERMAL INC.

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY

For the Six Months Ended June 30, 2014 and the Year Ended December 31, 2013

					Additional					Accumulated			Non-
	Number of		Common		Paid-In		Accumulated			Comprehensive			controlling
	Shares		Shares		Capital		Deficit			Income (Loss)			Interest			Totals
Balance at December 31, 2012	101,516,764	$	101,516	$	99,524,850	$	(32,845,150	)	$	(3,944	)	$	56,081,198		$	122,858,470
Non-controlling equity contribution from Gerlach Green Energy, LLC	-		-		-		-			-			7,460			7,460
Distributions to non-controlling interest entity	-		-		-		-			-			(117,248	)		(117,248	)
Stock issued under terms of employment agreement	577,778		578		99,422		-			-			-			100,000
Stock compensation	-		-		756,935		-			-			-			756,935
Unrealized loss on investment	-		-		-		-			(23,377	)		-			(23,377	)
Net income	-		-		-		1,946,579			-			2,184,070			4,130,649
Balance at December 31, 2013	102,094,542		102,094		100,381,207		(30,898,571	)		(27,321	)		58,155,480			127,712,889
Distributions to non-controlling interest entities	-		-		-		-			-			(13,328,948	)		(13,328,948	)
Stock issued by the exercise of employee stock options	1,077,000		1,077		336,544		-			-			-			337,621
Stock issued by the exercise of stock purchase warrants	135,136		136		67,432											67,568
Stock compensation	559,122		559		776,906		-			-			-			777,465
Unrealized loss and reclassification to net income	-		-		-		-			27,321			-			27,321
Net income	-		-		-		186,607			-			1,052,154			1,238,761
Balance at June 30, 2014 - unaudited	103,865,800	$	103,866	$	101,562,089	$	(30,711,964	)	$	-		$	45,878,686		$	116,832,677

The accompanying notes are an integral part of these interim consolidated financial statements.
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U.S. GEOTHERMAL INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Unaudited

June 30, 2014

NOTE 1 - ORGANIZATION AND DESCRIPTION OF BUSINESS

U.S. Geothermal Inc. 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, manages and operates power plants that utilize geothermal resources to produce energy. The Company’s operations have been, primarily, focused in the Western United States of 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”). Such rules and regulations allow the omission of certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles in the United States of America, so long as such omissions do not render the financial statements misleading. Certain prior period amounts have been reclassified to conform to the current period presentation.

In the opinion of management, these financial statements reflect all adjustments that are necessary for a fair statement of the results for the periods presented. All adjustments were of a normal recurring nature. These interim financial statements should be read in conjunction with the annual financial statements of the Company included in its Report on Form 10-K.

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)	Etoile Holdings Inc. (incorporated in the Bahamas);
xvii)	Mayacamas Energy LLC (organized in the State of California);
xviii)	Skyline Geothermal LLC (organized in the State of Delaware); and
xix)	Skyline Geothermal Holding, Inc. (incorporated 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 statements of operations will consolidate the subsidiary’s full operations, and will separately disclose the elimination of the non-controlling interest’s allocation of profits and losses.

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The following are summarized accounting policies considered to be significant by the Company’s management:

Accounting Method

The Company’s consolidated financial statements are prepared using the accrual basis of accounting in accordance with generally accepted accounting principles in the United States of America (“U.S. GAAP”) and have been consistently applied in the preparation of the consolidated financial statements.

Use of Estimates

The preparation of consolidated financial statements in accordance with generally accepted accounting principles requires the use of estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities known to exist as of the date the consolidated financial statements are published, and the reported amounts of revenues and expenses during the reporting period. Uncertainties with respect to such estimates and assumptions are inherent in the preparation of the Company’s consolidated financial statements; accordingly, it is possible that the actual results could differ from these estimates and assumptions and could have a material effect on the reported amounts of the Company’s consolidated financial position and consolidated results of operations.

Cash and Cash Equivalents

The Company considers all unrestricted cash, short-term deposits, and other investments with original maturities of no more than ninety days when acquired to be cash and cash equivalents for the purposes of the statement of cash flows. Under the Loan Guarantee Agreement at Neal Hot Springs with the Department of Energy, all funds for USG Oregon LLC are deposited into PNC Bank subject to certain procedural restrictions on the use of the funds. The waterfall of funds out of the Revenue account is processed semi-annually. At June 30, 2014, $4.1 million in USG Oregon LLC funds were deposited at PNC Bank and $278,000 in Oregon USG Holdings LLC funds were deposited at Umpqua Bank, and were unavailable for immediate corporate needs. Discussion regarding restricted cash is included in Note 3.

Accounts Receivable Allowance for Doubtful Accounts

Trade Accounts Receivable
Management estimates the amount of trade accounts receivable that may not be collectible and records an allowance for doubtful accounts. The allowance is an estimate based upon aging of receivable balances, historical collection experience, and the periodic credit evaluations of our customers’ financial condition. Receivable balances are written off when we determine that the balance is uncollectible. As of June 30, 2014 and December 31, 2013, there were no balances that were over 90 days past due and no balance in allowance for doubtful accounts was recognized.

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Grant Accounts Receivable
For receivables from grants from Federal or State agencies, the Company records the receivable amounts net of the funds expected to be received. Therefore, no allowance accounts are considered to be necessary for receivables from grants at June 30, 2014 and December 31, 2013.

Concentration of Credit Risk

The Company’s cash and cash equivalents, including restricted cash, consisted of commercial bank deposits, money market accounts, and petty cash. Cash deposits are held in commercial banks in Boise, Idaho and Portland, Oregon. Deposits are guaranteed by the Federal Deposit Insurance Corporation (“FDIC”) up to $250,000 per legal entity. At June 30, 2014, the Company’s total cash balance, excluding money market funds, was $3,627,990, and bank deposits amounted to $3,779,079. The primary difference was due to outstanding checks and deposits. Of the bank deposits, $2,313,205 was not covered by or was in excess of FDIC insurance guaranteed limits. At June 30, 2014, the Company’s money market funds invested in government backed securities totaled $30,133,806 and were not subject to deposit insurance.

Equity Securities

The Company determines the appropriate classification of marketable securities at the time of purchase and reevaluates this designation as of each balance sheet date. The Company classifies these securities as either held-to-maturity, trading, or available-for-sale. All marketable securities and restricted investments were classified as available-for-sale securities. The Company classifies its investments as “available for sale” because it does not intend to actively buy and sell for short-term profits. The Company's investments are subject to market risk, primarily interest rate and credit risk. The fair value of investments is determined using observable or quoted market prices for those securities.

Available-for-sale securities are carried at fair value, with unrealized gains and losses included as a component of accumulated other comprehensive income (loss). Realized gains and losses, declines in value judged to be other than temporary and interest on available-for-sale securities are included in net income. The cost of securities sold is based on the specific identification method.

Property, Plant and Equipment

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

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

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

Intangible Assets

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

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

Currently, amortization expense is being calculated on a straight-line basis over an estimated utilization period of 30 years for assets placed in service. If an intangible water or geothermal right is forfeited or otherwise lost, the remaining unamortized costs are expensed in the period of forfeiture. An impaired right is reduced to its estimated fair market value in the year the impairment is realized. Costs incurred that extend the term of an intangible right are capitalized and amortized over the new estimated period of utilization.

Impairment of Long-Lived Assets

The Company evaluates its long-term assets annually for impairment and when circumstances/events occur that may impact the fair value of the assets. An impairment loss would be recognized if the carrying amount of a capitalized asset is not recoverable and exceeds its fair value. The most recent assessment was performed based upon financial conditions and assumptions as of December 31, 2013, and there have not been any significant changes in financial conditions and assumptions subsequent to that assessment date. Management believes that there have not been any circumstances that have warranted the recognition of losses due to the impairment of long-lived assets.

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Stock Options Granted to Employees and Non-employees

The Company follows financial accounting standards that require the measurement of the value of employee services received in exchange for an award of an equity instrument based on the grant-date fair value of the award. For employees, directors and officers, the fair value of the awards are expensed over the vesting period. The current vesting period for all such options is eighteen months.

Non-employee stock-based compensation is granted at the Board of Director’s discretion to reward select consultants for exceptional performance. Prior to issuance of the awards, the Company was not under any obligation to issue the stock options. Subsequent to the award, the recipient was not obligated to perform any services. Therefore, the fair value of these options was expensed on the grant date, which was also the measurement date.

Under the fair value recognition provisions, share-based compensation cost is measured at the grant date based on the value of the award and is recognized as expense over the vesting period. Determining the fair value of share-based awards at the grant date requires judgment. In addition, judgment is also required in estimating the amount of share-based awards that are expected to be forfeited. If actual results differ significantly from these estimates, stock-based compensation expense and our results of operations could be materially impacted.

Stock Based Compensation Granted to Employees

The Company recognizes the value of common stock granted to employees and directors over the periods in which the services are received. The value of those services is based upon the estimated fair value of the common stock to be awarded. Estimated fair value is adjusted each reporting period. At the end of each vesting period, estimated fair value is adjusted to fair market value. The adjustment is reflected in the reporting period in which the vesting occurs.

Earnings (Losses) Per Share

The Company follows financial accounting standards, which provides for calculation of "basic" and "diluted" earnings (losses) per share. Basic earnings per share includes no dilution and is computed by dividing net income available to common shareholders by the weighted average common shares outstanding for the period. Diluted earnings per share reflect the potential dilution of securities that could share in the earnings of an entity similar to fully diluted earnings per share. Both basic and diluted were presented for the calculation of the income per share for the periods that reported income. Stock equivalents were not included in the calculation for the periods that reported losses since their inclusion would be considered anti-dilutive. Total common stock equivalents on a fully diluted basis at June 30, 2014 and December 31, 2013 were 126,209,335 and 124,494,963; respectively.

Financial Instruments

The Company’s financial instruments consist of cash and cash equivalents, trade account and other receivables, refundable tax credits, and accounts payable and accrued liabilities. Unless otherwise noted, it is management’s opinion that the Company is not exposed to significant interest, currency or credit risks arising from these financial instruments. The fair values of these financial instruments approximate their carrying values, unless otherwise noted.

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

-14-

Revenue

Revenue Recognition

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

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

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

Asset Retirement Obligations

The Company records the fair value of estimated asset retirement obligations (“AROs”) associated with tangible long-lived assets in the period incurred or acquired. AROs are legal obligations to settle under existing or enacted law, statue, or contract. The value of these obligations are originally based upon discounted cash flow estimates and are accreted to full value over time through charges to operations. Costs associated with future conditions are recognized as AROs in the period the condition occurs or is known to the Company. Generally, costs associated with AROs are earthwork, revegetation, well capping, and structure removal necessary to return the sites to their original conditions.

Reclassification

Certain amounts in the prior period financial statements have been reclassified to conform to the current period presentation. These reclassifications had no effect on reported losses, total assets, or stockholders’ equity as previously reported.

-15-

Recent Accounting Pronouncements

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

Stock Compensation
In June 2014, FASB issued Accounting Standards Update No. 2014-12 (“Update 2014-12”),Compensation-Stock Compensation, Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period(Topic 718). Update 2014-12 provides guidance on how to account for share-based payment awards that require a specific performance target to be achieved in order for the employees to become eligible to vest in the awards. Update 2014-12 is effective for annual periods and interim periods within those annual periods beginning after December 15, 2015. Management is still evaluating the applicability and possible impact this update may have on the accounting treatment and its financial statement presentation.

Presentation of Property, Plant and Equipment
In April 2014, FASB issued Accounting Standards Update No. 2014-08 (“Update 2014-08”),Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360), Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity.Update 2014-08 provides guidance to address the issues surrounding the reporting of discontinued operations and enhance the convergence of the FASB’s and the International Accounting Standard Board’s reporting requirements for discontinued operations. Update 2014-08 is effective for annual periods and interim periods within those annual periods beginning after December 15, 2015. Management is still evaluating the applicability and possible impact this update may have on the accounting treatment and its financial statement presentation.

-16-

NOTE 3 – RESTRICTED CASH AND BOND RESERVES

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

Current restricted cash and bond reserves:

		June 30,		December 31,
Restricting Entities/Purpose		2014		2013
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		666,190		19,848
U.S. Department of Energy, Debt Service Reserve		1,739,993		2,191,172
State of California Division of Oil, Gas and Geothermal Resources, Well Cash Bond		100,000		-
	$	3,376,183	$	3,081,020

Long-term restricted cash and bond reserves:

		June 30,		December 31,
Restricting Entities/Purpose		2014		2013
Nevada Energy, PPA Security Bond	$	1,468,898	$	1,468,898
Prudential Capital Group, Debt Service Reserves		1,594,473		1,594,437
Prudential Capital Group, Maintenance Reserves		660,439		751,183
Prudential Capital Group, Well Reserves		159,216		53,072
U.S. Department of Energy, Operations Reserves		270,000		270,000
U.S. Department of Energy, Debt Service Reserves		2,600,323		2,668,179
U.S. Department of Energy, Short Term Well Field Reserves		4,660,094		4,507,391
U.S. Department of Energy, Long-Term Well Field Reserves		4,503,399		4,501,191
U.S. Department of Energy, Capital Expenditure Reserves		2,864,518		3,000,794
	$	18,781,360	$	18,815,145

The well bonding requirements ensure that the Company has sufficient financial resources to construct, operate and maintain geothermal wells while safeguarding subsurface, surface and atmospheric resources from unreasonable degradation, and to protect ground water aquifers and surface water sources from contamination. Other future costs of environmental remediation cannot be reasonably estimated and have not been recorded. The debt service reserves are required to provide assurance that the Company will have sufficient funds to meet its debt payment obligations for the terms specified by the loan agreements. The maintenance and capital expenditure reserves are required by the lending entities to ensure that funds are available to acquire and maintain critical components of power plants and related supporting structures to enable the plants to operate according to expectations. Except for the PPA Security Bond, all of the restricted funds consisted of cash deposits or money market accounts held in commercial banks. Portions of the cash deposits are subject to FDIC insurance. See note 2 for details. The PPA Security Bond is held by the power purchaser. All of the reserve accounts were considered to be fully funded at June 30, 2014 and December 31, 2013. As described in note 16, the Geyser’s acquisition included a short term well bond of $100,000 at June 30, 2014.

