ora20160818_10q.htm

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):

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 09, 2016, the number of outstanding shares of common stock, par value $0.001 per share, was 49,634,659.

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.

	September 30,			December 31,
	2016			2015
	(Dollars in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	90,066		$	185,919
Restricted cash and cash equivalents (all related to VIEs)		50,525			49,503
Receivables:
Trade		65,198			55,301
Other		13,645			7,885
Inventories		12,973			18,074
Costs and estimated earnings in excess of billings on uncompleted contracts		38,025			25,120
Prepaid expenses and other		38,940			33,334
Total current assets		309,372			375,136
Deposits and other		18,738			17,968
Deferred charges		40,690			42,811
Property, plant and equipment, net ($1,499,112 and $1,481,258 related to VIEs, respectively)		1,570,307			1,559,335
Construction-in-process ($82,476 and $129,165 related to VIEs, respectively)		271,853			248,835
Deferred financing and lease costs, net		5,188			4,022
Intangible assets, net		56,052			25,875
Goodwill		7,071			—
Total assets	$	2,279,271		$	2,273,982

LIABILITIES AND EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	102,854		$	91,955
Billings in excess of costs and estimated earnings on uncompleted contracts		37,134			33,892
Current portion of long-term debt:
Limited and non-recourse (all related to VIEs):
Senior secured notes		28,121			29,930
Other loans		21,494			21,495
Full recourse		12,302			11,229
Total current liabilities		201,905			188,501
Long-term debt, net of current portion:
Limited and non-recourse (all related to VIEs):
Senior secured notes (less deferred financing costs of $9,957 and $10,852, respectively)		273,017			294,476
Other loans (less deferred financing costs of $6,821 and $7,492, respectively)		267,210			275,888
Full recourse:
Senior unsecured bonds (plus unamortized premium based upon 7% of $0 and $513, respectively and less deferred financing costs of $849 and $283, respectively)		203,483			249,698
Other loans (less deferred financing costs of $290 and $435, respectively)		12,373			18,687
Accumulated losses of unconsolidated company in excess of investment		16,664			8,100
Liability associated with sale of tax benefits		1,043			11,665
Deferred lease income		55,460			58,099
Deferred income taxes		34,961			32,654
Liability for unrecognized tax benefits		10,260			10,385
Liabilities for severance pay		19,020			19,323
Asset retirement obligation		22,099			20,856
Other long-term liabilities		20,862			1,776
Total liabilities		1,138,357			1,190,108
Commitments and contingencies (Note 10)

Reedemable noncontrolling interest		4,972			—

Equity:
The Company's stockholders' equity:
Common stock, par value $0.001 per share; 200,000,000 shares authorized; 49,634,659 and 49,107,901 shares issued and outstanding as of September 30, 2016 and December 31, 2015, respectively		50			49
Additional paid-in capital		859,855			849,223
Retained earnings		191,627			148,396
Accumulated other comprehensive income		(11,503	)		(7,667	)
		1,040,029			990,001
Noncontrolling interest		95,913			93,873
Total equity		1,135,942			1,083,874
Total liabilities and equity	$	2,279,271		$	2,273,982

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
	(Dollars in thousands, except per share data)						(Dollars in thousands, except per share data)
Revenues:
Electricity	$	109,795		$	97,245		$	321,664		$	278,124
Product		74,822			65,607			174,408			145,446
Total revenues		184,617			162,852			496,072			423,570
Cost of revenues:
Electricity		66,481			61,501			192,410			179,604
Product		43,647			42,019			99,504			89,826
Total cost of revenues		110,128			103,520			291,914			269,430
Gross margin		74,489			59,332			204,158			154,140
Operating expenses:
Research and development expenses		1,086			335			2,030			1,112
Selling and marketing expenses		4,793			4,383			12,136			12,099
General and administrative expenses		19,093			7,950			36,625			25,597
Write-off of unsuccessful exploration activities		1,294			185			2,714			359
Operating income		48,223			46,479			150,653			114,973
Other income (expense):
Interest income		266			53			831			106
Interest expense, net		(17,137	)		(17,748	)		(51,561	)		(54,435	)
Derivatives and foreign currency transaction gains (losses)		(222	)		1,296			(2,592	)		(641	)
Income attributable to sale of tax benefits		3,463			8,634			12,380			18,917
Other non-operating income (expense), net		(5,546	)		(131	)		(5,306	)		(1,523	)
Income from continuing operations before income taxes and equity in losses of investees		29,047			38,583			104,405			77,397
Income tax (provision) benefit		(11,988	)		38,211			(29,387	)		26,696
Equity in losses of investees, net		(2,653	)		(3,133	)		(4,734	)		(4,892	)
Income from continuing operations		14,406			73,661			70,284			99,201
Net income attributable to noncontrolling interest		(2,326	)		(1,522	)		(4,584	)		(2,616	)
Net income attributable to the Company's stockholders	$	12,080		$	72,139		$	65,700		$	96,585
Comprehensive income:
Net income		14,406			73,661			70,284			99,201
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		1,337			(4,318	)		(3,829	)		(4,154	)
Loss in respect of derivative instruments designated for cash flow hedge		22			22			65			68
Amortization of unrealized gains in respect of derivative instruments designated for cash flow hedge		(24	)		(29	)		(72	)		(90	)
Comprehensive income		15,741			69,336			66,448			95,025
Comprehensive income attributable to noncontrolling interest		(2,326	)		(1,522	)		(4,584	)		(2,616	)
Comprehensive income attributable to the Company's stockholders	$	13,415		$	67,814		$	61,864		$	92,409
Earnings per share attributable to the Company's stockholders:
Basic:
Net income	$	0.24		$	1.47		$	1.33		$	2.00
Diluted:
Net income	$	0.24		$	1.41		$	1.31		$	1.93
Weighted average number of shares used in computation of earnings per share attributable to the Company's stockholders:
Basic		49,599			49,023			49,410			48,388
Diluted		50,289			51,113			50,097			50,011
Dividend per share declared	$	0.07		$	0.06		$	0.45		$	0.20

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

	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, 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		2,996		3		26,012		—			—			26,015			—			26,015
Cash paid to non controlling 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:
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
Balance at December 31, 2015		49,107	$	49	$	849,223	$	148,396		$	(7,667	)	$	990,001		$	93,873		$	1,083,874

Stock-based compensation		—		—		3,383		—			—			3,383			—			3,383
Exercise of options by employees and directors		528		1		7,249		—			—			7,250			—			7,250
Cash paid to noncontrolling interest		—		—		—		—			—			—			(10,622	)		(10,622	)
Cash dividend declared, $0.45 per share		—		—		—		(22,469	)		—			(22,469	)		—			(22,469	)
Increase in noncontrolling interest in GB		—		—		—		—			—			—			8,272			8,272
Net income		—		—		—		65,700			—			65,700			4,390			70,090
Other comprehensive income (loss), net of related taxes:
Loss in respect of derivative instruments designated for cash flow hedge (net of related tax of $40)		—		—		—		—			65			65			—			65
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)		—		—		—		—			(3,829	)		(3,829	)		—			(3,829	)
Amortization of unrealized gains in respect of derivative instruments designated for cash flow hedge (net of related tax of $44)		—		—		—		—			(72	)		(72	)		—			(72	)

Balance at September 30, 2016		49,635	$	50	$	859,855	$	191,627		$	(11,503	)	$	1,040,029		$	95,913		$	1,135,942

