Edgar Filing: ORMAT TECHNOLOGIES, INC.

ora20150930_10q.htm

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

	For the quarterly period ended September 30, 2015

	or

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

	For the transition period from to

Commission file number: 001-32347

ORMAT TECHNOLOGIES, INC.

(Exact name of registrant as specified in its charter)

DELAWARE	88-0326081
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification Number)

6225 Neil Road, Reno, Nevada	89511-1136
(Address of principal executive offices)	(Zip Code)

(775) 356-9029

(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 ☑ 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 ☑ No ☐

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

Large accelerated filer ☑	Accelerated filer ☐	Non-accelerated filer ☐	Smaller reporting company ☐
	(Do not check if a smaller reporting company)

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

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date: As of November 3, 2015, the number of outstanding shares of common stock, par value $0.001 per share, was 49,035,593.

ORMAT TECHNOLOGIES, INC.

FORM 10-Q

FOR THE QUARTER ENDED SEPTEMBER 30, 2015

PART I — FINANCIAL INFORMATION

ITEM 1.	FINANCIAL STATEMENTS	4

ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	25

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	58

ITEM 4.	CONTROLS AND PROCEDURES	58

PART II — OTHER INFORMATION

ITEM 1.	LEGAL PROCEEDINGS	59

ITEM 1A.	RISK FACTORS	60

ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	60

ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	60

ITEM 4.	MINE SAFETY DISCLOSURES	60

ITEM 5.	OTHER INFORMATION	60

ITEM 6.	EXHIBITS	61

SIGNATURES		62

Certain Definitions

Unless the context otherwise requires, all references in this quarterly report to “Ormat”, “the Company”, “we”, “us”, “our company”, “Ormat Technologies” or “our” refer to Ormat Technologies, Inc. and its consolidated subsidiaries.

iii

PART I - FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	September 30,			December 31,
	2015			2014
	(Dollars in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	171,541		$	40,230
Restricted cash and cash equivalents (all related to VIEs)		70,523			93,248
Receivables:
Trade		52,313			48,609
Related entity		—			451
Other		9,946			10,141
Due from Parent		—			1,337
Inventories		16,595			16,930
Costs and estimated earnings in excess of billings on uncompleted contracts		14,459			27,793
Deferred income taxes		1,344			251
Prepaid expenses and other		34,011			34,884
Total current assets		370,732			273,874
Deposits and other		17,506			20,044
Deferred charges		36,235			37,567
Property, plant and equipment, net ($1,522,076 and $1,339,342 related to VIEs, respectively)		1,580,379			1,437,637
Construction-in-process ($125,425 and $162,006 related to VIEs, respectively)		230,561			296,722
Deferred financing and lease costs, net		24,718			27,057
Intangible assets, net		26,202			28,655
Total assets	$	2,286,333		$	2,121,556
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	85,226		$	88,276
Deferred income taxes		975			974
Short term revolving credit lines with banks (full recourse)		—			20,300
Billings in excess of costs and estimated earnings on uncompleted contracts		22,616			24,724
Current portion of long-term debt:
Limited and non-recourse (all related to VIEs):
Senior secured notes		33,197			34,368
Other loans		21,495			17,995
Full recourse		17,228			19,116
Total current liabilities		180,737			205,753
Long-term debt, net of current portion:
Limited and non-recourse (all related to VIEs):
Senior secured notes		317,909			360,366
Other loans		288,753			264,625
Full recourse:
Senior unsecured bonds (plus unamortized premium based upon 7% of $590)		250,058			250,289
Other loans		23,070			34,351
Unconsolidated investments		12,667			3,617
Liability associated with sale of tax benefits		18,580			39,021
Deferred lease income		58,325			60,560
Deferred income taxes		31,360			66,220
Liability for unrecognized tax benefits		7,112			7,511
Liabilities for severance pay		18,826			20,399
Asset retirement obligation		20,282			19,142
Other long-term liabilities		697			2,956
Total liabilities		1,228,376			1,334,810
Commitments and contingencies (Note 10)
Equity:
The Company's stockholders' equity:
Common stock, par value $0.001 per share; 200,000,000 shares authorized; 49,035,593 and 45,537,162 shares issued and outstanding as of September 30, 2015 and December 31, 2014, respectively		49			46
Additional paid-in capital		846,998			742,006
Retained earnings		128,352			41,539
Accumulated other comprehensive income		(12,844	)		(8,668	)
		962,555			774,923
Noncontrolling interest		95,402			11,823
Total equity		1,057,957			786,746
Total liabilities and equity	$	2,286,333		$	2,121,556

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

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND

COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
	(Dollars in thousands, except per share data)						(Dollars in thousands, except per share data)
Revenues:
Electricity	$	97,245		$	102,506		$	278,124		$	289,015
Product		65,607			37,736			145,446			121,266
Total revenue		162,852			140,242			423,570			410,281
Cost of revenues:
Electricity		61,501			61,727			179,604			186,083
Product		42,019			23,040			89,826			75,307
Total cost of revenue		103,520			84,767			269,430			261,390
Gross margin		59,332			55,475			154,140			148,891
Operating expenses:
Research and development expenses		335			250			1,112			395
Selling and marketing expenses		4,383			4,258			12,099			10,853
General and administrative expenses		7,950			7,179			25,597			20,847
Write-off of unsuccessful exploration activities		185			—			359			8,107
Operating income		46,479			43,788			114,973			108,689
Other income (expense):
Interest income		53			35			106			236
Interest expense, net		(17,748	)		(22,494	)		(54,435	)		(65,084	)
Foreign currency translation and transaction gains (losses)		1,296			(2,946	)		(641	)		(3,639	)
Income attributable to sale of tax benefits		8,634			5,487			18,917			18,334
Gain from sale of property, plant and equipment		—			—			—			7,628
Other non-operating income (expense), net		(131	)		243			(1,523	)		649
Income before income taxes and equity in losses of investees		38,583			24,113			77,397			66,813
Income tax (provision) benefit		38,211			(6,444	)		26,696			(17,731	)
Equity in losses of investees, net		(3,133	)		(899	)		(4,892	)		(1,210	)
Net income		73,661			16,770			99,201			47,872
Net income attributable to noncontrolling interest		(1,522	)		(256	)		(2,616	)		(670	)
Net income attributable to the Company's stockholders	$	72,139		$	16,514		$	96,585		$	47,202
Comprehensive income:
Net income		73,661			16,770			99,201			47,872
Other comprehensive income (loss), net of related taxes:
Change in unrealized gains or losses in respect of the Company's share in derivatives instruments of unconsolidated investment		(4,318	)		(1,069	)		(4,154	)		(5,157	)
Loss in respect of derivative instruments designated for cash flow hedge		22			(933	)		68			(933	)
Amortization of unrealized gains in respect of derivative instruments designated for cash flow hedge		(29	)		(35	)		(90	)		(107	)
Comprehensive income		69,336			14,733			95,025			41,675
Comprehensive income attributable to noncontrolling interest		(1,522	)		(256	)		(2,616	)		(670	)
Comprehensive income attributable to the Company's stockholders	$	67,814		$	14,477		$	92,409		$	41,005
Earnings per share attributable to the Company's stockholders:
Basic:
Net income	$	1.47		$	0.36		$	2.00		$	1.04
Diluted:
Net income	$	1.41		$	0.36		$	1.93		$	1.03
Weighted average number of shares used in computation of earnings per share attributable to the Company's stockholders:
Basic		49,023			45,690			48,388			45,594
Diluted		51,113			46,102			50,011			45,917
Dividend per share declared	$	0.06		$	0.05		$	0.2		$	0.16

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

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF EQUITY

(Unaudited)

	The Company's Stockholders' Equity
							Retained			Accumulated
					Additional		Earnings			Other
	Common Stock				Paid-in		(Accumulated			Income						Noncontrolling			Total
	Shares		Amount		Capital		Deficit)			(Loss)			Total			Interest			Equity

	(Dollars in thousands, except per share data)

Balance at December 31, 2013		45,461	$	46	$	735,295	$	(3,088	)	$	487		$	732,740		$	12,371		$	745,111

Stock-based compensation		—		—		4,308		—			—			4,308			—			4,308
Exercise of options by employees and directors		70		—		889		—			—			889			—			889
Cash paid to non controlling interest		—		—		—		—			—			—			(589	)		(589	)
Cash dividend declared, $0.16 per share		—		—		—		(7,279	)		—			(7,279	)		—			(7,279	)
Increase in noncontrolling interest		—		—		—		—			—			—			257			257
Acquisition of noncontrolling interest in Crump		—		—		159		—			—			159			(987	)		(828	)
Net income		—		—		—		47,202			—			47,202			670			47,872
Other comprehensive income (loss), net of related taxes:
Loss in respect of derivative instruments designated for cash flow hedge (net of related tax of $572)		—		—		—		—			(933	)		(933	)		—			(933	)
Change in unrealized gains or losses in respect of the Company's share in derivative instruments of unconsolidated investment (net of related tax of $0)		—		—		—		—			(5,157	)		(5,157	)		—			(5,157	)
Amortization of unrealized gains in respect of derivative instruments designated for cash flow hedge (net of related tax of $44)		—		—		—		—			(107	)		(107	)		—			(107	)

Balance at September 30, 2014		45,531	$	46	$	740,651	$	36,835		$	(5,710	)	$	771,822		$	11,722		$	783,544

Balance at December 31, 2014		45,537	$	46	$	742,006	$	41,539		$	(8,668	)	$	774,923		$	11,823		$	786,746

Stock-based compensation		—		—		3,077		—			—			3,077			—			3,077
Exercise of options by employees and directors		502		—		4,612		—			—			4,612			—			4,612
Share exchange with Parent (Note 1)		2,996		3		26,012		—			—			26,015			—			26,015
Cash paid to noncontrolling interest		—		—		—		—			—			—			(4,507	)		(4,507	)
Cash dividend declared, $0.2 per share		—		—		—		(9,772	)		—			(9,772	)		—			(9,772	)
Issuance of shares to noncontrolling interest, net of transaction costs		—		—		71,291		—			—			71,291			85,470			156,761
Net income		—		—		—		96,585			—			96,585			2,616			99,201
Other comprehensive income (loss), net of related taxes:
Loss in respect of derivative instruments designated for cash flow hedge (net of related tax of $42)		—		—		—		—			68			68			—			68
Change in unrealized gains or losses in respect of the Company's share in derivative instruments of unconsolidated investment (net of related tax of $0)		—		—		—		—			(4,154	)		(4,154	)		—			(4,154	)
Amortization of unrealized gains in respect of derivative instruments designated for cash flow hedge (net of related tax of $56)		—		—		—		—			(90	)		(90	)		—			(90	)

Balance at September 30, 2015		49,035	$	49	$	846,998	$	128,352		$	(12,844	)	$	962,555		$	95,402		$	1,057,957

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

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months Ended September 30,
	2015			2014

	(Dollars in thousands)
Cash flows from operating activities:
Net income	$	99,201		$	47,872
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		80,463			74,836
Amortization of premium from senior unsecured bonds		(230	)		(230	)
Accretion of asset retirement obligation		1,140			1,122
Stock-based compensation		3,077			4,308
Amortization of deferred lease income		(2,014	)		(2,014	)
Income attributable to sale of tax benefits, net of interest expense		(13,068	)		(10,130	)
Equity in losses of investees		4,893			1,210
Mark-to-market of derivative instruments		3,906			(4,467	)
Loss on disposal of property, plant and equipment		531			—
Write-off of unsuccessful exploration activities		360			8,107
Gain on severance pay fund asset		(102	)		798
Gain on sale of a subsidiary		—			(7,628	)
Gain on acquisition of controlling interest		—			—
Deferred income tax provision		(34,613	)		13,071
Liability for unrecognized tax benefits		(399	)		656
Deferred lease revenues		(221	)		(188	)
Other		484			(181	)
Changes in operating assets and liabilities, net of amounts acquired:
Receivables		(2,879	)		21,624
Costs and estimated earnings in excess of billings on uncompleted contracts		13,334			6,433
Inventories		335			4,952
Prepaid expenses and other		(3,033	)		(5,163	)
Deposits and other		(294	)		279
Accounts payable and accrued expenses		(21,904	)		(10,868	)
Due from/to related entities, net		451			(64	)
Billings in excess of costs and estimated earnings on uncompleted contracts		(2,108	)		37,407
Liabilities for severance pay		(1,573	)		(1,857	)
Other long-term liabilities		(2,259	)		(527	)
Due from/to Parent		(513	)		(588	)
Net cash provided by operating activities		122,965			178,770
Cash flows from investing activities:
Cash acquired in organizational restructuring and share exchange with parent (Note 1)		15,391			—
Net change in restricted cash, cash equivalents and marketable securities		22,725			(76,387	)
Cash received from sale of a subsidiary		—			35,250
Capital expenditures		(117,588	)		(122,587	)
Cash grant received from the U.S. Treasury under Section 1603 of the ARRA		—			27,427
Investment in unconsolidated companies		—			(631	)
Decrease in severance pay fund asset, net of payments made to retired employees		2,934			1,493
Net cash used in investing activities		(76,538	)		(135,435	)
Cash flows from financing activities:
Proceeds from sale of membership interests to noncontrolling interest, net of transaction costs		156,761			—
Proceeds from long-term loans, net of transaction costs		42,000			140,000
Proceeds from exercise of options by employees		4,612			741
Payment for acquisition of noncontrolling interest in Crump		-			(1,490	)
Purchase of OFC Senior Secured Notes		(30,638	)		(12,860	)
Proceeds from revolving credit lines with banks		598,800			2,400,683
Repayment of revolving credit lines with banks		(619,100	)		(2,484,600	)
Cash received from non-controlling interest		1,654			2,234
Repayments of long-term debt		(40,532	)		(80,223	)
Cash paid to non-controlling interest		(13,863	)		(9,215	)
Cash paid for interest rate cap		-			(1,505	)
Deferred debt issuance costs		(5,038	)		(4,724	)
Cash dividends paid		(9,772	)		(7,279	)
Net cash provided by (used in) financing activities		84,884			(58,238	)
Net change in cash and cash equivalents		131,311			(14,903	)
Cash and cash equivalents at beginning of period		40,230			57,354
Cash and cash equivalents at end of period	$	171,541		$	42,451
Supplemental non-cash investing and financing activities:
Increase (decrease) in accounts payable related to purchases of property, plant and equipment	$	18,930		$	(5,221	)

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

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1 — GENERAL AND BASIS OF PRESENTATION

These unaudited condensed consolidated interim financial statements of Ormat Technologies, Inc. and its subsidiaries (collectively, the “Company”) have been prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”) and pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”) for interim financial statements. Accordingly, they do not contain all information and notes required by U.S. GAAP for annual financial statements. In the opinion of management, these unaudited condensed consolidated interim financial statements reflect all adjustments, which include normal recurring adjustments, necessary for a fair statement of the Company’s consolidated financial position as of September 30, 2015, the consolidated results of operations and comprehensive income (loss) for the nine-month periods ended September 30, 2015 and 2014 and the consolidated cash flows for the nine-month periods ended September 30, 2015 and 2014.

The financial data and other information disclosed in the notes to the condensed consolidated financial statements related to these periods are unaudited. The results for the nine-month period ended September 30, 2015 are not necessarily indicative of the results to be expected for the year ending December 31, 2015.

These condensed consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in the Company’s annual report on Form 10-K for the year ended December 31, 2014. The condensed consolidated balance sheet data as of December 31, 2014 was derived from the audited consolidated financial statements for the year ended December 31, 2014, but does not include all disclosures required by U.S. GAAP.

Dollar amounts, except per share data, in the notes to these financial statements are rounded to the closest $1,000.

Deferred tax asset in Kenya

Previously, the Company had a valuation allowance for the additional 50% investment deduction reducing its deferred tax asset in Kenya as the utilization of the related tax losses was not probable within the original five year carryforward period. As a result of the change in legislation and the expected continued profitability during the extended carryforward period, the Company expects that it will be able to fully utilize the carryforward tax losses within the ten year period and as such released the valuation allowance in Kenya resulting in a $49.4 million of tax benefits in the three month period ended September 30, 2015.

Amatitlan financing

On July 31, 2015, one of our indirect wholly-owned subsidiaries, Ortitlản, Limitada, obtained a 12-year secured term loan in the principal amount of $42.0 million for the 20 MW Amatitlan power plant in Guatemala. Under the credit agreement with Banco Industrial S.A. and Westrust Bank (International) Limited, we can expand the Amatitlan power plant with financing to be provided either via equity, additional debt from Banco Industrial S.A. or from other lenders, subject to certain limitations on expansion financing in the credit agreement.

The loan is payable in 48 quarterly payments commencing September 30, 2015. The loan bears interest at a rate per annum equal to of the sum of the LIBO Rate (which cannot be lower than 1.25%) plus a margin of (i) 4.35% as long as the Company’s guaranty of the loan (as described below) is outstanding or (ii) 4.75% otherwise. Interest is payable quarterly, on March 30, June 30, September 30 and December 30 of each year, on the stated maturity date of the loan and on any prepayment or payment of the loan. The loan must be prepaid on the occurrence of certain events, such as casualty, condemnation, asset sales and expansion financing not provided by the lenders under the credit agreement, among others. The loan may be voluntarily prepaid if certain conditions are satisfied, including payment of a premium (ranging from 100-50 basis points) if prepayment occurs prior to the eighth anniversary of the loan.

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

There are various restrictive covenants under the Amatitlan credit agreement. These include, among others, (i) a financial covenant to maintain a Debt Service Coverage Ratio (as defined in the credit agreement) of not less than 1.15 to 1.00 as of the last day of any fiscal quarter and (ii) limitations on Restricted Payments (as defined in the credit agreement) that among other things would limit dividends that could be paid to us unless the historical and projected Debt Service Coverage Ratio is not less than 1.25 to 1.00 for the four fiscal quarterly periods (calculated as a single accounting period). As of September 30, 2015, the actual historical and projected 12-month Debt Service Coverage Ratio was 7.94 and 1.97, respectively. The credit agreement includes various events of default that would permit acceleration of the loan (subject in some cases to grace and cure periods). These include, among others, a Change of Control (as defined in the credit agreement) and failure to maintain certain required balances in debt service and maintenance reserve accounts. The credit agreement includes certain equity cure rights for failure to maintain the Debt Service Coverage Ratio and the minimum amounts required in the debt service and maintenance reserve accounts.

The loan is secured by substantially all the assets of the borrower and a pledge of all of the membership interests of the borrower.

The Company has guaranteed payment of all obligations under the credit agreement and related financing documents. The guaranty is limited in the sense that the Company is only required to pay the guaranteed obligations if a “trigger event” occurs. A trigger event is the occurrence and continuation of a default by Instituto Nacional de Electricidad (“INDE”) in its payment obligations under the power purchase agreement for the Amatitlàn power plant or a refusal by INDE to receive capacity and energy sold under that power purchase agreement. Our obligations under the guaranty may be terminated prior to payment in full of the guaranteed obligations under certain circumstances described in the guaranty. If our guaranty is terminated early, the interest rate payable on the loan would increase as described above.

As of September 30, 2015, $41.1 million of this loan is outstanding.

OFC Senior Secured Notes prepayment

In June 2015, the Company repurchased $30.6 million aggregate principal amount of its OFC Senior Secured Notes from certain OFC noteholders. As a result of the repurchase, the Company recognized a loss of $1.7 million, including amortization of deferred financing cost of $0.5 million, which is included in other non-operating income (expense), net in the consolidated statements of operations and comprehensive income for the nine months ended September 30, 2015.

Northleaf transaction

On April 30, 2015, Ormat Nevada Inc. (“Ormat Nevada”), a wholly-owned subsidiary of the Company, closed the sale of approximately 36.75% of the aggregate membership interests in ORPD LLC (“ORPD”), a new holding company and subsidiary of Ormat Nevada, that indirectly owns the Puna geothermal power plant in Hawaii, the Don A. Campbell geothermal power plant in Nevada, and nine power plant units across three recovered energy generation assets known as OREG 1, OREG 2 and OREG 3 to Northleaf Geothermal Holdings, LLC for $162.3 million. The net proceeds to the Company were $156.8 million after payment of $5.5 million of transaction costs. The sale was made under the Agreement for Purchase of Membership Interests dated February 5, 2015. This transaction closed on April 30, 2015 and resulted in a taxable gain in the U.S. of approximately $102.1 million, for which the Company will utilize a portion of its Net Operating Loss (“NOL”) and tax credit carryforwards to fully offset the tax impact of the gain.

Following the transaction, the Company maintains control of ORPD and continues to consolidate the entity with non-controlling interest being recorded. Consequently, the Company recorded the net proceeds from the issuance of membership interests as an increase to additional paid-in capital of $71.3 million and non-controlling interests of $85.5 million. See Note 11 for tax details.

Share exchange transaction

On February 12, 2015, the Company completed the share exchange transaction with its then-parent entity, Ormat Industries Ltd. ("OIL") following which, the Company became a noncontrolled public company and its public float increased from approximately 40% to approximately 76% of its total shares outstanding. Under the terms of the share exchange, OIL shareholders received 0.2592 shares in the Company for each share in OIL, or an aggregate of approximately 30.2 million shares, reflecting a net issuance of approximately 3.0 million shares (after deducting the 27.2 million shares that OIL held in the Company). Consequently, the number of total shares of the Company outstanding increased from approximately 45.5 million shares to approximately 48.5 million shares as of the closing of the share exchange.

In exchange, the Company also received $15.4 million in cash, $0.6 million in other assets and $12.1 million in land and buildings and assumed $0.5 million in liabilities. OIL's principal business purpose was to hold its interest in the Company and the transaction resulted in a transfer of non-material assets from OIL to the Company. Therefore, there was no change in the reporting entity as a result of the transaction and the Company recognized the transfer of net assets at their carrying value as presented in OIL's financial statements. Any activities of OIL will be accounted for prospectively by the Company.

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

OFC 2 loan prepayment

On June 20, 2014, Phase I of the Tuscarora Facility achieved Project Completion under the OFC 2 Note Purchase Agreement. In accordance with the terms of the Note Purchase Agreement and following recalibration of the financing assumptions, the loan amount was adjusted through a principal prepayment of $4.3 million.

Solar project sale

On March 26, 2014, the Company signed an agreement with RET Holdings, LLC to sell the Heber Solar project in Imperial County, California for $35.25 million. The Company received the first payment of $15.0 million during the first quarter of 2014 and the second payment for the remaining $20.25 million in the second quarter of 2014. The Company recognized pre-tax gain of approximately $7.6 million in the second quarter of 2014.

Other comprehensive income

For the nine months ended September 30, 2015 and 2014, the Company classified $22,000 and $107,000, respectively, from accumulated other comprehensive income, of which $35,000 and $173,000, respectively, were recorded to reduce interest expense and $13,000 and $66,000, respectively, were recorded against the income tax provision, in the condensed consolidated statements of operations and comprehensive income. For the three months ended September 30, 2015 and 2014, the Company classified $7,000 and $35,000, respectively, from accumulated other comprehensive income, of which $10,000 and $57,000, respectively, were recorded to reduce interest expense and $3,000 and $22,000, respectively, were recorded against the income tax provision, in the condensed consolidated statements of operations and comprehensive income.

Write-off of unsuccessful exploration activities

Write-off of unsuccessful exploration activities for the three and nine months ended September 30, 2015 were $0.2 million and $0.4 million, respectively. Write-off of unsuccessful exploration activities for the nine months ended September 30, 2014, was $8.1 million. This represents the write-off of exploration costs related to the Company’s exploration activities in the Wister site in California, which the Company determined in the second quarter of 2014 would not support commercial operations.