-17-

NOTE 4 – INVESTMENT IN EQUITY SECURITIES

During the quarter ended March 31, 2014, all of the Company’s holdings of equity securities (150,000 shares of Alterra Power Corp, a publicly traded renewable energy company) were sold for $41,528, which resulted in a realized loss of $27,967. For the current quarter, the net change of $27,321 was reclassified from other comprehensive income to net income as a result of the sale.

NOTE 5 - PROPERTY, PLANT AND EQUIPMENT

During the quarter ended June 30, 2014, the Company acquired a group of companies that included long-term assets that totaled $7.74 million (land of $1.6 million, well and drilling construction in progress of $6.14 million). See note 16 for details. The Company continued with development activities for Phase II San Emidio (located in Northwestern Nevada) and the Guatemala projects. For Phase II San Emidio, over $206,000 was incurred for well drilling and permitting. At Guatemala, over $353,000 was incurred on temperature gradient wells and plant facilities. Costs that exceeded $74,800 were incurred at Neal Hot Springs, Oregon on a bridge.

During the quarter ended March 31, 2014, the Company continued with development activities for Phase II San Emidio, Nevada and the Guatemala projects. For Phase II San Emidio, over $81,000 was incurred on a seismic study, well pad permitting, and well drilling, At Guatemala, over $395,000 was incurred on temperature gradient wells.

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

		June 30,			December 31,
		2014			2013
Land	$	3,207,025		$	1,603,509
Power production plant		162,071,575			161,868,687
Grant proceeds for power plants		(52,965,236	)		(52,965,236	)
Wells		67,621,167			67,620,661
Grant proceeds for wells		(3,464,555	)		(3,464,555	)
Furniture and equipment		1,663,152			1,462,312
		178,133,128			176,125,378
Less: accumulated depreciation		(23,993,150	)		(20,895,943	)
		154,139,978			155,229,435
Construction in progress		13,601,950			6,354,503
	$	167,741,928		$	161,583,938

-18-

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

		June 30,
		2014		2013
Three months ended	$	1,344,175	$	1,620,030
Six months ended		3,097,207		3,246,497

Changes in Construction in Progress are summarized as follows:

		For the Six Months		For the Year
		Ended June 30,		Ended December
		2014		31, 2013
Beginning balances	$	6,354,503	$	2,877,994
Development/construction		1,047,389		3,694,978
Grant reimbursements and rebates		-		(33,325	)
Acquisition (note 16)		6,200,058		-
Transfers into production		-		(185,144	)
Ending balances	$	13,601,950	$	6,354,503

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

		June 30,		December 31,
		2014		2013
Raft River, Idaho:
Unit II, power plant, substation and transmission lines	$	750,493	$	750,493
Unit II, well construction		2,127,166		2,121,502
		2,877,659		2,871,995
San Emidio, Nevada:
Unit II, power plant, substation and transmission lines		6,947		3,910
Unit II, well construction		2,043,281		1,753,299
		2,050,228		1,757,209
The Geysers, California:
Power plant and facilities		60,637		-
Well construction		6,139,421		-
		6,200,058		-
El Ceibillo, Republic of Guatemala:
Well Construction		2,465,505		1,725,299
Plant and facilities		8,500		-
		2,474,005		1,725,299
	$	13,601,950	$	6,354,503

-19-

NOTE 6 – INTANGIBLE ASSETS

During the quarter ended June 30, 2014, the Company acquired a group of companies that included geothermal water rights located at The Geysers in Northern California that amounted to $278,872 (see note 16 for details).

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

		June 30,			December 31,
		2014			2013
In operation:
Neal Hot Springs, Oregon:
Geothermal water and mineral rights	$	625,337		$	625,337
San Emidio, Nevada:
Geothermal water and mineral rights		4,825,220			4,825,220
Less: accumulated amortization		(1,026,592	)		(935,749	)
		4,423,965			4,514,808
Inactive:
Raft River, Idaho:
Surface water rights		146,343			146,343
Geothermal water and mineral rights		1,251,540			1,251,540
Granite Creek, Nevada:
Geothermal water and mineral rights		451,299			451,299
Guatemala City, Guatemala:
Geothermal water and mineral rights		625,000			625,000
Gerlach, Nevada:
Geothermal water and mineral rights		997,000			997,000
The Geysers, California:
Geothermal water rights (note 16)		278,872			-
San Emidio, Nevada:
Surface water rights		4,323,520			4,323,520
Geothermal water and mineral rights		3,440,580			3,440,580
Less: prior accumulated amortization		(430,072	)		(430,072	)
		11,084,082			10,805,210
	$	15,508,047		$	15,320,018

Amortization expense was charged to plant operations for the following periods:

		June 30,
		2014		2013
Three months ended	$	45,421	$	62,361
Six months ended		90,843		124,681

-20-

Estimated aggregate amortization expense for the next five years is as follows:

		Projected
		Amounts
Years ending December 31,
2014	$	90,843
2015		181,685
2016		181,685
2017		181,685
2018		181,685
	$	817,583

NOTE 7 – PROVISION FOR INCOME TAXES

Income taxes are recorded based upon the liability method. Under this approach, deferred income taxes are recorded to reflect the tax consequences in future years of differences between the tax basis of assets and liabilities and their financial reporting amounts at each year-end. A valuation allowance is recorded against deferred tax assets if management does not believe the Company has met the “more likely than not” standard imposed by accounting standards to allow recognition of such an asset.

At June 30, 2014, the Company had net deferred tax assets calculated at an expected rate, noted in the table below, of approximately $19,330,000 (December 31, 2013 - $10,714,000). As management of the Company cannot determine that it is more likely than not that the Company will realize the benefit of the net deferred tax asset, a valuation allowance equal to the net deferred tax asset was recorded at June 30, 2014 and December 31, 2013. For the current periods ended June 30, 2014 and 2013, the Company has recognized the net deferred income tax asset to the extent of the impact created from current book earnings. During the year ended December 31, 2013, the Company engaged a tax matters consultant to evaluate the value and timing of adjusting the deferred tax valuation allowance. The Company anticipates that any tax obligations will be fully offset by the utilization of prior reserved deferred tax benefits for the year ended December 31, 2013.

The significant components of the net deferred tax asset calculated with the estimated effective income tax rate at June 30, 2014 and December 31, 2013 were as follows:

		June 30,			December 31,
		2014			2013
Deferred tax assets*:
Net operating loss carry forward	$	41,946,000		$	38,400,000
Stock based compensation		1,899,000			1,868,000
Deferred tax liabilities*:
Depreciation and amortization		(24,515,000	)		(29,554,000	)
Net deferred income tax asset		19,330,000			10,714,000
Estimated deferred tax asset recognized and utilized in current period		(473,000	)		(1,578,000	)
Deferred tax asset valuation allowance		(18,857,000	)		(9,136,000	)
Net deferred tax asset	$	-		$	-

* - significant components of deferred assets and liabilities are considered to be long-term.

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

-21-

	For the Years Ended December 31,
	2014	2013
U.S. Federal statutory rate	34.0%	34.0%
Average State income tax, net of federal tax effect	4.2	4.2
Production tax credits	-	-
Net effective tax rate	38.2%	38.2%

At June 30, 2014, the Company had net income tax operating loss carry forwards of approximately $109,805,000 ($100,524,000 in December 31, 2013), which expire in the years 2023 through 2034. The change in the allowance account from December 31, 2013 to June 30, 2014 was an increase of $9,721,000 for the anticipated deferred tax allocations based on 2014 income.

The net change in the deferred tax asset valuation allowance account is detailed as follows:

		For the Six		For the Year
		Months Ended		Ended December
		June 30, 2014		31, 2013
Change in net operating loss	$	3,546,000	$	16,258,000
Change in estimated effective tax rate		-		614,000
Net change in difference between book and tax stock compensation costs		31,000		251,000
Change in estimated deferred tax asset recognized and utilized in current period		1,105,000		(1,578,000	)
Change in period book to income tax depreciation		5,039,000		(17,518,000	)
Net change in deferred tax valuation allowance	$	9,721,000	$	(1,973,000	)

At December 31, 2013, Raft River Energy I LLC has a book-to-tax difference of $35.7 million due to the acceleration of intangible drilling costs and depreciation. By contract, 99% percent of this book-to-tax difference has been allocated to the non-controlling interest and would not be available to the consolidated group to offset future tax liabilities. At December 31, 2013, USG Oregon LLC has a book-to-tax difference of $38.1 million due to the acceleration of depreciation.

Although Management believes that its estimates are reasonable, no assurance can be given that the final tax outcome of these matters will not be different than that which is reflected in our tax provisions. Ultimately, the actual tax benefits to be realized will be based upon future taxable earnings levels, which are very difficult to predict.

Accounting for Income Tax Uncertainties and Related Matters

The Company may be assessed penalties and interest related to the underpayment of income taxes. Such assessments would be treated as a provision of income tax expense on the financial statements. For the year ended December 31, 2013, nine months ended December 31, 2012 and the fiscal year ended March 31, 2012, no income tax expense has been realized as a result of operations and no income tax penalties and interest have been accrued related to uncertain tax positions. The Company files income tax returns in the U.S. federal jurisdiction and in the States of Idaho, California and Oregon. These filings are subject to a three year statute of limitations. The Company’s evaluation of income tax positions included the year ended December 31, 2013, the nine months ended December 31, 2012 and the fiscal year ended March 31, 2012 could be subject to agency examinations as of December 31, 2013. No filings are currently under examination. No adjustments have been made to reduce the estimated income tax benefit at fiscal year end. Any valuations relating to these income tax provisions will comply with U.S. Generally Accepted Accounting Principles.

-22-

NOTE 8 - CAPITAL LEASE OBLIGATIONS

Effective May 10, 2012, the Company entered into two capital lease obligations for the purchase of a boom lift and a telehandler from Caterpillar Financial Services Corporation. The boom lift contract is payable in 36 monthly payments of $1,094 that began on June 11, 2012 and has an effective annual interest rate of 5.985% . The telehandler contract is payable in 36 monthly payments of $3,155 that began on June 11, 2012 and has an effective annual interest rate of 6.14% . Both contracts with Caterpillar Financial Services Corporation have bargain purchase options at the end of the contracts scheduled for May 2015. At June 30, 2014, all of the lease obligations were considered to be current.

The scheduled future lease payments for the two contracts are presented as follows:

		Capital Lease
Years ending December 31,		Amounts
2014	$	25,499
2015		21,249
Total future payments		46,748
Less: imputed interest portion		(1,405	)
	$	45,343

At June 30, 2014, the net book value of the equipment under capital lease amounted to $58,028 ($155,000, less $96,972 accumulated amortization).

NOTE 9 – NOTES PAYABLE

U.S. Department of Energy
On August 31, 2011, USG Oregon LLC (“USG Oregon”), a subsidiary of the Company, completed the first funding drawdown associated with the U.S. Department of Energy (“DOE”) $96.8 million loan guarantee (“Loan Guarantee”) to construct its power plant at Neal Hot Springs in Eastern Oregon (the “Project”). The U.S. Treasury’s Federal Financing Bank, as lender for the Project, issues payments direct to vendors. All loan advances covered by the Loan Guarantee have been made under the Future Advance Promissory Note (the “Note”) dated February 23, 2011. Upon the occurrence and continuation of an event of default under the transaction documents, all amounts payable under the Note may be accelerated. In connection with the Loan Guarantee, the DOE has been granted a security interest in all of the equity interests of USG Oregon, as well as in the assets of USG Oregon, including a mortgage on real property interests relating to the Project site. The loan advances began August 31, 2011 and the last advance was taken on July 31, 2013. 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. On August 12, 2013, proceeds of the ITC cash grant were distributed in accordance with the loan agreement, with $11,870,137 of the proceeds being used to prepay the Project loan, $11,167,473 of proceeds being used to fund a series of Project reserves, and balance of $9,711,930 being distributed as equity to the project owners. After the loan prepayment, the remaining final loan balance was $70,386,576. The loan principal is scheduled to be paid over 21.5 years with semi-annual installments including interest calculated at an aggregate fixed interest rate of 2.598% . The principal payment amounts are calculated on a straight-line basis according to the life of the loans and the original loan principal amounts. The principal portion of the aggregate loan payment is adjusted as individual tranches are extinguished. The principal payments are scheduled to start at $1,709,963 and are expected to be reduced to $1,626,251 on February 10, 2017. The loan balance at June 30, 2014 totaled $69,265,762 (estimated current portion $3,419,927).

-23-

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

				Annual Interest
Description		Amount		Rate %
Advances by date:
August 31, 2011*	$	2,328,422		2.997
September 28, 2011		10,043,467		2.755
October 27, 2011		3,600,026		2.918
December 2, 2011		4,377,079		2.795
December 21, 2011		2,313,322		2.608
January 25, 2012		8,968,019		2.772
April 26, 2012		13,029,325		2.695
May 30, 2012		19,497,204		2.408
August 27, 2012		7,709,454		2.360
December 28, 2012		2,567,121		2.396
June 10, 2013		2,355,316		2.830
July 3, 2013*		2,242,628		3.073
July 31, 2013*		4,026,582		3.214
		83,057,965
Principal paid through June 30, 2014		(13,792,203	)
Loan balance at June 30, 2014	$	69,265,762

* - Individual tranches have been fully extinguished.