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

	Nine Months Ended September 30,
	2016			2015
	(Dollars in thousands)
Cash flows from operating activities:
Net income	$	70,284		$	99,201
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		77,565			80,463
Amortization of premium from senior unsecured bonds		(513	)		(230	)
Accretion of asset retirement obligation		1,243			1,140
Stock-based compensation		3,383			3,077
Amortization of deferred lease income		(2,014	)		(2,014	)
Income attributable to sale of tax benefits, net of interest expense		(5,920	)		(13,068	)
Equity in losses of investees		4,735			4,893
Mark-to-market of derivative instruments		(381	)		3,906
Loss on disposal of property, plant and equipment		—			531
Write-off of unsuccessful exploration activities		2,714			360
Gain on severance pay fund asset		(690	)		(102	)
Deferred income tax provision		20,742			(34,613	)
Liability for unrecognized tax benefits		(125	)		(399	)
Deferred lease revenues		(625	)		(221	)
Other		—			484
Changes in operating assets and liabilities, net of amounts acquired:
Receivables		(13,711	)		(2,879	)
Costs and estimated earnings in excess of billings on uncompleted contracts		(12,905	)		13,334
Inventories		5,339			335
Prepaid expenses and other		(5,364	)		(3,033	)
Deposits and other		(867	)		(294	)
Accounts payable and accrued expenses		10,463			(21,904	)
Due from/to related entities, net		—			451
Billings in excess of costs and estimated earnings on uncompleted contracts		3,242			(2,108	)
Liabilities for severance pay		(369	)		(1,573	)
Other long-term liabilities		1,801			(2,259	)
Due from/to Parent		—			(513	)
Net cash provided by operating activities		158,027			122,965
Cash flows from investing activities:
Cash acquired in organizational restructuring and share exchange with parent		—			15,391
Net change in restricted cash, cash equivalents and marketable securities		(1,022	)		22,725
Capital expenditures		(107,951	)		(117,588	)
Cash paid for acquisition of controlling interest in a subsidiary, net of cash acquired		(18,135	)		—
Decrease in severance pay fund asset, net of payments made to retired employees		1,919			2,934
Net cash used in investing activities		(125,189	)		(76,538	)
Cash flows from financing activities:
Proceeds from exercise of options by employees		7,250			4,612
Proceeds from issuance of senior unsecured notes, net of transaction costs		203,483			—
Purchase of Senior unsecured notes		(249,468	)		—
Purchase of OFC Senior Secured Notes		(6,815	)		(30,638	)
Proceeds from sale of membership interests to uncontrolling interest, net of transaction costs		—			156,761
Proceeds from long-term loans, net at transaction costs		—			42,000
Proceeds from revolving credit lines with banks		259,900			598,800
Repayment of revolving credit lines with banks		(259,900	)		(619,100	)
Cash received from non-controlling interest		1,972			1,654
Repayments of long-term debt		(40,997	)		(40,532	)
Cash paid to noncontrolling interest		(17,296	)		(13,863	)
Payments of capital leases		(845	)		—
Deferred debt issuance costs		(3,506	)		(5,038	)
Cash dividends paid		(22,469	)		(9,772	)
Net cash provided by (used in) financing activities		(128,691	)		84,884
Net change in cash and cash equivalents		(95,853	)		131,311
Cash and cash equivalents at beginning of period		185,919			40,230
Cash and cash equivalents at end of period	$	90,066		$	171,541
Supplemental non-cash investing and financing activities:
Increase (decrease) in accounts payable related to purchases of property, plant and equipment	$	(4,517	)	$	18,930
Accrued liabilities related to financing activities	$	6,291		$	—

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

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, 2016, the consolidated results of operations and comprehensive income (loss) for the nine-month periods ended September 30, 2016 and 2015 and the consolidated cash flows for the nine-month periods ended September 30, 2016 and 2015.

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, 2016 are not necessarily indicative of the results to be expected for the year ending December 31, 2016.

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, 2015. The condensed consolidated balance sheet data as of December 31, 2015 was derived from the Company’s audited consolidated financial statements for the year ended December 31, 2015, 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.

Issuance of Senior Unsecured Bonds

On September 11, 2016, the Company concluded an auction tender and accepted subscriptions for $204 million aggregate principal amount of two tranches (approximately $67 million principal amount of Series 2 and approximately $137 million principal amount of Series 3) of senior unsecured bonds (Series 2 Bonds, Series 3 Bonds and, collectively, "Bonds"). The Bonds were issued in an unregistered offering outside the United States to investors who are not "U.S. persons",as such term is defined in Regulation S under the Securities Act of 1933, as amended (the "Securities Act"), and otherwise subject to the requirements of Regulation S. The "Series 2 Bonds" will mature in September 2020 and bear interest at a fixed rate of 3.7% per annum, payable semi-annually. The "Series 3 Bonds" will mature in September 2022 and bear interest at a fixed rate of 4.45% per annum, payable semi-annually. The Bonds will be repaid at maturity in a single bullet payment, unless earlier prepaid by Ormat pursuant to the terms and conditions of the trust instrument that governs the Bonds. Both tranches received a rating of ilA+ from Maloot S&P in Israel with a stable outlook. The Company used the proceeds from the offering and sale of the Bonds to fully prepay its existing senior unsecured bonds in the amount of $250 million. As a result of the prepayment, the Company recognized a loss in the amount of $5 million, including prepayment fees of approximately $5 million and amortization of premium of $0.3 million, which was included in other non-operating income (expense), net in the consolidated statements of operations and comprehensive income for the three and nine months ended September 30, 2016.

Guadeloupe power plant transaction

In July 2016, we announced that we closed the previously announced acquisition of Geothermie Bouillante SA (“GB”). GB owns and operates the 14.75 MW Bouillante geothermal power plant located in Guadeloupe Island, a French territory in the Caribbean, which currently generates approximately 13 MW. GB also owns two exploration licenses providing an expansion potential of up to 45 MW of capacity.

Pursuant to the terms of an Amended and Restated Investment Agreement (“Investment Agreement”) and Shareholders Agreement with Sageos Holding (“Sageos”), a wholly owned subsidiary of Bureau de Recherches Géologiques et Minières (“BRGM”), the Company together with Caisse des Dépôts et Consignations (“CDC”), a French state-owned financial organization, acquired an approximately 80% interest in GB, allocated 75% to the Company and 25% to CDC. The Company and CDC will gradually increase their combined interest in GB to 85% and Sageos will hold the remaining balance. As part of the agreement, CDC will pay the Company a premium.

Pursuant to the agreements, the Company paid approximately $20.6 million (of which approximately $2.0 million was paid in October 2016 as a subsequent adjustment to the purchase price) to Sageos for its approximately 60% interest in GB. In addition, the Company is committed to further invest $8.4 million (approximately €7.5 million) in the next two years, which will increase the Company’s interest to 63.75%. The cash will be used mainly for the enhancement of the power plant.

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The Company has planned modifications to the existing equipment as well as to further develop the asset, with a potential of reaching a total of 45 MW in phased development by 2021. Under the Investment Agreement, the Company will pay Sageos an additional amount of up to $13.4 million (approximately €12 million) subject to the achievement of agreed production thresholds and capacity expansion within a defined time period.

The Bouillante power plant sells its electricity under a 15-year PPA that was entered into in February 2016 with Électricité de France S.A. (“EDF”), the French electric utility. The Company plans to optimize the use of the resource at the existing facilities and recover its current production to its design capacity of 14.75 MW by mid-2017.

The Company accounted for the transaction based on the provision of Accounting Standard Codification 805, Business Combinations, and consequently recorded intangible asset of $33.0 million pertaining to the 15-year PPA with EDF and $7.1 million of goodwill. Additionally, following the transaction, the Company gained control over GB effective July 5, 2016 and consolidated the entity with redeemable noncontrolling interest of $5.0 million and noncontrolling interest of $8.3 million being recorded. The redeemable noncontrolling interest pertains to Sageos right to sell its equity interest in GB to the Company for cash considerations. The noncontrolling interest pertains to CDC and was included under noncontrolling interest in the consolidated statements of equity.

The revenues of GB of approximately $4.1 million were included in the Company’s consolidated statements of operations and comprehensive income for the three and nine months ended September 2016.

Alevo transaction

On March 30, 2016, the Company signed an agreement with a subsidiary of Alevo Group SA (“Alevo”), a leading provider of energy storage systems, to jointly build, own and operate the Rabbit Hill Energy Storage Project (“Rabbit Hill”) located in Georgetown, Texas. The Company will own and fund the majority of the costs associated with Rabbit Hill and, under the terms of the agreement, will provide engineering and construction services and balance of plant equipment. Alevo will provide its innovative GridBank™ inorganic lithium ion energy storage system in conjunction with the power conversion systems. In addition, Alevo will provide ongoing management and operations and maintenance services for the life of the project. The Company will hold an 85% interest in the Rabbit Hill project entity which will decrease to 50.1% after reaching certain internal rate of return (“IRR”) targets. The Company will consolidate Rabbit Hill as a majority owned indirect subsidiary.

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 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 (“Northleaf”).

We are currently finalizing the documentation related to the sale of a minority interest in the second phase of the Don A. Campbell power plant. Upon Ormat Nevada's contribution of the project to ORPD, Northleaf will pay to Ormat Nevada an amount equal to Northleaf proportionate interest in ORPD multiplied by the value of the project to be contributed. We estimate that Ormat Nevada will receive approximately $43 million cash in connection with the contribution, which is expected in the fourth quarter of 2016.

Deferred tax asset in Kenya

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 5 years to 10 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 $49.4 million of tax benefits in the three month period ended September 30, 2015.

OFC Senior Secured Notes prepayment

In September 2016, the Company repurchased $6.8 million aggregate principal amount of its OFC Senior Secured Notes from the OFC noteholders. As a result of the repurchase, the Company recognized a loss of $0.6 million, including amortization of deferred financing costs, which was included in other non-operating income (expense), net in the consolidated statements of operations and comprehensive income for the three and nine months ended September 30, 2016.

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

In June 2015, the Company repurchased $30.6 million aggregate principal amount of its OFC Senior Secured Notes from the OFC noteholders. As a result of the repurchase, the Company recognized a loss of $1.7 million, including amortization of deferred financing costs of $0.5 million, which was 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.