Acquisition of interests in Crump Geyser and North Valley geothermal projects

On August 5, 2014, the Company signed a definitive Purchase and Sale Agreement with Alternative Earth Resources Inc. (“AER”), pursuant to which the Company paid $1.5 million in cash and (i) purchased AER's (a) 50% interest in Crump Geyser Company (“CGC”), which holds the rights to the Crump Geyser geothermal project, and (b) rights to the North Valley geothermal project and (ii) obtained an option, exercisable over a four-year period, to purchase certain of AER's New Truckhaven geothermal leases. Prior to this transaction, CGC was consolidated by the Company as a variable interest entity. As a result of the acquisition of the remaining interest, the Company continues to consolidate CGC, but now as a wholly owned indirect subsidiary, and so the carrying value of the noncontrolling interest of CGC of $1.0 million was reclassified to the Company's equity and the difference of $0.2 million between the fair value of the consideration paid and the related carrying value of the nonconrolling interest acquired was recorded within “additional paid in capital” in the condensed consolidated statement of equity.

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Concentration of credit risk

Financial instruments that potentially subject the Company to a concentration of credit risk consist principally of temporary cash investments and accounts receivable.

The Company places its temporary cash investments with high credit quality financial institutions located in the United States (“U.S.”) and in foreign countries. At September 30, 2015 and December 31, 2014, the Company had deposits totaling $41,071,000 and $23,488,000, respectively, in seven U.S. financial institutions that were federally insured up to $250,000 per account. At September 30, 2015 and December 31, 2014, the Company’s deposits in foreign countries amounted to approximately $134,986,000 and $24,304,000, respectively.

At September 30, 2015 and December 31, 2014, accounts receivable related to operations in foreign countries amounted to approximately $22,981,000 and $21,935,000, respectively. At September 30, 2015 and December 31, 2014, accounts receivable from the Company’s primary customers amounted to approximately 73.7% and 69.0%, respectively, of the Company’s accounts receivable.

Sierra Pacific Power Company and Nevada Power Company (subsidiaries of NV Energy, Inc.) accounted for 15.3% and 14.7% of the Company’s total revenue for the three months ended September 30, 2015 and 2014, respectively and 19.3% and 16.6% for the nine months ended September 30, 2015 and 2014, respectively.

Southern California Edison accounted for 13.4% and 19.9% of the Company’s total revenue for the three months ended September 30, 2015 and 2014, respectively, and 11.1% and 15.2% for the nine months ended September 30, 2015 and 2014, respectively.

Kenya Power and Lighting Co. Ltd. accounted for 13.5% and 15.8% of the Company’s total revenue for the three months ended September 30, 2015 and 2014, respectively, and 15.4% and 15.6% for the nine months ended September 30, 2015 and 2014, respectively.

The Company performs ongoing credit evaluations of its customers’ financial condition. The Company has historically been able to collect on all of its receivable balances, and accordingly, no provision for doubtful accounts has been made.

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

NOTE 2 — NEW ACCOUNTING PRONOUNCEMENTS

New accounting pronouncements effective in the nine-month period ended September 30, 2015

Service Concession Arrangements

In January 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-05, Service Concession Arrangements, Topic 853. The update provides that an operating entity should not account for a service concession arrangement within the scope of this update as a lease in accordance with Topic 840, Leases. The amendments also specify that the infrastructure used in a service concession arrangement should not be recognized as property, plant, and equipment of the operating entity. A service concession arrangement is an arrangement between a public-sector entity grantor and an operating entity under which the operating entity operates the grantor’s infrastructure and may provide the construction, upgrading, or maintenance services for the grantor’s infrastructure. The amendments apply to an operating entity of a service concession arrangement entered into with a public-sector entity grantor when the arrangement meets both of the following conditions: (1) the grantor controls or has the ability to modify or approve the services that the operating entity must provide for the infrastructure, to whom it must provide them, and at what price and (2) the grantor controls, through ownership, beneficial entitlement, or otherwise, any residual interest in the infrastructure at the end of the term of the arrangement. The guidance was applied on a modified retrospective basis to service concession arrangements in existence at January 1, 2015. The adoption of this guidance did not have a material impact on the Company’s consolidated financial statements.

New accounting pronouncements effective in future periods

Simplifying the Measurement of Inventory

In July 2015, the FASB issued ASU 2015-11, Simplifying the Measurement of Inventory, Topic 330. The update contains no amendments to disclosure requirements, but replaces the concept of ‘lower of cost or market’ with that of ‘lower of cost and net realizable value’. The amendments in this update are effective for annual reporting periods beginning after December 15, 2016, including interim periods within those reporting periods. The amendments should be applied prospectively with early adoption permitted. The Company is currently evaluating the potential impact, if any, of the adoption of this update on its consolidated financial statements.

Amendments to Fair Value Measurement

In June 2015, the FASB issued ASU 2015-10, Amendment to Fair Value Measurement, Subtopic 820-10. The amendment provides that the reporting entity shall disclose for each class of assets and liabilities measured at fair value in the statement of financial position the following information: for recurring fair value measurements, the fair value measurement at the end of the reporting period, and for non-recurring fair vale measurement, the fair value measurement at the relevant measurement date and the reason for the measurement. The amendments in this update are effective for annual reporting periods beginning after December 15, 2015, including interim periods within those reporting periods. Early adoption is permitted, including adoption in an interim period. The Company is currently evaluating the potential impact, if any, of the adoption of this update on its consolidated financial statements.

Amendments to the Consolidation Analysis

In February 2015, the FASB issued ASU 2015-02, Amendments to the Consolidation Analysis, Topic 810. The update provides that all reporting entities that hold a variable interest in other legal entities will need to re-evaluate their consolidation conclusions and potentially revise their disclosures. This amendment affects both variable interest entity (“VIE”) and voting interest entity (“VOE”) consolidation models. The update does not change the general order in which the consolidation models are applied. A reporting entity that holds an economic interest in, or is otherwise involved with, another legal entity (has a variable interest) should first determine if the VIE model applies, and if so, whether it holds a controlling financial interest under that model. If the entity being evaluated for consolidation is not a VIE, then the VOE model should be applied to determine whether the entity should be consolidated by the reporting entity. Since consolidation is only assessed for legal entities, the determination of whether there is a legal entity is important. It is often clear when the entity is incorporated, but unincorporated structures can also be legal entities and judgment may be required to make that determination. The update contains a new example that highlights the judgmental nature of this legal entity determination. The update is effective for annual reporting periods beginning after December 15, 2015, including interim periods within those reporting periods. Early adoption is permitted, including adoption in an interim period. The Company is currently evaluating the potential impact, if any, of the adoption of this update on its consolidated financial statements.

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Simplifying the Presentation of Debt Costs

In August 2015, the FASB issued ASU 2015-15, Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements, Subtopic 835-30. The update clarifies that given the absence of authoritative guidance within Update 2015-03 for debt issuance costs described below, debt issuance costs related to line-of-credit arrangement can be deferred and presented as assets and subsequently amortized ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings under the line-of-credit arrangement. The amendments in this update are effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. Early adoption is permitted. The Company is currently evaluating the potential impact, if any, of the adoption of these amendments on its consolidated financial statements.

In April 2015, the FASB issued ASU 2015-03, Interest-Imputation of Interest: Simplifying the Presentation of Debt Costs, Subtopic 835-30. The update provides that debt issuance costs related to a recognized debt liability be presented in the balance sheet as direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The amendments in this update are effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. Early adoption is permitted. The Company plans to adopt this update in its interim period beginning January 1, 2016 and expects the potential impact to be a reclassification of the debt issuance costs totaling $20.3 million as of September 30, 2015.

Revenues from Contracts with Customers

In May 2014, the FASB issued ASU 2014-09, Revenues from Contracts with Customers, Topic 606, which was a joint project of the FASB and the International Accounting Standards Board to clarify the principles for recognizing revenue and to develop a common revenue standard for U.S. GAAP and International Financial Reporting Standards. The update provides that an entity should recognize revenue in connection with the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Specifically, an entity is required to apply each of the following steps: (1) identify the contract(s) with the customer; (2) identify the performance obligations in the contracts; (3) determine the transaction price; (4) allocate the transaction price to the performance obligation in the contract; and (5) recognize revenue when (or as) the entity satisfies a performance obligation. The amendments in this update are effective for annual reporting periods beginning after December 15, 2017, including interim periods within those reporting periods. Early adoption is permitted no earlier than 2017 for calander fiscal year entities. The Company is currently evaluating the potential impact, if any, of the adoption of these amendments on its consolidated financial statements.

NOTE 3 — INVENTORIES

Inventories consist of the following:

	September 30,		December 31,
	2015		2014
	(Dollars in thousands)
Raw materials and purchased parts for assembly	$	5,470	$	4,840
Self-manufactured assembly parts and finished products		11,125		12,090
Total	$	16,595	$	16,930

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

NOTE 4 — UNCONSOLIDATED INVESTMENTS

Unconsolidated investments consist of the following:

	September 30,			December 31,
	2015			2014
	(Dollars in thousands)
Sarulla	$	(12,667	)	$	(3,617	)

The Sarulla Project

The Company is a 12.75% member of a consortium which is in the process of developing the Sarulla geothermal power project in Indonesia with expected generating capacity of approximately 330 megawatts (“MW”). The Sarulla project is located in Tapanuli Utara, North Sumatra, Indonesia and will be owned and operated by the consortium members under the framework of a Joint Operating Contract (“JOC”) and Energy Sales Contract (“ESC”) that were signed on April 4, 2013. Under the JOC, PT Pertamina Geothermal Energy (“PGE”), the concession holder for the project, has provided the consortium with the right to use the geothermal field, and under the ESC, PT PLN, the state electric utility, will be the off-taker at Sarulla for a period of 30 years. In addition to its equity holdings in the consortium, the Company designed the Sarulla plant and will supply its Ormat Energy Converters (“OECs”) to the power plant, as further described below.

The project is being constructed in three phases of approximately 110 MW each, utilizing both steam and brine extracted from the geothermal field to increase the power plant’s efficiency. The first phase of operations is expected to commence towards the end of 2016 and the remaining two phases of operations are scheduled to commence within 18 months thereafter. Engineering, procurement and construction (“EPC”) are in progress. The infrastructure work has been substantially completed and major equipment, including Ormat’s partial OECs and Toshiba’s steam turbine, have arrived in country. The drilling of production and injection wells is also in progress in all three phases. However, the project company is experiencing delays in drilling and reaching EPC milestones, as well as cost overruns, mainly in the field development of the second and third phases of the project. The consortium members are currently examining the significance of these cost overruns and their implications for the project's budget as well as for the financing of the project (described below).

On May 16, 2014, the consortium closed $1.17 billion in financing for the development of the Sarulla project with a consortium of lenders comprised of Japan Bank for International Cooperation (“JBIC”), the Asian Development Bank and six commercial banks and obtained construction and term loans on a limited recourse basis backed by a political risk guarantee from JBIC. Of the $1.17 billion, $0.1 billion (which was drawn down by the Sarulla project company on May 23, 2014) bears a fixed interest rate and $1.07 billion bears interest at a rate linked to LIBOR.

The Sarulla consortium entered into interest rate swap agreements with various international banks in order to fix the Libor interest rate on up to $0.96 billion of the $1.07 billion credit facility at a rate of 3.4565%. The interest rate swap became effective as of June 4, 2014 along with the second draw-down by the project company of $50.0 million.

The Sarulla project company accounted for the interest rate swap as a cash flow hedge upon which changes in the fair value of the hedging instrument, relative to the effective portion, will be recorded in other comprehensive income. As such, during the nine months ended September 30, 2015, the project recorded a loss equal to $32.6 million, of which the Company's share was $4.2 million which was recorded in other comprehensive income. The related accumulated loss recorded by the Company as of September 30, 2015 is $12.3 million.

Pursuant to a supply agreement that was signed in October 2013, the Company is supplying its OECs to the power plant and has added the $255.6 million supply contract to its product segment backlog. All of the scheduled milestones under Ormat’s supply agreement were achieved and the manufacturing work is currently progressing as planned. The Company started to recognize revenue from the project during the third quarter of 2014 and will continue to recognize revenue over the course of the next two to three years. The Company has eliminated the related intercompany profit of $5.2 million against equity in loss of investees.

During the nine months ended September 30, 2015, the Company did not make any additional investment contributions to the Sarulla project.

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

NOTE 5— FAIR VALUE OF FINANCIAL INSTRUMENTS

The fair value measurement guidance clarifies that fair value is an exit price, representing the amount that would be received upon selling an asset or paid upon transferring a liability in an orderly transaction between market participants. As such, fair value is a market-based measurement that should be determined based on assumptions that market participants would use in pricing an asset or liability. The guidance establishes a fair value hierarchy that prioritizes the inputs to valuation techniques 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 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of the fair value hierarchy under the fair value measurement guidance are described below:

Level 1 — Unadjusted quoted prices in active markets that are accessible at the measurement date for identical assets or liabilities;

Level 2 — Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability;

Level 3 — Prices or valuation techniques that require inputs that are both significant to the fair value measurement and unobservable (supported by little or no market activity).

The following table sets forth certain fair value information at September 30, 2015 and December 31, 2014 for financial assets and liabilities measured at fair value by level within the fair value hierarchy, as well as cost or amortized cost. As required by the fair value measurement guidance, assets and liabilities are classified in their entirety based on the lowest level of inputs that is significant to the fair value measurement.

				September 30, 2015
				Fair Value
	Carrying Value at September 30, 2015			Total			Level 1		Level 2			Level 3
	(Dollars in thousands)
Assets:
Current assets:
Cash equivalents (including restricted cash accounts)	$	44,187		$	44,187		$	44,187	$	—		$	—
Derivatives:
Swap transaction on natural gas price ⁽¹⁾		223			223			—		223			—
Liabilities:
Current liabilities:
Derivatives:
Currency forward contracts ⁽²⁾		(1,548	)		(1,548	)		—		(1,548	)		—
	$	42,862		$	42,862		$	44,187	$	(1,325	)	$	—

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

				December 31, 2014
				Fair Value
	Carrying Value at December 31, 2014			Total			Level 1		Level 2			Level 3
	(Dollars in thousands)
Assets
Current assets:
Cash equivalents (including restricted cash accounts)	$	85,076		$	85,076		$	85,076	$	—		$	—
Derivatives:
Swap transaction on natural gas price ⁽¹⁾		4,129			4,129			—		4,129			—
Liabilities:
Current liabilities:
Derivatives:
Currency forward contracts ⁽²⁾		(2,882	)		(2,882	)		—		(2,882	)		—
	$	86,323		$	86,323		$	85,076	$	1,247		$	—

⁽¹⁾

This amount relates to a swap contract on natural gas prices, valued primarily based on observable inputs, including forward and spot prices for related commodity indices, and is included within “prepaid expenses and other” and “accounts payable and accrued expenses” on September 30, 2015 and December 31, 2014, respectively, in the consolidated balance sheets with the corresponding gain or loss being recognized within “Electricity revenue” in the consolidated statement of operations and comprehensive income.

⁽²⁾

These amounts relate to derivatives which represent currency forward contracts valued primarily based on observable inputs, including forward and spot prices for currencies, netted against contracted rates and then multiplied against notional amounts, and are included within “accounts payable and accrued expenses” on September 30, 2015 and December 31, 2014, in the consolidated balance sheet with the corresponding gain or loss being recognized within “Foreign currency translation and transaction losses” in the consolidated statement of operations and comprehensive income.

The amounts set forth in the tables above include investments in debt instruments and money market funds (which are included in cash equivalents). Those securities and deposits are classified within Level 1 of the fair value hierarchy because they are valued using quoted market prices in an active market.

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The following table presents the amounts of gain (loss) recognized in the consolidated statements of operations and comprehensive income on derivative instruments not designated as hedges:

		Amount of recognized gain (loss)
Derivatives not designated as	Location of recognized gain	Three Months Ended September 30,					Nine Months Ended September 30,
hedging instruments	(loss)	2015		2014			2015			2014

Swap transaction on oil price	Electricity revenue		—		1,657			—			1,885

Swap transactions on natural gas price	Electricity revenue		369		2,295			767			(609	)

Currency forward contracts	Foreign currency translation and transaction gains (losses)		869		(2,422	)		(1,349	)		(2,430	)
		$	1,238	$	1,530		$	(582	)	$	(1,154	)

On September 3, 2013, the Company entered into a Natural Gas Index (“NGI”) swap contract with a bank covering a notional quantity of approximately 4.4 million British Thermal Units (“MMbtu”) for settlement effective January 1, 2014 until December 31, 2014, in order to reduce its exposure to fluctuations in natural gas prices under its Power Purchase Agreements (“PPAs”) with Southern California Edison to below $4.035 per MMbtu. The contract did not have up-front costs. Under the terms of this contract, the Company made floating rate payments to the bank and received fixed rate payments from the bank on each settlement date. The swap contract had a monthly settlement whereby the difference between the fixed price of $4.035 per MMbtu and the market price on the first commodity business day on which the relevant commodity reference price is published in the relevant calculation period (January 1, 2014 to December 1, 2014) was settled on a cash basis.

On October 16, 2013, the Company entered into an NGI swap contract with a bank covering a notional quantity of approximately 4.2 million MMbtu for settlement effective January 1, 2014 until December 31, 2014, in order to reduce its exposure to fluctuations in natural gas prices under its PPAs with Southern California Edison to below $4.103 per MMbtu. The contract did not have any up-front costs. Under the terms of this contract, the Company made floating rate payments to the bank and received fixed rate payments from the bank on each settlement date. The swap contract had a monthly settlement whereby the difference between the fixed price of $4.103 per MMbtu and the market price on the first commodity business day on which the relevant commodity reference price is published in the relevant calculation period (January 1, 2014 to December 1, 2014) was settled on a cash basis.

On October 16, 2013, the Company entered into a New York Harbor Ultra-Low Sulfur Diesel swap contract with a bank covering a notional quantity of 275,000 BBL effective from January 1, 2014 until December 31, 2014 to reduce the Company’s exposure to fluctuations in the energy rate caused by fluctuations in oil prices under the 25 MW PPA for the Puna complex. The Company entered into this contract because the swap had a high correlation with the avoided costs (which are incremental costs that the power purchaser avoids by not having to generate such electrical energy itself or purchase it from others) that Hawaii Electric Light Company (“HELCO”) uses to calculate the energy rate. The contract did not have any up-front costs. Under the term of this contract, the Company made floating rate payments to the bank and received fixed rate payments from the bank on each settlement date ($125.15 per BBL). The swap contract had a monthly settlement whereby the difference between the fixed price of $125.15 per BBL and the monthly average market price was settled on a cash basis.

On March 6, 2014, and on May 14, 2015, the Company entered into NGI swap contracts with a bank covering a notional quantity of approximately 2.2 MMbtu for settlement effective January 1, 2015 until March 31, 2015, and covering a notional quantity of approximately 2.4 MMbtu for settlement effective June 1, 2015 until December 31, 2015, respectively, in order to reduce its exposure to fluctuations in natural gas prices under its PPAs with Southern California Edison to below $4.95 per MMbtu and below $3.00 per MMbtu, respectively. The contracts did not have any up-front costs. Under the terms of these contracts, the Company made, and will make, floating rate payments to the bank and received, and will receive, fixed rate payments from the bank on each settlement date. The swap contracts have monthly settlements whereby the difference between the fixed price and the market price on the first commodity business day on which the relevant commodity reference price is published in the relevant calculation period (January 1, 2015 to March 1, 2015 and June 1, 2015 to December 31, 2015) are settled on a cash basis.

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The foregoing swap transactions were not designated as hedge transactions and are marked to market with the corresponding gains or losses recognized within “Electricity revenue” in the consolidated statements of operations and comprehensive income. The Company recognized a net gain from these transactions of $0.8 million in the nine months ended September 30, 2015, compared to net gain of $1.3 million in the nine months ended September 30, 2014. For the three months ended September 30, 2015 and 2014, the Company recognized a net gain from these transactions of $0.4 million and $4.0 million, respectively.

There were no transfers of assets or liabilities between Level 1, Level 2 and Level 3 during the nine months ended September 30, 2015.

The fair value of the Company’s long-term debt approximates its carrying amount, except for the following:

	Fair Value				Carrying Amount
	September 30, 2015		December 31, 2014		September 30, 2015		December 31, 2014
	(Dollars in millions)				(Dollars in millions)
Olkaria III Loan - DEG	$	28.5	$	32.2	$	27.6	$	31.6
Olkaria III Loan - OPIC		266.4		279.4		269.1		282.6
Amatitlan Loan		43.2		—		41.1		—
Senior Secured Notes:
Ormat Funding Corp. ("OFC")		36.0		71.4		33.3		67.2
OrCal Geothermal Inc. ("OrCal")		53.3		55.5		51.8		55.1
OFC 2 LLC ("OFC 2")		234.2		238.8		266.0		272.5
Senior Unsecured Bonds		262.0		265.4		250.1		250.4
Loan from institutional investors		6.2		12.2		6.0		11.9

The fair value of OFC Senior Secured Notes is determined using observable market prices as these securities are traded. The fair value of all the long-term debt is determined by a valuation model, which is based on a conventional discounted cash flow methodology and utilizes assumptions of current borrowing rates. The fair value of revolving lines of credit is determined using a comparison of market-based price sources that are reflective of similar credit ratings to those of the Company.

The carrying value of other financial instruments, such as revolving lines of credit, deposits, and other long-term debt approximates fair value.

The following table presents the fair value of financial instruments as of September 30, 2015:

	Level 1		Level 2		Level 3		Total
	(Dollars in millions)
Olkaria III - DEG	$	—	$	—	$	28.5	$	28.5
Olkaria III - OPIC		—		—		266.4		266.4
Amatitlan loan		—		43.2		—		43.2
Senior Secured Notes:
OFC		—		36.0		—		36.0
OrCal		—		—		53.3		53.3
OFC 2		—		—		234.2		234.2
Senior unsecured bonds		—		—		262.0		262.0
Loan from institutional investors		—		—		6.2		6.2
Other long-term debt		—		8.3		—		8.3
Deposits		15.8		—		—		15.8

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The following table presents the fair value of financial instruments as of December 31, 2014:

	Level 1		Level 2		Level 3		Total
	(Dollars in millions)
Olkaria III Loan - DEG	$	—	$	—	$	32.2	$	32.2
Olkaria III Loan - OPIC		—		—		279.4		279.4
Senior Secured Notes:
OFC		—		71.4		—		71.4
OrCal		—		—		55.5		55.5
OFC 2		—		—		238.8		238.8
Senior unsecured bonds		—		—		265.4		265.4
Loan from institutional investors		—		—		12.2		12.2
Other long-term debt		—		10.0		—		10.0
Revolving lines of credit		—		20.3		—		20.3
Deposits		17.3		—		—		17.3

NOTE 6 — STOCK-BASED COMPENSATION

The 2004 Incentive Compensation Plan

In 2004, the Company’s Board of Directors adopted the 2004 Incentive Compensation Plan (“2004 Incentive Plan”), which provides for the grant of the following types of awards: incentive stock options, non-qualified stock options, restricted stock, stock appreciation rights (“SARs”), stock units, performance awards, phantom stock, incentive bonuses, and other possible related dividend equivalents to employees of the Company, directors and independent contractors. Under the 2004 Incentive Plan, a total of 3,750,000 shares of the Company’s common stock were reserved for issuance, all of which could be issued as options or as other forms of awards. Options and SARs granted to employees under the 2004 Incentive Plan cliff vest and are exercisable from the grant date as follows: 25% after 24 months, 25% after 36 months, and the remaining 50% after 48 months. Options granted to non-employee directors under the 2004 Incentive Plan cliff vest and are exercisable one year after the grant date. Vested stock-based awards may be exercised for up to ten years from the grant date. The shares of common stock will be issued from the Company’s authorized share capital upon exercise of options or SARs. The 2004 Incentive Plan expired in May 2012 upon adoption of the 2012 Incentive Compensation Plan (“2012 Incentive Plan”), except as to share based awards outstanding under the 2004 Incentive Plan on that date.