SAIC Constructors LLC
Effective August 27, 2010, the Company’s wholly owned subsidiary (USG Nevada LLC) signed a construction loan agreement with SAIC Constructors LLC (“SAIC”). The new 9.0 net megawatt power plant was considered complete and operational for financial reporting purposes on September 1, 2012. On February 15, 2013, USG Nevada LLC signed a settlement agreement with SAIC that defined the terms of three separate debt components to settle the obligations incurred under the construction loan agreement. As of December 31, 2013, two components of the settlement agreement were paid in full. On April 30, 2013, SAIC signed a loan agreement with Nevada USG Holdings LLC (parent company of USG Nevada LLC and wholly owned subsidiary of the Company), that further defined the terms of the remaining debt component of $2 million. This remaining obligation will be repaid in quarterly installments of $119,382, including interest at 7.0% per annum that began on July 31, 2013. The loan balance at June 30, 2014 totaled $1,671,132 (estimated current portion $285,016).

Prudential Capital Group
On September 26, 2013, the Company’s wholly owned subsidiary (USG Nevada LLC) entered into a note purchase agreement with the Prudential Capital Group’s related entities (“Prudential”) to finance the Phase I San Emidio geothermal project located in northwest Nevada. The term of the note is approximately 24 years, and bears interest at fixed rate of 6.75% per annum. Interest payments are due quarterly. Principal payments are due quarterly based upon minimum debt service coverage ratios established according to operating results and available cash balances. All amounts owing under the notes and the note purchase agreement or any related financing document are secured by USG Nevada LLC’s right, title and interest in and to its real and personal property, including the San Emidio project and the equity interests in USG Nevada LLC. At June 30, 2014, the balance of the loan was $30,499,440 (estimated current portion $423,779).

-24-

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

For the Fiscal Year Ended		Principal
June 30,		Payments
2015	$	4,128,722
2016		4,379,534
2017		4,367,440
2018		4,262,604
2019		4,043,494
Thereafter		80,254,539
	$	101,436,333

NOTE 10 - CAPITAL STOCK

The Company is authorized to issue 250,000,000 shares of common stock. All shares have equal voting rights, are non-assessable and have one vote per share. Voting rights are not cumulative and, therefore, the holders of more than 50% of the common stock could, if they choose to do so, elect all of the directors of the Company.

On April 2, 2014, the Company issued 559,122 shares of common stock (restricted shares) at a price of $0.74 per share to employees.

During the quarter ended June 30, 2014, the Company issued 352,500 shares of common stock as a result of employees and former employees exercising stock options priced at $0.31 per share.

During the quarter ended March 31, 2014, the Company issued 724,500 shares of common stock as a result of employees and former employees exercising stock options priced between $0.31 and $0.46 per share.

On March 14, 2014, the Company issued 135,136 shares of common stock to an investor exercising stock purchase warrants at a price of $0.50 per share.

During the year ended December 31, 2013, the Company issued 577,778 shares of common stock (300,000 restricted shares) to an employee of the Company at prices between $0.35 and $0.36 per share under the terms of an employment agreement.

NOTE 11 - 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 December 2009 and September 2013, whereby the Company can grant options to the extent of 15% of the current outstanding common shares. Under the plan, all forfeited and exercised options can be replaced with new offerings. As of June 30, 2014, the Company can issue stock option grants totaling up to 15,579,870 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. At June 30, 2014, the Company had 11,966,500 options granted and outstanding.

-25-

On April 2, 2014, the Company awarded 2,883,500 stock options at an exercise price of $0.74 expiring on April 2, 2019 to its employees and directors.

During the quarter ended June 30, 2014, 352,500 stock options exercisable at the price of $0.31 were exercised by employees and former employees.

During the quarter ended March 31, 2014, 724,500 stock options exercisable at prices between $0.31 and $0.46 were exercised by employees and former employees.

On February 22, 2014, 30,000 stock options exercisable at a price of $0.46 issued to employees were forfeited due to the termination of employment.

On September 25, 2013, 95,000 stock options exercisable at a price of $1.78 expired without exercise.

On September 1, 2013, the Company granted 15,000 stock options to an employee exercisable at a price of $0.41 until September 1, 2018.

On July 22, 2013, the Company granted 1,950,000 stock options to employees exercisable at a price of $0.46 until July 22, 2018.

On May 26, 2013, 6,375 stock options exercisable at a price of $0.92 were forfeited due to employee termination.

On May 19, 2013, 1,465,000 stock options exercisable at a price of $2.22 expired without exercise.

On April 19, 2013, the Company granted 1,250,000 stock options to employees exercisable at a price of $0.35 until April 19, 2023.

The following table reflects the summary of stock options outstanding at December 31, 2012 and changes for the year ended December 31, 2013 and six months ended June 30, 2014:

				Weighted
				Average		Weighted
	Number of			Exercise		Average		Aggregate
	shares under			Price Per		Fair		Intrinsic
	options			Share		Value		Value
Balance outstanding, December 31, 2012	10,239,625		$	0.91	$	0.55	$	5,606,309
Forfeited/Expired	(1,566,375	)		2.18		1.20		(1,872,094	)
Exercised	-			-		-		-
Granted	3,215,000			0.42		0.25		808,500
Balance outstanding, December 31, 2013	11,888,250			0.61		0.38		4,542,715
Forfeited/Expired	(1,728,250	)		0.46		0.24		(1,207,408	)
Exercised	(1,077,000	)		0.32		0.16		(171,134	)
Granted	2,883,500			0.74		0.40		1,153,400
Balance outstanding, June 30, 2014	11,966,500		$	0.62	$	0.40	$	4,317,573

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

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

	For the Six Months	For the Year
	Ended June 30,	Ended December
	2014	31, 2013
Dividend yield	0	0
Expected volatility	81-100%	71-81%
Risk free interest rate	0.69-0.82%	0.27-0.82%
Expected life (years)	3.19	4.63

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.

The following table summarizes information about the stock options outstanding at June 30, 2014:

OPTIONS OUTSTANDING
		REMAINING	NUMBER OF
EXERCISE	NUMBER OF	CONTRACTUAL	OPTIONS
PRICE	OPTIONS	LIFE (YEARS)	EXERCISABLE		INTRINSIC VALUE
$ 1.58	68,000	0.23	68,000	$	26,435
0.86	1,300,000	1.20	1,300,000		752,207
0.83	2,590,000	1.93	2,590,000		1,269,100
0.60	100,000	2.20	100,000		36,072
0.31	1,865,000	3.15	1,865,000		290,128
0.46	1,895,000	4.06	947,500		230,148
0.41	15,000	4.17	7,500		1,506
0.35	1,250,000	8.80	937,500		253,500
0.74	2,883,500	4.75	720,875		287,232
$ 0.62	11,966,500	3.77	8,536,375	$	3,146,328

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The following table summarizes information about the stock options outstanding at December 31, 2013:

OPTIONS OUTSTANDING
		REMAINING	NUMBER OF
EXERCISE	NUMBER OF	CONTRACTUAL	OPTIONS
PRICE	OPTIONS	LIFE (YEARS)	EXERCISABLE		INTRINSIC VALUE
$ 0.92	1,698,250	0.40	1,698,250	$	1,200,208
1.58	68,000	0.73	68,000		26,435
0.86	1,300,000	1.70	1,300,000		752,207
0.83	2,590,000	2.43	2,590,000		1,269,100
0.60	100,000	2.70	100,000		36,072
0.31	2,917,000	3.65	2,187,750		340,332
0.46	1,950,000	4.56	487,500		118,414
0.41	15,000	4.67	3,750		753
0.35	1,250,000	9.30	625,000		169,000
$ 0.61	11,888,250	3.43	9,060,250	$	3,912,521

A summary of the status of the Company’s nonvested stock options outstanding at December 31, 2012 and changes during the year ended December 31, 2013 and six months ended June 30, 2014 are presented as follows:

				Weighted		Weighted
				Average Grant		Average
	Number of			Date Fair Value		Grant Date
	Options			Per Share		Fair Value
Nonvested, December 31, 2012	2,212,750		$	0.31	$	0.16
Granted	3,215,000			0.42		0.25
Vested	(2,599,750	)		0.35		0.23
Forfeited/Expired	-			-		-
Nonvested, December 31, 2013	2,828,000			0.39		0.23
Granted	2,162,625			0.74		0.40
Vested	(1,553,000	)		0.36		0.18
Forfeited/Expired	(7,500	)		0.46		0.24
Nonvested, June 30, 2014	3,430,125		$	0.63	$	0.34

As of June 30, 2014, there was $924,876 of total unrecognized compensation cost related to nonvested share-based compensation arrangements granted under the Plan. That cost is expected to be recognized over a weighted-average period of 1.5 years. The total fair value of options vested at June 30, 2014 and December 31, 2013 was $662,389 and $683,143, respectively.

Stock Compensation Plan (Restricted Shares)

On April 19, 2013, the Company granted an officer and director 300,000 common shares valued at $0.35 per share, which were distributed at the end of a one-year vesting period subsequent to period end. The recipient meets 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. These shares were issued in July 2013 to the recipient and held by the Company until vested. The total fair value of options at the grant date was $105,000 and the recognized cost through June 30, 2014 was $31,208.

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On April 2, 2014, the Company issued 559,122 shares of Company stock at a price of $0.74 that fully vest on April 2, 2015 to its employees and directors. The total fair value at the grant date was $413,750 and the recognized cost through June 30, 2014 was $83,868.

Stock Purchase Warrants

At June 30, 2014, the outstanding broker warrants and share purchase warrants consisted of the following:

			Broker
			Warrant	Share		Warrant
	Broker		Exercise	Purchase		Exercise
Expiration Date	Warrants		Price	Warrants		Price
September 16, 2015	246,285	$	1.25	4,104,757	$	1.25
May 23, 2017	255,721		0.44	-		-
December 21, 2017	-		-	5,770,272		0.50

On March 14, 2014, 135,136 share purchase warrants were exercised by an investor at the warrant exercise price of $0.50.

On February 2013, 500,000 stock purchase warrants at an exercise price of $5.00 expired without exercise.

NOTE 12 – FAIR VALUE MEASUREMENT

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

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

Level 1 – Quoted prices are available in active markets for identical assets or liabilities. Active markets are those in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

Level 3 – Pricing inputs include significant inputs that are generally unobservable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to the Company’s needs.

Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

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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 as of June 30, 2014 at fair value on a recurring basis:

		Total		Level 1		Level 2		Level 3
Assets:
Money market accounts *	$	30,133,806	$	30,133,806	$	-	$	-

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

As allowed by current financial reporting standards, the Company has elected not to implement fair value recognition and reporting for all non-financial assets and non-financial liabilities, except for those that are recognized or disclosed at fair value in the financial statements on a recurring basis, that is, at least annually.

NOTE 13 - RELATED PARTY TRANSACTIONS

At June 30, 2014 and December 31, 2013 the amounts of $1,409 and $3,089; respectively, were payable to the officers of the Company for routine expense reimbursement. These amounts are unsecured and due on demand.

The Company paid directors’ fees for the six months ended June 30, 2014 and 2013 totalled $57,600 and $54,000; respectively.

NOTE 14 - COMMITMENTS AND CONTINGENCIES

Operating Lease Agreements

The Company has entered into several lease agreements with terms expiring up to December 1, 2034 for geothermal properties in Washoe County Nevada; Republic of Guatemala; Neal Hot Springs, Oregon and adjoining the Raft River properties in Raft River, Idaho. The Company incurred total lease expenses for the six months ended June 30, 2014 and 2013, of $219,199 and $115,091; respectively.

BLM Lease Agreements

The Company believes that it is in compliance with all of the following lease terms.

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

San Emidio
The lease contracts are for approximately 21,905 acres of land and geothermal rights located in the San Emidio Desert, Nevada. The lease contracts have primary terms of 10 years. Per federal regulations applicable for the contracts, the lessee has the option to extend the primary lease term another 40 years if the BLM does not need the land for any other purpose and the lessee is maintaining production at commercial quantities. The leases require the lessee to conduct operations in a manner that minimizes adverse impacts to the environment.

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Gerlach
The Gerlach Geothermal LLC assets are comprised of two BLM geothermal leases and one private lease totaling 3,615 acres. Both BLM leases have a royalty rate which is based upon 10% of the value of the resource at the wellhead. The amounts are calculated according to a formula established by Minerals Management Service (“MMS”). One of the two BLM leases has a second royalty commitment to a third party of 4% of gross revenue for power generation and 5% for direct use based on BTUs consumed at a set comparable price of $7.00 per million BTU of natural gas. The private lease has a 10 year primary term and would receive a royalty of 3% gross revenue for the first 10 years and 4% thereafter.

Granite Creek
The Company has three geothermal lease contracts with the BLM for the Granite Creek properties. The lease contracts are for approximately 2,443.7 acres of land and geothermal water rights located in North Western Nevada. The lease contracts have primary terms of 10 years. Per federal regulations applicable for the contracts, the lessee has the option to extend the primary lease term another 40 years if the BLM does not need the land for any other purpose and the lessee is maintaining production at commercial quantities. The leases state annual lease payments of $2,444, not including processing fees, and expire October 2017.

Raft River Energy I LLC
The Company has entered into several lease contracts for approximately 1,298 acres of land and geothermal water rights located in the Raft River area located in Southern Idaho. The contracts expire from March 2013 to December 2033. The contracted lease payments are scheduled for $31,287 for the year ended December 31, 2014.

The Geysers, California
On April 22, 2014, the Company acquired companies that held five significant lease contracts for approximately 3,809 acres (6.0 square miles) of land and geothermal water rights in The Geysers area located in Northern California. The contracts that have stated expiration dates, expire from February 2017 to October 2019. The remaining contracts renew indefinitely with payments made within contracted terms (held by payment). The contracted lease payments are scheduled for $274,000 for the year ended December 31, 2014.