Other comprehensive income

For the nine months ended September 30, 2016 and 2015, the Company classified $7,000 and $22,000, respectively, from accumulated other comprehensive income, of which $11,000 and $35,000, respectively, were recorded to reduce interest expense and $4,000 and $13,000, 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, 2016 and 2015, the Company classified $2,000 and $7,000, respectively, related to derivative instruments designated as cash flow hedges, from accumulated other comprehensive income, of which $3,000 and $10,000, respectively, were recorded to reduce interest expense and $1,000 and $3,000, respectively, were recorded against the income tax provision, in the condensed consolidated statements of operations and comprehensive income. The accumulated net loss included in other comprehensive income as of September 30, 2016, is $582,000

Write-offs of unsuccessful exploration activities

Write-offs of unsuccessful exploration activities for the nine and three months ended September 30, 2016, were $2.7 million and $1.3 million, respectively, and $0 million for the nine and three months ended September 30, 2015. These write-offs of exploration costs are related to the Company’s exploration activities in The United States and Chile, which the Company determined would not support commercial operations.

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, 2016 and December 31, 2015, the Company had deposits totaling $35.2 million and $19 million, respectively, in seven U.S. financial institutions that were federally insured up to $250,000 per account. At September 30, 2016 and December 31, 2015, the Company’s deposits in foreign countries amounted to approximately $72.4 million and $181.0 million, respectively.

At September 30, 2016 and December 31, 2015, accounts receivable related to operations in foreign countries amounted to approximately $36.3 million and $27.8 million, respectively. At September 30, 2016 and December 31, 2015, accounts receivable from the Company’s primary customers amounted to approximately 60% and 66%, respectively, of the Company’s accounts receivable.

Sierra Pacific Power Company and Nevada Power Company (subsidiaries of NV Energy, Inc.) accounted for 14.4% and 15.3% of the Company’s total revenues for the three months ended September 30, 2016 and 2015, respectively, and 18.6% and 19.3% for the nine months ended September 30, 2016 and 2015, respectively.

Kenya Power and Lighting Co. Ltd. accounted for 15.1% and 13.5% of the Company’s total revenues for the three months ended September 30, 2016 and 2015, respectively, and 16.4% and 15.4% for the nine months ended September 30, 2016 and 2015, respectively.

Southern California Public Power Authority accounted for 7.7% and 3.3% of the Company’s total revenues for the three months ended September 30, 2016 and 2015, respectively, and 9.9% and 4.3% for the nine months ended September 30, 2016 and 2015, respectively.

Hyundai (Sarulla geothermal power project) accounted for 24% and 22% of the Company’s total revenues for the three months ended September 30, 2016 and 2015, respectively, and 14% and 16% for the nine months ended September 30, 2016 and 2015, 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.

NOTE 2 — NEW ACCOUNTING PRONOUNCEMENTS

New accounting pronouncements effective in the nine-month period ended September 30, 2016

Amendments to Fair Value Measurement

In June 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“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 value 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. The adoption of this guidance did not have a material impact on the Company’s 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 (i.e. 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 discretion used to make this legal entity determination. The update is effective for annual reporting periods beginning after December 15, 2015, including interim periods within those reporting periods. The adoption of this guidance did not have a material impact on the Company’s consolidated financial statements.

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 arrangements 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. The Company adopted this update in its interim period beginning January 1, 2016 and continues to present debt issuance costs related to such line-of-credit arrangements as assets amortized ratably over the respective term of the line-of credit arrangements. Debt issuance costs related to such line-of-credit arrangements as of September 30, 2016 and December 31, 2015, totaled $2.6 million and $1.0 million, respectively.

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. The Company retrospectively adopted this update in its interim period beginning January 1, 2016. The impact of the adoption resulted in a reclassification of debt issuance costs totaling $17.9 million and $19.1 million as of September 30, 2016 and December 31, 2015, respectively.

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

New accounting pronouncements effective in future periods

Improvement to Employee Share-Based Payment Accounting

In March 2016, the FASB issued ASU 2016-09, Improvement to Employee Share-Based Payment Accounting, an update to the guidance on stock-based compensation. Under the new guidance, all excess tax benefits and tax deficiencies will be recognized in the income statement as they occur. This will replace the current guidance, which requires tax benefits that exceed compensation cost (windfalls) to be recognized in equity. It will also eliminate the need to maintain a “windfall pool,” and will remove the requirement to delay recognizing a windfall until it reduces current taxes payable. The new guidance will also change the cash flow presentation of excess tax benefits, classifying them as operating inflows, consistent with other cash flows related to income taxes. Today, windfalls are classified as financing activities. Also, this will affect the dilutive effects in earnings per share, as there will no longer be excess tax benefits recognized in additional paid in capital. Today those excess tax benefits are included in assumed proceeds from applying the treasury stock method when computing diluted EPS. Under the amended guidance, companies will be able to make an accounting policy election to either (1) continue to estimate forfeitures or (2) account for forfeitures as they occur. This updated guidance is effective for annual and interim periods beginning after December 15, 2016. Early adoption is permitted. The Company is currently evaluating the potential impact, if any, of the adoption of this update on its consolidated financial statements.

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 calendar fiscal year entities. The Company is currently evaluating the potential impact, if any, of the adoption of these amendments on its consolidated financial statements.

In March 2016, the FASB issued ASU 2016-08, Principal versus Agent Considerations. The amendment in this Update do not change the core principal of the guidance and are intended to improve the operability and understandability of the implementation guidance on principal versus agent considerations. When another entity is involved in providing goods or services to a customer, an entity is required to determine if the nature of its promise is to provide the specific good or service itself (that is, the entity is a principal) or to arrange for that good or service to be provided by the other party (that is, the entity is an agent). The guidance includes indicators to assist an entity in determining whether it acts as a principal or agent in a specified transaction. 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 calendar fiscal year entities. The Company is currently evaluating the potential impact, if any, of the adoption of these amendments on its consolidated financial statements.

Leases

In February 2016, the FASB issued ASU 2016-02, Leases, Topic 842. The amendment in this Update introduce a number of changes and simplifications from previous guidance, primarily the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases. The Update retains the distinction between finance leases and operating leases and the classification criteria between the two types remain substantially similar. Also, lessor accounting remains largely unchanged from previous guidance, however, key aspects in the Update were aligned with the revenue recognition guidance in Topic 606. Additionally, the Update defines a lease as a contract, or part of a contract, that conveys the right to control the use of identified asset for a period of time in exchange for considerations. Control over the use of the identified means that the customer has both (a) the right to obtain substantially all of the economic benefits from the use of the asset and (b) the right to direct the use of the asset. The amendments in this update are effective for annual reporting periods beginning after December 15, 2018, including interim periods within those reporting periods. 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.

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Recognition and Measurement of Financial Assets and Financial Liabilities

In January 2016, the FASB issued ASU 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities. The update primarily requires that an entity should present separately, in other comprehensive income, the portion of the total change in the fair value of a liability resulting from a change in the instrument-specific credit risk if the entity has elected to measure the liability at fair value in accordance with the fair value option for financial instruments. The application of this update should be by means of cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year of adoption. The amendments in this update are effective for financial statements issued for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. Early adoption is permitted as of the beginning of the fiscal year of adoption. The Company is currently evaluating the potential impact, if any, of the adoption of this update on its consolidated financial statements.

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.

NOTE 4 — UNCONSOLIDATED INVESTMENTS

Unconsolidated investments consist of the following:

	September 30,			December 31,
	2016			2015
	(Dollars in thousands)
Sarulla	$	(16,664	)	$	(8,100	)

The Sarulla Project

The Company holds a 12.75% equity interest in a consortium which is in the process of developing the Sarulla geothermal power project in Indonesia with an 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 is currently in the commissioning and fine tuning stage but commercial operation date is expected to be delayed by few weeks. The delay is a result of local riots protesting the EPC contractor that caused a work stoppage. Work has resumed and we currently expect commercial operation of the first phase to begin in January 2017. For the second phase, engineering and procurement has been substantially completed, site construction is in progress and all of the equipment to be supplied by Ormat was delivered. For the third phase, engineering and procurement is still in progress, Construction work at the site is in progress and manufacturing of equipment to be supplied by Ormat is underway as planned. Drilling activities for the second and third phases are still ongoing and the project has achieved to date, based on preliminary estimates, approximately 80% of the required production capacity and approximately 80% of the required injection capacity. The project has missed a few milestones defined under the loan documents, but has received waivers from the lenders and commercial operation of the second and third phases is still expected to commence within 18 months after commercial operation of the first phase. As of September 30, 2016, the project is in compliance with milestones agreed with the lenders. The project is experiencing delays in the field development and certain cost overruns resulting from delays and excess drilling costs. Although estimated cost at completion is still within the approved budget (including contingencies), the lenders have requested that the sponsors commit additional equity. The sponsors have agreed and financing documents were revised to reflect this request. With respect to Ormat’s role as a supplier, all contractual milestones under the supply agreement were achieved.