The 2012 Incentive Compensation Plan

In May 2012, the Company’s shareholders adopted the 2012 Incentive Plan, which provides for the grant of the following types of awards: incentive stock options, non-qualified stock options, restricted stock, SARs, stock units, performance awards, phantom stock, incentive bonuses, and other possible related dividend equivalents to employees of the Company, directors and independent contractors. Under the 2012 Incentive Plan, a total of 4,000,000 shares of the Company’s common stock have been reserved for issuance, all of which could be issued as options or as other forms of awards. Options and SARs granted to employees under the 2012 Incentive Plan typically vest and become exercisable as follows: 25% vest 24 months after the grant date, an additional 25% vest 36 months after the grant date, and the remaining 50% vest 48 months after the grant date. Options granted to non-employee directors under the 2012 Incentive Plan will vest and become exercisable one year after the grant date. The term of stock-based awards typically ranges from six to ten years from the grant date. The shares of common stock will be issued from the Company’s authorized share capital upon exercise of options or SARs.

The 2012 Incentive Plan empowers the Company’s Board of Directors, in its discretion, to amend the 2012 Incentive Plan in certain respects. Consistent with this authority, in February 2014 the Board adopted and approved certain amendments to the 2012 Incentive Plan. The key amendments are as follows:

● Increase of per grant limit: Section 15(a) of the 2012 Incentive Plan was amended to allow the grant of up to 400,000 shares of the Company’s common stock with respect to the initial grant of an equity award to newly hired executive officers in any calendar year; and

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

● Acceleration of vesting: Section 15(l) of the 2012 Incentive Plan was amended to clarify the Company’s ability to provide in the applicable award agreement that part and/or all of the award will be accelerated upon the occurrence of certain predetermined events and/or conditions, such as a "change in control" (as defined in the 2012 Incentive Plan, as amended).

NOTE 7 — INTEREST EXPENSE, NET

The components of interest expense are as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014

Interest related to sale of tax benefits	$	2,375		$	3,430		$	7,062		$	9,678
Interest expense		16,510			19,910			50,430			57,139
Less — amount capitalized		(1,137	)		(846	)		(3,057	)		(1,733	)
	$	17,748		$	22,494		$	54,435		$	65,084

NOTE 8 — EARNINGS PER SHARE

Basic earnings per share attributable to the Company’s stockholders is computed by dividing net income or loss attributable to the Company’s stockholders by the weighted average number of shares of common stock outstanding for the period. The Company does not have any equity instruments that are dilutive, except for employee stock-based awards.

The table below shows the reconciliation of the number of shares used in the computation of basic and diluted earnings per share:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014

Weighted average number of shares used in computation of basic earnings per share		49,023		45,690		48,388		45,594
Add:
Additional shares from the assumed exercise of employee stock options		2,090		412		1,626		323

Weighted average number of shares used in computation of diluted earnings per share		51,113		46,102		50,014		45,917

The number of stock-based awards that could potentially dilute future earnings per share and that were not included in the computation of diluted earnings per share because to do so would have been anti-dilutive was 341,946 and 3,344,331 for the three months ended September 30, 2015 and 2014, respectively, and 600,169 and 3,257,456 for the nine months ended September 30, 2015 and 2014, respectively.

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

NOTE 9 — BUSINESS SEGMENTS

The Company has two reporting segments: the Electricity segment and the Product segment. These segments are managed and reported separately as each offers different products and serves different markets. The Electricity segment is engaged in the sale of electricity from the Company’s power plants pursuant to PPAs. The Product segment is engaged in the manufacture, including design and development, of turbines and power units for the supply of electrical energy and in the associated construction of power plants utilizing the power units manufactured by the Company to supply energy from geothermal fields and other alternative energy sources. Transfer prices between the operating segments are determined based on current market values or cost plus markup of the seller’s business segment.

Summarized financial information concerning the Company’s reportable segments is shown in the following tables:

	Electricity		Product		Consolidated
	(Dollars in thousands)
Three Months Ended September 30, 2015:
Net revenue from external customers	$	97,245	$	65,607	$	162,852
Intersegment revenue		—		10,657		10,657
Operating income (loss)		28,346		18,133		46,479
Segment assets at period end *		2,103,754		182,579		2,286,333
* Including unconsolidated investments		—		—		—

Three Months Ended September 30, 2014:
Net revenue from external customers	$	102,506	$	37,736	$	140,242
Intersegment revenue		—		7,244		7,244
Operating income (loss)		32,411		11,377		43,788
Segment assets at period end *		2,083,715		88,198		2,171,913
* Including unconsolidated investments		1,339		—		1,339

Nine Months Ended September 30, 2015:
Net revenue from external customers	$	278,124	$	145,446	$	423,570
Intersegment revenue		—		41,314		41,314
Operating income (loss)		73,220		41,753		114,973
Segment assets at period end *		2,103,754		182,579		2,286,333
* Including unconsolidated investments		—		—		—

Nine Months Ended September 30, 2014:
Net revenue from external customers	$	289,015	$	121,266	$	410,281
Intersegment revenue		—		43,580		43,580
Operating income (loss)		72,850		35,839		108,689
Segment assets at period end *		2,083,715		88,198		2,171,913
* Including unconsolidated investments		1,339		—		1,339

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Reconciling information between reportable segments and the Company’s consolidated totals is shown in the following table:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014

Revenue:
Total segment revenue	$	162,852		$	140,242		$	423,570		$	410,281
Intersegment revenue		10,658			7,244			41,314			43,580
Elimination of intersegment revenue		(10,658	)		(7,244	)		(41,314	)		(43,580	)
Total consolidated revenue	$	162,852		$	140,242		$	423,570		$	410,281

Operating income:
Operating income	$	46,479		$	43,788		$	114,973		$	108,689
Interest income		53			35			106			236
Interest expense, net		(17,748	)		(22,494	)		(54,435	)		(65,084	)
Foreign currency translation and transaction gains (losses)		1,296			(2,946	)		(641	)		(3,639	)
Income attributable to sale of equity interest		8,634			5,487			18,917			18,334
Gain from sale of property, plant and equipment		—			—			—			7,628
Other non-operating income (expense), net		(131	)		243			(1,523	)		649
Total consolidated income before income taxes and equity in income of investees	$	38,583		$	24,113		$	77,397		$	66,813

NOTE 10 — COMMITMENTS AND CONTINGENCIES

●

Jon Olson and Hilary Wilt, together with Puna Pono Alliance, an unincorporated association, filed suit on February 17, 2015, in the Third Circuit Court for the State of Hawaii, requesting declaratory and injunctive relief requiring that Puna Geothermal Venture (“PGV”) conform to an ordinance that the plaintiffs allege will prohibit PGV from engaging in night drilling operations at its KS-16 well site. On May 17, 2015, the original filing was amended by a second amended complaint, adding the county of Hawaii and the State of Hawaii Department of Land and Natural Resources as defendants to the case. PGV believes that the allegations have no merit, and will continue to defend itself vigorously.

●

On July 8, 2014, Global Community Monitor, LiUNA, and two residents of Bishop, California filed a complaint in the United States District Court for the Eastern District of California, alleging that Mammoth Pacific, L.P., the Company and Ormat Nevada are operating three geothermal generating plants in Mammoth Lakes, California (MP-1, MP-II and PLES-I) in violation of the federal Clean Air Act (“CAA”) and Great Basin Unified Air Pollution Control District rules. On June 26, 2015, the United States District Court for the Eastern District of California rejected many of the parties' initial arguments. On October 14, 2015, the court denied the defendants’ motion to dismiss the plaintiffs’ sole remaining claim. The discovery stage will now commence. The Company believes that the allegations of the lawsuit have no merit, and will continue to defend itself vigorously.

●

On April 5, 2012, the International Brotherhood of Electrical Workers Local 1260 (“Union”) filed a petition with the National Labor Relations Board (“NLRB”) seeking to organize the operations and maintenance employees at the Puna Project. PGV lost the union election by a slim margin in May 2012. The election results and PGV’s obligation to negotiate with the Union were appealed to the United States Court of Appeals for the Ninth Circuit, but were remanded back to the NLRB after the Supreme Court of the United States’ decision in NLRB v. Noel Canning, 573 U.S., 134 S.Ct. 2550 (2014). On November 26, 2014, the NLRB found that a certification of representative should be issued. In January 2015, the parties submitted a briefing to the NLRB as to whether summary judgment is appropriate. On June 26, 2015, the Board rejected PGV's arguments and ordered PGV to recognize the Union. On June 30, 2015, PGV appealed the NLRB decision to the United States Court of Appeals for the DC Circuit. The NLRB also filed a complaint and requested a hearing on December 8, 2015 to bring unfair labor practice allegations before an administrative law judge even though the charges turn in large part on the disposition of the appeal. The Company believes that it has valid defenses under law.

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

●

In January 2014, Ormat learned that two former employees filed a "qui tam" complaint seeking damages, penalties and other relief, alleging that the Company and certain of its subsidiaries (collectively, the "Ormat Parties"), submitted fraudulent applications and certifications to obtain grants for the Puna and North Brawley projects. The United States Department of Justice declined to intervene. The complaint, which is pending before the United States District Court for the District of Nevada, has entered the discovery stage. On July 7, 2015, the Court issued a protective order stipulating limitations against the relators for the benefit of the Ormat Parties, to ensure the protection of confidentiality for sensitive Ormat Parties’ documents. The Ormat Parties believe that the allegations of the lawsuit have no merit, and will continue to defend themselves vigorously.

●

On August 14, 2015, a former local sales representative in Chile, Aquavant, S.A., filed a preliminary motion with the 18th Civil Court of Santiago, requesting the production of documents relating to the Company’s activities in Chile. The motion alleges, based on the theory of unjust enrichment, that the Ormat Parties should pay agency fees to the plaintiffs in connection with the EPC contract entered into with Enel Green Power and/or Empresa Nacional del Petroleo, and/or other activities in Chile. The preliminary motion was denied by the 18th Civil Court. Plaintiffs refiled the motion in substantively similar form before the 11th Civil Court of Appeals in Santiago. The 11th Civil Court granted the motion, and has issued an order for Ormat to produce certain documents. Defendants subsequently filed a motion to dismiss the document production order, which was denied on October 6, 2015. The Ormat Parties believe that they have valid defenses under law.

●

In addition, from time to time, the Company is named as a party to various other lawsuits, claims and other legal and regulatory proceedings that arise in the ordinary course of our business. These actions typically seek, among other things, compensation for alleged personal injury, breach of contract, property damage, punitive damages, civil penalties or other losses, or injunctive or declaratory relief. With respect to such lawsuits, claims and proceedings, the Company accrues reserves when a loss is probable and the amount of such loss can be reasonably estimated. It is the opinion of the Company’s management that the outcome of these proceedings, individually and collectively, will not be material to the Company’s consolidated financial statements as a whole.

NOTE 11 — INCOME TAXES

Income tax benefit for the nine months ended September 30, 2015 includes a tax benefit of a $49.4 million deferred tax asset relating to the release of the valuation allowance for the additional 50% investment deduction for our Olkaria 3 power plant in Kenya based on amendments to the Kenya Income Tax Act that came into effect on September 11, 2015 and which extended the period to utilize such investment deduction from five years to ten years. The Company’s effective tax rate for the nine months ended September 30, 2015, excluding the income tax benefit of $49.4 million, and 2014 was 29.3% and 26.5%, respectively. The effective tax rate, excluding the income tax benefit of $49.4 million, differs from the federal statutory rate of 35% for the nine months ended September 30, 2015 due to: (i) a full valuation allowance against the Company’s U.S. deferred tax assets in respect of NOL carryforwards and unutilized tax credits (see below), (ii) lower tax rates in Israel; and (iii) a tax credit and tax exemption related to the Company’s subsidiaries in Guatemala. The effect of the tax credit and tax exemption for the three months ended September 30, 2015 and 2014 was $602,000 and $895,000, respectively, and for the nine months ended September 30, 2015 and 2014 was $2,628,000 and $2,921,000, respectively.

At December 31, 2014, the Company had U.S. federal NOL carryforwards of approximately $280.2 million and state NOL carryforwards of approximately $216.5 million, with a full valuation allowance available to reduce future taxable income, which expire between 2021 and 2034 for federal NOLs and between 2014 and 2034 for state NOLs. The Company’s investment tax credits (“ITCs”) in the amount of $0.7 million at December 31, 2014 are available for a 20-year period and expire between 2022 and 2024. Production tax credits (“PTCs”) in the amount of $71.4 million at December 31, 2014 are available for a 20-year period and expire between 2026 and 2034.

Realization of the deferred tax assets and tax credits is dependent on generating sufficient taxable income in appropriate jurisdictions prior to expiration of the NOL carryforwards and tax credits. The most significant factor considered with respect to the ability of the Company to realize these deferred tax assets is the Company’s U.S. cumulative results over the past three years, which made it difficult to support a conclusion that expected taxable income from future operations justifies recognition of deferred tax assets. Based on the results, a valuation allowance in the amount of $111.3 million and $114.8 million was recorded against the U.S. deferred tax assets as of December 31, 2014 and 2013, respectively as, at this point in time, it is more likely than not that the deferred tax assets will not be realized except for the Northleaf transaction as more fully described below.

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

As more fully described in Note 1 (under the heading “Northleaf Transaction”), the Company entered into a significant transaction for the partial sale of certain assets which resulted in a taxable gain in the U.S., for which the Company expects to utilize a portion of its NOL and tax credit carryforwards to fully offset the tax impact of the gain. In 2015 or in future years, if sufficient additional evidence of the Company’s ability to generate future taxable income is established, the Company may be required to reduce or fully release the valuation allowance, resulting in income tax benefits in its consolidated statement of operations.

The total amount of undistributed earnings of foreign subsidiaries for income tax purposes was approximately $75.9 million at December 31, 2014. It is the Company’s intention to reinvest undistributed earnings of its foreign subsidiaries and thereby indefinitely postpone their remittance. Accordingly, no provision has been made for foreign withholding taxes or U.S. income taxes which may become payable if undistributed earnings of foreign subsidiaries were paid as dividends to the Company. The additional taxes on that portion of undistributed earnings which is available for dividends are not practicably determinable.

The Company believes that based on its plans to increase operations outside of the U.S., the cash generated from the Company’s operations outside of the U.S. will be reinvested outside of the U.S. In addition, the Company’s U.S. sources of cash and liquidity are sufficient to meet its needs in the U.S. and, accordingly, the Company does not currently plan to repatriate the funds it has designated as being permanently invested outside the U.S. If the Company changes its plans, it may be required to accrue and pay U.S. taxes to repatriate these funds.

A reconciliation of the beginning and ending amounts of unrecognized tax benefits is as follows:

	Nine Months Ended September 30,
	2015			2014
	(Dollars in thousands)
Balance at beginning of year	$	7,511		$	4,950
Additions based on tax positions taken in prior years		43			93
Additions based on tax positions taken in the current year		825			563
Reduction based on tax positions taken in prior years		(1,267	)		—
Balance at end of year	$	7,112		$	5,606

NOTE 12 — SUBSEQUENT EVENTS

Term loan prepayment

In October 2015, the Company prepaid in full a term loan with a group of financial institutions in accordance with the loan’s prepayment provisions. The aggregate outstanding principal amount of the term loan was $6 million as of September 30, 2015 and the total prepayment amount was $6.2 million comprising principal and interest.

Cash dividend

On November 3, 2015, the Company’s Board of Directors declared, approved and authorized payment of a quarterly dividend of $2.9 million ($0.06 per share) to all holders of the Company’s issued and outstanding shares of common stock on November 18, 2015, payable on December 2, 2015.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Cautionary Note Regarding Forward-Looking Statements

This quarterly report on Form 10-Q includes “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical facts, included in this quarterly report that address activities, events or developments that we expect or anticipate will or may occur in the future, including such matters as our projections of annual revenue, expenses and debt service coverage with respect to our debt securities, future capital expenditures, business strategy, competitive strengths, goals, development or operation of generation assets, market and industry developments and the growth of our business and operations, are forward-looking statements. When used in this quarterly report on Form 10-Q, the words “may”, “will”, “could”, “should”, “expects”, “plans”, “anticipates”, “believes”, “estimates”, “predicts”, “projects”, “potential”, or “contemplate” or the negative of these terms or other comparable terminology are intended to identify forward-looking statements, although not all forward-looking statements contain such words or expressions. The forward-looking statements in this quarterly report are primarily located in the material set forth under the headings “Management’s Discussion and Analysis of Financial Condition and Results of Operations”, “Risk Factors”, and “Notes to Condensed Consolidated Financial Statements”, but are found in other locations as well. These forward-looking statements generally relate to our plans, objectives and expectations for future operations and are based upon management’s current estimates and projections of future results or trends. Although we believe that our plans and objectives reflected in or suggested by these forward-looking statements are reasonable, we may not achieve these plans or objectives. You should read this quarterly report on Form 10-Q completely and with the understanding that actual future results and developments may be materially different from what we expect due to a number of risks and uncertainties, many of which are beyond our control.

Specific factors that might cause actual results to differ from our expectations include, but are not limited to:

●

significant considerations, risks and uncertainties discussed in this quarterly report;

●

geothermal resource risk (such as the heat content, useful life and geological formation of the reservoir);

●

operating risks, including equipment failures and the amounts and timing of revenue and expenses;

●

financial market conditions and the results of financing efforts;

●

the impact of fluctuations in oil and natural gas prices on the energy price component under certain of our power purchase agreements (PPAs);

●

risks and uncertainties with respect to our ability to implement any new or recently announced business goals or initiatives in segments of the clean energy industry or new or additional geographic focus areas;

●

environmental constraints on operations and environmental liabilities arising out of past or present operations, including the risk that we may not have, and in the future may be unable to procure, any necessary permits or other environmental authorizations;

●

construction or other project delays or cancellations;

●

political, legal, regulatory, governmental, administrative and economic conditions and developments in the United States and other countries in which we operate;

●

the enforceability of long-term PPAs for our power plants;

●

contract counterparty risk;

●

weather and other natural phenomena including earthquakes, volcanic eruption, drought that may cause a shortage of cooling water in some of our assets and other natural disasters;

●

the impact of recent and future federal, state and local regulatory proceedings and changes, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, public policies and government incentives that support renewable energy and enhance the economic feasibility of our projects at the federal and state level in the United States and elsewhere, and carbon-related legislation;

●

changes in environmental and other laws and regulations to which our company is subject, as well as changes in the application of existing laws and regulations;

●

current and future litigation;

●

our ability to successfully identify, integrate and complete acquisitions, including risks arising in connection with the acquisition of our former parent company, Ormat Industries.

●

competition from other geothermal energy projects and new geothermal energy projects developed in the future, and from alternative electricity producing technologies;

●

market or business conditions and fluctuations in demand for energy or capacity in the markets in which we operate;

●

the direct or indirect impact on our company’s business of various forms of hostilities including the threat or occurrence of war, terrorist incidents or cyber-attacks or responses to such threatened or actual incidents or attacks, including the effect on the availability of and premiums on insurance;

●

development and construction of solar photovoltaic (Solar PV) projects, if any, may not materialize as planned;

●

the effect of and changes in current and future land use and zoning regulations, residential, commercial and industrial development and urbanization in the areas in which we operate;

●

the risk factors set forth in our Annual Report on Form 10-K for the year ended December 31, 2014 and any update contained herein and other risks and uncertainties detailed from time to time in our filings with the Securities and Exchange Commission; and

●

other uncertainties which are difficult to predict or beyond our control and the risk that we may incorrectly analyze these risks and uncertainties or that the strategies we develop to address them may be unsuccessful.

Investors are cautioned that these forward-looking statements are inherently uncertain. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results or outcomes may vary materially from those described herein. Other than as required by law, we undertake no obligation to update forward-looking statements even though our situation may change in the future. Given these risks and uncertainties, readers are cautioned not to place undue reliance on such forward-looking statements.

The following discussion and analysis of our financial condition and results of operations should be read together with our condensed consolidated financial statements and related notes included elsewhere in this report and the “Risk Factors” section of our Annual Report on Form 10-K for the year ended December 31, 2014 and any updates contained herein as well as those set forth in our reports and other filings made with the SEC.

General

Overview

We are a leading vertically integrated company, engaged primarily in the geothermal and recovered energy power business. With the objective of becoming a leading global provider of renewable energy, we are focused on several key initiatives, which directly align with our new strategic plan, as described below.

We design, develop, build, sell, own, and operate clean, environmentally friendly geothermal and recovered energy-based power plants, usually using equipment that we design and manufacture.

Our geothermal power plants include both power plants that we have built and power plants that we have acquired, while we have built all of our recovered energy-based plants. We currently conduct our business activities in the following two business segments:

●

The Electricity segment — in this segment, we develop, build, own and operate geothermal and recovered energy-based power plants in the United States and geothermal power plants in other countries around the world, and sell the electricity they generate; and

●

The Product segment — in this segment we design, manufacture and sell equipment for geothermal and recovered energy-based electricity generation, remote power units and other power generating units and provide services relating to the engineering, procurement, construction, operation and maintenance of geothermal and recovered energy-based power plants.

Both our Electricity segment and Product segment operations are conducted in the United States and rest of the world. Our current generating portfolio includes geothermal plants in the United States, Guatemala and Kenya, as well as recovered energy generation plants in the United States.

For the nine months ended September 30, 2015, our total revenue increased by 3.2% (from $410.3 million to $423.6 million) over the corresponding period in 2014.

For the nine months ended September 30, 2015, Electricity segment revenue was $278.1 million, compared to $289.0 million for the nine months ended September 30, 2014, a decrease of 3.8% from the prior year period. Product segment revenue for the nine months ended September 30, 2015 was $145.4 million, compared to $121.3 million during the nine months ended September 30, 2014, an increase of 19.9% from the prior year period.

During the nine months ended September 30, 2015 and 2014, our consolidated power plants generated 3,513,803 million megawatt hours (MWh) and 3,281,785 MWh, respectively, an increase of 7.1%.

For the nine months ended September 30, 2015, our Electricity segment revenue represented approximately 65.7% of our total revenue, while our Product segment revenue represented approximately 34.3% of our total revenue. For the nine months ended September 30, 2014, our Electricity segment revenue represented approximately 70.4% of our total revenue, while our Product segment revenue represented approximately 29.6% of our total revenue.

For the nine months ended September 30, 2015, approximately 75.0% of our Electricity segment revenue was derived from PPAs with fixed energy rates which are not affected by fluctuations in energy commodity prices. We have variable price PPAs in California and Hawaii, which provide for payments based on the local utilities’ avoided cost, which is the incremental cost that the power purchaser avoids by not having to generate such electrical energy itself or purchase it from others, as follows:

●

the energy rates under the PPAs in California for each of the Ormesa complex, the Heber 1 and Heber 2 power plants in the Heber complex and the G2 power plant in the Mammoth complex change primarily based on fluctuations in natural gas prices; and

●

the prices paid for electricity pursuant to the 25 MW PPA for the Puna complex in Hawaii change primarily due to variations in the price of oil.

We reduced our economic exposure to fluctuations in the price of oil until December 31, 2014 and in the price of natural gas until March 31, 2015 and from June 1, 2015 until December 31, 2015, by entering into derivatives transactions. In the first nine months of 2015, we recorded a $0.7 million gain in Electricity revenue related to these transactions.