Office Lease

Park Center Boulevard
On August 12, 2013, the Company signed a 5 year lease agreement for office space and janitorial services. The lease payments are due in monthly installments starting February 1, 2014. The monthly payments that begin February 1, 2014 have two components which include a base rate of $3,234 that is not subject to increase and a rate beginning at $6,418 that is adjusted annually according to the cost of living index. The contract includes a 5 year extension option. For the six months ended June 30, 2014, the office lease costs totaled $57,915.

Tyrell Lane
Under the contract, the lease payments were due in monthly installments of $6,535. The contract ended January 31, 2014. The total office lease costs incurred under the contract and the prior contract for year ended December 31, 2013 totaled $78,423 ($39,211 for the six months ended June 30, 2013).

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Contracted Lease Obligation Schedule

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

Year Ending
December 31,		Amount
2014	$	471,699
2015		818,119
2016		849,406
2017		844,344
2018		801,001
Thereafter		14,163,250

Power Purchase Agreements

Raft River Energy I LLC
The Company signed a power purchase agreement with Idaho Power Company for the sale of power generated from its joint venture Raft River Energy I LLC. The Company also signed a transmission agreement with Bonneville Power Administration for transmission of electricity from this plant to Idaho Power. These agreements will govern the operational revenues for the initial phases of the Company’s operating activities.

USG Nevada LLC
As a part of the purchase of the assets from Empire Geothermal Power, LLC and Michael B. Stewart acquisition (“Empire Acquisition”), a power purchase agreement with Sierra Pacific Power Company was assigned to the Company. The contract had a stated expected output of 3,250 kilowatts maximum per hour and extended through 2017. During the year ended March 31, 2012, the power purchase agreement was replaced by a new amended and restated 25 year contract signed in December of 2011 that sets the new rate at $89.75 per megawatt hour with a 1% annual escalation rate. The new contract currently allows for a maximum of 73,444 megawatt hours annually that will be paid for at the full contract price. Upon declaration of commercial operation under the PPA, an Operating Security Deposit is required to be maintained at NV Energy for the full term of the PPA. As of June 30, 2014, the Company has funded a security deposit of $1,468,898.

USG Oregon LLC
In December of 2009, the Company’s subsidiary (USG Oregon LLC), signed a power purchase agreement with Idaho Power Company for the sale of power generated by the Neal Hot Springs, Oregon project. The agreement has a term of 25 years and provides for the purchase of power up to 25 megawatts (22 megawatt planned annual average output level). Beginning 2012, the flat energy price is $96.00 per megawatt hour. The price escalates annually by 3.9% in the initial years and by 1.0% during the latter years of the agreement. The approximate 25-year levelized price is $117.65 per megawatt hour.

Asset Retirement Obligations (“AROs”)

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 $800,000. Obligations related to decommissioning four existing wells were estimated to total $600,000. These obligations are based upon the expected future value of the remedy or settlement and the values have not been calculated at discounted rates. At June 30, 2014, the Company has not considered it necessary to specifically fund these obligations. Since management is still evaluating the development plan for this project that could eliminate or significantly reduce these obligations, no charges directly associated the asset retirement obligations have been charged to operations. All of the obligations are considered to be long-term at June 30, 2014.

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Raft River Energy I LLC, USG Nevada LLC, and USG Oregon LLC
These Companies operate in Idaho, Nevada and Oregon and are subject to environmental laws and regulations of these states. The plants, wells, pipelines and transmission lines are expected to have long useful lives. Generally, these assets will require funds for retirement or reclamation. However, these estimated obligations are believed to be less than or not significantly more than the assets’ estimated salvage values. Therefore, as of June 30, 2014, no retirement obligations have been recognized.

401(k) Plan
The Company offers a defined contribution plan qualified under section 401(k) of the Internal Revenue Code to all its eligible employees. All employees are eligible at the beginning of the quarter after completing 3 months of service. Subsequent to June 30, 2013, the Company began matching 50% of the employee’s contribution up to 6%. Prior to June 30, 2013, the plan required the Company to match 25% of the employee’s contribution up to 6%. Employees may contribute up to the maximum allowed by the Internal Revenue Code. The Company made matching contributions to the plan that totaled $49,543 and $19,456 for the six months ended June 30, 2014 and 2013, respectively.

NOTE 15 – JOINT VENTURES/NON-CONTROLLING INTERESTS

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

		June 30,		December 31,
		2014		2013
Gerlach Geothermal LLC interest held by Gerlach Green Energy, LLC	$	403,265	$	404,352
Oregon USG Holdings LLC interest held by Enbridge Inc.		24,316,586		35,926,826
Raft River Energy I LLC interest held by Raft River I Holdings, LLC		21,158,835		21,824,302
	$	45,878,686	$	58,155,480

Gerlach Geothermal LLC
On April 28, 2008, the Companyformed Gerlach Geothermal, LLC (“Gerlach”) with our partner,Gerlach Green Energy, LLC (“GGE”). The purpose of the joint venture is the exploration of the Gerlach geothermal system, which is located in northwestern Nevada, near the town of Gerlach. Based upon the terms of the members’ agreement, the Company owns a 60% interest and GGE owns a 40% interest in Gerlach Geothermal, LLC. The agreement gives GGE an option to maintain its 40% ownership interest as additional capital contributions are required. If GGE dilutes to below a 10% interest, their ownership position in the joint venture would be converted to a 10% net profits interest. The Company has contributed $757,190 in cash and $300,000 for a geothermal lease and mineral rights; and the GGE has contributed $704,460 of geothermal lease, mineral rights and exploration data.

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

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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 project in the Neal Hot Springs project located in Malheur County, Oregon. On February 20, 2014, a new determination under the existing agreement was reached with Enbridge that established their ownership interest percentage at 40% and the Company’s at 60%, effective January 1, 2013. Oregon Holdings has a 100% ownership interest in USG Oregon LLC. Enbridge has contributed a total of $32,801,000, including the debt conversion, to Oregon Holdings in exchange for a direct ownership interest. During the six months ended June 30, 2014, distributions were made to the Company and Enbridge that totaled $9,809,525 and $13,304,947; respectively.

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

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

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

Effective May 17, 2011, a repair services agreement (“RSA”) was executed between RREI and U.S. Geothermal Services, LLC for the purpose of funding repairs of two underperforming wells. The agreement defined terms of the RSA repair costs and RSA repair management fees that would be funded by the loan. The outstanding loan balance will accrue interest at 12.0% per annum. The RSA payments will be made preferentially from project cash flow at a rate of 90% of increased cash created by the repairs and cash availability on a quarterly basis. The repairs were completed in January 2012. Based upon the financial conditions applicable to the loan, RREI did not make any payments during the year ended December 31, 2012. As of December 31, 2012, the loan balance amounted to $2,136,150. During the six months ended June 30, 2014 and the year ended December 31, 2013, RREI made principal payments on the loan of $625,361 and $755,288; respectively. The balance of the loan at June 30, 2014 was $755,501. The loan balance and related interest effects are fully eliminated during the consolidation process.

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NOTE 16 – ACQUISITION OF RAM POWER’S GEYSERS PROJECT

On April 22, 2014, the Company acquired all of the ownership shares of a group of companies owned by Ram Power Corp.’s (“Ram”) that hold all interests in the Geysers Project located in Northern California for a total of $6.78 million ($6.4 million purchase price, plus $0.38 million in other acquisition costs). The acquisition included Ram’s subsidiaries: Western GeoPower, Inc., Skyline Geothermal Holdings, Inc., and Etoile Holdings, Inc. which includes all membership interests in Mayacamas Energy LLC and Skyline Geothermal LLC. The assets acquired included 4 production/injection wells, restricted cash, land and geothermal water rights. The Company assumed the on-going liabilities of the companies which included an asset retirement obligations with estimated value of $1.4 million. The Company will evaluate whether to construct a power plant or sell the steam to one of the existing power companies in the area. The total acquisition cost was allocated as follows:

		Acquisition Costs
Assets:
Restricted cash, short term well bond	$	100,000
Land		1,603,516
Geothermal water rights		278,872
Construction in progress:
Wells		6,139,420
Plant and facilities		60,637
		8,182,445
Liabilities:
Asset retirement obligations		(1,400,000	)
Net acquisition cost	$	6,782,445

NOTE 17 - SUBSEQUENT EVENTS

The Company has evaluated events and transactions that have occurred after the balance sheet date through August 14, 2014, which is considered to be the issuance date. No events were identified for disclosure.

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

INFORMATION REGARDING FORWARD LOOKING STATEMENTS

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

• our business and growth strategies;

• our future results of operations;

• anticipated trends in our business;

• the capacity and utilization of our geothermal resources;

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

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

• availability and costs of drilling rigs and field services;

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

• our working capital requirements and availability;

• our illustrative plant economics;

• market conditions in the geothermal energy industry; and

• the impact of environmental and other governmental regulation.

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

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

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

• incorrect estimates of required capital expenditures;

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

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

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

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

• our ability to successfully identify and integrate acquisitions;

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

• our dependence on key personnel;

• the potential for claims arising from geothermal plant operations;

• general competitive conditions within the geothermal energy industry; and

• financial market conditions.

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

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

General Background and Discussion

The following discussion should be read in conjunction with our unaudited consolidated financial statements for the quarter ended June 30, 2014 and notes thereto included in this report.

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

For the quarter ended June 30, 2014, the Company was focused on:

1)	Operating and optimizing Neal Hot Springs, San Emidio and Raft River power plants;
2)	Evaluating drill results, leasing additional lands, and planning new drilling at El Ceibillo;
3)	Permitting new wells and drilling at San Emidio for Phase II;
4)	Completing acquisition of the WGP Geysers project; and
5)	Evaluating potential new geothermal projects and acquisition opportunities.

Project Overview

The following is a list of projects that are in operation, under development or under exploration. Projects in operation 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, previous estimates of property development costs may be low.

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Projects in Operation
			Generating		Contract
Project	Location	Ownership	Capacity (megawatts)	Power Purchaser	Expiration
Raft River (Unit I)	Idaho	JV(2)	13.0(1)	Idaho Power	2032
San Emidio (Unit I)	Nevada	100%	9.0	Sierra Pacific	2038
Neal Hot Springs	Oregon	JV(3)	22.0	Idaho Power	2036

(1)	Based on the designed annual average net output. The actual output of the Raft River Unit I plant currently is approximately 10.0 megawatts annual average.
(2)	As part of the financing package for Unit I of the Raft River project, we have contributed $16.5 million in cash and approximately $1.4 million in property to Raft River Energy I LLC, the Unit I project joint venture company. Raft River I Holdings, LLC, a subsidiary of The Goldman Sachs Group, contributed $34 million to finance the construction of the project.
(3)	In September 2010, the Company’s wholly owned subsidiary (Oregon USG Holdings LLC) entered into agreements that formulated a strategic partnership with Enbridge (U.S.) Inc. (“Enbridge”). Enbridge contributed approximately $32.8 million to the Neal Hot Springs geothermal project. Enbridge’s equity interest in the project is 40%.

Projects Under Development
					Estimated
			Target	Projected	Capital
			Development	Commercial	Required
Project	Location	Ownership	(Megawatts)	Operation Date	($million)	Power Purchaser
El Ceibillo Phase I	Guatemala	100%	25	3rd Quarter 2016	$135	MOU
San Emidio Phase II	Nevada	100%	11	4thQuarter 2016	$66	TBD
WGP Geysers	California	100%	26	TBD	TBD	TBD

Additional Properties
Project	Location	Ownership	Target Development (Megawatts)
Gerlach	Nevada	60%	TBD
Granite Creek	Nevada	100%	TBD
El Ceibillo Phase II	Guatemala	100%	25
San Emidio Phase III	Nevada	100%	17.2
Neal Hot Springs II	Oregon	100%	28
Raft River Unit II	Idaho	100%	26
Raft River Unit III	Idaho	100%	32
Vale Butte	Oregon	100%	TBD

Resource Details
	Property Size
Property	(square miles)	Temperature (ºF)	Depth (Ft)	Technology
Raft River	10.8	275-302	4,500-6,000	Binary
WGP Geysers	6.0	500	6,000-10,000	Steam
San Emidio	35.8	289-316	1,500-3,000	Binary
Neal Hot Springs	9.6	311-347	2,500-3,000	Binary
Gerlach	5.6	338-352	2,000-3,000	Binary
Granite Creek	3.8	TBD	TBD	Binary
El Ceibillo	38.6	410-526	1,800-TBD	Steam
Vale Butte	0.6	290-300	TBD	Binary

Neal Hot Springs, Oregon
Neal Hot Springs is located in Eastern Oregon near the town of Vale, the county seat of Malheur County. The Neal Hot Springs facility is designed as a 22 megawatt net annual average power plant, consisting of three separate, 7.33 net megawatt modules. The facility achieved commercial operation under the terms of the power purchase agreement on November 16, 2012. Generation from the facility during the second quarter of 2014 totaled 40,629 megawatt-hours with an average of 20.34 net megawatts per hour of operation. Plant availability was 91.4% during the quarter. Our planned annual maintenance outages were taken during the quarter with each Unit going through their respective maintenance schedules while the other two units remained in operation. A total of 453 hours (18.9 days) of scheduled maintenance were taken in April and May. Plant availability exclusive of the scheduled maintenance was 98.3%

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On June 27, 2013, the Company accepted substantial completion by the EPC contractor of all three of the Neal Hot Springs units. Final completion of the project was achieved on July 31, 2013. The DOE loan for the project was closed at final completion with a balance of $70.4 million that bears an interest rate of 2.598% over a 22 year term. The total construction cost of the project was $128.1 million, plus an additional $11.2 million is held in various project reserve accounts.