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 (loss). During the three and nine months ended September 30, 2016, the project recorded a gain equal to $10.5 million and a loss of $30 million, respectively, net of deferred tax of $5.4 million and $15.4 million, respectively, of which the Company's share was $1.3 million and $3.8 million, respectively, which were recorded in other comprehensive income (loss). The related accumulated loss recorded by the Company in other comprehensive income (loss) as of September 30, 2016 is $10.9 million.

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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. 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 years. The Company has eliminated the related intercompany profit of $10.8 million against equity in loss of investees.

During the nine months ended September 30, 2016, the Company did not make any additional cash equity investments in the Sarulla project.

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).

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The following table sets forth certain fair value information at September 30, 2016 and December 31, 2015 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, 2016
				Fair Value
	Carrying Value at September 30, 2016			Total			Level 1		Level 2			Level 3
	(Dollars in thousands)
Assets:
Current assets:
Cash equivalents (including restricted cash accounts)	$	12,635		$	12,635		$	12,635	$	—		$	—
Derivatives:
Currency forward contracts ⁽²⁾		249			249			—		249			—
Liabilities:
Current liabilities:
Derivatives:
Call and put options on oil price ⁽¹⁾	$	(1,776	)	$	(1,776	)	$	—	$	(1,776	)	$	—
Call option on natural gas price ⁽¹⁾		(1,534	)		(1,534	)		—		(1,534	)		—
Currency forward contracts ⁽²⁾		(30	)		(30	)		—		(30	)		—
	$	9,544		$	9,544		$	12,635	$	(3,091	)	$	—

				December 31, 2015
				Fair Value
	Carrying Value at December 31, 2015			Total			Level 1		Level 2			Level 3
	(Dollars in thousands)
Assets
Current assets:
Cash equivalents (including restricted cash accounts)	$	31,428		$	31,428		$	31,428	$	—		$	—
Derivatives:
Currency forward contracts ⁽²⁾		7			7			—		7			—
Liabilities:
Current liabilities:
Derivatives:
Currency forward contracts ⁽²⁾		(169	)		(169	)		—		(169	)		—
	$	31,266		$	31,266		$	31,428	$	(162	)	$	—

⁽¹⁾

These amounts relate to call and put option transactions on oil and natural gas prices, valued primarily based on observable inputs, including spot prices for related commodity indices, and is included within “Accounts payable and accrued expenses” on September 30, 2016 in the consolidated balance sheets with the corresponding gain or loss being recognized within “Derivatives and foreign currency transaction gains (losses)” 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 “prepaid expenses and other” and “accounts payable and accrued expenses” on September 30, 2016 and December 31, 2015, in the consolidated balance sheet with the corresponding gain or loss being recognized within “Derivatives and foreign currency transaction gains (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)
		Three Months Ended September 30,				Nine Months Ended September 30,
Derivatives not designated as hedging instruments	Location of recognized gain (loss)	2016		2015		2016			2015


Call options on natural gas price	Derivatives and foreign currency transaction gains (losses)		32		—		(1,114	)		—
Call and put options on oil price	Derivatives and foreign currency transaction gains (losses)		230		—		(1,312	)		—
Swap transactions on natural gas price	Electricity revenue		—		369		—			767
Currency forward contracts	Derivatives and foreign currency and transaction gains (losses)		689		869		1,154			(1,349	)
		$	951	$	1,238	$	(1,272	)	$	(582	)

On March 6, 2014, the Company entered into a Natural Gas Index (“NGI”) swap contract with a bank covering a notional quantity of approximately 2.2 million British Thermal Units (“MMbtu”) for settlement effective January 1, 2015 until March 31, 2015, and covering a notional amount of approximately 2.4 MMbtu for settlement effective June 1, 2015 until December 31, 2015, in order to reduce its exposure to fluctuations in natural gas prices under its power purchase agreements (“PPAs”) with Southern California Edison to below $4.95 per MMbtu and below $3.00 per MMbtu, respectively. The swap contracts did not have any up-front costs. Under the terms of these contracts, the Company made floating rate payments to the bank and received fixed rate payments from the bank on each settlement date. The swap contracts had 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 was published in the relevant calculation period (January 1, 2015 to March 1, 2015 and June 1, 2015 to December 31, 2015) was settled on a cash basis.

On February 2, 2016, the Company entered into Henry Hub Natural Gas Future contracts under which it has written a number of call options covering a notional quantity of approximately 4.1 MMbtu with exercise prices of $2 and expiration dates ranging from February 24, 2016 until December 27, 2016 in order to reduce its exposure to fluctuations in natural gas prices under its PPAs with Southern California Edison. The Company received an aggregate premium of approximately $1.9 million from these call options. The call option contracts have monthly expiration dates at which the options can be called and the Company would have to settle its liability on a cash basis.

On February 24, 2016, the Company entered into Brent Oil Future contracts under which it has written a number of call options covering a notional quantity of approximately 185,000 barrels (“BBL”) of Brent with exercise prices of $32.80 to $35.50 and expiration dates ranging from March 24, 2016 until December 22, 2016 in order to reduce its exposure to fluctuations in Brent prices under its PPA with HELCO. The Company received an aggregate premium of approximately $1.1 million from these call options. The call option contracts have monthly expiration dates whereby the options can be called and the Company would have to settle its liability on a cash basis. Moreover, during March 2016, the Company rolled 2 existing call options covering a total notional quantity of 31,800 BBL of Brent in order to limit its exposure to $41 to $42.50 instead of $32.80 to $33.50. In addition, the Company entered into short risk reversal transactions (sell call and buy put options) by rolling existing call options covering notional quantities of 16,500 BBL and 17,000 BBL in order to limit its exposure from the outstanding call options originally entered into in February 2016 to a range of $28.50 to $37.50 and $28 to $38.50, respectively.

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The foregoing future, forward and swap transactions were not designated as hedge transactions and are marked to market with the corresponding gains or losses recognized within “Derivatives and foreign currency transaction gains (losses)” and “Electricity revenues” in the consolidated statements of operations and comprehensive income, respectively. The Company recognized a net gain from these transactions of $1.0 million and a net loss of $1.3 million in the three and nine months ended September 30, 2016, respectively, compared to a net gain of $0.9 million and a net loss of $1.3 million in the three and nine months ended September 30, 2015, under Derivatives and foreign currency transaction gains (losses), and a net gain of $0.4 million and a $0.8 million, in the three and nine months ended September 30, 2015, respectively, under Electricity revenues.

There were no transfers of assets or liabilities between Level 1, Level 2 and Level 3 during the nine months ended September 30, 2016.

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

	Fair Value				Carrying Amount
	September 30, 2016		December 31, 2015		September 30, 2016		December 31, 2015
	(Dollars in millions)				(Dollars in millions)
Olkaria III Loan - DEG	$	20.8	$	24.2	$	19.7	$	23.7
Olkaria III Loan - OPIC		257.3		262.6		251.1		264.6
Amatitlan Loan		38.5		41.7		37.6		40.3
Senior Secured Notes:
Ormat Funding Corp. ("OFC")		19.6		30.0		19.7		30.0
OrCal Geothermal Inc. ("OrCal")		41.6		43.8		40.1		43.3
OFC 2 LLC ("OFC 2")		231.0		231.1		251.3		262.0
Senior Unsecured Bonds		201.0		264.5		204.3		250.0
Other long-term debt		7.2		—		8.7		—

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 other 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, 2016:

	Level 1		Level 2		Level 3		Total
	(Dollars in millions)
Olkaria III - DEG	$	—	$	—	$	20.8	$	20.8
Olkaria III - OPIC		—		—		257.3		257.3
Amatitlan loan		—		38.5		—		38.5
Senior Secured Notes:
OFC		—		19.6		—		19.6
OrCal		—		—		41.6		41.6
OFC 2		—		—		231.0		231.0
Senior unsecured bonds		—		—		201.0		201.0
Other long-term debt		—		—		7.2		7.2
Deposits		14.5		—		—		14.5

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, 2015:

	Level 1		Level 2		Level 3		Total
	(Dollars in millions)
Olkaria III Loan - DEG	$	—	$	—	$	24.2	$	24.2
Olkaria III Loan - OPIC		—		—		262.6		262.6
Amatitlan Loan		—		41.7		—		41.7
Senior Secured Notes:
OFC		—		30.0		—		30.0
OrCal		—		—		43.8		43.8
OFC 2		—		—		231.1		231.1
Senior unsecured bonds		—		—		264.5		264.5
Other long-term debt		—		6.7		—		6.7
Deposits		15.9		—		—		15.9

NOTE 6 — STOCK-BASED COMPENSATION

The 2004 Incentive Compensation Plan

In 2004, the Company’s Board of Directors (the “Board”) 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 Board, 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

● 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).