To comply with obligations under their respective PPAs, certain of our project subsidiaries are structured as special purpose, bankruptcy remote entities and their assets and liabilities are ring-fenced. Such assets are not generally available to pay our debt other than debt at the respective project subsidiary level. However, these project subsidiaries are allowed to pay dividends and make distributions of cash flows generated by their assets to us subject in some cases to restrictions in debt instruments, as described below.

Electricity segment revenue is also subject to seasonal variations and can be affected by higher-than-average ambient temperatures, as described below under “Seasonality”. In addition, the revenue we report in our financial statements may show more variation due to our increased use of derivatives in connection with our variable price PPAs and the accounting principles associated with our use of those derivatives.

Revenue attributable to our Product segment is based on the sale of equipment, engineering, procurement and construction (EPC) contracts and the provision of various services to our customers. Product segment revenue may vary from period to period because of the timing of our receipt of purchase orders and the progress of our equipment manufacturing and execution of the relevant project.

Our management assesses the performance of our two operating segments differently. In the case of our Electricity segment, when making decisions about potential acquisitions or the development of new projects, management typically focuses on the internal rate of return of the relevant investment, technical and geological matters and other business considerations. Management evaluates our operating power plants based on revenue and expenses, and our projects that are under development based on costs attributable to each such project. Management evaluates the performance of our Product segment based on the timely delivery of our products, performance quality of our products, revenue and expenses and costs actually incurred to complete customer orders compared to the costs originally budgeted for such orders.

Recent Developments

The most significant developments in our company and business since January 1, 2015 are described below:

●

We have refined and started to implement a number of the elements of the new multi-year strategic plan which we announced on March 31, 2015, following an in-depth review of the plan by our Board during meetings in August. We expect the plan to evolve over time in response to market conditions and other factors. At this time however, we expect that our primary focus will be as follows:

Expand our geographical reach. While we continue to evaluate opportunities worldwide, we currently see Mexico, Chile and Indonesia as very attractive markets for us. We are actively looking at ways to expand our presence in those countries. In addition, we are looking to expand and accelerate growth through aquisition activities globally.

Expand into new technologies. We ultimately hope to be able to leverage our technological capabilities over a variety of renewable energy platforms, including solar power generation and energy storage. Initially, however, we expect that our focus will be on expanding our core geothermal competencies, such as expanding into more high temperature geothermal generation equipment and facilities. For example, we recently announced a new collaboration with Toshiba described below, which we anticipate may facilitate joint development of geothermal systems consisting of Ormat’s binary system and Toshiba’s flash system, among other things. We may acquire companies with technological capabilities we do not currently have, or develop new technology ourselves, where we can effectively leverage our expertise to implement this part of our strategic plan.

Expand our customer base. We are evaluating a number of strategies for expanding our customer base. In the near term, however, we expect that a majority of our revenue will continue to be generated as it now is, with our traditional electrical utility customer base for the Electricity segment and our on-going business development efforts for new customers for our Product segment.

While we believe that long-term growth can be realized through our transformational efforts over time, there is no assurance if and when we will meet our objective to become a leading global provider of renewable energy or that such efforts will result in long-term growth. To be clear, we see these new initiatives as incremental measures to enhance shareholder values. While we implement the plan, we expect to continue, and expand, both through organic growth, acquisitions, and other measures, our current business lines both in the Electricity and Product segments.

●

On October 14, 2015, we announced that we signed a strategic collaboration agreement (SCA) with Toshiba Corporation to develop strategic opportunities for collaboration in the areas of geothermal power generation systems and related equipment. Under the terms of the agreement, Ormat and Toshiba will explore and develop strategic opportunities that will enable them to offer potential customers a more competitive solution for comprehensive supplies and services related to geothermal development, from resource assessment, field development and power plant EPC to power plant operation.

	●	On September 11, 2015, Kenya's Income Tax Act was amended pursuant to certain provisions of the recently adopted Finance Act, 2015. Among other matters, these amendments retain the enhanced investment deduction of 150% under Section 17B of the Income Tax Act, extend the period for deduction of tax losses from five years to ten years under Sections 15(4) and 15(5) of the Income Tax Act, and amend the effective date from January 1, 2016 to January 1, 2015 under Sections 15(4) and 15(5) of the Income Tax Act. Previously, the Company had a valuation allowance for the additional 50% investment deduction reducing its deferred tax asset in Kenya as the utilization of the related tax losses was not probable within the original five year carryforward period. As a result of the change in legislation and the expected continued profitability during the extended carryforward period, the Company expects that it will be able to fully utilize the carryforward tax losses within the ten year period and as such released the valuation allowance in Kenya resulting in a $49.4 million tax benefit in the three month period ended September 30, 2015.

	●	On September 17, 2015, the Don A. Campbell geothermal power plant located in Mineral County, Nevada began commercial operation 10 months after the project broke ground and less than two years after we commenced firm operation of the first phase in December 2013. The phase II power plant is expected to generate 19 MW (net) on a yearly average basis and we sell the electricity under a 20-year PPA with the Southern California Public Power Authority (SCPPA). SCPPA resells the entire output of this plant to the Los Angeles Department of Water and Power (LADWP).

●

On July 31, 2015, one of our indirect wholly-owned subsidiaries, Ortitlàn, Limitada, obtained a 12-year secured term loan in the principal amount of $42.0 million for the 20 MW Amatitlàn power plant in Guatemala. Under the credit agreement with Banco Industrial S.A. and Westrust Bank (International) Limited, we have the flexibility to expand the Amatitlàn power plant with financing to be provided either via equity, additional debt from Banco Industrial S.A. or from other lenders, subject to certain limitations on expansion financing in the credit agreement.

●

On June 8, 2015, we repurchased $30.6 million aggregate principal amount of our OFC Senior Secured Notes from certain OFC noteholders. As a result of the repurchase, we recognized a loss of $1.7 million, including amortization of deferred financing cost of $0.5 million, which is included in other non-operating income (expense), net in the consolidated statements of operations and comprehensive income for the nine months ended September 30, 2015.

●

On May 7, 2015, we announced that we were selected through a competitive bid process and signed a $98.8 million EPC contract for a geothermal project in Chile. Under the terms of the EPC contract we will provide two air-cooled OECs for a high enthalpy reservoir. The project is scheduled to be completed by mid-2017.

●

On April 30, 2015, we announced the closing of the equity transaction with Northleaf Geothermal Holdings, LLC. Pursuant to the purchase agreement, which the parties executed on February 5, 2015, Northleaf acquired a 36.75% equity interest in ORPD LLC, a newly established Ormat holding company subsidiary, for a purchase price of $162.3 million. The joint venture includes Ormat's Puna geothermal power plant in Hawaii, the Don A. Campbell geothermal power plant in Nevada, and nine power plant units across three recovered energy generation assets known as OREG 1, OREG 2, and OREG 3. The purchase price implies an aggregate transaction value of approximately $442.0 million. The actual purchase price and the percentage interest acquired by Northleaf were adjusted based on the Canadian Dollar/US Dollar exchange rate and was affected by the devaluation of the Canadian Dollar.

●

On March 24, 2015, we announced that we entered into a 20-year PPA with Southern California Public Power Authority (SCPPA) for interstate delivery of electricity from the second phase of the Don A. Campbell project in Mineral County, Nevada. Under the terms of the PPA, the second phase of the Don A. Campbell project will receive a rate of $81.25 per megawatt hour with no annual escalation. The project began commercial operation on September 17, 2015. Northleaf Capital Partners, Ormat's new joint venture investor, will purchase an approximately 36.75% interest in the project which will be added to the existing ORPD projects portfolio once the project is completed and commissioned.

●

On February 12, 2015, we announced the completion of the share exchange transaction with Ormat Industries, our then-parent company, in which we acquired Ormat Industries through the issuance of 30,203,186 new shares of our common stock to Ormat Industries' shareholders in exchange for all of the outstanding ordinary shares of Ormat Industries, reflecting an exchange ratio of 0.2592 shares of our common stock for each ordinary share of Ormat Industries. One of the key consequences of this transaction was that the number of shares of our common stock held by non-affiliated, “public” shareholders was increased from approximately 40% to approximately 76% of our total shares outstanding, which we believe should help elevate trading volume and may increase equity coverage.

As previously disclosed, we entered into several agreements in connection with the share exchange, including the following:

●

Voting agreements with the then principal shareholders of Ormat Industries, FIMI ENRG, Limited Partnership and FIMI ENRG, L.P. (together FIMI) and Bronicki Investments Ltd. (Bronicki), which currently beneficially own approximately 14.91% and 8.26% of our outstanding shares, respectively. Under these voting agreements, FIMI and Bronicki agreed, among other things, to comply in all respects with the Israeli Tax Ruling applicable to the Ormat Industries shareholders.

●

Voting neutralization agreements with FIMI and Bronicki, whereby FIMI and Bronicki agreed, among other things, to certain restrictions on their shares of our common stock. Among other things, these voting neutralization agreements:

require these shareholders to vote all voting securities owned by FIMI and Bronicki and their respective affiliates in excess of 16% and 9%, respectively, of the combined voting power of our shares in proportion to votes cast by the other holders of our voting securities at any time any action is to be taken by our stockholders;

prohibit the acquisition of our voting securities by FIMI and Bronicki and their respective affiliates if after giving effect to any such acquisition FIMI and Bronicki and their respective affiliates would beneficially own voting securities representing in the aggregate more than 20% and 12%, respectively, of the combined voting power of our shares;

prohibit, prior to January 1, 2017 and subject to certain exceptions, the sale of more than 10% of our voting securities owned in the aggregate by FIMI and Bronicki;

allow, following January 1, 2017, the sale of our voting securities owned by FIMI and Bronicki only if they are not acting in concert to sell or, if they are, only with 20 days’ prior written notice to us, subject to certain exceptions for public sales and mergers and acquisitions transactions; and

prohibit FIMI and Bronicki from renewing their shareholder rights agreement beyond its current expiration date of May 22, 2017.

●

A registration rights agreement whereby FIMI and Bronicki may, subject to certain limitations, require us to prepare and file with the SEC a registration statement to register a public offering of the shares of our common stock held by them, on customary terms and conditions set forth in the agreement.

●

On February 5, 2015, the Tel Aviv Stock Exchange (the TASE) approved the listing of our common stock on the TASE beginning on February 10, 2015 and our common stock is now listed on both the NYSE and the TASE. We are still subject to the rules and regulations of the NYSE and of the SEC. Under the local regime for dual listing, U.S. listed companies, such as us, may dual-list on the TASE without additional regulatory requirements, using the same periodic reports, financial and other relevant disclosure information that they submit to the SEC and NYSE. However, as a result of the local regime requirements, we have undertaken, as part of the TASE listing, not to issue preferred stock for as long as our shares of common stock are listed on the TASE.

●

On February 4, 2015, we announced that the second phase of the McGinness Hills geothermal power plant located in Lander County, Nevada began commercial operation. Since February 1, 2015, the complex sells electricity under an amended PPA with NV Energy at a new energy rate of $85.58/MWh with one percent annual escalator through December 2032. Following resource confirmation and excellent performance of the first phase of McGinness Hills, which had been operational since June 2012, the second phase initiated construction in March 2014. The second phase of the McGinness Hills plant came on line on February 1, 2015 and brought the complex’s total capacity to approximately 72MW.

Trends and Uncertainties

The geothermal industry in the United States has historically experienced significant growth followed by a consolidation of owners and operators of geothermal power plants. Since 2001, there has been increased demand for energy generated from geothermal resources in the United States as costs for electricity generated from geothermal resources have become more competitive. Much of this is attributable to legislative and regulatory requirements and incentives, such as state renewable portfolio standards and federal tax credits. The American Recovery and Reinvestment Act of 2009 (ARRA) further encourages the use of geothermal energy through production tax credits (PTCs) or investment tax credits (ITCs) as well as cash grants (which are discussed in more detail in the section entitled “Government Grants and Tax Benefits” below), although the ARRA benefits will expire absent new legislation that extends the deadline. In response, the geothermal industry in the United States has seen a wave of new entrants and, over the last several years, consolidation involving smaller developers. We believe that future demand for energy generated from geothermal and other renewable resources in the United States will be driven by further commitment and implementation of renewable portfolio standards as well as the introduction of additional tax incentives and greenhouse gas initiatives. The trends that from time to time impact our operations are subject to market cycles.

Although other trends, factors and uncertainties may impact our operations and financial condition, including many that we do not or cannot foresee, we believe that our results of operations and financial condition for the foreseeable future will be primarily affected by the following trends, factors and uncertainties:

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We expect to continue to generate the majority of our revenue from our Electricity segment through the sale of electricity from our power plants. All of our current revenue from the sale of electricity are derived from payments under long-term PPAs related to fully-contracted power plants. We also intend to continue to pursue opportunities, as they arise in our recovered energy business, in the Solar PV sector and in other forms of clean energy. In addition, pursuant to our strategic plan, we are pursuing PPAs with enterprises that will increase our potential customer base.

●

As noted in "Recent Developments" we have adopted a new strategic plan for growth of our company, in terms of geographic scope, customer base, and technology platforms covered by our product and service offerings, with a view to driving increased net income from operations. Under this plan, we will continue to focus on organic growth and increasing operational efficiency of our existing business lines. However, we also plan to actively pursue acquisition opportunities, both in our existing business lines and the solar power generation and energy storage businesses targeted as part of the plan. We will face a number of challenges and uncertainties in implementing this plan, and we may revise elements of the plan in response to market conditions or other factors as we move forward with the plan.

	●	The continued awareness of climate change may result in significant changes in the business and regulatory environments, which may create business opportunities for us. For example in June 2013 President Barack Obama announced a new national climate action plan, directing the EPA to complete new carbon dioxide pollution standards for both new and existing power plants. The EPA published rules relating to carbon pollution standards for certain existing, new, modified and reconstructed power plants on October 23, 2015. Under the Clean Power Plan that applies to certain existing power plants, states are to prepare –plans to meet the EPA’s goal of cutting carbon emission from the power sector by 32% below 2005 levels nationwide by 2030. In addition, several states and regions are already addressing legislation to reduce greenhouse gas emissions. For example, California’s state climate change law, AB 32, which was signed into law in September 2006, regulates most sources of greenhouse gas emissions and aims to reduce greenhouse gas emissions to 1990 levels by 2020. On October 20, 2011 the California Air Resources Board adopted cap-and-trade regulations to reduce California’s greenhouse gas emissions under AB 32. On April 29, 2015 California’s Governor Brown issued an Executive Order setting an interim target of 40% below 1990 levels by 2030. In addition to California, twenty U.S. states have set greenhouse gas emissions reduction targets. Regional initiatives are also being developed to reduce greenhouse gas emissions and develop trading systems for renewable energy credits. In the United States, approximately 40 states have adopted renewable portfolio standards (RPS), renewable portfolio goals, or similar laws requiring or encouraging electric utilities in such states to generate or buy a certain percentage of their electricity from renewable energy sources or recovered heat sources. On April 12, 2011, the California Senate Bill X1-2 (SBX1-2) was signed into law, and increased California’s RPS to 33% by December 31, 2020. In October 2015, California Governor signed SB 350. Under the new bill the California’s RPS have been increased to 50% by 2030. In June 2015, Hawaii Governor has signed a bill that sets the state’s renewable energy goal at 100% by 2045.These bills may facilitate additional sales and trading options when negotiating PPAs and selling electricity from our projects.

	●	In June 2013, the Nevada state legislature passed three bills that were signed by Nevada’s Governor and were expected to support additional renewable energy development in the state. Senate Bill (SB) No. 123 from 2013 required the retirement or elimination of not less than 800 MW of coal-fired electric generating capacity on or before December 31, 2019 and the construction or acquisition of, or contracting for, 550 MW of anticipated natural gas resources and 350 MW of electric generating capacity from renewable energy facilities. The provisions of SB 123 have been fulfilled in part and indefinitely suspended in part:

Three new solar PV projects totaling 215 MW and acquisitions by Nevada Power of 3 existing natural-gas-fired facilities generating about 496 MW of electric power fulfilled most of the SB 123 mandate.

Approximately 135 MW of the SB 123 mandate has not been fulfilled, and the requirement to do that has been indefinitely suspended by new legislation adopted by the Nevada legislature in 2015. That legislation, AB 498, suspended the SB 123 mandate with respect to the portion of the mandate that has not been fulfilled.

Final regulations have been adopted to implement other 2013 Nevada legislation related to renewable portfolio standards (or RPS) in Nevada and the related quantification and qualification of different types of portfolio energy credits that may be used by Nevada utilities to satisfy RPS requirements. These regulations (when fully effective) are expected to align Nevada’s RPS with current RPS standards in other states in the regional WREGIS market, such as by:

eliminating a 2.4 multiplier that previously applied to new solar PV distributed generation,

phasing out (by 2025) Nevada's inclusion of energy efficiency credits which have previously counted for up to 25% of Nevada's RPS and phasing out recognition of the related portfolio energy credits ("PECs") for purposes of Nevada's RPS, and

diminishing the allowance for station usage PECs for geothermal projects under the Nevada RPS.

●

On September 26, 2014, Governor Brown of California signed into law Assembly Bill No. 2363 (AB-2363), which requires the California Public Utilities Commission to adopt, by December 31, 2015, a methodology for determining the costs of integrating eligible renewable energy resources.

●

Outside of the United States, in November 2012 the United States, Brunei, and Indonesia formed the Asia-Pacific comprehensive partnership and President Obama announced the allocation of $6.0 billion for green energy development in Asia. Also, on June 30, 2013, President Obama announced the “Power Africa” initiative pursuant to which the United States will invest $7.0 billion in Sub-Saharan Africa over the following five years, with the aim of doubling access to power. Sub-Saharan Africa includes three countries (Ethiopia, Kenya and Tanzania) that have large geothermal potential as well as operating geothermal power plants. We accelerated our efforts to expand business development activities in those areas by, among other things, participating in new bids. In addition, we expect that a variety of governmental initiatives will create new opportunities for the development of new projects, as well as create additional markets for our products. These initiatives include the award of long-term contracts to independent power generators, the creation of competitive wholesale markets for selling and trading energy, capacity and related energy products and the adoption of programs designed to encourage “clean” renewable and sustainable energy sources.

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In the Electricity segment, we expect intense competition from the solar and wind power generation industry to continue and increase. While we believe the expected demand for renewable energy will be large enough to accommodate increased competition, any such increase and the amount of renewable energy under contract as well as a potential decline in natural gas prices due to increased production which can affect the market price for electricity may contribute to a reduction in electricity prices. Despite increased competition from the solar and wind power generation industry, we believe that base load electricity, such as geothermal-based energy, will continue to be an important source of renewable energy in areas with commercially viable geothermal resources. Also, geothermal power plants can positively impact electrical grid stability and provide valuable ancillary services because of their base load nature. In the geothermal industry, due to reduced competition for geothermal leases, we have experienced a decrease in the upfront fee required to secure geothermal leases.

●

In the Product segment, we experience increased competition from binary power plant equipment suppliers including the major steam turbine manufacturers. While we believe that we have a distinct competitive advantage based on our accumulated experience and current worldwide share of installed binary generation capacity, an increase in competition may impact our ability to secure new purchase orders from potential customers. The increased competition may also lead to a reduction in the prices that we are able to charge for our binary equipment, which in turn may reduce our profitability.

●

The changing natural gas landscape, the resulting effect on natural gas pricing (in either direction) and the corresponding implications for electric utilities and other producers of electricity in terms of planning for and choosing a source of fuel, will affect the pricing under our PPAs that have short run avoided cost pricing, as described below, and may affect the pricing under new PPA’s that we may sign.

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The 38 MW Puna complex has three PPAs, of which the 25 MW PPA has a monthly variable energy rate based on the local utility’s avoided costs. A decrease in the price of oil will result in a decrease in the incremental cost that the power purchaser avoids by not generating its electrical energy needs from oil, which will result in a reduction of the energy rate that we may charge under this PPA. In order to reduce our exposure to oil we signed fixed rate PPAs for the remaining 13 MW.

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Since May 2012, the energy pricing under our PPAs for the Ormesa, Mammoth and Heber complexes (for a total of 161 MW) were variable rate based on short run avoided cost pricing that is impacted by gas prices. However, in 2013, we signed new fixed rate PPAs that reduced our current exposure to short run avoided cost by 18 MW and by an additional 44 MW in 2016. We entered into derivative transactions at a fixed price of $4.95 per MMbtu for the period from January 1, 2015 until March 31, 2015. In May 2015 we entered into a new derivative transaction at a fixed price of $3.00 per MMbtu and reduced our exposure to short run avoided cost in the period from June 1, 2015 until December 31, 2015.

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The viability of a geothermal resource depends on various factors such as the resource temperature, the permeability of the resource (i.e., the ability to get geothermal fluids to the surface) and operational factors relating to the extraction and injection of the geothermal fluids. Such factors, together with the possibility that we may fail to find commercially viable geothermal resources in the future, represent significant uncertainties that we face in connection with our growth expectations.

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As our power plants (including their respective well fields) age, they may require increased maintenance with a resulting decrease in their availability, potentially leading to the imposition of penalties if we are not able to meet the requirements under our PPAs as a result of any decrease in availability.

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Our foreign operations are subject to significant political, hostilities, economic and financial risks, which vary by country. As of the date of this report, those risks include security conditions in Israel, the partial privatization of the electricity sector in Guatemala and the political uncertainty currently prevailing in some of the countries in which we operate, as further described in the “Risk Factors” section of our annual report on Form 10-K for the year ended December 31, 2014. Although we maintain, among other, things political risk insurance for most of our investments in foreign power plants to mitigate these risks, insurance does not provide complete coverage with respect to all such risks.

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The Sarulla 330 MW project was released for construction, and we began to recognize our first product segment revenue in the quarter ended September 30, 2014 under the supply contract we signed with the EPC contractor. Going forward we expect to derive significant revenue from the supply contract. We expect to generate additional income from our 12.75% equity investment in the Sarulla consortium following the commercial operation of the project. The Sarulla project’s future operations may be impacted by various factors which we do not control given our minority position in the consortium, as well as other factors discussed in the “Risk Factors” section of our annual report on Form 10-K for the year ended December 31, 2014.

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FERC is allowed under PURPA to terminate, upon the request of a utility, the obligation of the utility to purchase the output of a Qualifying Facility if FERC finds that there is an accessible competitive market for energy and capacity sales from the Qualifying Facility. The legislation does not affect existing PPAs. We do not expect this modification to the law to affect our U.S. power plants significantly, as all of our current PPAs are long-term. FERC has granted the California investor-owned utilities a waiver of the mandatory purchase obligations from Qualifying Facilities above 20 MW. If the utilities in the regions in which our domestic power plants operate were to be relieved of the mandatory purchase obligation, they would not be required to purchase energy from us upon termination of the existing PPA, which could have an adverse effect on our revenue.

Revenue

We generate our revenue from the sale of electricity from our geothermal and recovered energy-based power plants; the design, manufacture and sale of equipment for electricity generation; and the construction, installation and engineering of power plant equipment.

Revenue attributable to our Electricity segment is derived from the sale of electricity from our power plants pursuant to long-term PPAs. While approximately 75.0% of our Electricity revenue for the nine months ended September 30, 2015 was derived from PPAs with fixed price components, we have variable price PPAs in California and Hawaii. Our 143MW California SO#4 PPAs are subject to the impact of fluctuations in natural gas prices whereas the price paid for electricity pursuant to the 25 MW PPA for the Puna complex in Hawaii is impacted by the price of oil. Accordingly, our revenue from those power plants may fluctuate. In each of 2013 and 2014, we entered into derivative transactions in an attempt to reduce our exposure to fluctuations in the prices of oil from Puna’s PPAs until December 31, 2014 and natural gas from California SO#4 PPAs until March 31, 2015 and from June 1, 2015 until December 31, 2015.