In February 2014, the final ownership interest in the Neal Hot Springs project was determined to be 60% for U.S. Geothermal and 40% for Enbridge. As a result of the final agreement, U.S. Geothermal received an approximate $6.2 million cash distribution from the partnership. The first cash distribution of profits was made from the project in March, and U.S. Geothermal received $4.6 million. Under the terms of the U.S. Department of Energy loan agreement, profits from the project are distributed to the equity partners semi-annually (February and August).

The PPA for the project was signed on December 11, 2009 with the Idaho Power Company. The PPA has a 25 year term with a starting average price for the year 2012 of $96.00 per megawatt-hour and escalates at a variable percentage annually. On May 20, 2010, the Idaho Public Utilities Commission approved the PPA with no changes to the terms and conditions. Power generated during 2013 was paid at an average price of $99.00 per megawatt-hour. 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 73.3% of the average price for three months (March, April, May). The average price paid under the PPA for 2014 has increased to $102.78 per megawatt-hour.

San Emidio, Nevada
The Phase 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. Generation from the facility during the second quarter 2014 totaled 15,686 megawatt-hours, with an average of 9.18 net megawatts per hour of operation. Plant availability was 78.2% during the quarter due to an extended maintenance outage that was required to perform a one-time warranty modification to the turbine that added a squeeze film dampener, or 5^th bearing to the unit to minimize vibration over the life of the turbine. The same squeeze film dampener bearings were also previously added successfully to the three units at Neal Hot Springs in 2013. A total of 439 hours (18.3 days) of scheduled maintenance was taken during the quarter. Plant availability exclusive of scheduled maintenance was 97.9%

The Phase I plant completed its capacity testing during the first quarter of 2013, and as a result of the capacity test exceeding the design output, the plant was up-rated to 9.0 megawatt net annual average per hour from the design point basis of 8.6 megawatts. Substantial Completion under the Engineering Procurement and Construction (“EPC) contract with SAIC was achieved February 21, 2013 and Final Completion under the terms of the EPC was executed on June 24, 2013. Upon Substantial Completion, SAIC held a construction loan on the project with a balance of $27 million, which was divided into a $25 million loan (which has been paid in full) and a $2 million unsecured loan with a 5 year term at 7% interest which is being paid down with quarterly payments of $119,382.

The $25 million construction loan held by SAIC was paid off in September of 2013, and was replaced with long term notes purchased by Prudential Capital Group’s related entities. The Prudential notes are for an aggregate of approximately $30.74 million, have a term of approximately 24 years, and bear a fixed interest rate of 6.75% per annum.

On June 1, 2011, an amended and restated PPA was signed with Sierra Pacific Power Company d/b/a NV Energy for the sale of up to 19.9 megawatts of electricity on an annual average basis. The PPA was approved by the Public Utility Commission of Nevada on December 27, 2011. The PPA has a 25 year term with a base price of $89.75 per megawatt-hour, and a 1% annual escalation rate. Power generated during 2013 was paid at the price of $90.27 per megawatt-hour. The average price paid under the PPA for 2014 has increased to $91.17 per megawatt-hour.

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As a result of the delays experienced in permitting additional wells on BLM administered leases, it has been determined that it is not possible to complete the development of the Phase II project within the development time frame required in the existing 19.9 megawatt NV Energy PPA. The Phase II expansion is dependent on successful development of additional production and injection well capacity. The cost of development for Phase II is estimated at approximately $66 million. We expect that approximately 75% of the Phase II development may be funded by project loans, with the remainder funded through equity financing.

A Small Generator Interconnection Agreement for 16 megawatts of transmission capacity was executed with Sierra Pacific Power Company on December 28, 2010. An application to increase the interconnection agreement to the full 19.9 megawatts allowed under the PPA was submitted to NV Energy on January 9, 2014.

On October 30, 2009, the Company was awarded $3.77 million in Recovery Act funding for the exploration and development of its San Emidio geothermal power project using advanced geophysical exploration techniques. This award was categorized under the “Innovative Exploration and Drilling Projects” section of the American Recovery and Reinvestment Act. The first stage of the DOE project applied innovative, seismic and satellite imagery techniques along with state-of-the-art structural modeling, to locate large aperture fractures that represent high-productivity geothermal drilling targets and was completed in 2011. Two zones along the 4.5 mile long San Emidio fault structure were identified as high quality targets for drilling during the first phase of the DOE program, a South Zone and a North Zone.

The second stage of the DOE program is a 50-50 cost shared drilling plan that is intended to follow up on targets identified in the first stage. Drilling started in the South Zone, and two wells were completed by the Company. After approval of the drilling program by the DOE in November 2011, one of the first two wells was deepened and three additional wells were completed in the South Zone with the costs being shared on a 50-50 basis.

Permitting was initiated with the Bureau of Land Management (“BLM”) for four new observation wells to be drilled in the South Zone to follow up on the high temperatures found in wells 61-21 (302°F) and 45-21 (316°F). As part of the permitting process, cultural and biological surveys were performed, and the well design and drilling program were submitted during the quarter. Permits for three wells were issued by the BLM on April 29^th and a drill rig was mobilized to the site on June 26^th. Subsequent to the end of the quarter, the first well (OW-14) was completed.

Well 61-21 (formerly OW-10) in the South Zone, was reworked beginning on October 25, 2013 and was completed on November 2, 2013. Flow testing of 61-21 was completed subsequent to the end of the quarter. To allow early for early long term testing of this southern resource area, a cross tie is being constructed between the two project area, Construction of the cross tie pipeline has been started, and once complete well 61-21 will be connected into the existing plant. Well 61-21 is expected to start delivering fluid to the plant during the third quarter.

In the North Zone, well OW-12 was drilled during the fourth quarter of 2013 to a depth of 3,643 feet and found a bottomhole temperature of approximately 180°F. No additional drilling is currently planned for the North Zone.

Raft River, Idaho

The Raft River project is located in Southern Idaho, near the town of Malta, and achieved commercial operation in January 2008. Generation from the facility during the second quarter 2014 totaled 18,069 megawatt-hours, with an average of 8.78 net megawatts per hour of operation. Plant availability was 94.0% during the quarter. Second quarter availability was impacted by 108 hours of annual scheduled maintenance, with availability for the balance of the quarter at 99.1% .

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The PPA for the project was signed on September 24, 2007 with the Idaho Power Company. 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. Power generated during 2013 was paid at an average price of $59.47 per megawatt-hour. The Idaho Power PPA has a seasonal pricing structure that pays 120% of the average price for four months (July, August, November, December), 100% of the average price for five months (January, February, June, September, October) and 73.5% of the average price for three months (March, April, May). The average price paid under the PPA for 2014 has increased to $60.72 per megawatt-hour. In addition to the price paid for energy by Idaho Power, Raft River currently receives $4.75 per megawatt-hour under a separate contract for the sale of Renewable Energy Credits to Holy Cross Energy, a Colorado electric cooperative.

The project was awarded an $11.4 million cost-shared, thermal fracturing program grant from the Department of Energy, which began the first stage of injection in June 2013 and continued until September 2013 when the second stage was started. Four, 300 foot deep seismic monitoring wells were completed in the area around well RRG-9 and seismic geophones were installed. Seismic monitoring will be conducted for the duration of the thermal fracturing program. Injection continued through the quarter from power plant injectate at an approximate temperature of 140°F. Flow in to the well has seen a moderate increase indicating that additional permeability was developing. In early April, high pressure injection of brine into the well was initiated over two days with injection pressures of 850 to 1000 pounds at the well head. There has been an approximate 100% increase in the amount of fluid well RRG-9 is now taking, with injection of spent brine continuing through the quarter.

If the fracturing program is successful, and permeability is improved to a commercial level, well RRG-9 may be utilized as a production or injection well for the existing Raft River power plant. The Company’s contributions for the thermal fracturing program are made in-kind by the use of the RRG-9 well, well field data, and monitoring support.

Republic of Guatemala
A geothermal energy rights concession located 14 kilometers southwest of Guatemala City was awarded to U.S. Geothermal Guatemala S.A., a wholly owned subsidiary of the Company in April 2010. The concession has a 5 year term for the development and construction of a power plant. Discussions are being held with the Guatemalan Ministry of Energy and Mines to support a new schedule based on the current status of the project. There are 24,710 acres (100 square kilometers) in the concession which is at the center of the Aqua and Pacaya twin volcano complex. We have also applied to the Guatemalan Ministry of Energy for an extension to our lease concession, and expect approval shortly.

An office and staff are located in Guatemala City and a 17 acre plant site has been leased on land adjacent to the existing wells. A new lease was negotiated during the quarter for an additional 80 acres, bringing the total surface lease positon to 97 acres. Several parties have expressed interest in the potential purchase of an equity interest in the El Ceibillo project. El Ceibillo, the first development target on the concession, is located near the town of Amatitlan, in a developed industrial zone immediately adjacent to the highway that connects Guatemala City to the Port of San Jose on the Pacific coast.

An initial development of a 25 megawatt (Phase I) power plant is planned in the El Ceibillo area of the concession, but the final size of the facility will be determined after drilling and resource delineation has advanced. Initial transmission studies have been completed, and identified the grid interconnection point approximately 1.2 miles (2 kilometers) from the site.

A temperature gradient (“TG”) drilling program was initiated during the first quarter of 2014 with a series of 656 foot (200 meter) deep wells planned. Nine TG wells have been completed with depths ranging from 656 to 1,312 feet (200 to 400 meters). Bottom hole temperatures found in this shallow drilling program range from 176 to 413°F (80 to 211°C) with two of the wells encountering permeability and flowing brine. The data from these wells provided a more accurate temperature gradient map of the underlying geothermal resource which has assisted in identifying future drilling targets.

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A first phase of drilling took place during the third quarter of 2013 when well EC-1 was drilled to a depth of 4,829 feet (1,472 meters) and encountered a bottom hole temperature of 491°F (255°C), with the temperature gradient at the bottom of the hole rising at a rate of 7.1°F/100 Feet (129.1°C/km) . High temperatures in excess of 392°F (>200°C) were encountered in the well beginning at a depth of 2,625 feet (800 meters), which represents a potential high temperature reservoir interval in excess of 2,204 feet (672 meters) thick. Due to the high temperature gradient found in the lower section of the well, the decision was made to deepen the well. The final depth of the well is 5,650 feet (1,722 meters) with a measured bottom-hole temperature of 526°F (274°C). Clean out and short term flow tests were conducted along with temperature surveys and have been incorporated in the geologic model of the reservoir.

In early September 2013, the Guatemalan Ministry of the Environment and Natural Resources (“MARN”) issued the Environmental License for the construction and operation of the planned, first phase, 25 megawatt power plant at the El Ceibillo site. The license is based on the Environmental Impact Assessment Study that was submitted in December 2012, describing the initial design of the 25 megawatt facility, and requires the submittal of final design specifications for review by MARN prior to starting physical construction of the plant. Additionally, the license requires compliance with all legal and regulatory requirements under Guatemalan law, submittal of an air quality monitoring plan, and that final design comply with the strict guidelines for noise, dust and hydrogen sulfide emissions. Prior to issuance of the license, an environmental bond of Q344,850 Quetzals (approximately US $45,000) was posted with the Ministry of Environment and Natural Resources.

A binding Memorandum of Understanding (“MOU”) was signed on October 18, 2012 with one of the largest power brokers in Central America. The MOU establishes the framework for a PPA that includes a 15-year term for an initially estimated 25 megawatts of power generation up to a maximum of 50 megawatts of power generation. The MOU includes a project power price that the Company believes is competitive with the prevailing energy prices in the region. Several conditions precedent must be met before the PPA is negotiated and becomes effective, including confirming the geothermal reservoir by an independent reservoir engineer, obtaining all required permits and authorizations, and securing a project finance commitment.

The MOU may be terminated (i) as a result of the bankruptcy of any of the parties, (ii) on January 1, 2015, unless such date is extended by mutual agreement, because the construction of the project has not been initiated and/or the commercial operation date has been moved beyond the date set out in the PPA framework, or (iii) if the geothermal resource found lacks the conditions to sustain a long-term commercial production that allows electric power to be produced under the necessary conditions of profitability.

The El Ceibillo geothermal project area had nine previous wells drilled into the geothermal concession during the 1990s which have depths ranging from 560 to 2,000 feet (170 to 610 meters). A few of those wells had adequate flow and temperature to support a direct use application. Six of the wells had measured reservoir temperatures in the range of 365°F to 400°F and had high conductive gradients that indicated rapidly increasing temperature with depth. Fluid samples and mineralization from the wells indicated the existence of a high permeability reservoir below or near the existing well field.

WGP Geysers
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.

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WGP Geysers is an advanced stage project that encompasses the former Pacific Gas and Electric Unit 15, which once had a 62 megawatt (gross) capacity geothermal power plant that was shut down in l989. The project includes 3,809 acres of geothermal leases and property, development design plans, and permits for a proposed 26 (net) megawatt power plant. There are four existing wells drilled in 2008-2009 which are immediately available for production or injection, with a fifth, historic well that has temporary plugs installed but can be reworked. The four new wells have been tested with an initial steam flow totaling 462,000 pounds per hour. A report prepared in 2012 by GeothermEx, a third party reservoir engineering firm, states that the total initial power capacity from these wells is estimated at about 30 megawatts (gross). The report further estimated that the sustainable long-term production from the resource is conservatively estimated at 26 megawatts (net) assuming 25% of the geothermal fluid that is withdrawn is injected back into the reservoir.

A 12 month extension for the Sonoma County Conditional Use Permit to construct the 26 megawatt power plant was applied for and was approved on June 12^th. Additionally, an application was made to the Sonoma County Air Quality Board for a permit to conduct flow tests on the four production wells drilled in 2009. The Air Quality permit was approved on June 19^th.