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

On June 13, 2016, the Company granted its employees, in aggregated 1,080,000 SAR under the Company’s 2012 Incentive Plan. The exercise price of each SAR is $42.87, which represented the fair market value of the Company’s common stock on the grant date. Such SARs will expire six years from the date of the grant and will vest over 4 years as follows: 50% after two years; an additional 25% after three years and the remaining 25% after four years from the grant date.

The fair value of each SAR on the grant date was $11.98 for senior management and $11.42 for other employees. The Company calculated the fair value of each SAR on the grant date using the Exercise Multiple-Based Lattice SAR-Pricing model based on the following assumptions:

Risk-free interest rate	1.29	%
Expected life (in years)	6
Dividend yield	1.14
Expected volatility	30.7	%
Forfeiture rate:
Senior management	0.0	%
Other employees	10.5	%
Sub-Optimal Exercise Factor:
Senior management	2.5
Other employees	2.0

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, 2016:
Net revenue from external customers	$	109,795	$	74,822	$	184,617
Intersegment revenue		—		14,835		14,835
Operating income		23,903		24,320		48,223
Segment assets at period end		2,137,845		141,426		2,279,271

Three Months Ended September 30, 2015:
Net revenue from external customers	$	97,245	$	65,607	$	162,852
Intersegment revenue		—		10,658		10,658
Operating income		28,346		18,133		46,479
Segment assets at period end		2,103,754		182,579		2,286,333

Nine Months Ended September 30, 2016:
Net revenues from external customers	$	321,664	$	174,408	$	496,072
Intersegment revenues		—		36,042		36,042
Operating income		91,502		59,151		150,653
Segment assets at period end		2,137,845		141,426		2,279,271

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

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						Nine Months Ended
	2016			2015			2016			2015


Revenue:
Total segment revenue	$	184,617		$	162,852		$	496,072		$	423,570
Intersegment revenue		14,835			10,658			36,042			41,314
Elimination of intersegment revenue		(14,835	)		(10,658	)		(36,042	)		(41,314	)
Total consolidated revenue	$	184,617		$	162,852		$	496,072		$	423,570

Operating income:
Operating income	$	48,223		$	46,479		$	150,653		$	114,973
Interest income		266			53			831			106
Interest expense, net		(17,137	)		(17,748	)		(51,561	)		(54,435	)
Derivatives and foreign currency transaction gains (losses)		(222	)		1,296			(2,592	)		(641	)
Income attributable to sale of tax benefits		3,463			8,634			12,380			18,917
Other non-operating income (expense), net		(5,546	)		(131	)		(5,306	)		(1,523	)
Total consolidated income before income taxes and equity in income of investees	$	29,047		$	38,583		$	104,405		$	77,397

NOTE 10 — COMMITMENTS AND CONTINGENCIES

●

Jon Olson and Hilary Wilt, together with Puna Pono Alliance filed a complaint 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”) comply with 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 complaint was amended to add the county of Hawaii and the State of Hawaii Department of Land and Natural Resources as defendants to the case. On October 10, 2016, the court issued its decision in response to each of the plaintiffs’ and defendants’ motions for summary judgment, denying plaintiffs’ motion and granting defendant PGV's and the County of Hawaii’s cross motions for summary judgment, effectively rendering the plaintiffs’ action moot.

●

On July 8, 2014, Global Community Monitor, LiUNA, and two residents of Bishop, California filed a complaint in the U.S. 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 and Great Basin Unified Air Pollution Control District rules. On June 26, 2015, in response to a motion by the defendants, the court dismissed all but one of the plaintiffs’ causes of action. On October 14, 2015, the court denied the defendants’ motion to dismiss the plaintiffs’ sole remaining claim. During the second quarter of 2016, the discovery phase was completed and plaintiff Global Community Monitor was dismissed as a party. Both the remaining plaintiffs and the defendants have submitted cross motions for summary judgment. The motions have been briefed and are pending before the court. 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 NLRB seeking to organize the operations and maintenance employees at the Puna project. A global settlement was reached in principle in February 2016, which includes a Union disclaimer of interest, the withdrawal of letters from the Union to the NRLB and signed individual settlement agreements, all of which are immaterial. All issues are now settled and closed.

●

In January 2014, Ormat learned that two former employees filed a “qui tam” complaint seeking damages, penalties and other relief of approximately $375 million, 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 U.S. Department of Justice declined to intervene. On October 25, 2016, the parties entered into a final settlement agreement providing for the dismissal of the claim without any admission of wrongdoing by the Ormat Parties and payment of $11 million (inclusive of fees and costs). The settlement amount of $11 million was included in general and administrative expenses in the consolidated statements of operations and comprehensive income for the three and nine months ended September 30, 2016.

●

On March 29, 2016, a former local sales representative in Chile, Aquavant, S.A., filed a claim on the basis of unjust enrichment against Ormat’s subsidiaries in the 27th Civil Court of Santiago, Chile. The claim requests that the court order Ormat to pay Aquavant $4.6 million in connection with its activities in Chile, including the EPC contract for the Cerro Pabellon project and various geothermal concessions, plus 3.75% of Ormat geothermal products sales in Chile over the next 10 years. Pursuant to various petitions submitted by defendants, including a motion describing preliminary, procedural defenses, on August 18, 2016, and then on October 10, 2016, the 27th Civil Court issued a number of decisions, which include removal of the file to the 11th Civil Court of Santiago, thereby delaying a determination on the larger issues of jurisdiction and competency of the Chilean courts as a substantive (and not procedural) defense. The Company believes that it has valid defenses under law, and intends to defend itself vigorously.

●

On August 5, 2016 George Douvris, Stephanie Douvris, Michael Hale, Cheryl Cacocci, Hillary E. Wilt and Christina Bryan, acting for themselves and on behalf of all other similarly situated residents of the lower Puna District, filed a complaint in the Third Circuit Court of the State of Hawaii’ seeking certification of a class action for preliminary and permanent injunctive relief, consequential and punitive damages, attorney’s fees and statutory interest against PGV and other presently unknown defendants, The complaint purports that injury and other damages in an undisclosed amount were caused to the plaintiffs as a result of an alleged toxic release by PGV in the wake of Hurricane Iselle in August 2014. On August 25, 2016, the Company filed to remove the case to the United States District Court for the District of Hawaii. On September 23, 2016, plaintiffs filed a motion for joinder of HELCO as an additional defendant, to amend the complaint, and to remand the case back to the Third Circuit Court. The plaintiffs’ motion will be heard before the federal court in mid-November, 2016. The Company believes that it has valid defenses under law, and intends to defend itself vigorously.

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

●

On May 21, 2014, Elko County, Nevada appealed to the Supreme Court of Nevada the Nevada Governor's Office of Energy’s award of an energy tax abatement to ORNI 42 LLC for our Tuscarora power plant. Lander County, Nevada similarly appealed the Office of Energy’s Award of an energy tax abatement to ORNI 39 LLC for our McGinness power plant. Both of the appeals request that the Court overturn the Office of Energy’s decision and deny, retroactively and going forward, the tax abatement benefits for the full 20 year period, valued at approximately $18.6 million for our McGinness power plant and approximately $6.2 million for our Tuscarora power plant, of which only a small portion was utilized as of September 30, 2016. Following full briefing on both plaintiffs’ and defendants’ motions for summary judgment, on September 7, 2016, a hearing was held before the court. The Company believes that it has valid defenses under the law and will continue to defend itself vigorously.

●

On June 20, 2016, Nadia Garcia, individually and as successor in interest to Thomas Garcia Valenzuela, and as guardian ad litem to Emerie Garcia, Khamilla Garcia and Reyene Adam, filed a complaint against Ormat Technologies, Ormat Nevada and Ormesa LLC in the Superior Court of Imperial County seeking unspecified monetary damages. The Garcia complaint alleges that the Ormat defendants caused the wrongful death, personal injury and other harm to Thomas Garcia when he was employed by Martin Hydroblasting Services, Inc. and suffered injuries leading to his death while performing work at the Ormesa plant site on or around March 31, 2016. Subject to reservations, the insurer of the deceased’s employer has accepted the tender for both the costs of defense and the case outcome, and counsel has been appointed to represent Ormat.

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

The Company’s effective tax rate for the nine months ended September 30, 2016 and 2015 was 28.1% and 29.3%, respectively. The effective rate for the nine months ended September 30, 2015 excludes the income tax benefit of $49.4 million due to the release of the valuation allowance in Kenya. The effective tax rate differs from the federal statutory rate of 35% for the nine months ended September 30, 2016 due to: (i) a full valuation allowance against the Company’s U.S. deferred tax assets in respect of net operating loss ("NOL") carryforwards and unutilized tax credits (see below), (ii) lower tax rate in Israel of 16%, partially offset by a tax rate in Kenya of 37.5%; 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, 2016 and 2015 was $600,000 and $602,000, respectively, and for the nine months ended September 30, 2016 and 2015 was $2,398,000 and $2,628,000, respectively.