Our Electricity segment revenue is also subject to seasonal variations, as more fully described in “Seasonality” below.

Our PPAs generally provide for energy payments alone, or energy and capacity payments. Generally, capacity payments are payments calculated based on the amount of time that our power plants are available to generate electricity. Some of our PPAs provide for bonus payments in the event that we are able to exceed certain target capacity levels and the potential forfeiture of payments if we fail to meet certain minimum target capacity levels. Energy payments, on the other hand, are payments calculated based on the amount of electrical energy delivered to the relevant power purchaser at a designated delivery point. The rates applicable to such payments are either fixed (subject, in certain cases, to certain adjustments) or are based on the relevant power purchaser’s avoided costs. Our more recent PPAs generally provide for energy payments alone with an obligation to compensate the off-taker for its incremental costs as a result of shortfalls in our supply.

Revenue attributable to our Product segment fluctuates between periods, mainly based on our ability to receive customer orders, the status and timing of such orders, delivery of raw materials and the completion of manufacturing. Larger customer orders for our products are typically the result of our participating in, and winning, tenders or requests for proposals issued by potential customers in connection with projects they are developing. Such projects often take a significant amount of time to design and develop and are subject to various contingencies, such as the customer’s ability to raise the necessary financing for a project. Consequently, we are generally unable to predict the timing of such orders for our products and may not be able to replace existing orders that we have completed with new ones. As a result, revenue from our Product segment fluctuates (sometimes, extensively) from period to period. In both 2013 and 2014, we experienced a significant increase in our Product segment customer orders, which has increased our Product segment backlog.

The following table sets forth a breakdown of our revenue for the periods indicated:

	Revenue (dollars in thousands)								% of Revenue for Period Indicated
	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended September 30,						Nine Months Ended September 30,
	2015		2014		2015		2014		2015			2014			2015			2014
Revenue:
Electricity	$	97,245	$	102,506	$	278,124	$	289,015		59.7	%		73.1	%		65.7	%		70.4	%
Product		65,607		37,736		145,446		121,266		40.3			26.9			34.3			29.6
Total	$	162,852	$	140,242	$	423,570	$	410,281		100	%		100	%		100	%		100	%

The following table sets forth the geographic breakdown of the revenue attributable to our Electricity and Product segments for the periods indicated:

	Revenue (dollars in thousands)								% of Revenue for Period Indicated
	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended September 30,						Nine Months Ended September 30,
	2015		2014		2015		2014		2015			2014			2015			2014
Electricity Segment:
United States	$	68,123	$	72,908	$	192,159	$	202,860		70.1	%		71.1	%		69.1	%		70.2	%
Foreign		29,122		29,598		85,965		86,155		29.9			28.9			30.9			29.8
Total	$	97,245	$	102,506	$	278,124	$	289,015		100	%		100	%		100	%		100	%

Product Segment:
United States	$	3,776	$	-	$	8,876	$	17,000		5.8	%		-	%		6.1	%		14	%
Foreign		61,831		37,736		136,570		104,266		94.2			100			93.9			86.0
Total	$	65,607	$	37,736	$	145,446	$	121,266		100	%		100	%		100	%		100	%

Seasonality

The prices paid for the electricity generated by some of our domestic power plants pursuant to our PPAs are subject to seasonal variations. The prices (mainly for capacity) paid for electricity under the PPAs with Southern California Edison and Pacific Gas & Electric in California for the Heber 1 and 2 power plants in the Heber complex, the Mammoth complex, the Ormesa complex, and the North Brawley power plant are higher in the months of June through September. As a result, we receive, and expect to continue to receive in the future, higher revenue during such months. In the winter, our power plants produce more energy principally due to the lower ambient temperature, which has a favorable impact on the energy component of our Electricity revenue. However, the higher payments payable by Southern California Edison and Pacific Gas & Electric Company in the summer months have a more significant impact on our revenue than that of the higher energy component of our Electricity revenue generally generated in winter due to increased efficiency. As a result, our Electricity revenue is generally slightly higher in the summer than in the winter.

Breakdown of Cost of Revenue

Electricity Segment

The principal cost of revenue attributable to our operating power plants includes operation and maintenance expenses comprised of salaries and related employee benefits, equipment expenses, costs of parts and chemicals, costs related to third-party services, lease expenses, royalties, startup and auxiliary electricity purchases, property taxes, insurance and, for some of our projects, purchases of make-up water for use in our cooling towers and also depreciation and amortization. For our California power plants, as well as power plants in Nevada that sell electricity to California, our principal cost of revenue also includes transmission charges and scheduling charges. Some of these expenses, such as parts, third-party services and major maintenance, are not incurred on a regular basis. This results in fluctuations in our expenses and our results of operations for individual power plants from quarter to quarter. Payments made to government agencies and private entities on account of site leases where plants are located are included in cost of revenue. Royalty payments, included in cost of revenue, are made as compensation for the right to use certain geothermal resources and are paid as a percentage of the revenue derived from the associated geothermal rights. Royalties constituted approximately 4.0% and 4.3% of Electricity segment revenue for the nine months ended September 30, 2015 and September 30, 2014, respectively.

Product Segment

The principal cost of revenue attributable to our Product segment includes materials, salaries and related employee benefits, expenses related to subcontracting activities, and transportation expenses. Sales commissions to sales representatives are included in selling and marketing expenses. Some of the principal expenses attributable to our Product segment, such as a portion of the costs related to labor, utilities and other support services are fixed, while others, such as materials, construction, transportation and sales commissions, are variable and may fluctuate significantly, depending on market conditions. As a result, the cost of revenue attributable to our Product segment, expressed as a percentage of total revenue, fluctuates. Another reason for such fluctuation is that in responding to bids for our products, we price our products and services in relation to existing competition and other prevailing market conditions, which may vary substantially from order to order.

Cash, Cash Equivalents, Marketable Securities and Short-Term Bank Deposit

Our cash and cash equivalents, as of September 30, 2015 increased to $171.5 million from $40.2 million as of December 31, 2014. This increase was principally due to: (i) $123.0 million derived from operating activities during the nine months ended September 30, 2015; (ii) $156.8 million net proceeds derived from the issuance of shares to noncontrolling interest, (iii) $42.0 million of proceeds from the loan for our Amatitlan power plant; (iv) $15.4 million derived from our share exchange transaction with Ormat Industries; and (v) a net change in restricted cash, cash equivalents and marketable securities of $22.7 million. This increase was partially offset by: (i) our use of $117.6 million to fund capital expenditures; (ii) $30.6 million of cash paid to repurchase a portion of our OFC Senior Secured Notes; (iii) net repayment of $40.5 million of long-term debt; (iv) repayment of $20.3 million of our revolving credit lines with commercial banks; (v) $13.9 million cash paid to non-controlling interest; and (vi) $9.8 million cash dividend paid. Our corporate borrowing capacity under committed lines of credit with different commercial banks as of September 30, 2015 was $537.5 million, as described below in “Liquidity and Capital Resources”, of which we have utilized $392.6 million as of September 30, 2015.

Critical Accounting Estimates and Assumptions

A comprehensive discussion of our critical accounting estimates and assumptions is included in the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section in our annual report on Form 10-K for the year ended December 31, 2014.

New Accounting Pronouncements

See Note 2 to our condensed consolidated financial statements set forth in Item 1 of this quarterly report for information regarding new accounting pronouncements.

Results of Operations

Our historical operating results in dollars and as a percentage of total revenue are presented below. A comparison of the different periods described below may be of limited utility primarily as a result of (i) our recent construction or disposition of new power plants and enhancement of acquired power plants; and (ii) fluctuation in revenue from our Product segment.

	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
	(Dollars in thousands, except per share data)						(Dollars in thousands, except per share data)
Statements of Operations Historical Data:
Revenue:
Electricity	$	97,245		$	102,506		$	278,124		$	289,015
Product		65,607			37,736			145,446			121,266
		162,852			140,242			423,570			410,281
Cost of revenues:
Electricity		61,501			61,727			179,604			186,083
Product		42,019			23,040			89,826			75,307
		103,520			84,767			269,430			261,390
Gross margin
Electricity		35,744			40,779			98,520			102,932
Product		23,588			14,696			55,620			45,959
		59,332			55,475			154,140			148,891
Operating expenses:
Research and development expenses		335			250			1,112			395
Selling and marketing expenses		4,383			4,258			12,099			10,853
General and administrative expenses		7,950			7,179			25,597			20,847
Impairment charge		—			—			—			—
Write-off of unsuccessful exploration activities		185			—			359			8,107
Operating income		46,479			43,788			114,973			108,689
Other income (expense):
Interest income		53			35			106			236
Interest expense, net		(17,748	)		(22,494	)		(54,435	)		(65,084	)
Foreign currency translation and transaction gains (losses)		1,296			(2,946	)		(641	)		(3,639	)
Income attributable to sale of tax benefits		8,634			5,487			18,917			18,334
Gain from sale of property, plant and equipment		—			—			—			7,628
Other non-operating income (expense), net		(131	)		243			(1,523	)		649

Income before income taxes and equity in losses of investees		38,583			24,113			77,397			66,813
Income tax (provision) benefit		38,211			(6,444	)		26,696			(17,731	)
Equity in losses of investees, net		(3,133	)		(899	)		(4,892	)		(1,210	)
Net income		73,661			16,770			99,201			47,872
Net income attributable to noncontrolling interest		(1,522	)		(256	)		(2,616	)		(670	)
Net income attributable to the Company's stockholders	$	72,139		$	16,514		$	96,585		$	47,202
Earnings per share attributable to the Company's stockholders:
Basic:
Net income	$	1.47		$	0.36		$	2.00		$	1.04
Diluted:
Net income	$	1.41		$	0.36		$	1.93		$	1.03
Weighted average number of shares used in computation of earnings per share attributable to the Company's stockholders:
Basic		49,023			45,690			48,388			45,594
Diluted		51,113			46,102			50,011			45,917

	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
Statements of Operations Data:
Revenue:
Electricity		59.7	%		73.1	%		65.7	%		70.4	%
Product		40.3			26.9			34.3			29.6
		100.0			100.0			100.0			100.0
Cost of revenues:
Electricity		63.2			60.2			64.6			64.4
Product		64.0			61.1			61.8			62.1
		63.6			60.4			63.6			63.7
Gross margin
Electricity		36.8			39.8			35.4			35.6
Product		36.0			38.9			38.2			37.9
		36.4			39.6			36.4			36.3
Operating expenses:
Research and development expenses		0.2			0.2			0.3			0.1
Selling and marketing expenses		2.7			3.0			2.9			2.6
General and administrative expenses		4.9			5.1			6.0			5.1
Impairment charge		0.0			0.0			0.0			0.0
Write-off of unsuccessful exploration activities		0.1			0.0			0.1			2.0
Operating income		28.5			31.2			27.1			26.5
Other income (expense):
Interest income		0.0			0.0			0.0			0.1
Interest expense, net		(10.9	)		(16.0	)		(12.9	)		(15.9	)
Foreign currency translation and transaction gains (losses)		0.8			(2.1	)		(0.2	)		(0.9	)
Income attributable to sale of tax benefits		5.3			3.9			4.5			4.5
Gain from sale of property, plant and equipment					0.0			0.0			1.9
Other non-operating income (expense), net		(0.1	)		0.2			(0.4	)		0.2

Income before income taxes and equity in losses of investees		23.7			17.2			18.3			16.3
Income tax provision		23.5			(4.6	)		6.3			(4.3	)
Equity in losses of investees, net		(1.9	)		(0.6	)		(1.2	)		(0.3	)
Net income		45.2			12.0			23.4			11.7
Net income attributable to noncontrolling interest		(0.9	)		(0.2	)		(0.6	)		(0.2	)
Net income attributable to the Company's stockholders		44.3	%		11.8	%		22.8	%		11.5	%

Comparison of the Three Months Ended September 30, 2015 and the Three Months Ended September 30, 2014

Total Revenue

Total revenue for the three months ended September 30, 2015 was $162.9 million, compared to $140.2 million for the three months ended September 30, 2014, which represented a 16.1% increase from the prior year period. This increase was attributable to our Product segment, in which revenue increased by 73.9%, compared to the corresponding period in 2014.

Electricity Segment

Revenue attributable to our Electricity segment for the three months ended September 30, 2015 was $97.2 million, compared to $102.5 million for the three months ended September 30, 2014 despite a 10.0% increase in generation. This decrease was primarily attributable to our Puna power plant having lower energy rates due to the decrease in oil prices, as well as lower revenue in some of our power plants due to lower natural gas prices and a reduction in net gain on derivative contracts on oil and natural gas prices from $4.0 million in the three months ended September 30, 2014 to $0.4 million in the three months ended September 30, 2015. The decrease was partially offset by operations of the second phase of the McGinness Hills power plant in Nevada, which commenced commercial operation in February 2015.

Power generation in our power plants increased by 10.0% from 1,037,272 MWh in the three months ended September 30, 2014 to 1,141,058 MWh in the three months ended September 30, 2015 mainly due to the commencement of commercial operation of second phase of the McGinness Hills power plant.

Product Segment

Revenue attributable to our Product segment for the three months ended September 30, 2015 was $65.6 million, compared to $37.7 million for the three months ended September 30, 2014, which represented a 73.9% increase. The increase in our Product segment revenue was primarily due to timing of revenue recognition, different product mix and commencing revenue recognition in new contracts.

Total Cost of Revenue

Total cost of revenue for the three months ended September 30, 2015 was $103.5 million, compared to $84.8 million for the three months ended September 30, 2014, which represented a 22.1% increase. This increase was due to the increase in cost of revenue from our Product segment. As a percentage of total revenue, our total cost of revenue for the three months ended September 30, 2015, increased to 63.6%, from 60.4% for the three months ended September 30, 2014. This increase was attributable to an increase in the cost of revenue as a percentage of total revenue, in both our Electricity and Product segments, as further explained below.

Electricity Segment

Total cost of revenue attributable to our Electricity segment for the three months ended September 30, 2015 and for the three months ended September 30, 2014, was $61.5 million and $61.7 million, respectively. Despite additional costs of revenue related to the second phase of the McGinness Hills power plant that commenced commercial operation in February 2015, as discussed above, our total cost of revenue attributable to our Electricity segment remained flat as a result of a decrease in the O&M costs in many of our power plants. As a percentage of total electricity revenue, our total cost of revenue attributable to our Electricity segment for the three months ended September 30, 2015, was 63.2% compared to 60.2% for the three months ended September 30, 2014. This increase was due to the decrease in our Electricity segment revenue as discussed above.

The margin in the electricity segment for the three months ended September 30, 2015, was significantly impacted by approximately $6 million reduction in oil and natural gas prices as well as a $3.6 million net gain on derivative contracts compared to the three months ended September 30, 2014. Excluding these effects, the gross margin for the three months ended September 30, 2014 compared to the three months ended September 30, 2015, increased from 33.2% to 36.5%, respectively. This reflects the enhancements implemented in our power plants and the improved efficiencies of our operating portfolio along with the new capacity that came on line.

Product Segment

Total cost of revenue attributable to our Product segment for the three months ended September 30, 2015 was $42.0 million, compared to $23.0 million, for the three months ended September 30, 2014, which represented an 82.4% increase. This increase was primarily due to the increase in Product segment revenue, as discussed above. As a percentage of total Product segment revenue, our total cost of revenue attributable to our Product segment for the three months ended September 30, 2015, was 64.0% compared to 61.1%, for the three months ended September 30, 2014. This increase was primarily due to a different product mix in the relevant period.

Research and Development Expenses, Net

Research and development expenses for the three months ended September 30, 2015 and 2014 were $0.3 million.

Selling and Marketing Expenses

Selling and marketing expenses for the three months ended September 30, 2015 and 2014, were $4.4 million. Selling and marketing expenses for the three months ended September 30, 2015 constituted 2.7% of total revenue for such period, compared to 3.0% for the three months ended September 30, 2014.

General and Administrative Expenses

General and administrative expenses for the three months ended September 30, 2015 were $8.0 million, compared to $7.2 million for the three months ended September 30, 2014. General and administrative expenses for the three months ended September 30, 2015, constituted 5.0% of total revenue for such period, compared to 5.1% for the three months ended September 30, 2014.

Operating Income

Operating income for the three months ended September 30, 2015 was $46.5 million, compared to $43.8 million for the three months ended September 30, 2014, which represented a 6.1% increase. The increase in operating income was principally attributable to the increase in our gross margin in our Product segment primarily due to the increase in revenues, as discussed above. The increase was partially offset by a decrease in our gross margin in our Electricity segment principally due to the decrease in Electricity revenues, as discussed above. Operating income attributable to our Electricity segment for the three months ended September 30, 2015 was $28.3 million, compared to $32.4 million for the three months ended September 30, 2014. Operating income attributable to our Product segment for the three months ended September 30, 2015 was $18.1 million, compared to $11.4 million for the three months ended September 30, 2014.

Interest Expense, Net

Interest expense, net for the three months ended September 30, 2015 was $17.7 million, compared to $22.5 million for the three months ended September 30, 2014. This decrease was primarily due to (i) lower interest expense as a result of principal payments of long term debt and revolving credit lines with banks; and (ii) $1.1 million decrease in interest expense related to sale of tax benefits. The decrease was partially offset by an increase in interest expense related to a loan in the amount of $140.0 million received under the OFC 2 Senior Secured Notes to finance the construction of the second phase of the McGinness Hills power plant in August 2014.

Foreign Currency Translation and Transaction Gains (Losses)

Foreign currency translation and transaction gains for the three months ended September 30, 2015 were $1.3 million, compared to losses of $2.9 million for the three months ended September 30, 2014. Foreign currency translation and transaction gains and losses were attributable primarily to gains and losses on foreign currency forward contracts which were not accounted for as hedge transactions.

Income Attributable to Sale of Tax Benefits

Income attributable to the sale of tax benefits to institutional equity investors (as described below under “OPC Transaction” and “ORTP Transaction”) for the three months ended September 30, 2015 was $8.6 million, compared to $5.5 million for the three months ended September 30, 2014. This income mainly represents the value of PTCs and taxable income generated by OPC and ORTP of $3.8 million and $4.8 million, respectively, which were allocated to the respective investors in the three months ended September 30, 2015, compared to an income of $1.7 million and $3.9 million, respectively, in the three months ended September 30, 2014.

Income Taxes

Income tax benefit for the three months ended September 30, 2015 was $38.2 million, compared to income tax provision of $6.4 million for the three months ended September 30, 2014. Income tax benefit for the three months ended September 30, 2015, includes a $49.4 million deferred tax asset relating to the release of the valuation allowance for the additional 50% investment deduction for our Olkaria 3 power plant in Kenya based on amendments to the Kenya Income Tax Act that came into effect on September 11, 2015 and which extended the period to utilize such investment deduction from five years to ten years. Income tax provision for the three months ended September 30, 2015, excluding the $49.4 million, was $11.2 million, compared to $6.4 million for the three months ended September 30, 2014. Our effective tax rate for the three months ended September 30, 2015, excluding the $49.4 million, and the three months ended September 30, 2014, was 29.0% and 26.7%, respectively. The effective tax rate differs from the statutory rate of 35% for the three months ended September 30, 2015, primarily due to losses in the U.S. and certain foreign jurisdictions as described in Footnote 11 of the financial statements.

Equity in losses of investees, net

Equity in losses of investees, net for the three months ended September 30, 2015, was $3.1 million, compared to $0.9 million for the three months ended September 30, 2014. Equity in losses of investees, net derived from our 12.75% share in the losses of the Sarulla project and from profits elimination.

Net Income

Net income for the three months ended September 30, 2015 was $73.7 million, compared to $16.8 million for the three months ended September 30, 2014, which represents an increase of $56.9 million. The increase in net income was attributable to the deferred tax asset in Kenya and related expenses in the amount of $48.7 million, the increase of $2.7 million in operating income and lower interest expenses of $4.7 million, as discussed above.

Comparison of the Nine Months Ended September 30, 2015 and the Nine Months Ended September 30, 2014

Total Revenue

Total revenue for the nine months ended September 30, 2015 was $423.6 million, compared to $410.3 million for the nine months ended September 30, 2014, which represented a 3.2% increase from the prior year period. This increase was attributable to our Product segment, in which revenue increased by 19.9%, compared to the corresponding period in 2014. The increase was partially offset by a 3.8% decrease in our Electricity segment over the corresponding period in 2014.

Electricity Segment

Revenue attributable to our Electricity segment for the nine months ended September 30, 2015 was $278.1 million, compared to $289.0 million for the nine months ended September 30, 2014, which represented a 3.8% decrease in such revenue. This decrease was primarily attributable to our Puna power plant having lower generation due to a hurricane and lower energy rates due to the decrease in oil prices as well as lower revenue in some of our power plants due to lower natural gas prices. The decrease was partially offset by the commencement of operations of the second phase of the McGinness Hills power plant in Nevada in February 2015.

Power generation in our power plants increased by 7.1% from 3,281,785 MWh in the nine months ended September 30, 2014 to 3,513,803 MWh in the nine months ended September 30, 2015, mainly due to the commencement of commercial operation of the second phase of the McGinness Hills power plant, partially offset by the decrease in generation of the Puna and North Brawley power plants.

Product Segment

Revenue attributable to our Product segment for the nine months ended September 30, 2015 was $145.4 million, compared to $121.3 million for the nine months ended September 30, 2014, which represented a 19.9% increase. The increase in our Product segment revenue was primarily due to timing of revenue recognition, different product mix and commencing revenue recognition in new contracts.

Total Cost of Revenue

Total cost of revenue for the nine months ended September 30, 2015 was $269.4 million, compared to $261.4 million for the nine months ended September 30, 2014, which represents a 3.1% increase. This increase was primarily due to the increase in cost of revenue from our Product segment, partially offset by a decrease in cost of revenue from our Electricity segment. As a percentage of total revenue, our total cost of revenue for both the nine months ended September 30, 2015 and 2014, was 63.6%.

Electricity Segment

Total cost of revenue attributable to our Electricity segment for the nine months ended September 30, 2015 was $179.6 million, compared to $186.1 million for the nine months ended September 30, 2014, which represented a 3.5% decrease. This decrease was primarily due to: (i) reimbursement of $2.5 million of mining tax imposed on us based on an audit performed by the state of Nevada for the years ended December 31, 2008, 2009 and 2010 following our successful appeal of the audit decision in the first quarter of 2015 and (ii) the fact that in the nine months ended September 30, 2015 we did not incur costs that we incurred in the nine months ended September 30, 2014 to address the North Brawley power plant uncontrolled well flow. The decrease in our Electricity cost of revenue was partially offset by additional cost of revenue from the second phase of the McGinness Hills power plant that commenced commercial operation in February 2015, as discussed above. As a percentage of total Electricity revenue, our total cost of revenue attributable to our Electricity segment for the nine months ended September 30, 2015, was 64.6% compared to 64.4% for the nine months ended September 30, 2014.

Product Segment

Total cost of revenue attributable to our Product segment for the nine months ended September 30, 2015 was $89.8 million, compared to $75.3 million for the nine months ended September 30, 2014, which represented a 19.3% increase. This increase was primarily attributable to the increase in Product segment revenue, as discussed above. As a percentage of total Product segment revenue, our total cost of revenue attributable to our Product segment for the nine months ended September 30, 2015 was 61.8% compared to 62.1% for the nine months ended September 30, 2014.

Research and Development Expenses, Net

Research and development expenses excluding grants from the U.S. Department of Energy for the nine months ended September 30, 2015 were $1.1 million compared to $0.9 million for the nine months ended September 30, 2014. Grants from the U.S. Department of Energy related to the Enhanced Geothermal System project totaled $0 million and $0.5 million for the nine months ended September 30, 2015 and 2014, respectively.