Two development scenarios are under consideration for the WGP Geysers site, either a power sales or a steam sale agreement. The evaluation of these two options is underway and discussion with potential off takers is expected to begin during the third quarter.

Gerlach Joint Venture
The Gerlach Joint Venture, located adjacent to the town of Gerlach in Washoe County, Nevada is made up of both private and BLM geothermal leases. The Peregrine well, a historic exploration slim hole that encountered a lost circulation zone at a depth of 975 feet, was redrilled and the hole was opened from a 6.5 inch diameter well to a 12.5 inch diameter well. Lost circulation was confirmed with three zones through the 900 to 1,024 foot interval. The well was stopped at 1,070 feet total depth. Temperature surveys and a short clean out flow test were conducted on the well. The well flowed at an estimated 300-400 gallons per minute and the flowing temperature was 208°F. Geochemistry indicates an average potential source temperature of 374°F for the Gerlach site.

Drilling commenced on observation well 18-10a on October 30, 2011. The upper section of the well was drilled to 826 feet deep and an 8 inch liner was cemented in place. The well was secured and the drill rig was moved back to San Emidio. Temperature measurements in the well have provided the highest measured temperature in the field to date at 268°F within 160’ of surface and a temperature gradient of 6.4°F per 100’ in the bottom section of the hole.

Drilling to intersect a previously identified lost circulation target at 1,600 feet deep resumed on well 18-10a on April 14, 2012 and was stopped on April 18, 2012 at 1,943 feet deep. Circulation was lost in minor zones at 1,530 and 1,595 feet deep. Subsequent temperature surveys indicate an isothermal temperature profile at 241°F which may indicate that higher temperature fluid does not occur below the 18-10a well site.

A plan and budget has been developed to deepen well 18-10a to intersect the lost circulation zone at 2,800 feet deep to provide temperature information on the deep structure. Further work is dependent upon additional funding from the partners.

Granite Creek, Nevada
The Granite Creek assets are located about 6 miles north of Gerlach, Nevada along a geologic structure known to host geothermal features including the Great Boiling Spring and the Fly Ranch Geyser. A first stage gravity geophysical program was completed in the third quarter of 2008 and will be used to evaluate the resource potential, and help determine where to drill temperature-gradient exploration wells. After a detailed review of the geologic setting, the lease position at Granite Creek was reduced to 2,443.7 acres (3.8 square miles).

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Operating Results

For the six months ended June 30, 2014, the Company reported net income attributable to the Company of $186,607 ($0.00 income per share) which represented a $174,442 increase from net income of $12,165 reported in the same period in 2013 ($0.00 loss per share). For the three months ended June 30, 2014, the Company reported a net loss attributable to the Company of $1,152,813 ($0.01 loss per share) which represented a favorable decrease of $223,546 from the net loss of $1,376,359 reported in the same period in 2013 ($0.01 loss per share). Generally, favorable variances were reported related to the operations of the Company’s three power plants. Notable favorable variances were reported in professional and management fees, salaries and wages, and exploration costs. Notable unfavorable variances were reported in stock based compensation and interest expense.

Plant Operations
During the six months ended June 30, 2014, the Company’s energy production revenues and related operating costs originated from its three fully operational power plants. The San Emidio plant (USG Nevada LLC) is located in the San Emidio Desert in the northwestern part of the State of Nevada. The original San Emidio plant and related water rights were purchased in 2008. The old plant ceased operations in December 2011 and was replaced with a new plant that began commercial operations in May 2012. The Raft River plant (Raft River Energy I LLC) is located in South Eastern Idaho. The Raft River plant began operations in January of 2008. The new plant at Neal Hot Springs, Oregon (USG Oregon LLC) is located by Vale, Oregon and began commercial operations on November 16, 2012.

Overall, plant production for the second quarter 2014 was down from the first quarter 2014 due to down time for scheduled maintenance. Also, the contracted energy rates are lower in the second quarter for two power plants. The Neal Hot Springs and the Raft River plants earn 73.5% of the contracted rate in the months of March through May.

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

	For the Six Months Ended June 30,
	2014		2013
	$	%	$	%
Energy sales by plant:
Neal Hot Springs, Oregon	8,668,773	61.2	6,632,554	55.8
San Emidio, Nevada	3,385,617	23.9	3,355,309	28.3
Raft River, Idaho	2,106,744	14.9	1,887,635	15.9
	14,161,134	100.0	11,875,498	100.0

%- represents the percentage of total Company energy sales.

	For the Three Months Ended June 30,
	2014		2013
	$	%	$	%
Energy sales by plant:
Neal Hot Springs, Oregon	3,402,318	59.1	2,435,303	49.9
San Emidio, Nevada	1,450,525	25.2	1,628,382	33.3
Raft River, Idaho	907,194	15.7	823,154	16.8
	5,760,037	100.0	4,886,839	100.0

%- represents the percentage of total Company energy sales.

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

	For the Quarter Ended,
	June 30,	September 30,	December 31,	March 31,	June 30,
	2013	2013	2013	2014	2014
Neal Hot Spring, Oregon	30,016	25,832	53,445	56,047	40,629
San Emidio, Nevada	18,039	18,317	21,112	21,223	15,686
Raft River, Idaho	17,248	18,687	21,951	21,614	18,069
	65,303	62,836	96,508	98,884	74,384

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

The Neal Hot Springs plant was considered to be commercially operational on November 16, 2012. The quarter ended March 31, 2013, was the plant’s first full quarter of operations. For the six months ended June 30, 2014, plant energy revenues increased 30.7% (39.7% for the three months ended June 30, 2014) from the same period ended 2013. In April 2014, the plant completed its scheduled maintenance shutdown. A total of 400.5 hours of production was lost during the shutdown which was significantly less than experienced in 2013. Due to issues related to startup in 2013, the plant suffered down time of 490 hours in the first quarter of 2013 and 927 hours in the second quarter of 2013.

Plant operating costs increased $801,645 ($341,688 for the three months ended June 30, 2014), which was a 29.5% increase (24.4% increase for the three months ended June 30, 2014) for the six months ended June 30, 2014 from the same period ended 2013. The largest variances were noted in administrative support, insurance, and plant and well field maintenance costs. For the six months ended June 30, 2014 administrative and corporate support costs increased $154,230 ($51,751 for the three months ended June 30, 2014), which was a 65.6% increase (41.2% increase for the three months ended June 30, 2014) from the same period in 2013. Effective 2014, a contracted monthly corporate support fee of $13,750 was established. Additional consulting fees related to the general plant maintenance that amounted to over $38,000 for the six months ended June 30, 2014. For the six months ended June 30, 2014, the plant’s insurance costs totaled $209,500 ($104,692 for the three months ended June 30, 2014), which was an increase of $193,660 ($95,818 for the three months ended June 30, 2014) from the same period in 2013. In July 2013, the plant’s insurance coverage transferred from a builders’ risk policy to a full property coverage policy which resulted in a significant increase in cost. Plant and field maintenance costs increased $263,878 ($193,308 for the three months ended June 30, 2014), which was a 213.4% increase (242.9 % for the three months ended June 30, 2014) for the six months ended June 30, 2014 from the same period ended 2013. In July 2013, the plant’s Engineering, Procurement and Construction Company turned over plant maintenance responsibilities to the Company; therefore, most of the repair costs incurred after June 30, 2013, were not covered under warranty.

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

	Six Months Ended June 30,
	2014				2013				Variance
	$		%		$		%		$		%*
Plant revenues:
Energy sales	8,668,772		100.0		6,632,554		100.0		2,036,218		30.7
Plant expenses:
General operations	1,884,945		21.7		1,127,596		17.0		(757,349	)	(67.2	)
Depreciation and amortization	1,638,029		18.9		1,593,733		24.0		(44,296	)	(2.8	)
	3,522,974		40.6		2,721,329		41.0		(801,645	)	(29.5	)
Operating income	5,145,798		59.4		3,911,225		59.0		1,234,573		31.6
Other income (expense):
Interest expense	(890,227	)	(10.3	)	(982,213	)	(14.8	)	91,986		9.4
Other and interest income	11,182		0.1		14,394		0.2		(3,212	)	(22.3	)
	(879,045	)	(10.2	)	(967,819	)	(14.6	)	88,774		(9.2	)
Net income	4,266,753		49.2		2,943,406		44.4		1,323,347		45.0

%- represents the percentage of total plant operating revenues.

%*- represents the percentage of change from 2013 to 2014.Increases in revenues anddecreases in expenses from the prior period to the current period are considered to befavorable and are presented as positive figures.

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

	Three Months Ended June 30,
	2014				2013				Variance
	$		%		$		%		$		%*
Plant revenues:
Energy sales	3,402,318		100.0		2,435,303		100.0		967,015		39.7
Plant expenses:
General operations	944,950		27.8		609,354		25.1		(335,596	)	(55.1	)
Depreciation and amortization	820,526		24.1		814,434		33.4		(6,092	)	(0.7	)
	1,765,476		20.4		1,423,788		58.5		(341,688	)	(24.0	)
Operating income	1,636,842		48.1		1,011,515		41.5		625,327		61.8
Other income (expense):
Interest expense	(444,895	)	(13.0	)	(502,111	)	(20.6	)	57,216		11.4
Other and interest income	4,457		0.1		9,352		0.4		(4,895	)	(52.3	)
	(440,438	)	(12.9	)	(492,759	)	(20.2	)	52,321		10.6
Net income	1,196,404		35.2		518,756		21.3		677,648		130.6

%- represents the percentage of total plant operating revenues.
%*- represents the percentage of change from 2013 to 2014.Increases in revenues and decreases in expenses from the prior period to the current period are considered to be favorable and are presented as positive figures.

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

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

	Mega-		Ave. Rate		Depreciation
	watt	Energy	per		&
	Hours	Sales	Megawatt	Net Income*	Amortization
Quarter Ended:	Produced	($)	Hour ($)	($)	($)
December 31, 2012	23,256	2,329,030	88.7	1,451,523	256,670
March 31, 2013	46,137	4,197,252	90.6	2,424,648	779,299
June 30, 2013	30,016	2,435,304	80.2	518,754	814,434
September 30, 2013	25,832	2,875,686	110.9	829,374	810,573
December 31, 2013	53,445	6,058,169	113.3	3,644,359	812,766
March 31, 2014	56,047	5,266,454	93.8	3,070,350	817,503
June 30, 2014	40,629	3,402,318	83.7	1,196,404	820,526

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

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

For the six months ended June 30, 2014, the San Emidio plant reported net income of $219,927 which was a decrease of $402,277 (64.7% decrease) from the $622,204 in net income reported in the same period in 2013. For the three months ended June 30, 2014, the San Emidio plant reported a net loss of $203,424 which was a favorable decrease of $8,637 (4.1% decrease) from the $212,061 net loss reported in the same quarter in 2013. During the current quarter, the plant produced 15,686 megawatt hours, which was 13.0% lower than produced in the same quarter in 2013. In April 2014, the plant completed its annual scheduled maintenance shut down. A total of 415 hours of production was lost during the shutdown, which was more than 265 hours (176.7% increase) needed for the shutdown in April 2013. In the current quarter, additional time was needed to install a squeeze film dampener that will reduce the vibration on the turbine. Overall, the total plant operating costs for the current six months ended June 30, 2014 were consistent with the total costs incurred in the same period ended 2013.

For the six months ended June 30, 2014, the plant’s interest expense increased $410,430 (66.0% increase) from the same period ended 2013. During the quarter ended March 31, 2013, the plant loan had not been finalized and most of the interest incurred under the contractor’s obligations was capitalized. In the three months ended June 30, 2013, the plant incurred interest costs that totaled $621,712. In the three months ended March 31 and June 30, 2014, the plant incurred interest expense of $517,406 and $514,859; respectively.

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

	Six Months Ended June 30,
	2014				2013				Variance
	$		%		$		%		$		%*
Plant revenues:
Energy sales	3,385,617		100.0		3,355,309		100.0		30,308		0.9
Plant expenses:
Operations	1,504,312		44.4		1,338,916		39.9		(165,396	)	(12.4	)
Depreciation and amortization	629,190		18.6		772,374		23.0		143,184		18.5
	2,133,502		63.0		2,111,290		62.9		(22,212	)	(1.1	)
Operating income	1,252,115		37.0		1,244,019		37.1		8,096		0.7
Other income (expense):
Interest expense	(1,032,265	)	(30.5	)	(621,835	)	(18.5	)	(410,430	)	(66.0	)
Other income	77		0.0		20		0.0		57		285.0
	(1,032,188	)	(30.5	)	(621,815	)	(18.5	)	(410,373	)	(66.0	)
Net income	219,927		6.5		622,204		18.6		(402,277	)	(64.7	)

%- represents the percentage of total plant operating revenues.
%*- represents the percentage of change from 2013 to 2014.Increases in revenues and decreases in expenses from the prior period to the current period are considered to be favorable and are presented as positive figures.

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

	Three Months Ended June 30,
	2014				2013				Variance
	$		%		$		%		$		%*
Plant revenues:
Energy sales	1,450,525		100.0		1,628,382		100.0		(177,856	)	(10.9	)
Plant expenses:
Operations	822,884		56.7		853,425		52.4		30,541		3.6
Depreciation and amortization	316,283		21.8		365,314		22.4		49,031		13.4
	1,139,167		99.2		1,218,739		74.8		79,572		6.5
Operating income	311,358		78.5		409,643		25.2		(98,285	)	(24.0	)
Other income (expense):
Interest expense	(514,859	)	(35.5	)	(621,712	)	(38.2	)	106,853		17.2
Other income	77		0.0		8		0.0		69		#
	(514,782	)	(35.5	)	(621,704	)	(38.2	)	106,922		17.2
Net income	(203,424	)	(14.0	)	(212,061	)	(13.0	)	8,637		(4.1	)

%- represents the percentage of total plant operating revenues.
%*- represents the percentage of change from 2013 to 2014.Increases in revenues and decreases in expenses from the prior period to the current period are considered to be favorable and are presented as positive figures.