The Company is currently in a net deferred tax asset position with a full valuation allowance. As of December 31, 2015, the Company had U.S. federal NOL carryforwards of approximately $281 million and state NOL carryforwards of approximately $191 million, which expire between 2022 and 2034 for federal NOLs and between 2016 and 2034 for state NOLs, and production tax credits (“PTCs”) in the amount of $71.4 million at December 31, 2015 are available for a 20-year period and expire between 2026 and 2036. The Company also has offsetting deferred tax liabilities in the U.S.

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. Based upon available evidence of the Company’s ability to generate additional taxable income in the future and historical losses in prior years, a full valuation allowance is recorded against the U.S. deferred tax assets, as it is more likely than not that the deferred tax assets will not be utilized.

The total amount of undistributed earnings of foreign subsidiaries for income tax purposes was approximately $233.8 million at December 31, 2015. 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. and, accordingly, we do not currently plan to repatriate the funds we have designated as being permanently invested outside of the U.S. If we change our plans, we may be required to accrue and pay U.S. taxes to repatriate these funds.

The Company is subject to income taxes in the U.S. (federal and state) and numerous foreign jurisdictions. Significant judgment is required in evaluating tax positions and determining the position for income taxes. Reserves are established to tax-related uncertainties based on estimates of whether, and the extent to which additional taxes will be due. As of September 30, 2016, the Company is unaware of any potentially significant uncertain tax positions for which a reserve has not been established.

In November 2015, the Kenya Revenue Authority (“KRA”) commenced a tax audit covering all taxes relating to our operations in Kenya. During 2016, the Company submitted all documents requested by the KRA, which is currently processing the provided information. The Company expects to receive KRA’s audit findings once KRA completes its review and audit.

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

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 revenues, 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:

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, 2015 and any updates contained herein as well as those set forth in our reports and other filings made with the SEC.

We are a leading vertically integrated company, engaged 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 under 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 two business segments:

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

For the nine months ended September 30, 2016, our total revenues increased by 17.1% (from $423.6 million to $496.1 million) over the corresponding period in 2015.

For the nine months ended September 30, 2016, Electricity segment revenues were $321.7 million, compared to $278.1 million for the nine months ended September 30, 2015, an increase of 15.7% from the prior year period. Product segment revenues for the nine months ended September 30, 2016 were $174.4 million, compared to $145.4 million during the nine months ended September 30, 2015, an increase of 19.9% from the prior year period.

During the nine months ended September 30, 2016 and 2015, our consolidated power plants generated 3,962,181 megawatt hours (MWh) and 3,513,803 MWh, respectively, an increase of 12.8%.

For the nine months ended September 30, 2016, our Electricity segment generated approximately 64.8% of our total revenues, while our Product segment generated approximately 35.2% of our total revenues. For the nine months ended September 30, 2015, our Electricity segment generated approximately 65.7% of our total revenues, while our Product segment generated approximately 34.3% of our total revenues.

For the nine months ended September 30, 2016, approximately 85.7% of our Electricity segment revenues were 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:

We recently reduced our economic exposure to fluctuations in the price of oil and natural gas from February 3, 2016 until December 29, 2016 and before that we reduced our economic exposure to fluctuations in the price of natural gas from March 31, 2015 and from June 1, 2015 until December 31, 2015, by entering into derivatives 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 revenues are also subject to seasonal variations and can be affected by higher-than-average ambient temperatures, as described below under “Seasonality”.

Revenues attributable to our Product segment are based on the sale of equipment, engineering, procurement and construction (EPC) contracts and the provision of various services to our customers. Product segment revenues 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 revenues, expenses, and EBITDA, 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, revenues and costs actually incurred to complete customer orders compared to the costs originally budgeted for such orders.

The most significant developments in our company and business since January 1, 2016 are described below:

Pursuant to the terms of an Amended and Restated Investment Agreement (Investment Agreement) and Shareholders Agreement with Sageos Holding (Sageos), a wholly owned subsidiary of Bureau de Recherches Géologiques et Minières (BRGM), Ormat together with Caisse des Dépôts et Consignations (CDC), a French state-owned financial organization, acquired an approximately 80% interest in GB allocated 75% to Ormat and 25% to CDC. Ormat and CDC will gradually increase their combined interest in GB to 85% and Sageos will hold the remaining balance.

Pursuant to the agreements, we paid approximately $20.6 million (approximately €18.5 million) to Sageos for its approximately 60% interest in GB. In addition, we are committed to further invest $8.4 million (approximately €7.5 million) in the next two years, which will increase our interest to 63.75%. The cash will be used mainly for the enhancement of the power plant.

We have planned modifications to the existing equipment as well as to further develop the asset, with a potential of reaching a total of 45 MW in phased development by 2021. Under the Investment Agreement, we will pay Sageos an additional amount of up to $13.4 million (approx. €12 million) subject to the achievement of agreed production thresholds and capacity expansion within a defined time period.

Bouillante power plant sells its electricity under a 15-year power purchase agreement (PPA) that was entered into in February 2016 with Électricité de France S.A. (EDF), the French electric utility. We plan to optimize the use of the resource at the existing facilities and recover its current production to its design capacity of 14.75 MW by mid-2017. Upon completion of the enhancement, the plant is expected to generate approximately $22.3 million (approximately €20 million) of annual revenues.

The geothermal industry in the United States has historically experienced significant growth followed by a consolidation of owners and operators of geothermal power plants. There has been increased demand for energy generated from geothermal and other renewable resources in the United States as costs for electricity generated from renewable 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 U.S. government encourages the use of geothermal and other renewable energy through production tax credits (PTCs) or investment tax credits (ITCs) (which are discussed in more detail in the section entitled “Government Grants and Tax Benefits” below). 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:

Final regulations have been adopted to implement other 2013 Nevada legislation related to 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:

This means, among other things, that one of the metrics some investors may use to evaluate power plant revenues--average price per MWh--can fluctuate from year to year. For example, decreases in current oil and natural gas prices contributed to a decline in our average revenue per MWh during 2015 compared to 2014. Based on total Electricity segment revenues for those years, we earned, on average, $77.75 and $85.89 per MWh in 2015 and 2014, respectively. In the nine months ended September 30, 2016, we earned $81.2 per MWh and $71.0 per MWh in the same period last year. Oil and natural gas prices, together with other factors that affect our Electricity Segment revenues, could cause changes in our average rate per MWH in the future. 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.

We generate our revenues 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.

Revenues attributable to our Electricity segment are derived from the sale of electricity from our power plants pursuant to long-term PPAs. While approximately 88.7% of our Electricity revenues for the nine months ended September 30, 2016 were derived from PPAs with fixed price components, we have variable price PPAs in California and Hawaii. Our approximately 90 MW SO#4 PPAs in California 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 revenues from those power plants may fluctuate.

Our Electricity segment revenues are 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.

Revenues attributable to our Product segment fluctuate 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, revenues from our Product segment fluctuate (sometimes, extensively) from period to period. In both 2014 and 2015, 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 revenues for the periods indicated:

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

The contribution of our domestic and foreign operations within our Electricity segment and Product segment to combined pre-tax income differ in a number of ways.

Electricity Segment. Our Electricity segment domestic revenues were approximately 96% and 124% higher than our Electricity segment foreign revenues for the nine months ended September 30, 2016 and 2015 and approximately 78% and 134% higher for the three months ended September 30, 2016 and 2015, respectively. However, domestic operations in our Electricity segment have higher costs of revenues and expenses than the foreign operations in our Electricity segment. Our foreign power plants are located in lower-cost regions, like Kenya and Guatemala, which favorably impacts payroll and maintenance expenses among other items. They are also newer than most of our domestic power plants and therefore tend to have lower maintenance costs and higher availability factors than our domestic power plants.

Product Segment. Our Product segment foreign revenues were more than ninety percent (90%) of our total Product segment revenues for the three and nine months ended September 30, 2016 and 2015. Our Product segment foreign activity also benefits from lower costs of revenues and expenses than Product segment domestic activity. Accordingly, our Product segment foreign activity contributes more than our Product segment domestic activity to our pre-tax income from operations.

Relative Contributions. While our combined (domestic and foreign) Electricity segment revenues exceeded our combined Product segment revenues by approximately $147,256,000 and $132,678,000, respectively, for the nine months ended September 30, 2016 and 2015, and by approximately $34,973,000 and $31,638,000 for the three months ended September 30, 2016, and 2015, respectively, (primarily foreign), Product segment revenues resulted in higher pre-tax income from foreign operations for both of those periods.