Selling and Marketing Expenses

Selling and marketing expenses for the nine months ended September 30, 2015 were $12.1 million, compared to $10.9 million for the nine months ended September 30, 2014. The increase was primarily due to higher sales commissions related to our Product segment due to different commissions mix. Selling and marketing expenses for the nine months ended September 30, 2015 constituted 2.9% of total revenue for such period, compared to 2.6% for the nine months ended September 30, 2014.

General and Administrative Expenses

General and administrative expenses for the nine months ended September 30, 2015 were $25.6 million, compared to $20.8 million for the nine months ended September 30, 2014. The increase was due to $3.8 million of expenses related to the share exchange with Ormat Industries, as discussed above under “Recent Developments”. General and administrative expenses for the nine months ended September 30, 2015, excluding the costs related to the share exchange, constituted 5.0% of total revenue for such period, compared to 5.1% for the nine months ended September 30, 2014.

Write-off of Unsuccessful Exploration Activities

There was a $0.4 million write-off of unsuccessful exploration activities for the nine months ended September 30, 2015. Write-off of unsuccessful exploration activities for the nine months ended September 30, 2014 was $8.1 million. This represented the write-off of exploration costs related to our exploration activities in the Wister site in California, which we determined in the second quarter of 2014 would not support commercial operation.

Operating Income

Operating income for the nine months ended September 30, 2015 was $115.0 million, compared to $108.7 million for the nine months ended September 30, 2014, which represents a 5.8% increase. The increase in operating income was principally attributable to the write-off of unsuccessful exploration activities in the amount of $8.1 million in the nine months ended September 30, 2014 and to an increase in our gross margin in our Product segment, as discussed above. The increase was partially offset by a decrease in our gross margin in our Electricity segment principally due to the decrease in Electricity revenues, and by costs associated with the share exchange, both as discussed above. Operating income attributable to our Electricity segment for the nine months ended September 30, 2015 was $73.2 million, compared to $72.9 million for the nine months ended September 30, 2014. The increase in operating income attributable to our Electricity segment was principally attributable to a decrease in write-off of unsuccessful exploration activities in the amount of $7.7 million offset by lower gross margin as described above. Operating income attributable to our Product segment for the nine months ended September 30, 2015 was $41.8 million, compared to $35.8 million for the nine months ended September 30, 2014.

Interest Expense, Net

Interest expense, net for the nine months ended September 30, 2015 was $54.4 million, compared to $65.1 million for the nine months ended September 30, 2014. This decrease was primarily due to (i) lower interest expense as a result of principal payments of long term debt and revolving credit lines with banks; (ii) $2.6 million decrease in interest related to sale of tax benefits and (iii) $1.3 million in capitalized interest. The decrease was partially offset by an increase in interest expense related to a loan in the amount of $140.0 million received under the OFC 2 Senior Secured Notes to finance the construction of second phase of the McGinness Hills power plant in August 2014.

Foreign Currency Translation and Transaction Losses

Foreign currency translation and transaction losses for the nine months ended September 30, 2015 were $0.6 million, compared to $3.6 million for the nine months ended September 30, 2014. Foreign currency translation and transaction losses were attributable primarily to losses on foreign currency forward contracts which were not accounted for as hedge transactions.

Income Attributable to Sale of Tax Benefits

Income attributable to the sale of tax benefits to institutional equity investors (as described below under “OPC Transaction” and “ORTP Transaction”) for the nine months ended September 30, 2015 was $18.9 million, compared to $18.3 million for the nine months ended September 30, 2014. This income represents the value of PTCs and taxable income or loss generated by OPC and ORTP and allocated to the investors in the amount of $3.9 million and $15.0 million, respectively, in the nine months ended September 30, 2015, compared to $4.9 million and $13.4 million, respectively, in the nine months ended September 30, 2014. This decrease was primarily attributable to lower depreciation for tax purposes mainly in OPC as a result of declining depreciation rates using MACRS.

Gain from Sale of Property, Plant and Equipment

There was no gain from the sale of property, plant and equipment in the nine months ended September 30, 2015. Gain from the sale of property, plant and equipment for the nine months ended September 30, 2014 was $7.6 million. This gain relates to the sale of the Heber Solar project in Imperial County, California for an aggregate purchase price of $35.25 million in the first quarter of 2014. We received the first payment of $15.0 million in the first quarter of 2014, and the second payment for the remaining $20.25 million in the second quarter of 2014. We recognized the gain in the second quarter of 2014.

Other non-operating income (loss)

Other non-operating loss for the nine months ended September 30, 2015 was $1.5 million, compared to non-operating income of $0.6 million for the nine months ended September 30, 2014. Other non-operating loss for the nine months ended September 30, 2015 includes a capital loss of $1.7 million resulting from the repurchase of $30.6 million aggregate principal amount of our OFC Senior Secured Notes.

Income Taxes

Income tax benefit for the nine months ended September 30, 2015 was $26.7 million, compared to income tax provision of $17.7 million for the nine months ended September 30, 2014. Income tax benefit for the nine months ended September 30, 2015, includes a $49.4 million deferred tax asset relating to the release of the valuation allowance for the additional 50% investment deduction for our Olkaria 3 power plant based on amendments to Kenya Income Tax Act that came into effect on September 11, 2015 and which extended the period to utilize such investment deduction from five years to ten years. Income tax provision for the nine months ended September 30, 2015, excluding the $49.4 million, was $22.7 million, compared to $6.4 million for the nine months ended September 30, 2014. Our effective tax rate for the nine months ended September 30, 2015, excluding the $49.4 million, and the nine months ended September 30, 2014 was 29.3% and 26.5%, respectively. The effective tax rate differs from the statutory rate of 35% for the nine months ended September 30, 2015, primarily due to losses in the U.S. and certain foreign jurisdictions as described in Footnote 11 of the financial statements.

Equity in losses of investees, net

Equity in losses of investees, net for the nine months ended September 30, 2015 was $4.9 million, compared to $1.2 million for the nine months ended September 30, 2014. Equity in losses of investees, net derived from our 12.75% share in the losses of the Sarulla project and from profits elimination.

Net Income

Net income for the nine months ended September 30, 2015 was $99.2 million, compared to $47.9 million for the nine months ended September 30, 2014, which represents an increase of $51.3 million. The increase in net income was principally attributable to the deferred tax asset in Kenya and related expenses in the amount of $48.7 million, the increase of $6.3 million in operating income and the decrease in interest expense of $10.6 million, as discussed above. The increase was partially offset by a $7.6 million gain from the sale of property, plant and equipment in the nine months ended September 30, 2014, as discussed above.

Liquidity and Capital Resources

Our principal sources of liquidity have been derived from cash flows from operations, proceeds from third party debt in the form of borrowings under credit facilities and private offerings, issuances of notes, project financing, tax monetization transactions, short term borrowing under our lines of credit, sale of membership interests and cash grants we received under the ARRA. We have utilized this cash to develop and construct power generation plants, fund our acquisitions, pay down existing outstanding indebtedness, and meet our other cash and liquidity needs.

As of September 30, 2015, we had access to (i) $171.5 million in cash and cash equivalents of which $148.2 million is related to foreign jurisdictions; and (ii) $144.8 million of unused corporate borrowing capacity under existing lines of credit with different commercial banks.

Our estimated capital needs for the remainder of 2015 include approximately $18 million for capital expenditures on new projects under development or construction, exploration activity, operating projects, and machinery and equipment purchases, as well as $31.2 million for debt repayment.

We believe that based on our plans to increase our operations outside of the U.S., the cash generated from our operations outside of the U.S. will be reinvested outside of the U.S. In addition, our U.S. sources of cash and liquidity are sufficient to meet our needs in the U.S. and, accordingly, we do not currently plan to repatriate the funds we have designated as being permanently invested outside the U.S. If we change our plans, we may be required to accrue and pay U.S. taxes to repatriate these funds.

We expect to finance our estimated capital needs with: (i) the sources of liquidity described above; (ii) positive cash flows from our operations; and (iii) future project financing and refinancing (including construction loans). Management believes that these sources will address our anticipated liquidity, capital expenditures, and other investment requirements.

Third-Party Debt

Our third-party debt is composed of two principal categories. The first category consists of project finance debt or acquisition financing that we or our subsidiaries have incurred for the purpose of developing and constructing, refinancing or acquiring our various projects, which are described below under “Non-Recourse and Limited-Recourse Third-Party Debt”. The second category consists of debt incurred by us or our subsidiaries for general corporate purposes, which are described below under “Full-Recourse Third-Party Debt.”

Non-Recourse and Limited-Recourse Third-Party Debt

OFC Senior Secured Notes — Non-Recourse

In February 2004, OFC, one of our subsidiaries, issued $190.0 million of OFC Senior Secured Notes for the purpose of refinancing the acquisition cost of the Brady, Ormesa and Steamboat 1, 1A, 2 and 3 power plants, and the financing of the acquisition cost of 50% of the Mammoth complex. The OFC Senior Secured Notes have a final maturity date of December 30, 2020. Principal and interest on the OFC Senior Secured Notes are payable in semi-annual payments. The OFC Senior Secured Notes are collateralized by substantially all of the assets of OFC and those of its wholly owned subsidiaries and are fully and unconditionally guaranteed by all of the wholly owned subsidiaries of OFC. There are various restrictive covenants under the OFC Senior Secured Notes, which include limitations on additional indebtedness of OFC and its wholly owned subsidiaries. Failure to comply with these and other covenants will, subject to customary cure rights, constitute an event of default by OFC. In addition, there are restrictions on the ability of OFC to make distributions to its shareholders, which include a required historical and projected 12-month debt service coverage ratio of not less than 1.25 (measured semi-annually as of June 30 and December 31 of each year). If OFC fails to comply with the debt service coverage ratio it will be prohibited from making distributions to its shareholders. We are only required to measure these covenants on a semi-annual basis and as of June 30, 2015, (the last measurement date of the covenants) the actual historical 12-month debt service coverage ratio was 1.26 and the pro-forma 12-month debt service coverage ratio was 1.29 (on a semi-annual basis and as of June 30, 2015). There were $33.3 million aggregate principal amount of OFC Senior Secured Notes outstanding as of September 30, 2015.

In June 2015, we repurchased from OFC noteholders $30.6 million of the aggregate principal amount of our OFC Senior Secured Notes, which resulted in approximately $2.5 million of saving in interest expense. We recognized a loss of approximately $1.7 million in the nine months ended September 30, 2015 as a result of that repurchase. In January 2014, we repurchased from OFC noteholders $13.2 million of the aggregate principal amount of our OFC Senior Secured Notes. We recognized a gain of approximately $0.3 million in the year ended December 31, 2014.

OrCal Geothermal Senior Secured Notes — Non-Recourse

In December 2005, OrCal, one of our subsidiaries, issued $165.0 million of OrCal Senior Secured Notes for the purpose of refinancing the acquisition cost of the Heber complex. The OrCal Senior Secured Notes have been rated BBB- by Fitch Ratings. The OrCal Senior Secured Notes have a final maturity date of December 30, 2020. Principal and interest on the OrCal Senior Secured Notes are payable in semi-annual payments. The OrCal Senior Secured Notes are collateralized by substantially all of the assets of OrCal and those of its wholly owned subsidiaries and are fully and unconditionally guaranteed by all of the wholly owned subsidiaries of OrCal. There are various restrictive covenants under the OrCal Senior Secured Notes which include limitations on additional indebtedness of OrCal and its wholly owned subsidiaries. Failure to comply with these and other covenants will, subject to customary cure rights, constitute an event of default by OrCal. In addition, there are restrictions on the ability of OrCal to make distributions to its shareholders, which include a required historical and projected 12-month debt service coverage ratio of not less than 1.25 (measured semi-annually as of June 30 and December 31 of each year). If OrCal fails to comply with the debt service coverage ratio it will be prohibited from making distributions to its shareholders. We are only required to measure these covenants on a semi-annual basis and as of June 30, 2015, (the last measurement date of the covenants) the actual historical 12-month debt service coverage ratio was 1.26, and the pro-forma 12-month debt service coverage ratio was 1.33. There were $51.8 million of OrCal Senior Secured Notes outstanding as of September 30, 2015.

OFC 2 Senior Secured Notes — Limited Recourse During Construction and Non-Recourse Thereafter

In September 2011, OFC 2, one of our subsidiaries, and its wholly owned project subsidiaries (collectively, the OFC 2 Issuers) entered into a note purchase agreement (the Note Purchase Agreement) with OFC 2 Noteholder Trust, as purchaser, John Hancock, as administrative agent, and the Department of Energy (DOE), as guarantor, in connection with the offer and sale of up to $350.0 million aggregate principal amount of OFC 2 Senior Secured Notes due December 31, 2034. As of September 30, 2015, we have utilized $291.7 million of the notes and we do not expect further drawdowns under this agreement.

Subject to the fulfillment of customary and other specified conditions precedent, the OFC 2 Senior Secured Notes may be issued in up to six distinct series associated with the phased construction (Phase I and Phase II) of the Jersey Valley, McGinness Hills and Tuscarora geothermal power plants, which are owned by the OFC 2 Issuers. The OFC 2 Senior Secured Notes will mature and the principal amount of the OFC 2 Senior Secured Notes will be payable in equal quarterly installments and in any event not later than December 31, 2034. Each series of notes will bear interest at a rate calculated based on a spread over the U.S. Treasury yield curve that will be set at least ten business days prior to the issuance of such series of notes. Interest will be payable quarterly in arrears. The DOE guarantees payment of 80% of principal and interest on the OFC 2 Senior Secured Notes pursuant to Section 1705 of Title XVII of the Energy Policy Act of 2005, as amended. The conditions precedent to the issuance of the OFC 2 Senior Secured Notes include certain specified conditions required by the DOE in connection with its guarantee of the OFC 2 Senior Secured Notes.

In October 2011, the OFC 2 Issuers completed the sale of $151.7 million in aggregate principal amount of 4.687% Series A Notes due 2032 (the Series A Notes). The net proceeds from the sale of the Series A Notes, after deducting transaction fees and expenses, were approximately $141.1 million, and were used to finance a portion of the construction costs of Phase I of the McGinness Hills and Tuscarora power plants and to fund certain reserves. Principal and interest on the Series A Notes are payable quarterly in arrears on the last day of March, June, September and December of each year.

On June 20, 2014, Phase I of the Tuscarora facility achieved project completion under the OFC 2 Note Purchase Agreement. In accordance with the terms of the Note Purchase Agreement, we recalibrated the original financing assumptions and as a result the loan amount was adjusted through a principal payment of $4.3 million.

On August 29, 2014, OFC 2 signed a $140.0 million loan under the OFC 2 senior secured notes to finance the construction of the McGinness Hills Phase 2 project. This draw is the last tranche (Series C notes) under the Note Purchase Agreement with John Hancock Life Insurance Company (USA), and is guaranteed by the U.S Department of Energy Loan Programs Office in accordance with and subject to the Department’s Loan Guarantee Program under section 1705 of Title XVII of the Energy Policy Act of 2005. The $140.0 million loan, which matures in December 2032, carries a 4.61% coupon with principal to be repaid on a quarterly basis. The OFC 2 Notes, which include loans for the Tuscarora, Jersey Valley and McGinness Hills complexes, are rated “BBB” by Standard & Poor’s.

In connection with the drawdown, on August 13, 2014, we entered into an on-the-run interest lock agreement with a financial institution with a termination date of August 15, 2014. This on-the-run interest lock agreement had a notional amount of $140.0 million and was designated by us to be a cash flow hedge. The objective of this cash flow hedge was to eliminate the variability in the change in the 10-year U.S. Treasury rate as that is one of the components in the annual interest rate of OFC 2 loan that was forecasted to be fixed on August 15, 2014. As such, we hedged the variability in total proceeds attributable to changes in the 10-year U.S. Treasury rate for the forecasted issuance of fixed rate OFC 2 loan. On the settlement date of August 18, 2014, we paid $1.5 million to the counterparty of the on-the-run interest rate lock agreement.

The OFC 2 Senior Secured Notes are collateralized by substantially all of the assets of OFC 2 and those of its wholly owned subsidiaries and are fully and unconditionally guaranteed by all of the wholly owned subsidiaries of OFC 2. There are various restrictive covenants under the OFC 2 Senior Secured Notes, which include limitations on additional indebtedness of OFC 2 and its wholly owned subsidiaries. Failure to comply with these and other covenants will, subject to customary cure rights, constitute an event of default by OFC 2. In addition, there are restrictions on the ability of OFC 2 to make distributions to its shareholders. Among other things, the distribution restrictions include a historical and projected quarterly debt service coverage ratio requirement of at least 1.2 (on a blended basis for all of the OFC 2 power plants) and 1.5 on a pro forma basis (giving effect to the distributions). We are required to measure these covenants on a quarterly basis and as of September 30, 2015, the last measurement date of the covenants, the actual debt service coverage ratio was 2.28 and the pro-forma 12-month debt service coverage ratio was 2.18. There were $266.0 million of OFC 2 Senior Secured Notes outstanding as of September 30, 2015.

We provided a guarantee in connection with the issuance of the Series A and C Notes, which will be available to be drawn upon if certain trigger events occur. One trigger event is the failure of any facility financed by the relevant series of OFC 2 Senior Secured Notes to reach completion and meet certain operational performance levels (the non-performance trigger) which gives rise to a prepayment obligation on the OFC 2 Senior Secured Notes. The other trigger event is a payment default on the OFC 2 Senior Secured Notes or the occurrence of certain fundamental defaults that result in the acceleration of the OFC 2 Senior Secured Notes, in each case that occurs prior to the date that the relevant facility financed by such OFC 2 Senior Secured Notes reaches completion and meets certain operational performance levels. A demand on our guarantee based on the non-performance trigger is limited to an amount equal to the prepayment amount on the OFC 2 Senior Secured Notes necessary to bring the OFC 2 Issuers into compliance with certain coverage ratios. A demand on our guarantee based on the other trigger event is not so limited.

Olkaria III Finance Agreement with OPIC — Limited Recourse during Construction and Non-Recourse Thereafter

In August 2012, OrPower 4, one of our subsidiaries, entered into a finance agreement with OPIC, an agency of the United States government, to provide limited-recourse senior secured debt financing in an aggregate principal amount of up to $310.0 million (the OPIC Loan) for the refinancing and financing of our Olkaria III geothermal power complex in Kenya. The finance agreement was amended on November 9, 2012.

The OPIC Loan is comprised of three tranches:

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Tranche I in an aggregate principal amount of $85.0 million, which was drawn in November 2012, was used to prepay approximately $20.5 million (plus associated prepayment penalty and breakage costs of $1.5 million) of the DEG Loan, as described below under “Full Recourse Third Party Debt”. The remainder of Tranche I proceeds was used for reimbursement of prior capital costs and other corporate purposes.

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Tranche II in an aggregate principal amount of $180.0 million was used to fund the construction and well field drilling for Plant 2 of the Olkaria III geothermal power complex. In November 2012, an amount of $135.0 million was disbursed under this Tranche II, and in February 2013 the remaining $45.0 million was distributed under this Tranche II.

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Tranche III in an aggregate principal amount of $45.0 million was used to fund the construction of Plant 3 of the Olkaria III geothermal power complex and was drawn down in full in November 2013.

In July 2013, we completed the conversion of the interest rate applicable to both Tranche I and Tranche II from a floating interest rate to a fixed interest rate. The average fixed interest rate for Tranche I, which has an outstanding balance of $72.0 million and matures on December 15, 2030 and Tranche II, which has an outstanding balance of $156.2 million and matures on June 15, 2030, is 6.31%. In November 2013, we fixed the interest rate applicable to Tranche III. The fixed interest rate for Tranche III, which has an outstanding balance of $41.0 million and matures on December 15, 2030, is 6.12%.

OrPower 4 has a right to make voluntary prepayments of all or a portion of the OPIC Loan subject to prior notice, minimum prepayment amounts, and a prepayment premium of 2.0% in the first two years after the Plant 2 commercial operation date, declining to 1% in the third year after the Plant 2 commercial operation date, and without premium thereafter, plus a redemption premium. In addition, the OPIC Loan is subject to customary mandatory prepayment in the event of certain reductions in generation capacity of the power plants, unless such reductions will not cause the projected ratio of cash flow to debt service to fall below 1.7.

The OPIC Loan is secured by substantially all of OrPower 4’s assets and by a pledge of all of the equity interests in OrPower 4.

The finance agreement includes customary events of default, including failure to pay any principal, interest or other amounts when due, failure to comply with covenants, breach of representations and warranties, non-payment or acceleration of other debt of OrPower 4, bankruptcy of OrPower 4 or certain of its affiliates, judgments rendered against OrPower 4, expropriation, change of control, and revocation or early termination of security documents or certain project-related agreements, subject to various exceptions and notice, cure and grace periods.

The repayment of the remaining outstanding DEG Loan (see “Full-Recourse Third-Party Debt” below) in the amount of approximately $27.6 million as of September 30, 2015, has been subordinated to the OPIC Loan.

There are various restrictive covenants under the OPIC Loan, which include a required historical and projected 12-month debt service coverage ratio of not less than 1.4 (measured as of March 15, June 15, September 15 and December 15 of each year). If OrPower 4 fails to comply with these financial ratios it will be prohibited from making distributions to its shareholders. In addition, if the debt service coverage ratio falls below 1.1, subject to certain cure rights; such failure will constitute an event of default by OrPower 4. This covenant in respect of Tranche I became effective on December 15, 2014. As of September 30, 2015, the actual historical and projected 12-month debt service coverage ratio was 2.20 and 2.00, respectively.

As of September 30, 2015, $269.1 million of the OPIC loan was outstanding.

Amatitlàn financing

On July 31, 2015, one of our indirect wholly-owned subsidiaries, Ortitlản, Limitada, obtained a 12-year secured term loan in the principal amount of $42.0 million for the 20 MW Amatitlàn power plant in Guatemala. Under the credit agreement with Banco Industrial S.A. and Westrust Bank (International) Limited, we can expand the Amatitlàn power plant with financing to be provided either via equity, additional debt from Banco Industrial S.A. or from other lenders, subject to certain limitations on expansion financing in the credit agreement.

There are various restrictive covenants under the Amatitlàn credit agreement. These include, among others, (i) a financial covenant to maintain a Debt Service Coverage Ratio (as defined in the credit agreement) of not less than 1.15 to 1.00 as of the last day of any fiscal quarter and (ii) limitations on Restricted Payments (as defined in the credit agreement) that among other things would limit dividends that could be paid to us unless the historical and projected Debt Service Coverage Ratio is not less than 1.25 to 1.00 for the four fiscal quarterly periods (calculated as a single accounting period). As of September 30, 2015, the actual historical and projected 12-month Debt Service Coverage Ratio was 7.94 and 1.97, respectively. The credit agreement includes various events of default that would permit acceleration of the loan (subject in some cases to grace and cure periods). These include, among others, a Change of Control (as defined in the credit agreement) and failure to maintain certain required balances in debt service and maintenance reserve accounts. The credit agreement includes certain equity cure rights for failure to maintain the Debt Service Coverage Ratio and the minimum amounts required in the debt service and maintenance reserve accounts.

The loan is secured by substantially all the assets of the borrower and a pledge of all of the membership interests of the borrower.

As of September 30, 2015, $41.1 million of this loan is outstanding.