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

-48-

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

	Mega-		Ave. Rate			Depreciation
	watt	Energy	per	Net Income		&
	Hours	Sales	Megawatt	(Loss)*		Amortization
Quarter Ended:	Produced	($)	Hour ($)	($)		($)
June 30, 2012(1)	5,465	427,931	77.6	(8,693	)	181,333
September 30, 2012	8,280	745,494	89.7	101,154		253,429
December 31, 2012	16,231	1,459,078	90.0	(223,412	)	416,091
March 31, 2013	19,228	1,726,927	90.3	834,266		407,060
June 30, 2013	18,039	1,628,382	90.3	(212,058	)	365,314
September 30, 2013	18,317	1,531,260	83.6	355,499		307,854
December 31, 2013	21,112	1,905,813	90.3	180,931		312,273
March 31, 2014	21,223	1,935,091	91.2	423,351		312,908
June 30, 2014	15,686	1,450,526	92.5	(203,424	)	316,283

⁽¹⁾ - The new power plant became commercially operational on May 25, 2012. The plant produced power at a lower “test rate” in May and at the full contract rate of .08975 per kilowatt hour in June.

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

Raft River, Idaho Unit I (Raft River Energy I LLC) Plant Operations
The net loss from Raft River Energy I LLC (“RREI”) operations of $517,819 for the six months ended June 30, 2014, favorably decreased by $116,970 (18.4% decrease) from the net loss for the same period ended in 2013. The net loss of $579,568 for the three months ended June 30, 2014, favorably decreased by $136,035 (19.0% decrease) from the net loss for the same quarter ended in 2013. During the current quarter, the plant produced 18,069 megawatt hours, which was 4.8% lower than produced in the same quarter in 2013. In April 2014, the plant completed its annual scheduled maintenance shutdown. A total of 108 hours of production was lost during the shutdown, which was 128 hours (54.3% fewer hours) less than the hours needed for the April 2013 scheduled shutdown. In April 2013, additional repairs were needed for the circulation water pumps. Total plant operating costs increased $124,398 ($112,680 for the three months ended June 30, 2014), which was a 4.7% increase (16.9% for the three months ended June 30, 2014) for the six months ended June 30, 2014 from the same period ended 2013. For the current quarter, plant and field maintenance costs were reasonably consistent with the maintenance costs incurred in 2013. In the quarter ended March 31, 2013, RREI offset repair costs with proceeds received from grants related to well repairs that amounted to $217,594. These repairs of wells RRG-2 and RRG-7 were completed in January 2012.

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The summarized statements of operations for RREI are as follows:

	Six Months Ended June 30,
	2014				2013				Variance
	$		%		$		%		$		%*
Plant revenues:
Energy sales	2,106,745		91.9		1,887,635		91.1		219,110		11.6
Energy credit sales	186,705		8.1		184,566		8.9		2,139		1.2
	2,293,450		100.0		2,072,201		100.0		221,249		10.7
Plant expenses:
General operations	1,895,921		82.7		1,683,476		81.2		(212,445	)	(12.6	)
Depreciation and amortization	856,087		37.3		944,134		45.6		88,047		9.3
	2,752,008		120.0		2,627,610		126.8		(124,398	)	(4.7	)
Operating income	(458,558	)	(20.0	)	(555,409	)	(26.8	)	96,851		17.4
Other income (expense):
Interest expense	(59,728	)	(2.6	)	(93,001	)	(4.5	)	33,273		35.8
Other and interest income	467		0.0		13,621		0.7		(13,154	)	996.6	)
	(59,261	)	(2.6	)	(79,380	)	(3.8	)	20,119		25.3
Net income	(517,819	)	(22.6	)	(634,789	)	(30.6	)	116,970		(18.4	)

%- represents the percentage of total plant operating revenues.
%*- represents the percentage of change from 2013 to 2014.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.

-50-

	Three Months Ended June 30,
	2014				2013				Variance
	$		%		$		%		$		%*
Plant revenues:
Energy sales	907,194		91.4		823,154		90.5		84,040		10.2
Energy credit sales	85,837		8.6		86,237		9.5		(400	)	(0.5	)
	993,031		100.0		909,391		100.0		83,640		9.2
Plant expenses:
General operations	1,118,614		112.6		1,103,739		121.4		(14,875	)	(1.3	)
Depreciation and amortization	428,180		43.1		472,094		51.9		43,914		9.3
	1,546,794		155.7		1,575,833		173.3		29,039		1.8
Operating income	(553,763	)	(55.7	)	(666,442	)	(73.3	)	112,679		16.9
Other income (expense):
Interest expense	(26,009	)	(2.6	)	(49,370	)	(5.4	)	23,361		47.3
Other and interest income	204		0.0		210		0.0		(6	)	(2.9	)
	(25,805	)	(2.6	)	(49,160	)	(5.4	)	23,355		47.5
Net income	(579,568	)	(58.3	)	(715,602	)	(78.7	)	136,034		19.0

%- represents the percentage of total plant operating revenues.
%*- represents the percentage of change from 2013 to 2014.Increases in revenues and decreases in expenses from the prior period to the current period are considered to be favorable and are presented as positive figures.

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

Key quarterly production data for RREI is summarized as follows:

	Mega-		Ave. Rate			Depreciation
	watt	Energy	per	Net Income		&
	Hours	Sales	Megawatt	(Loss)*		Amortization
Quarter Ended:	Produced	($)	Hour ($)	($)		($)
June 30, 2012	15,999	765,255	50.3	(805,286	)	507,783
September 30, 2012	17,836	1,176,107	68.1	2,348		505,560
December 31, 2012	21,170	1,398,218	67.9	154,752		505,559
March 31, 2013	19,675	1,064,481	56.1	67,620		472,040
June 30, 2013	17,248	823,154	49.9	(715,605	)	472,094
September 30, 2013	18,687	1,260,124	69.5	(1,165	)	450,222
December 31, 2013	21,951	1,479,499	69.0	254,302		450,222
March 31, 2014	21,614	1,199,551	57.9	61,749		427,907
June 30, 2014	18,069	907,194	52.6	(579,568	)	428,180

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

Professional and Management Fees

For the six months ended June 30, 2014, the Company incurred professional and management fees of $567,947, which was a decrease of $163,624 (22.4.6 % decrease) from the same period in 2013. For the three months ended June 30, 2014, the Company incurred professional and management fees of $197,964, which was a decrease of $234,226 (54.2% decrease) from the same period in 2013. The contract with the former CEO’s consulting firm began in May 2013. Consulting fees of $155,393 were paid in the second quarter of 2013. During the first and second quarters of 2014, fees were paid to the former CEO’s consulting firm of $39,761 and $14,400; respectively. The original contract ended April 2014, and was extended through December 2014 at a reduced rate of $1,000 per month. Consulting costs of $95,702 ($58,421 for the three months ended June 30, 2014) were paid to a geologist in the six months ended June 30, 2014, which was an increase of $62,259 ($32,978 increase for the three months ended June 30, 2014). In the quarter ended March 31, 2013, these costs were included in the Company salaries and wages. During the six months ended June 30, 2014, the Company incurred audit/audit related, legal and SOX consulting costs that amounted to approximately $168,000, $135,000 and $47,000; respectively. During the six months ended June 30, 2013, the Company incurred audit/audit related, legal and SOX consulting costs that amounted to approximately $224,000, $131,000 and $65,000; respectively.

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Salaries and Wages
Salaries and wages include payroll and related costs incurred for exploration, design and development costs that cannot be capitalized, as well as general management and administration. Payroll and related costs for plant operations are expensed as plant production costs. For the six months ended June 30, 2014, the Company reported $1,072,057 in salaries and related costs which was a decrease of $46,086 (4.1% decrease) from the same period in 2013. For the three months ended June 30, 2014, the Company reported $677,344 in salaries and related costs, which was an increase of $123,689 (22.3% increase) from the same period in 2013. Salaries and related costs for administration and development employees before allocations were $261,816 ($259,879 in the three months ended June 30, 2014), which was 20.6% (40.4% higher in the three months ended June 30, 2014) higher in the six months ended June 30, 2014 than in the same period ended 2013. In the current six months, fewer amounts of payroll costs ($245,502 less) were allocated to capital projects than in the same period in 2013. In April 2014, the Company awarded raises to its employees that averaged 2.9%, and bonuses were awarded that totaled $376,750. In April 2013, employee bonuses were awarded that totaled $171,000. For the first and second quarters of 2013, approximately $188,000 and $138,000; respectively, in payroll and related costs were capitalized for design and other development activities for the Neal Hot Springs, Oregon project. For the six months ended June 30, 2013, $306,108 ($122,018 for the three months ended June 30, 2013) of the portions of plant managements’ time was allocated to general corporate management and other non-capital development activities.

Management and development employee salaries and related costs are as follows:

	For the Six Months Ended June 30,
	2014		2013		Variance
Financial Element	$		$		$		%
Total Company salary and related costs, excluding plant operations	1,531,537		1,269,721		261,816		20.6
Cost allocations:
Capital projects	(212,184	)	(457,686	)	245,502		53.6
Operating management charged to general corporate management and other non-capital development activities	-		306,108		(306,108	)	#
Corporate management and support for plant operations	(247,296	)	-		(247,296	)	#
	1,072,057		1,118,143		(46,086	)	(4.1	)

%- represents the percentage of change from 2013 to 2014. #- variance percentage that is extremely high or undefined.

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	For the Three Months Ended June 30,
	2014		2013		Variance
Financial Element	$		$		$		%
Total Company salary and related costs, excluding plant operations	902,821		642,942		259,879		40.4
Cost allocations:
Capital projects	(100,466	)	(211,305	)	110,839		52.5
Operating management charged to general corporate management and other non-capital development activities	-		122,018		(122,018	)	#
Corporate management and support for plant operations	(125,011	)	-		(125,011	)	#
	677,344		553,655		123,689		22.3

%- represents the percentage of change from 2013 to 2014.
#- variance percentage that is extremely high or undefined.

Stock Based Compensation
For the six months ended June 30, 2014, the Company reported $777,465 in stock based compensation, which was an increase of $513,712 (194.8% increase) from the same period in 2013. For the three months ended June 30, 2014, the Company reported $630,153 in stock based compensation, which was an increase of $425,763 (208.3% increase) from the same period in 2013. Stock based compensation includes the calculated values for both Company stock and stock options. The Company uses the Black-Scholes option-pricing model to value the cost of the outstanding stock options. The higher value of the stock options for the current quarter was directly impacted by the number of outstanding options and the increase in the Company’s stock price and the related increase in the volatility of the Company’s stock price. On April 2, 2014, the Company awarded employees 2,883,500 stock options and 559,122 shares (restricted shares). In the prior year, the Company did not issue stock options to employees until July 22, 2013 (1,950,000 options, no restricted shares to employees). During the current six months ended June 30, 2014, the Company’s common stock price reached a high of $0.95 and a low of $0.38 ($0.62 average daily closing price). During the six months ended June 30, 2013, the Company’s common stock price reached a high of $0.43 and a low of $0.31 ($0.35 average daily closing price).

The stock based compensation components are summarized as follows:

	For the Six Months Ended
	June 30,
	2014	2013	Variances
	$	$	$	%
Total Stock Based Compensation:
Stock option compensation	662,390	242,460	419,930	173.2
Stock compensation	115,075	21,293	93,782	440.4
	777,465	263,753	513,712	194.8

%- represents the percentage of change from 2013 to 2014.

-53-

	For the Three Months Ended
	June 30,
	2014	2013	Variances
	$	$	$	%
Total Stock Based Compensation:
Stock option compensation	541,328	183,098	358,230	195.7
Stock compensation	88,825	21,293	67,532	316.3
	630,153	204,391	425,762	208.3

%- represents the percentage of change from 2013 to 2014.

Exploration Costs
For the six months ended June 30, 2014, the Company reported $24,086 in exploration costs, which was a decrease of $137,923 (85.1% decrease) from the same quarter in 2013. For the three months ended June 30, 2014, the Company reported $19,402 in exploration costs, which was a decrease of $394,975 (95.3% decrease) from the same quarter in 2013. During the six months ended June 30, 2013, the Company incurred drilling costs that exceeded $565,000 ($396,000 for the three months ended June 30, 2014) for test wells at Guatemala (U.S. Geothermal Guatemala S.A.).

Interest Expense
During the six months ended June 30, 2014, the Company reported $1,989,729 in interest expense from notes payable, which was an increase of $385,544 (24.0% increase) from the same period in 2013. During the three months ended June 30, 2014, the Company reported $1,008,737 in interest expense from notes payable, which was a decrease of $115,146 (10.2% decrease) from the same period in 2013. The primary reason for the increase related to the amount interest expense incurred by USG Nevada LLC (San Emidio, Nevada). During the quarter ended March 31, 2013, the Prudential Capital Group loan had not been finalized and most of the interest incurred under the contractor’s obligations was capitalized. In the three months ended June 30, 2013, USG Nevada LLC incurred interest costs that totaled $621,712. In the three months ended March 31 and June 30, 2014, USG Nevada LLC incurred interest expense of $517,406 and $514,859; respectively.