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 2 power plant 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 revenues from these power plants 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 revenues. The higher payments payable by Southern California Edison and Pacific Gas & Electric Company in the summer months offset the negative impact on our revenues from lower generation in the summer due to the higher ambient temperature.

The principal cost of revenues 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. In our California power plants, our principal cost of revenues also includes transmission charges and scheduling charges. In some of our Nevada power plants, we also incur transmission and wheeling 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 revenues. Royalty payments, included in cost of revenues, are made as compensation for the right to use certain geothermal resources and are paid as a percentage of the revenues derived from the associated geothermal rights. Royalties constituted approximately 3.9% and 3.9% of Electricity segment revenues for the nine months ended September 30, 2016 and September 30, 2015, respectively, and approximately 3.7% and 3.8% of Electricity segment revenues for the three months ended September 30, 2016 and September 30, 2015, respectively.

The principal cost of revenues 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 revenues attributable to our Product segment, expressed as a percentage of total revenues, 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.

Our cash and cash equivalents decreased to $90.1 million as of September 30, 2016 from $185.9 million as of December 31, 2015. This decrease was principally due to: (i) prepayment of $249.5 million of senior unsecured bonds (ii) our use of $108.0 million to fund capital expenditures (iii) $18.1 million net cash paid for the acquisition of GB; (iv) net repayment of $41.0 million of long-term debt; (v) $17.3 million cash paid to non-controlling interests; and (vi) a $22.5 million cash dividend paid. This decrease was partially offset by: (i) $203.5 million net proceeds from the issuance of two new series of senior unsecured bonds; and (ii) $158.0 million derived from operating activities during the nine months ended September 30, 2016. Our corporate borrowing capacity under committed lines of credit with different commercial banks as of September 30, 2016 was $524.8 million, as described below in “Liquidity and Capital Resources”. As of September 30, 2016, we have utilized $317.5 million of our corporate borrowing capacity.

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, 2015.

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

Our historical operating results in dollars and as a percentage of total revenues 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 revenues from our Product segment.

Comparison of the Three Months Ended September 30, 2016 and the Three Months Ended September 30, 2015

Total revenues for the three months ended September 30, 2016 were $184.6 million, compared to $162.9 million for the three months ended September 30, 2015, which represented a 13.4% increase from the prior year period. This increase was attributable to both our Electricity and Product segments, in which revenues increased by 12.9% and 14.0%, respectively, compared to the corresponding period in 2015.

Revenues attributable to our Electricity segment for the three months ended September 30, 2016 were $109.8 million, compared to $97.2 million for the three months ended September 30, 2015, representing a 12.9% increase from the prior period. This increase was primarily attributable to: (i) the commencement of operations of the second phase of the Don A. Campbell power plant in Nevada in September 2015, and the commencement of operations of our Plant 4 at the Olkaria III complex in Kenya in January 2016, (ii) higher energy rates under the Heber 1 new PPA commencing in December 2015 and (iii) the consolidation of our Guadeloupe power plant, effective July 5, 2016, with revenues of $4.1 million for the period from July 5, 2016 to September 30, 2016, which resulted from the acquisition of 59.73% of GB, in July 2016.

Power generation in our power plants increased by 10.8% from 1,141,058 MWh in the three months ended September 30, 2015 to 1,263,916 MWh in the three months ended September 30, 2016 mainly due to the commencement of commercial operation of the second phase of the Don A. Campbell power plant in Nevada, and of our Plant 4 at the Olkaria III complex in Kenya, as discussed above.

Revenues attributable to our Product segment for the three months ended September 30, 2016 were $74.8 million, compared to $65.6 million for the three months ended September 30, 2015, which represented a 14.0% increase. The increase in our Product segment revenue was primarily due to an increase of approximately $7 million in revenue recognition from our new projects in Turkey, partially offset by other projects in Turkey, several of which were completed in the year ended December 31, 2015, and due to timing of revenue recognition and a different product mix.

Total cost of revenues for the three months ended September 30, 2016 was $110.1 million, compared to $103.5 million for the three months ended September 30, 2015, which represented a 6.4% increase. This increase was due to an increase in cost of revenues from both our Electricity and Product segments. As a percentage of total revenues, our total cost of revenues for the three months ended September 30, 2016 decreased to 59.7% from 63.6% for the three months ended September 30, 2015.

Total cost of revenues attributable to our Electricity segment for the three months ended September 30, 2016 was $66.5 million, compared to $61.5 million for the three months ended September 30, 2015, which represented an 8.1% increase from the prior period. This increase was primarily due to additional costs of revenues from the second phase of the Don A. Campbell power plant that commenced commercial operation in September 2015, and the commencement of operations of our Plant 4 at the Olkaria III complex in Kenya in January 2016, as discussed above, partially offset by a decrease in the cost of revenues in several power plants in our portfolio. As a percentage of total Electricity revenues, our total cost of revenues attributable to our Electricity segment for the three months ended September 30, 2016 was 60.6% compared to 63.2% for the three months ended September 30, 2015. This decrease was primarily due to higher efficiency in our operating power plants as well as the lower costs of operating the two new power plants mentioned above.

Total cost of revenues attributable to our Product segment for the three months ended September 30, 2016 was $43.6 million, compared to $42.0 million for the three months ended September 30, 2015, which represented a 3.9% increase. This increase was primarily attributable to the increase in Product segment revenues, as discussed above. As a percentage of total Product segment revenues, our total cost of revenues attributable to our Product segment for the three months ended September 30, 2016 was 58.3%, compared to 64.0% for the three months ended September 30, 2015. This decrease was mainly attributable to improvements made at our manufacturing facility as well as different product mix and margins in the various sales contracts we entered into for this segment during these periods.

Research and development expenses for the three months ended September 30, 2016 were $1.1 million, compared to $0.3 million for the three months ended September 30, 2015.

Selling and marketing expenses for both the three months ended September 30, 2016 and 2015 were $4.8 million. Selling and marketing expenses for the three months ended September 30, 2016 constituted 2.6% of total revenues for such period, compared to 2.7% for the three months ended September 30, 2015.

General and administrative expenses for the three months ended September 30, 2016 were $19.1 million, compared to $8.0 million for the three months ended September 30, 2015. The increase was mainly due to $11.0 million in one-time expenses related to a settlement with certain former employees of the Company to settle claims brought by such employees against the company under the qui tam provisions of the False Claims Act. Excluding the one-time costs, general and administrative expenses for the three months ended September 30, 2016, constituted 4.4% of total revenues for such period, compared to 4.9% for the three months ended September 30, 2015.

Operating income for the three months ended September 30, 2016 was $48.2 million, compared to $46.5 million for the three months ended September 30, 2015, which represented a 3.8% increase. The increase in operating income was principally attributable to the increase in our gross margin in both our Electricity and Product segments primarily due to the increase in revenues, as discussed above, partially offset by $11.0 million in one-time expenses related to a settlement with certain former employees of the company of a claims brought by such employees against the company under the qui tam provisions of the False Claims Act. Operating income attributable to our Electricity segment for the three months ended September 30, 2016 was $23.9 million, compared to $28.3 million for the three months ended September 30, 2015. The decrease was primarily due to one-time expenses related to a settlement as discussed above, partially offset by an increase in gross margin. Operating income attributable to our Product segment for the three months ended September 30, 2016 was $24.3 million, compared to $18.1 million for the three months ended September 30, 2015.

Interest expense, net for the three months ended September 30, 2016 was $17.1 million, compared to $17.7 million for the three months ended September 30, 2015. This decrease was primarily due to lower interest expense as a result of principal payments of long term debt and revolving credit lines with banks.

Derivatives and foreign currency transaction gains (losses) for the three months ended September 30, 2016 were a loss of $0.2 million, compared to a gain of $1.3 million for the three months ended September 30, 2015. Derivatives and foreign currency transaction gains for the three months ended September 30, 2016 and 2015 were attributable primarily to gains from foreign currency forward contracts which were not accounted for as hedge transactions.

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, 2016 was $3.5 million, compared to $8.6 million for the three months ended September 30, 2015. This income represents mainly the value of PTCs and taxable income or loss generated by ORTP and allocated to the investors. This decrease was primarily attributable to a lower taxable loss in ORTP.

Other non-operating loss for the three months ended September 30, 2016 was $5.5 million compared to $0.1 million for the three months ended September 30, 2015. Other non-operating loss for the three months ended September 30, 2016 includes: (i) prepayment fees of approximately $5.0 million due to the repayment of the senior unsecured bonds in September 2016, as discussed above; and (ii) a make whole premium of $0.6 million resulting from the repurchase of $6.8 million aggregate principal amount of our OFC Senior Secured Notes.