Full-Recourse Third-Party Debt

Union Bank. In February 2012, Ormat Nevada, our wholly owned subsidiary, entered into an amended and restated credit agreement with Union Bank. Under the amended and restated agreement, the credit termination date was extended from February 15, 2012 to February 7, 2014, which was subsequently extended to May 20, 2015, and then June 30, 2016. The aggregate amount available under the credit agreement is $50.0 million. The facility is limited to the issuance, extension, modification or amendment of letters of credit. Union Bank is currently the sole lender and issuing bank under the credit agreement, but is also designated as an administrative agent on behalf of banks that may, from time to time in the future, join the credit agreement as parties thereto. In connection with this transaction, we entered into a guarantee in favor of the administrative agent for the benefit of the banks, pursuant to which we agreed to guarantee Ormat Nevada’s obligations under the credit agreement. Ormat Nevada’s obligations under the credit agreement are otherwise unsecured.

There are various restrictive covenants under the credit agreement, including a requirement for Ormat Nevada to comply with the following financial ratios, which are measured quarterly: (i) a 12-month debt to EBITDA ratio not to exceed 4.5; (ii) 12-month debt service coverage ratio of not less than 1.35; and (iii) distribution leverage ratio not to exceed 2.0. As of September 30, 2015: (i) the actual 12-month debt to EBITDA ratio was 2.97; (ii) the 12-month debt service coverage ratio was 2.28; and (iii) the distribution leverage ratio was 1.7. In addition, there are restrictions on dividend distributions in the event of a payment default or noncompliance with such ratios, and subject to specified carve-outs and exceptions, a negative pledge on the assets of Ormat Nevada in favor of Union Bank.

As of September 30, 2015, letters of credit in the aggregate amount of $48.2 million remain issued and outstanding under this committed credit agreement with Union Bank.

HSBC. In May 2013, Ormat Nevada, entered into a credit agreement with HSBC Bank USA, N.A for one year with annual renewals, which was subsequently extended to May 31, 2015, and then to June 30, 2016. The aggregate amount available under the credit agreement is $25.0 million. This credit line is limited to the issuance, extension, modification or amendment of letters of credit and $10.0 million out of this credit line is available to be drawn for working capital needs. HSBC is currently the sole lender and issuing bank under the credit agreement, but is also designated as an administrative agent on behalf of banks that may, from time to time in the future, join the credit agreement as parties thereto. In connection with this transaction, we entered into a guarantee in favor of the administrative agent for the benefit of the banks, pursuant to which we agreed to guarantee Ormat Nevada’s obligations under the credit agreement. Ormat Nevada’s obligations under the credit agreement are otherwise unsecured.

There are various restrictive covenants under the credit agreement, including a requirement to comply with the following financial ratios, which are measured quarterly: (i) a 12-month debt to EBITDA ratio not to exceed 4.5; (ii) 12-month debt service coverage ratio of not less than 1.35; and (iii) distribution leverage ratio not to exceed 2.0. As of September 30, 2015: (i) the actual 12-month debt to EBITDA ratio was 2.97; (ii) the 12-month debt service coverage ratio was 2.28; and (iii) the distribution leverage ratio was 1.7. In addition, there are restrictions on dividend distributions in the event of a payment default or noncompliance with such ratios, and subject to specified carve-outs and exceptions, a negative pledge on the assets of Ormat Nevada in favor of HSBC.

As of September 30, 2015, letters of credit in the aggregate amount of $25.0 million remain issued and outstanding under this committed credit agreement.

Credit Agreements. We also have committed credit agreements with six other commercial banks for an aggregate amount of $462.5 million. Under the terms of these credit agreements, we or our Israeli subsidiary, Ormat Systems, can request (i) extensions of credit in the form of loans and/or the issuance of one or more letters of credit in the amount of up to $237.0 million and (ii) the issuance of one or more letters of credit in the amount of up to $225.5 million. The credit agreements mature at the end of October 2015 and November 2016. Loans and draws under the credit agreements or under any letters of credit will bear interest at the respective bank’s cost of funds plus a margin.

As of September 30, 2015, letters of credit with an aggregate stated amount of $312.7 million were issued and outstanding under these credit agreements.

Term Loans. We had a $20.0 million term loan with a group of institutional investors, which matured on July 16, 2015, that was payable in 12 semi-annual installments commencing January 16, 2010, and bore interest at a rate of 6.5%. As of September 30, 2015, this loan was fully repaid.

We have a $20.0 million term loan with a group of institutional investors, which matures on August 1, 2017, that is payable in 12 semi-annual installments commencing February 1, 2012, and bears interest at 6-month LIBOR plus 5.0%. As of September 30, 2015, $6.7 million was outstanding under this loan.

We have a $20.0 million term loan with a group of institutional investors, which matures on November 16, 2016, that is payable in ten semi-annual installments commencing May 16, 2012, and bears interest of 5.75%. As of September 30, 2015, $6.0 million was outstanding under this loan. This term loan was prepaid in full in October 2015, as noted in Footnote 12 of the financial statments.

Senior Unsecured Bonds. We have an aggregate principal amount of approximately $250.0 million of senior unsecured bonds issued and outstanding. We issued approximately $142.0 million aggregate principal amount of these bonds in August 2010 and an additional $107.5 million aggregate principal amount in February 2011. Subject to early redemption, the principal of the bonds is repayable in a single bullet payment upon the final maturity of the bonds on August 1, 2017. The bonds bear interest at a fixed rate of 7.00%, payable semi-annually. The bonds that we issued in February 2011 were issued at a premium which reflects an effective fixed interest of 6.75%.

Loan Agreement with DEG (The Olkaria III Complex). OrPower 4 entered into a project financing loan to refinance its investment in Plant 1 of the Olkaria III complex located in Kenya with a group of European Development Finance Institutions arranged by Deutsche Investitions-und Entwicklungsgesellschaft mbH (DEG). The DEG Loan will mature on December 15, 2018, and is payable in 19 equal semi-annual installments. Interest on the loan is variable based on 6-month LIBOR plus 4.0%. We fixed the interest rate on most of the loan at 6.90%. As of September 30, 2015, $27.6 million is outstanding under the DEG Loan (out of which $21.7 million bears interest at a fixed rate).

In October 2012, OrPower 4, DEG and the other parties thereto amended and restated the DEG Loan Agreement. The amendment became effective on November 9, 2012 upon the execution by OrPower 4 of the Tranche I and Tranche II Notes under the OPIC loan and the related disbursements of the proceeds thereof under the OPIC Finance Agreement (as described above under the heading “Non-Recourse and Limited–Recourse Third-Party Debt”). As part of the amendment we prepaid in full two loans under the DEG facility in the total principal amount of approximately $20.5 million. The amended and restated DEG Loan Agreement provides for (i) the release and discharge of all collateral security previously provided by OrPower 4 to the secured parties under the DEG Loan Agreement and the substitution of the Company’s guarantee of OrPower 4’s payment and certain other performance obligations in lieu thereof; (ii) the establishment of a LIBOR floor of 1.25% in respect of one of the loans under the DEG Loan Agreement and (iii) the elimination of most of the affirmative and negative covenants under the DEG Loan Agreement and certain other conforming provisions as a result of OrPower 4’s execution of the OPIC Finance Agreement and its obligations thereunder.

Our obligations under the credit agreements, the loan agreements, and the trust instrument governing the bonds, described above, are unsecured, but we are subject to a negative pledge in favor of the banks and the other lenders and certain other restrictive covenants. These include, among other things, a prohibition on: (i) creating any floating charge or any permanent pledge, charge or lien over our assets without obtaining the prior written approval of the lender; (ii) guaranteeing the liabilities of any third party without obtaining the prior written approval of the lender; and (iii) selling, assigning, transferring, conveying or disposing of all or substantially all of our assets, or a change of control in our ownership structure. Some of the credit agreements, the term loan agreements, and the trust instrument contain cross-default provisions with respect to other material indebtedness owed by us to any third party. In some cases, we have agreed to maintain certain financial ratios, which are measured quarterly, such as: (i) equity of at least $600.0 million and in no event less than 30% of total assets; (ii) 12-month debt, net of cash, cash equivalents, and short-term bank deposits to Adjusted EBITDA ratio not to exceed 7.0; and (iii) dividend distributions not to exceed 35% of net income in any calendar year. As of September 30, 2015: (i) total equity was $1,061.0 million and the actual equity to total assets ratio was 46.40% and (ii) the 12-month debt, net of cash and cash equivalents, to Adjusted EBITDA ratio was 2.81. During the nine months ended September 30, 2015, we distributed interim dividends in an aggregate amount of $9.8 million. The failure to perform or observe any of the covenants set forth in such agreements, subject to various cure periods, would result in the occurrence of an event of default and would enable the lenders to accelerate all amounts due under each such agreement.

As described above, we are currently in compliance with our covenants with respect to the credit agreements, the loan agreements and the trust instrument, and believe that the restrictive covenants, financial ratios and other terms of any of our (or Ormat Systems’) full-recourse bank credit agreements will not materially impact our business plan or operations.

Letters of Credit

Some of our customers require our project subsidiaries to post letters of credit in order to guarantee their respective performance under relevant contracts. We are also required to post letters of credit to secure our obligations under various leases and licenses and may, from time to time, decide to post letters of credit in lieu of cash deposits in reserve accounts under certain financing arrangements. In addition, our subsidiary, Ormat Systems is required from time to time to post performance letters of credit in favor of our customers with respect to orders of products.

As of September 30, 2015, committed letters of credit in the aggregate amount of $390.3 million remained issued and outstanding under the credit agreements with Union Bank, HSBC and five of the commercial banks as described under “Full-Recourse Third Party Debt”.

Puna Power Plant Lease Transactions

In May 2005, Puna Geothermal Venture (PGV), our Hawaiian subsidiary, entered into a transaction involving the original geothermal power plant of the Puna complex located on the Big Island (the Puna Power Plant).

Pursuant to a 31-year head lease (the Head Lease), PGV leased the Puna Power Plant to an unrelated lessor (the Puna lessor) in return for prepaid lease payments in the total amount of $83.0 million. The carrying value of the leased assets as of September 30, 2015 amounted to $31.3 million, net of accumulated depreciation of $29.5 million. The Puna Lessor simultaneously leased back the Puna Power Plant to PGV under a 23-year lease (the Project Lease). PGV’s rent obligations under the Project Lease will be paid solely from revenue generated by the Puna Power Plant under a PPA that PGV has with HELCO. The Head Lease and the Project Lease are non-recourse lease obligations to the Company. PGV’s rights in the geothermal resource and the related PPA have not been leased to the Puna Lessor as part of the Head Lease but are part of the Puna Lessor’s security package.

The transaction was concluded with financing parties by means of a leveraged lease transaction. A secondary stage of the lease transaction relating to two new geothermal wells that PGV drilled in the second half of 2005 (for production and injection) was completed on December 30, 2005. Pursuant to a 31-year head lease, PGV leased its geothermal power plant to the abovementioned financing parties in return for payments of $83.0 million by such financing parties to PGV, which are accounted for as deferred lease income.

There are various restrictive covenants under the lease agreement, including a requirement to have certain reserve funds that need to be managed by the indenture trustee in accordance with certain balance requirements. Such reserve funds amounted to $3.1 million and $2.5 million as of September 30, 2015 and 2014, respectively, and were included in restricted cash accounts in the consolidated balance sheets and were classified as current as they were used for current payments.

OPC Transaction

In June 2007, Ormat Nevada entered into agreements with affiliates of Morgan Stanley & Co. Incorporated and Lehman Brothers Inc. (Morgan Stanley Geothermal LLC and Lehman-OPC LLC, respectively), under which those investors purchased, for cash, interests in a newly formed subsidiary of Ormat Nevada, OPC, entitling the investors to certain tax benefits (such as PTCs and accelerated depreciation) and distributable cash associated with four geothermal power plants in Nevada.

The first closing under the agreements occurred in 2007 and covered our Desert Peak 2, Steamboat Hills, and Galena 2 power plants. The investors paid $71.8 million at the first closing. The second closing under the agreements occurred in 2008 and covered the Galena 3 power plant. The investors paid $63.0 million at the second closing.

Ormat Nevada continues to operate and maintain the power plants. Under the agreements, Ormat Nevada initially received all of the distributable cash flow generated by the power plants, while the investors received substantially all of the PTCs and the taxable income or loss (together, the Economic Benefits). Once Ormat Nevada recovered the capital that it invested in the power plants, which occurred in the fourth quarter of 2010, the investors began receiving both the distributable cash flow and the Economic Benefits. Once the investors reach a target after-tax yield on their investment in OPC (the OPC Flip Date), Ormat Nevada will receive 95% of both distributable cash and taxable income, on a going forward basis. Following the OPC Flip Date, Ormat Nevada also has the option to purchase the investors’ remaining interest in OPC at the then-current fair market value or, if greater, the investors’ capital account balances in OPC. If Ormat Nevada were to exercise this purchase option, it would become the sole owner of the power plants again.

Our voting rights in OPC are based on a capital structure that is comprised of Class A and Class B membership units. Through Ormat Nevada, we own all of the Class A membership units, which represent 75% of the voting rights in OPC, and the investors (as described below) own all of the Class B membership units, which represent 25% of the voting rights of OPC. Other than in respect of customary protective rights, all operational decisions in OPC are decided by the vote of a majority of the membership units. Following the OPC Flip Date, Ormat Nevada’s voting rights will increase to 95% and the investor’s voting rights will decrease to 5%. Ormat Nevada retains the controlling voting interest in OPC both before and after the OPC Flip Date and therefore consolidates OPC.

The Class B membership units have a 5% residual economic interest in OPC, which commences as of the OPC Flip Date. This residual 5% interest represents a noncontrolling interest and is not subject to mandatory redemption or guaranteed payments. The Class B membership units are currently held by Morgan Stanley Geothermal LLC and JPM. On October 30, 2009, Ormat Nevada acquired from Lehman-OPC LLC all of the Class B membership units of OPC held by Lehman-OPC LLC pursuant to a right of first offer for a purchase price of $18.5 million in cash and on February 3, 2011, Ormat Nevada sold to JPM all of the Class B membership units of OPC that it had acquired for a sale price of $24.9 million in cash.

ORTP Transaction

On January 24, 2013, Ormat Nevada entered into agreements with JPM under which JPM purchased interests in a newly formed subsidiary of Ormat Nevada, ORTP, entitling JPM to certain tax benefits (such as PTCs and accelerated depreciation) associated with certain geothermal power plants in California and Nevada.

Under the terms of the transaction, Ormat Nevada transferred the Heber complex, the Mammoth complex, the Ormesa complex, the Steamboat 2 and 3, Burdette (Galena 1) and Brady power plants to ORTP, and sold class B membership units in ORTP to JPM. In connection with the closing, JPM paid approximately $35.7 million to Ormat Nevada and will make additional payments to Ormat Nevada of 25% of the value of PTCs generated by the portfolio over time. The additional payments are expected to be made until December 31, 2016 and total up to a maximum amount of $11.0 million, of which we received $1.7 million and $2.2 million in the first quarters of 2015 and 2014, respectively.

Ormat Nevada will continue to operate and maintain the power plants. Under the agreements, Ormat Nevada will initially receive all of the distributable cash flow generated by the power plants, while JPM will receive substantially all of the Economic Benefits. JPM’s return is limited by the terms of the transaction. Once JPM reaches a target after-tax yield on its investment in ORTP (the ORTP Flip Date), Ormat Nevada will receive 97.5% of the distributable cash and 95.0% of the taxable income, on a going forward basis. At any time during the twelve-month period after the end of the fiscal year in which the ORTP Flip Date occurs (but no earlier than the expiration of five years following the date that the last of the power plants was placed in service for purposes of federal income taxes), Ormat Nevada also has the option to purchase JPM’s remaining interest in ORTP at the then-current fair market value. If Ormat Nevada were to exercise this purchase option, it would become the sole owner of the power plants again.

The Class B membership units entitle the holder to a 5.0% (allocation of income and loss) and 2.5% (allocation of cash) residual economic interest in ORTP. The 5.0% and 2.5% residual interest commences on achievement by JPM of a contractually stipulated return that triggers the ORTP Flip Date. The actual ORTP Flip Date is not known with certainty. This residual 5.0% and 2.5% interest represents a noncontrolling interest and is not subject to mandatory redemption or guaranteed payments.

Our voting rights in ORTP are based on a capital structure that is comprised of Class A and Class B membership units. Through Ormat Nevada, we own all of the Class A membership units, which represent 75.0% of the voting rights in ORTP. JPM owns all of the Class B membership units, which represent 25.0% of the voting rights of ORTP. Other than in respect of customary protective rights, all operational decisions in ORTP are decided by the vote of a majority of the membership units. Ormat Nevada retains the controlling voting interest in ORTP both before and after the ORTP Flip Date and therefore will continue to consolidate ORTP.

Liquidity Impact of Uncertain Tax Positions

As discussed in Note 11 to our condensed consolidated financial statements set forth in Item 1 of this quarterly report, we have a liability associated with unrecognized tax benefits and related interest and penalties in the amount of approximately $7.1 million as of September 30, 2015. This liability is included in long-term liabilities in our condensed consolidated balance sheet, because we generally do not anticipate that settlement of the liability will require payment of cash within the next twelve months. We are not able to reasonably estimate when we will make any cash payments required to settle this liability.

Dividends

The following are the dividends declared by us since September 30, 2013:

Date Declared	Dividend Amount per Share		Record Date	Payment Date
November 6, 2013	$	0.04	November 20, 2013	December 4, 2013
February 25, 2014	$	0.06	March 13, 2014	March 27, 2014
May 8, 2014	$	0.05	May 21, 2014	May 30, 2014
August 5, 2014	$	0.05	August 19, 2014	August 28, 2014
November 5, 2014	$	0.05	November 20, 2014	December 4, 2014
February 24, 2015	$	0.08	March 16, 2015	March 27, 2015
May 6, 2015	$	0.06	May 19, 2015	May 27, 2015
August 3, 2015	$	0.06	August 18, 2015	September 2, 2015
November 3, 2015	$	0.06	November 18, 2015	December 2, 2015

Historical Cash Flows

The following table sets forth the components of our cash flows for the periods indicated:

	Nine Months Ended September 30,
	2015			2014
	(Dollars in thousands)
Net cash provided by operating activities	$	122,965		$	178,770
Net cash used in investing activities		(76,538	)		(135,435	)
Net cash provided by (used in) financing activities		84,884			(58,238	)
Net change in cash and cash equivalents		131,311			(14,903	)

For the Nine Months Ended September 30, 2015

Net cash provided by operating activities for the nine months ended September 30, 2015 was $123.0 million, compared to $178.8 million for the nine months ended September 30, 2014. The net decrease of $55.8 million resulted primarily from (i) an increase in billing in excess of costs and estimated earnings on uncompleted contracts, net of $11.2 million in our Product segment in the nine months ended September 30, 2015, compared to $43.8 million in the nine months ended September 30, 2014, as a result of timing in billing of our customers; (ii) a decrease in accounts payable and accrued expenses, of $22.2 million in the nine months ended September 30, 2015, compared to $10.9 million in the nine months ended September 30, 2014, as a result of timing in payments of our payables; (iii) an increase in receivables, of $2.9 million in the nine months ended September 30, 2015, compared to a decrease of $21.6 million in the nine months ended September 30, 2014, as a result of timing of collection from our customers; and (iv) a decrease in deferred income tax liabilities of $34.6 million in the nine months ended September 30, 2015 due to the deferred tax asset in Kenya, as discussed above, compared to an increase of $13.1 million in the nine months ended September 30, 2014. The decrease was partially offset by the increase in cash inflow due to higher net income of $51.3 million, from $47.9 million for the nine months ended September 30, 2014 to $99.2 million for the nine months ended September 30, 2015 as described above.

Net cash used in investing activities for the nine months ended September 30, 2015 was $76.5 million, compared to $135.4 million for the nine months ended September 30, 2014. The principal factors that affected our net cash used in investing activities during the nine months ended September 30, 2015 were: (i) capital expenditures of $117.6 million, primarily for our facilities under construction, reduced by a net decrease of $22.7 million in restricted cash, and cash equivalents due to timing of debt repayments, and $15.4 million derived from cash of Ormat Industries due to the share exchange. The principal factors that affected our net cash used in investing activities during the nine months ended September 30, 2014 were capital expenditures of $122.6 million, primarily for our facilities under construction and a net increase of $76.4 million in restricted cash, and cash equivalents, due to timing of debt repayments, reduced by cash grant of $27.4 million received from the U.S. Treasury under Section 1603 of the ARRA relating to our Don A. Campbell geothermal power plant and our G1 refurbishment power plant at the Mammoth Complex and (ii) $35.3 million cash received due to the sale of the Heber Solar.

Net cash provided by financing activities for the nine months ended September 30, 2015 was $84.9 million, compared to $58.2 million used in for the nine months ended September 30, 2014. The principal factors that affected the net cash provided by financing activities during the nine months ended September 30, 2015 were: net proceeds from issuance of shares to noncontrolling interest in the amount of $156.8 million, and $42.0 million of proceeds from a term loan for our Amatitlan power plant, reduced by: (i) $30.6 million of cash paid to repurchase our OFC Senior Secured Notes; (ii) the repayment of long-term debt in the amount of $40.5 million; (iii) a net decrease of $20.3 million against our revolving lines of credit with commercial banks; and (iv) $9.8 million cash dividend paid. The principal factors that affected our net cash used in financing activities during the nine months ended September 30, 2014 were: (i) net repayment of $83.9 million under our revolving credit lines with commercial banks; (ii) the repayment of long-term debt in the amount of $80.2 million; (iii) $12.9 million of cash paid to repurchase our OFC Senior Secured Notes; (iv) $7.3 million cash dividend paid; and (v) $9.2 million of cash paid to non-controlling interest, reduced by $140.0 million of proceeds from sale of series C Senior Secured Notes in August 2014 by OFC2 to finance a portion of the construction costs of Phase 2 of the McGinness Hills facility.

EBITDA and Adjusted EBITDA

We calculate EBITDA as net income before interest, taxes, depreciation and amortization. We calculate Adjusted EBITDA as net income before interest, taxes, depreciation and amortization, adjusted for (i) termination fees, (ii) impairment of long-lived assets, (iii) write-off of unsuccessful exploration activities, (iv) any mark-to-market gains or losses from accounting for derivatives, (v) merger and acquisition transaction costs (vi) stock-based compensation, and (vii) gain from extinguishment of liability. EBITDA and Adjusted EBITDA are not measurements of financial performance or liquidity under accounting principles generally accepted in the United States of America, or U.S. GAAP, and should not be considered as an alternative to cash flow from operating activities or as a measure of liquidity or an alternative to net earnings as indicators of our operating performance or any other measures of performance derived in accordance with U.S. GAAP. EBITDA and Adjusted EBITDA are presented because we believe they are frequently used by securities analysts, investors and other interested parties in the evaluation of a company’s ability to service and/or incur debt. However, other companies in our industry may calculate EBITDA and Adjusted EBITDA differently than we do.

Adjusted EBITDA for the three months ended September 30, 2015 was $79.0 million, compared to $69.1 million for the three months ended September 30, 2014. Adjusted EBITDA for the nine months ended September 30, 2015 was $212.2 million, compared to $204.4 million for the nine months ended September 30, 2014.