Net Income Attributable to the Non-Controlling Interests
The net income attributable to the non-controlling interest entities is the line item that removes the portion of the total consolidated operations that are owned by the Company’s subsidiaries. For the six months ended June 30, 2014, the Company reported $1,052,154 in net income attributable to non-controlling interests, which was an increase of $795,866 from the $256,288 net income reported in the same period ended 2013. For the three months ended June 30, 2014, the Company reported $155,517 in net loss attributable to non-controlling interests, which was a favorable decrease of $434,751 from the $590,268 net loss reported in the same quarter ended 2013. The primary reason for the increase was due to the operations of the Neal Hot Springs plant which reported net income of $4,266,753, which was an increase of $1,323,347 for the six months ended June 30, 2014 from the same period ended 2013. For the three months ended June 30, 2014, the USG Oregon LLC reported net income of $1,196,404, which was an increase of $677,648 for the quarter ended 2013. The impact of the USG Oregon LLC’s operations on the Company’s reported income attributable to non-controlling entities was an increase of $529,338 ($271,059 increase for the three months) from the six months ended June 30, 2013 as compared to the same period ended 2014.

-54-

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

	For the Six Months Ended
	June 30,
Subsidiaries and Non-Controlling	2014		2013		Variance
Interest Entities	$		$		$	%
Oregon USG Holdings LLC interest held by Enbridge Inc.	1,694,707		1,027,180		667,527	65.0
Raft River Energy I LLC interest held by Raft River I Holdings, LLC	(641,467	)	(768,855	)	127,388	16.6
Gerlach Geothermal LLC interest held by Gerlach Green Energy, LLC	(1,086	)	(2,037	)	951	46.7
	1,052,154		256,288		795,866	310.5

%- represents the percentage of change from 2013 to 2014.

	For the Three Months Ended
	June 30,
Subsidiaries and Non-Controlling	2014		2013		Variance
Interest Entities	$		$		$	%
Oregon USG Holdings LLC interest held by Enbridge Inc.	478,562		179,490		299,072	166.6
Raft River Energy I LLC interest held by Raft River I Holdings, LLC	(633,000	)	(767,952	)	134,952	17.6
Gerlach Geothermal LLC interest held by Gerlach Green Energy, LLC	(1,079	)	(1,806	)	727	40.3
	(155,517	)	(590,268	)	434,751	73.7

%- represents the percentage of change from 2013 to 2014.

Off Balance Sheet Arrangements

As of June 30, 2014, the Company does not have any off balance sheet arrangements.

Liquidity and Capital Resources

We believe our cash and liquid investments at June 30, 2014 are adequate to fund our general operating activities through December 31, 2015. Other project development, such as Guatemala, Geysers and the San Emidio expansion, 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 recent financial credit crisis has not impacted the ability of our customers, Idaho Power Company and Sierra Pacific Power (NV Energy), to pay for their power. This power is sold under long-term contracts at fixed prices to large utilities. The status of the credit and equity markets could delay our project development activities while the Company seeks to obtain economic credit terms or a favorable equity market price to further the drilling and construction activities. The Company continues discussions with potential investors to evaluate alternatives for funding at the corporate and project levels.

-55-

On April 21, 2014, the Company completed the acquisition of Ram Power Corp.’s Geysers project for a total of $6.4 million in cash. The Ram subsidiaries included in the acquisition are Western GeoPower, Inc., Skyline Geothermal Holding, Inc., and Etoile Holdings Inc., which in turn includes all membership interests in Mayacamas Energy LLC and Skyline Geothermal LLC. The acquired Ram subsidiaries possess the full development interest in the project. These interests include all geothermal leases (covering 3809 acres), development design plans, and permits for a proposed 26 net megawatt power plant, and includes land and geothermal mineral rights ownership of the Mayacamas property purchased by Ram in 2010. This property contains 4 existing geothermal wells immediately available for production or injection and one historic well available for use after reworking. Finally, the acquisition includes a 50% undivided interest in the geothermal mineral rights relating to the property that contains the 5th existing well also purchased by Ram in 2010. The other 50% interest in this property is contained within an acquired leasehold interest.

On November 29, 2013 the Company filed a replacement shelf registration statement on Form S-3 with the SEC. The replacement shelf registration statement was filed as routine course of business due to the impending expiration of the Company’s existing shelf registration statement that, under SEC rules, would have expired on December 1, 2013. Pursuant to SEC rules, the expiration date of the existing shelf registration statement has been extended until the earlier of the effective date of the replacement shelf registration statement or May 30, 2014. Upon effectiveness of the S-3 on February 4, 2014, the Company may use the replacement shelf registration statement to offer and sell from time to time for a period of three years in one or more public offerings up to $50 million of common stock, warrants, or units consisting of any combination thereof. The terms of any securities offered under the replacement shelf registration statement, and the intended use of the resulting net proceeds, will be established at the times of any future offerings and will be described in prospectus supplements filed at such times with the SEC. The Company has no immediate plans to sell any additional stock under the replacement shelf registration statement at this time, but wishes to preserve the option in support of its future growth and development of its projects as well as strategic M&A opportunities.

Following the receipt of the Section 1603 Federal Investment Tax Credit (ITC) cash grant payment, and the Oregon Business Energy Tax Credit funds, and after the receipt and disbursement of all remaining construction reserve funds, which was finalized on January 27, 2014, the final ownership interest in the Neal Hot Springs project was calculated in accordance with the terms of the partnership agreement. Ownership interest in the project is final with 60% for U.S. Geothermal and 40% for Enbridge. As a result of the final agreement, U.S. Geothermal has received a $6.2 million cash distribution from the partnership.

Under the terms of the DOE loan agreement, project profits are distributed to the equity partners semi-annually (February and August), following Final Completion, which was achieved on August 1, 2013. U.S. Geothermal’s share of this first distribution received March 5, 2014 is $4.6 million, out of a total distribution to the partners of $7.7 million, which represents profits generated from the project since initial operation began in November 2012.

Under the Loan Guarantee Agreement at Neal Hot Springs with the Department of Energy, all funds for USG Oregon LLC are deposited into PNC Bank subject to certain procedural restrictions on the use of the funds. The waterfall of funds out of the Revenue account is processed semi-annually. At June 30, 2014, $16.4 million in USG Oregon LLC funds were deposited at PNC Bank, and were unavailable for immediate corporate needs.

For projects under construction before the end of 2010 and online before the end of 2013, a project was eligible to take a 30% investment tax credit (“ITC”) in lieu of the production tax credit (“PTC”). The ITC was able to be converted into a cash grant within the first 90 days of operation of the plant. Phase I at San Emidio attained commercial operation on May 25, 2012. An application was submitted in July 2012 electing to take the ITC cash grant in lieu of the PTC. The United States Department of Treasury notified the Company that it would allow $10.65 million in cash grant. The cash grant proceeds were received on November 10, 2012 and used to repay the Ares Capital bridge loan facility, with the remaining balance payable to USG Nevada LLC. An additional $1.05 million of cash grant items were subsequently approved and paid in March 2013. For the Neal Hot Springs project, an application was submitted in the first quarter 2013 electing to take the ITC cash grant, in lieu of the PTC, for approximately $35.9 million from U.S. Treasury and the funds would be used to fund reserves required under the DOE Loan Guarantee Agreement and return funds to our partner in the project, Enbridge. Due to federal sequestration in early 2013, the ITC cash grant amount received in April 2013 was reduced by 8.7% to $32.7 million.

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In July 2010, the Company applied to the Oregon Department of Energy for the Business Energy Tax Credit (“BETC”), which allows an income tax credit for up to $20 million in qualifying expenditures for a renewable energy project. The Neal Hot Springs project completed final certification for the credit and sold it to a pass-through partner, monetized at a cash value of $7.36 million (less a broker fee) in November 2013.

On May 21, 2012, the Company entered into a purchase agreement (the “Purchase Agreement”) with Lincoln Park Capital Fund, LLC (“LPC”), pursuant to which the Company has the right to sell to LPC up to $10,750,000 in shares of the Company’s common stock, (“Common Stock”), subject to certain limitations and conditions set forth in the Purchase Agreement and imposed by the Company’s board of directors and pricing committee thereof. Pursuant to the Purchase Agreement LPC initially purchased $750,000 in shares of Common Stock at $0.38 per share. Following this initial purchase, on any business day and as often as every other business day over the 36-month term of the Purchase Agreement, and up to an aggregate amount of an additional $10,000,000 (subject to certain limitations) in shares of Common Stock, the Company has the right, from time to time, at its sole discretion and subject to certain conditions to direct LPC to purchase up to 250,000 shares of Common Stock, which amount may be increased in accordance with the Purchase Agreement if the closing sale price of Common Stock on the NYSE MKT exceeds certain specified levels. The purchase price of shares of Common Stock pursuant to the Purchase Agreement will be based on prevailing market prices of Common Stock at the time of sales without any fixed discount, and the Company will control the timing and amount of any sales of Common Stock to LPC. No sales of Common Stock under the Purchase Agreement will be made through the TSX. The Purchase Agreement contains customary representations, warranties and agreements of the Company and LPC, limitations and conditions to completing future sale transactions, indemnification rights and other obligations of the parties. There is no upper limit on the price per share that LPC could be obligated to pay for Common Stock under the Purchase Agreement. LPC shall not have the right or the obligation to purchase any shares of Common Stock if the purchase price of those shares, determined as set forth in the Purchase Agreement, would be below $0.25 per share. The Company has the right to terminate the Purchase Agreement at any time, at no cost or penalty. Actual sales of shares of Common Stock to LPC under the Purchase Agreement will depend on a variety of factors to be determined by the Company from time to time, including (among others) market conditions, the trading price of the Common Stock and determinations by the Company as to available and appropriate sources of funding for the Company and its operations. As consideration for entering into the Purchase Agreement, the Company has issued to LPC 651,819 shares of Common Stock. The Company will not receive any cash proceeds from the issuance of these 651,819 shares. As of June 30, 2014, the Company has sold LPC an aggregate of 4,625,506 shares of common stock pursuant to the Purchase Agreement for net proceeds of approximately $1,343,639 (net of $86,911 broker and legal fees). On December 21, 2012, the Company and LPC entered into an Amendment No. 1 to the Purchase Agreement (the “Amendment”) to reduce the total amount that can be purchased under the Purchase Agreement, including amounts already purchased, from $10,750,000 to $6,500,000.

In September 2010, Oregon USG Holdings, LLC (a wholly owned subsidiary) entered into agreements with Enbridge (U.S.) Inc. that formed a strategic and financial partnership to finance the Neal Hot Springs project located in eastern Oregon. A component of these agreements included a $5 million convertible promissory note, which converted. The DOE guaranteed project loan was treated as an equity contribution by Enbridge to the project. The agreements also provided for additional equity contributions of $13.8 million from Enbridge that when combined with the $5 million convertible promissory note earned Enbridge a 20% direct ownership in the project. As a result of cost overruns for the project, and at the election of the Company, an additional payment obligation of up to $8 million was contributed by Enbridge that increased their direct ownership in the project by 1.5 percentage points for each $1 million contributed. Added to their base 20% ownership, additional payments increased Enbridge’s ownership to 27.5% . An additional $6 million cost overrun facility was established by Enbridge to cover costs that resulted from unexpected poor results from injection well drilling. The additional investment by Enbridge increased their ownership in USG Oregon LLC based on running a project financial model and determining what percentage of the forecasted project income would be allocated to Enbridge to arrive at a predetermined rate of return for the additional investment. In February 2014, the final ownership interest in the Neal Hot Springs project was determined to be 60% for U.S. Geothermal and 40% for Enbridge. As a result of the final agreement, U.S. Geothermal Inc. received an approximate $6.2 million cash distribution from the partnership.

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Potential Acquisitions and Acquisitions Completed Subsequent to Period End

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

Critical Accounting Policies

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

See Management’s Discussion and Analysis and the financial statements and related footnotes included in our Transition Report on Form 10-K for the year ended December 31, 2013, for a description of our critical accounting policies.

Item 3 – Quantitative and Qualitative Disclosures about Market Risk

Interest Risk on Investments
At June 30, 2014, the Company held investments of $30,133,806 in money market accounts. These are highly liquid investments that are subject to risks associated with changes in interest rates. The money market funds are invested in governmental obligations with minimal fluctuations in interest rates and fixed terms.

Foreign Currency Risk
The Company is subject to a limited amount of foreign currency risks associated with cash deposits maintained in Canadian currency. The Company has utilized and it is continuing to utilize the Canadian markets for raising capital. By proper timing of the transactions and then maintenance of adequate operating funds in other financial resources, the Company has been able to mitigate some of the risks surrounding foreign currency exchanges. At the quarter ended June 30, 2014, the Company held deposits that amounted to less than $10,000 in U.S. dollar equivalents. As a matter of standard operating practice, the Company does not maintain large balances of Canadian currency, and substantially all operating transactions are conducted in U.S. dollars.

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Prior to April 1, 2007, the strike price for the Company’s stock option plan had been stated in Canadian dollars as the plan had been administered through our Vancouver office and Pacific Corporate Trust Company. This subjected the Company to foreign currency risk in addition to the normal market risks associated with the stock price fluctuations. A long-term liability had been established to reflect the fair value of the stock options payable. The strike price on subsequent option grants is stated in U.S. dollars.

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 power purchase contracts that exceed 20 year periods for the power plants currently in production and scheduled to go into production. 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 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 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 six months ended June 30, 2014 that has materially affected, or is likely to materially affect, our internal control over financial reporting.

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PART II- OTHER INFORMATION

Item 1 - Legal Proceedings

None.

Item 1A - Risk Factors

See “Risk Factors” in our transition report on Form 10-K for the year ended December 31, 2013. There have been no material changes in the risk factors during the six months ended June 30, 2014.

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: August 14, 2014	By:/s/ Dennis J. Gilles
	Dennis J. Gilles
	Chief Executive Officer
Date: August 14, 2014
	By:/s/ Kerry D. Hawkley
	Kerry D. Hawkley
	Chief Financial Officer and Corporate Secretary

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EXHIBIT INDEX

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

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