The following table reconciles net cash provided by operating activities to EBITDA and Adjusted EBITDA for the three and nine-month periods ended September 30, 2015 and 2014:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014

Net cash provided by operating activities	$	10,239		$	75,191		$	122,965		$	178,770
Adjusted for:
Interest expense, net (excluding amortization of deferred financing costs)		15,244			20,038			47,571			59,366
Interest income		(53	)		(35	)		(106	)		(236	)
Income tax provision		(38,211	)		6,444			(26,696	)		17,731
Minority interest in earnings of subsidiaries		-			-			-			-
Adjustments to reconcile net income to net cash provided by operating activities (excluding depreciation and amortization)		91,326			(32,404	)		56,699			(56,062	)

EBITDA		78,545			69,234			200,433			199,569
Mark-to-market on derivatives which represent swap contracts on natural gas and oil prices		-			(4,165	)		4,129			(4,467	)
Stock-based compensation		921			1,502			3,077			4,308
Gain on sale of a subsidiary and property, plant and equipment		-			-			-			(7,628	)
Loss from extinguishment of liability		-			-			1,710			-
Share exchange transaction costs		-			-			3,800			-
Write-off of insuccessful exploration activities		185			-			359			8,107
Mark-to-market on derivatives which represent currency forward contracts		(645	)		2,537			(1,335	)		4,473
Adjusted EBITDA	$	79,006		$	69,108		$	212,173		$	204,362
Net cash used in investing activities	$	2,895		$	(106,423	)	$	(76,538	)	$	(135,435	)
Net cash used in financing activities	$	20,742		$	(6,437	)	$	84,884		$	(58,238	)

Capital Expenditures

Our capital expenditures primarily relate to two principal components: (i) the enhancement of our existing power plants and (ii) the development and construction of new power plants.

The following is an overview of projects that are fully released for construction:

Olkaria III Plant Four (Kenya). We are currently developing phase four of our Olkaria III complex. The additional 24 MW power plant will bring the complex’s total capacity to 134 MW. Field development, equipment manufacturing and site construction are all in an advanced stage. We recently signed an amended and restated 20 year PPA with KPLC. Phase four is expected to come on line in the first quarter of 2016.

Sarulla (Indonesia). We are part of a consortium that is currently developing the approximately 330 MW Sarulla project in Tapanuli Utara North Sumatra, Indonesia. The project will be constructed in three phases of approximately 110 MW each, utilizing both steam and brine extracted from the geothermal field to increase the power plant’s efficiency. The first phase of operations is expected to commence towards the end of 2016 and the remaining two phases of operations are scheduled to commence within 18 months thereafter. Engineering, procurement and construction are in progress. The infrastructure work has been substantially completed and major equipment, including Ormat’s partial OECs and Toshiba’s steam turbine have arrived in country. The drilling of production and injection wells is also in progress in all three phases. However, the project company is experiencing delays in drilling and in reaching EPC milestones, as well as cost overruns, mainly in the field development of the second and third phases of the project. The consortium members are currently examining the significance of these cost overruns and their implications for the project's budget as well as for the financing of the project (as described in Footnote 4 of the financial statements). All the scheduled milestones under Ormat’s supply agreement were achieved and the manufacturing work is currently progressing as planned.

The Sarulla project will be owned and operated by the consortium members under the framework of a Joint Operating Contract (JOC) and Energy Sales Contract (ESC). Under the JOC, PT Pertamina Geothermal Energy (PGE), the concession holder for the project, has provided the consortium with the right to use the geothermal field, and under the ESC, PT PLN, the state electric utility, will be the off-taker at Sarulla for a period of 30 years.

Heber 1 Power Plant. We are currently in the process of enhancing the Heber complex located in Imperial Valley, California. We drilled two additional wells in 2013 and four old wells were decommissioned. We intend to drill an additional well in 2015 and perform upgrades to surface equipment, following which we expect the capacity of the complex to reach 92MW. In 2013, we entered into a new PPA with SCPPA, which will replace the current Heber 1 PPA upon expiration that is expected at the end of 2015.

Platanares Project (Honduras). We are currently developing the Geotermica Platanares geothermal project in Honduras. We are appraising the well field and we will determine the expected capacity, which we anticipate in the first phase will be approximately 18MW.

The following is an overview of projects that are in an initial stage of construction:

Carson Lake Project. We plan to develop the 20 MW Carson Lake project on Bureau of Land Management (BLM) leases located in Churchill County, Nevada. Permitting documentation for the power plant was completed; however, we are still experiencing delays in the permitting process for the transmission line. We are not planning to invest material capital expenditures in this project in 2015.

CD 4 Project. We plan to develop 30 MW of new capacity at the Mammoth complex, on land which is comprised mainly of BLM leases. We have commenced field development and drilled one production well and one injection well. Continued drilling is subject to receipt of additional permits. As part of the process to secure transmission capacity and interconnection, we are participating in the SCE Wholesale Distribution Access Tariff Transition Cluster Generator Interconnection Process to deliver energy into the Southern California Edison system at the Casa Diablo Substation. We are not planning to invest material capital expenditures in this project in 2015.

We have estimated approximately $72 million in capital expenditures for the Olkaria III plant four that was fully released for construction and for enhancement of our existing power plants, in which we have invested approximately $62 million as of September 30, 2015. We expect to invest approximately $9 million of such total during the remainder of 2015 and the remaining approximately $1.5 million thereafter.

In addition, we estimate approximately $9 million in additional capital expenditures in the remainder of 2015 to be allocated as follows: (i) approximately $1.0 million in development of new projects; (ii) approximately $7 million for maintenance capital expenditures for our operating power plants and (iii) approximately $1 million in exploration activities related to various leases for geothermal resources in which we have started the exploration activity. In the aggregate, we estimate our total capital expenditures for the remainder of 2015 will be approximately $18 million.

Exposure to Market Risks

Based on current conditions, we believe that we have sufficient financial resources to fund our activities and execute our business plans. However, the cost of obtaining financing for our project needs may increase significantly or such financing may be difficult to obtain.

One market risk to which power plants are typically exposed is the volatility of electricity prices. Our exposure to such market risk is currently limited because many of our long-term PPAs (except for the 25 MW PPA for the Puna complex and the PPAs of the Heber 1 and 2 power plants in the Heber complex, the Ormesa complex and the G2 power plant in the Mammoth complex) have fixed or escalating rate provisions that limit our exposure to changes in electricity prices.

Since May 2012, the energy payments under the PPAs of the Heber 1 and 2 power plants in the Heber complex, the Ormesa complex and the G2 power plant in Mammoth complex are determined by reference to the relevant power purchaser’s SRAC. A decline in the price of natural gas, which is principal component of electricity production costs in California, will result in a decrease in the cost that the power purchaser avoids by not generating its electrical energy needs, which in turn will reduce the variable energy rate that we may charge under the relevant PPA for these power plants. In March 2014 and May 2015, we entered into derivative transactions to reduce our exposure to the price of natural gas under these PPAs, until March 31, 2015 and December 31, 2015, respectively. The Puna complex is currently benefiting from energy prices which are higher than the floor price under the 25 MW PPA for the Puna complex as a result of the high fuel costs that impact HELCO avoided costs. Likewise, in October 2013, we entered into a derivative transaction to reduce our exposure to the price of oil under the 25 MW PPA of the Puna complex, until December 31, 2014.

As of September 30, 2015, 94.1% of our consolidated long-term debt comprised a fixed rate debt and therefore was not subject to interest rate volatility risk. As of such date, 5.9% of our long-term debt was in the form of a floating rate instrument, exposing us to changes in interest rates in connection therewith. As of September 30, 2015, $56.5 million of our long-term debt remained subject to some floating rate risk.

We currently maintain our surplus cash in short-term, interest-bearing bank deposits, money market securities and commercial paper (with a minimum investment grade rating of AA by Standard & Poor’s Ratings Services (.

Our cash equivalents are subject to market risk due to changes in interest rates. Fixed rate securities may have their market value adversely impacted due to a rise in interest rates, while floating rate securities may produce less income than expected if interest rates fall. Due in part to these factors, our future investment income may fall short of expectation due to changes in interest rates or we may suffer losses in principal if we are forced to sell securities that decline in market value due to changes in interest rates.

Another market risk to which we are exposed is potential adverse changes in foreign currency exchange rates, in particular the fluctuation of the U.S. dollar versus the NIS. Risks attributable to fluctuations in currency exchange rates can arise when we or any of our foreign subsidiaries borrow funds or incur operating or other expenses in one type of currency but receive revenue in another. In such cases, an adverse change in exchange rates can reduce such subsidiary’s ability to meet its debt service obligations, reduce the amount of cash and income we receive from such foreign subsidiary, or increase such subsidiary’s overall expenses. Risks attributable to fluctuations in foreign currency exchange rates can also arise when the currency denomination of a particular contract is not the U.S. dollar. Substantially all of our PPAs in the international markets are either U.S. dollar-denominated or linked to the U.S. dollar. Our construction contracts from time to time contemplate costs which are incurred in local currencies. The way we often mitigate such risk is to receive part of the proceeds from the sale contract in the currency in which the expenses are incurred. Currently, we have forward contracts in place to reduce our foreign currency exposure, and expect to continue to use currency exchange and other derivative instruments to the extent we deem such instruments to be the appropriate tool for managing such exposure. We do not believe that our exchange rate exposure has or will have a material adverse effect on our financial condition, results of operations or cash flows.

We performed a sensitivity analysis on the fair values of our swap contracts on oil prices, put options on natural gas prices, long-term debt obligations, and foreign currency exchange forward contracts. The swap contracts on oil prices, put options on natural gas prices and foreign currency exchange forward contracts listed below principally relate to trading activities. The sensitivity analysis involved increasing and decreasing forward rates at September 30, 2015 and December 31, 2014 by a hypothetical 10% and calculating the resulting change in the fair values.

The results of the sensitivity analysis calculations as of September 30, 2015 and December 31, 2014 are presented below:

	Assuming a 10% Increase in Rates						Assuming a 10% Decrease in Rates
Risk	September 30, 2015			December 31, 2014			September 30, 2015			December 31, 2014		Change in the Fair Value of
	(Dollars in thousands)
NGI Price	$	(287	)	$	(685	)	$	287		$	685	NGI Swap
Foreign Currency		(4,294	)		(6,720	)		1,807			1,809	Foreign currency forward contracts
Interest Rate		(445	)		(1,102	)		454			1,129	OFC
Interest Rate		(698	)		(921	)		714			945	OrCal
Interest Rate		(9,538	)		(10,155	)		10,180			10,861	OFC 2
Interest Rate		(158	)		(244	)		160			249	Loan from DEG
Interest Rate		(9,399	)		(10,211	)		9,941			10,825	Loan from OPIC
Interest Rate		(2,111	)		(3,336	)		2,134			3,389	Senior unsecured bonds
Interest Rate		-	⁽¹⁾		-			-	⁽¹⁾		-	Amatitlan Loan

⁽¹⁾ The application of 10% increase to the interest rate, did not exceed the minimum rate as set in the credit agreement.

Effect of Inflation

We expect that inflation will not be a significant risk in the near term, given the current global economic conditions, however, that could change in the future. To address rising inflation, some of our contracts include certain mitigating factors against any inflation risk.

In connection with the Electricity segment, inflation may directly impact an expense incurred for the operation of our projects, hence increasing the overall operating cost to us. The negative impact of inflation may be partially offset by price adjustments built into some of our PPAs that could be triggered upon such occurrences. The energy payments pursuant to the PPAs for the Brady power plant, the Steamboat 2 and 3 power plant, the Steamboat Hills power plant, and the Burdette power plant increase every year through the end of the relevant terms of such agreements, though such increases are not directly linked to the CPI or any other inflationary index. Lease payments are generally fixed, while royalty payments are generally determined as a percentage of revenue and therefore are not significantly impacted by inflation. In our Product segment, inflation may directly impact fixed and variable costs incurred in the construction of our power plants, hence increasing our operating costs in that segment. In this segment, it is more likely that we will be able to offset part or all of the inflationary impact through our project pricing. With respect to power plants that we construct for our own electricity production, inflationary pricing may impact our operating costs which may be partially offset in the pricing of the new long-term PPAs that we negotiate.

Concentration of Credit Risk

Our credit risk is currently concentrated with the following major customers: Southern California Edison, HELCO, KPLC and Sierra Pacific Power Company and Nevada Power Company (subsidiaries of NV Energy). If any of these electric utilities fails to make payments under its PPAs with us, such failure would have a material adverse impact on our financial condition.

Sierra Pacific Power Company and Nevada Power Company accounted for 15.3% and 14.7% of our total revenue for the three months ended September 30, 2015 and 2014, respectively and 19.3% and 16.6% for the nine months ended September 30, 2015 and 2014, respectively.

Southern California Edison accounted for 13.4% and 19.9% of our total revenue for the three months ended September 30, 2015 and 2014, respectively and 11.1% and 15.2% for the nine months ended September 30, 2015 and 2014, respectively. Southern California Edison is also the power purchaser and revenue source for our Mammoth project, which we accounted for separately under the equity method of accounting through August 1, 2010.

HELCO accounted for 4.9% and 7.6% of our total revenue for the three months ended September 30, 2015 and 2014, respectively and 5.2% and 8.9% for the nine months ended September 30, 2015 and 2014, respectively.

KPLC accounted for 13.5% and 15.8% of our total revenue for the three months ended September 30, 2015 and 2014, respectively and 15.4% and 15.6% for the nine months ended September 30, 2015 and 2014, respectively.

Government Grants and Tax Benefits

The U.S. government encourages production of electricity from geothermal resources through certain tax subsidies. If we started construction of a new geothermal power plant in the U.S. by December 31, 2013, we are permitted to claim a tax credit against our U.S. federal income taxes equal to 30% of certain eligible costs when the project is placed in service. If we fail to meet the start of construction deadline for such a project, then the 30% credit is reduced to 10%. In lieu of the 30% tax credit (if the project qualifies), we are permitted to claim a tax credit based on the power produced from a geothermal power plant. These production-based credits, which in the first quarter of 2014 were 2.3 cents per kWh, are adjusted annually for inflation and may be claimed for ten years on the electricity produced by the project and sold to third parties after the project is placed in service. The owner of the power plant may not claim both the 30% tax credit and the production-based tax credit. Under current tax rules, any unused tax credit has a one-year carry back and a twenty-year carry forward. If we claim the ITC, our “tax basis” in the plant that we can recover through depreciation must be reduced by half of the ITC. If we claim the PTC, there is no reduction in the tax basis for depreciation. Companies that placed qualifying renewable energy facilities in service during 2009, 2010 or 2011 or that began construction of qualifying renewable energy facilities during 2009, 2010 or 2011 and placed them in service by December 31, 2013, may choose to apply for a cash grant from the U.S. Treasury in an amount equal to the ITC. Likewise, the tax basis for depreciation will be reduced by 50% of the cash grant received. Under the ARRA, the U.S. Treasury is instructed to pay the cash grant within 60 days of the application or the date on which the qualifying facility is placed in service.

On September 11, 2015, Kenya's Income Tax Act was amended pursuant to certain provisions of the recently adopted Finance Act, 2015. Among other matters, these amendments retain the enhanced investment deduction of 150% under Section 17B of the Income Tax Act, extend the period for deduction of tax losses from five years to ten years under Sections 15(4) and 15(5) of the Income Tax Act, and amend the effective date from January 1, 2016 to January 1, 2015 under Sections 15(4) and 15(5) of the Income Tax Act. Previously, we had a valuation allowance for the additional 50% investment deduction reducing our deferred tax asset in Kenya as the utilization of the related tax losses was not probable within the original five year carryforward period. As a result of the change in legislation and the expected continued profitability during the extended carryforward period, we expect that we will be able to fully utilize the carryforward tax losses within the ten year period and as such released the valuation allowance in Kenya resulting in a $49.4 million tax benefit in the three month period ended September 30, 2015.

Ormat Systems received “Benefited Enterprise” status under Israel’s Law for Encouragement of Capital Investments, 1959 (the Investment Law), with respect to two of its investment programs through 2011. In January 2011, new legislation amending the Investment Law was enacted. Under the new legislation, a uniform rate of corporate tax will apply to all qualified income of certain industrial companies, as opposed to the previous law’s incentives that are limited to income from a “Benefited Enterprise” during their benefits period. As a result, we now pay a uniform corporate tax rate of 16% with respect to that qualified income.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We incorporate by reference the information appearing under “Exposure to Market Risks” and “Concentration of Credit Risk” in Part I, Item 2 of this quarterly report on Form 10-Q.

ITEM 4. CONTROLS AND PROCEDURES

a. Evaluation of disclosure controls and procedures

Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures to ensure that the information required to be disclosed in our filings pursuant to Rule 13a-15 under the Securities and Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms and to ensure that such information is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. Based on that evaluation, as of September 30, 2015, our Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended) were effective.

b. Changes in internal controls over financial reporting

There were no changes in our internal controls over financial reporting in the third quarter of 2015 that have materially affected or are reasonably likely to materially affect our internal controls over financial reporting.

PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

There were no material developments in any legal proceedings to which the Company is a party during the third quarter of 2015, other than as described below.

●

●	On April 5, 2012, the International Brotherhood of Electrical Workers Local 1260 (“Union”) filed a petition with the National Labor Relations Board (“NLRB”) seeking to organize the operations and maintenance employees at the Puna Project. PGV lost the union election by a slim margin in May 2012. The election results and PGV’s obligation to negotiate with the Union were appealed to the United States Court of Appeals for the Ninth Circuit, but were remanded back to the NLRB after the Supreme Court of the United States’ decision in NLRB v. Noel Canning, 573 U.S., 134 S.Ct. 2550 (2014). On November 26, 2014, the NLRB found that a certification of representative should be issued. In January 2015, the parties submitted a briefing to the NLRB as to whether summary judgment is appropriate. On June 26, 2015, the Board rejected PGV's arguments and ordered PGV to recognize the Union. On June 30, 2015, PGV appealed the NLRB decision to the United States Court of Appeals for the DC Circuit. The NLRB also filed a complaint and requested a hearing on December 8, 2015, to bring unfair labor practice allegations before an administrative law judge even though the charges turn in large part on the disposition of the appeal. The Company believes that there are valid defenses under law.

●	In January 2014, Ormat learned that two former employees filed a "qui tam" complaint seeking damages, penalties and other relief, alleging that the Company and certain of its subsidiaries (collectively, the "Ormat Parties"), submitted fraudulent applications and certifications to obtain grants for the Puna and North Brawley projects. The United States Department of Justice declined to intervene. . The complaint, which is pending before the United States District Court for the District of Nevada, has entered the discovery stage. On July 7, 2015, the Court issued a protective order stipulating limitations against the relators for the benefit of the Ormat Parties, to ensure the protection of confidentiality for sensitive Ormat Parties’ documents. The Ormat Parties believe that the allegations of the lawsuit have no merit, and will continue to defend themselves vigorously.

●

ITEM 1A. RISK FACTORS

A comprehensive discussion of our other risk factors is included in the “Risk Factors” section of our annual report on Form 10-K for the year ended December 31, 2014 filed with the SEC on February 26, 2015.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable

ITEM 5. OTHER INFORMATION

Not applicable.

ITEM 6. EXHIBITS

We hereby file, as exhibits to this quarterly report, those exhibits listed on the Exhibit Index immediately following the signature page hereto.

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.

	ORMAT TECHNOLOGIES, INC.

	By:	/s/ DORON BLACHAR
		Name: Doron Blachar
		Title: Chief Financial Officer
Date: November 5, 2015

EXHIBIT INDEX

Exhibit No.		Document

	3.1	Second Amended and Restated Certificate of Incorporation, incorporated by reference to Exhibit 3.1 to Ormat Technologies, Inc. Registration Statement on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on July 20, 2004.

	3.2	Fourth Amended and Restated By-laws, incorporated by reference to Exhibit 3.2 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on January 2, 2013.

	3.3	Amended and Restated Limited Liability Company Agreement of OPC LLC dated June 7, 2007, by and among Ormat Nevada Inc., Morgan Stanley Geothermal LLC, and Lehman-OPC LLC, incorporated by reference to Exhibit 3.1 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on June 13, 2007.

	3.4	Limited Liability Company Agreement of ORTP, LLC dated as of January 24, 2013, between Ormat Nevada, Inc., a wholly-owned subsidiary of Ormat Technologies, Inc., and JPM Capital Corporation, incorporated by reference to Exhibit 10.1 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on January 30, 2013.

	3.5	Amended and Restated Limited Liability Company Agreement of ORPD LLC, dated as of April 30, 2015, by and among Ormat Nevada Inc., Northleaf Geothermal Holdings LLC and ORPD Holdings LLC, incorporated by reference to Exhibit 3.5 to Ormat Technologies, Inc. Quarterly Report on Form 10-Q for the quarter ended March 31, 2015.

	4.1	Form of Common Share Stock Certificate, incorporated by reference to Exhibit 4.1 to Ormat Technologies, Inc. Registration Statement on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on July 20, 2004.

	4.2	Form of Preferred Share Stock Certificate, incorporated by reference to Exhibit 4.2 to Ormat Technologies, Inc. Registration Statement on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on July 20, 2004.

	4.3	Form of Rights Agreement by and between Ormat Technologies, Inc. and American Stock Transfer & Trust Company, incorporated by reference to Exhibit 4.3 to Ormat Technologies, Inc. Registration Statement Amendment No. 2 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on October 22, 2004.

	4.4	Indenture for Senior Debt Securities, dated as of January 16, 2006, between Ormat Technologies, Inc. and Union Bank of California, incorporated by reference to Exhibit 4.2 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-3 (File No. 333-131064) to the Securities and Exchange Commission on January 26, 2006.

	4.5	Indenture for Subordinated Debt Securities, dated as of January 16, 2006, between Ormat Technologies, Inc. and Union Bank of California, incorporated by reference to Exhibit 4.3 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-3 (File No. 333-131064) to the Securities and Exchange Commission on January 26, 2006.

	4.6	Deed of Trust, dated as of August 3, 2010, between Ormat Technologies, Inc. and Ziv Haft Trust Company Ltd., as trustee, incorporated by reference to Exhibit 4.1 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on February 2, 2011.

	4.7	Addendum, dated as of January 27, 2011, to the Deed of Trust, dated as of August 3, 2010, between Ormat Technologies, Inc. and Ziv Haft Trust Company Ltd., as trustee, incorporated by reference to Exhibit 4.2 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on February 2, 2011.

	4.8	Form of Bond issued pursuant to the Deed of Trust, dated as of August 3, 2010 (as amended or supplemented), between Ormat Technologies, Inc. and Ziv Haft Trust Company Ltd., as trustee, incorporated by reference to Exhibit 4.3 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on February 2, 2011.

	4.9	Second Addendum, dated as of February 11, 2011, to the Deed of Trust, dated as of August 3, 2010 (as amended or supplemented), between Ormat Technologies, Inc. and Ziv Haft Trust Company Ltd., as trustee, incorporated by reference to Exhibit 4.7 to Ormat Technologies, Inc. Quarterly Report on Form 10-Q to the Securities and Exchange Commission on May 6, 2011.

	4.10	Indenture of Trust and Security Agreement, dated September 23, 2011, among OFC 2 LLC, ORNI 15 LLC, ORNI 39 LLC, ORNI 42 LLC, HSS II, LLC, and Wilmington Trust Company, as Trustee and Depository, incorporated by reference to Exhibit 4.8 to Ormat Technologies, Inc. Quarterly Report on Form 10-Q to the Securities and Exchange Commission on November 4, 2011..

	4.11	Third Addendum, dated as of December 1, 2011, to a Deed of Trust, dated as of August 3, 2010 as amended on January 31, 2011 (effective as of January 27, 2011) and on February 13, 2011, between Ormat Technologies, Inc. and Mishmeret — Trusts Services Company Ltd. (formerly Ziv Haft Trust Company Ltd.), as trustee, incorporated by reference to Exhibit 4.1 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on December 1, 2011.

	31.1	Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, filed herewith.

	31.2	Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, filed herewith.

	32.1	Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, furnished herewith.

	32.2	Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, furnished herewith.

	101.IN*	XBRL Instance Document.

	101.SC*	XBRL Taxonomy Extension Schema Document.

	101.CA*	XBRL Taxonomy Extension Calculation Linkbase Document.

	101.DE*	XBRL Taxonomy Extension Definition Linkbase Document.

	101.LA*	XBRL Taxonomy Extension Label Linkbase Document.

	101.PR*	XBRL Taxonomy Extension Presentation Linkbase Document.