Income tax provision for the three months ended September 30, 2016 was $12.0 million, compared to income tax benefit of $38.2 million for the three months ended September 30, 2015. 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 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. Our effective tax rate for the three months ended September 30, 2016 and the three months ended September 30, 2015, excluding the $49.4 million, was 41.3% and 29%, respectively. Our effective tax rate is principally based upon the composition of the income in different countries and changes related to valuation allowances for certain countries. Our aggregate effective tax rate for the three months ended September 30, 2015 is lower than the 35% U.S. federal statutory tax rate as a substantial portion of our income is derived in Israel which is taxed at the corporate tax rate of 16%, partially offset by taxes on earnings in Kenya which are taxed at a statutory rate of 37.5%. The effective tax rate for the three months ended September 30, 2016 is higher than the 35%. U.S. federal statutory tax rate primarily due to the $11 million one-time settlement expenses related to a settlement with certain former employees as described above and prepayment fees of approximately $5.0 million due to the repayment of the senior unsecured bonds in September 2016 which reduced income before income taxes with no impact on income tax (provision) benefit due to the valuation allowance on net deferred tax asset as described below. There is no impact on the Company’s income tax expense (benefit) related to U.S. earnings (losses) due to the offsetting impact on the provision related to the change in the valuation allowance on the Company’s U.S. net deferred tax asset position.

Equity in losses of investees, net for the three months ended September 30, 2016 was $2.7 million, compared to $3.1 million for the three months ended September 30, 2015. Equity in losses of investees, net are derived from our 12.75% share in the losses of the Sarulla project and from profits elimination.

Net income for the three months ended September 30, 2016 was $14.4 million, compared to $73.7 million for the three months ended September 30, 2015, which represents a decrease of $59.3 million. This decrease in net income was principally attributable to the $11 million one-time expenses in general and administrative expenses related to settlement, as discussed above, increase of $50.2 million in income tax provision, a decrease of $5.2 million in income attributable to sale of tax benefits, and a $5.4 million increase in other non-operating loss, all as discussed above.

Comparison of the Nine Months Ended September 30, 2016 and the Nine Months Ended September 30, 2015

Total revenues for the nine months ended September 30, 2016 were $496.1 million, compared to $423.6 million for the nine months ended September 30, 2015, which represented a 17.1% increase from the prior year period. This increase was attributable to both our Electricity and Product segments, in which revenues increased by 15.7% and 19.9%, respectively, compared to the corresponding period in 2015.

Revenues attributable to our Electricity segment for the nine months ended September 30, 2016 were $321.7 million, compared to $278.1 million for the nine months ended September 30, 2015, representing a 15.7% increase from the prior year period. This increase was primarily attributable to: (i) the commencement of operations of the second phase of the McGinness Hills power plant and Don A. Campbell power plants in Nevada in February 2015 and September 2015, respectively, and the commencement of operations of our Plant 4 at the Olkaria III complex in Kenya in January 2016; (ii) higher energy rates under the Heber 1 PPA commencing in December 2015; and (iii) the consolidation of our Guadeloupe power plant, effective July 5, 2016, with revenues of $4.1 million for the period from July 5, 2016 to September 30, 2016, which resulted from the acquisition of 59.73% of GB, in July 2016. The increase was partially offset by a reduction in revenues generated by some of our power plants due to lower oil and natural gas prices.

Power generation in our power plants increased by 12.8% from 3,513,803 MWh in the nine months ended September 30, 2015 to 3,962,181 MWh in the nine months ended September 30, 2016, mainly due to the commencement of commercial operation of the second phase of the McGinness Hills power plant and Don A. Campbell power plant in Nevada, and the commencement of operations of our Plant 4 at the Olkaria III complex in Kenya, as discussed above.

Revenues attributable to our Product segment for the nine months ended September 30, 2016 were $174.4 million, compared to $145.4 million for the nine months ended September 30, 2015, which represented a 19.9% increase. The increase in our Product segment revenues was primarily due to the start of revenue recognition from a new geothermal project that we constructed in Chile in the third quarter of 2015. We recognized approximately $48 million of revenue from this project in the nine months ended September 30, 2016, compared to approximately $14 million in the nine months ended September 30, 2015. The total contract price for the project is $98.8 million and it is scheduled to be completed by mid-2017. The increase was partially offset by a net decrease of approximately $9.0 million in revenue from our projects in Turkey and other foreign locations, several of which were completed in the year ended December 31, 2015, partially offset by revenue recognition from new projects in Turkey, and due to timing of revenue recognition and different product mix.

Total cost of revenues for the nine months ended September 30, 2016 was $291.9 million, compared to $269.4 million for the nine months ended September 30, 2015, which represented a 8.3% increase. This increase was due to the increase in cost of revenues from both our Electricity and Product segments. As a percentage of total revenues, our total cost of revenues for the nine months ended September 30, 2016 decreased to 58.8% from 63.6% for the nine months ended September 30, 2015. This decrease was attributable to a decrease in cost of revenues as a percentage of total revenues in both our Electricity and Product segments.

Total cost of revenues attributable to our Electricity segment for the nine months ended September 30, 2016 was $192.4 million, compared to $179.6 million for the nine months ended September 30, 2015, which represented a 7.1% increase from the prior year period. This increase was primarily due to: (i) additional costs of revenues from the second phase of the McGinness Hills power plant and Don A. Campbell power plant that commenced commercial operation in February 2015 and September 2015, respectively, the commencement of operations of our Plant 4 at the Olkaria III complex in Kenya in January 2016, and the consolidation of our Guadeloupe power plant as discussed above; and (ii) reimbursement in the three months ended March 31, 2015 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. As a percentage of total Electricity revenues, our total cost of revenues attributable to our Electricity segment for the nine months ended September 30, 2016 was 59.8% compared to 64.6% for the nine months ended September 30, 2015. This decrease was primarily due to higher efficiency in our operating power plants as well as the lower costs of operating the three new power plants mentioned above.

Total cost of revenues attributable to our Product segment for the nine months ended September 30, 2016 was $99.5 million, compared to $89.8 million for the nine months ended September 30, 2015, which represented a 10.8% increase. This increase was primarily attributable to the increase in Product segment revenues, as discussed above. As a percentage of total Product segment revenues, our total cost of revenues attributable to our Product segment for the nine months ended September 30, 2016 was 57.1%, compared to 61.8% for the nine months ended September 30, 2015. This decrease was mainly attributable to the different product mix and different margins in the various sales contracts we entered into for this segment during these periods as well as improvements made at our manufacturing facility.

Research and development expenses for the nine months ended September 30, 2016 were $2.0 million, compared to $1.1 million for the nine months ended September 30, 2015.

Selling and marketing expenses for both the nine months ended September 30, 2016 and 2015 were $12.1 million. Selling and marketing expenses remained at the same level, despite the increase in Product segment revenues. Selling and marketing expenses for the nine months ended September 30, 2016 constituted 2.4% of total revenues for such period, compared to 2.9% for the nine months ended September 30, 2015.

General and administrative expenses for the nine months ended September 30, 2016 were $36.6 million, compared to $25.6 million for the nine months ended September 30, 2015. The increase was mainly due to $11.0 million expenses related to a settlement with certain former employees of the company to settle claims brought by such employees against the company under the qui tam provisions of the False Claims Act, partially offset by $3.4 million of expenses related to the share exchange with Ormat Industries recorded in the three months ended March 31, 2015. Excluding the one-time costs, General and administrative expenses for the nine months ended September 30, 2016 constituted 5.2% of total revenues for such period, compared to 5.1%, excluding the costs related to the share exchange, for the nine months ended September 30, 2015.

Operating income for the nine months ended September 30, 2016 was $150.7 million, compared to $115.0 million for the nine months ended September 30, 2015, which represented a 31.0% increase. The increase in operating income was principally attributable to the increase in our gross margin in both our Electricity and Product segments primarily due to the increase in revenues, as discussed above, partially offset by $11.0 million in one-time expenses related to a settlement with certain former employees of the company of a claims brought by such employees against the company under the qui tam provisions of the False Claims Act. Operating income attributable to our Electricity segment for the nine months ended September 30, 2016 was $91.5 million, compared to $73.2 million for the nine months ended September 30, 2015. Operating income attributable to our Product segment for the nine months ended September 30, 2016 was $59.2 million, compared to $41.8 million for the nine months ended September 30, 2015.

Interest expense, net for the nine months ended September 30, 2016 was $51.6 million, compared to $54.4 million for the nine months ended September 30, 2015. This decrease was primarily due to (i) a lower interest expense as a result of principal payments of long term debt and revolving credit lines with banks; and (ii) a $0.8 million decrease in interest related to the sale of tax benefits. The decrease was partially offset by a $1.2 million decrease related to interest capitalized to projects.

Derivatives and foreign currency transaction losses for the nine months ended September 30, 2016 were $2.6 million, compared to $0.6 million for the nine months ended September 30, 2015. Derivatives and foreign currency transaction losses for the nine months ended September 30, 2016 were attributable primarily to $2.4 million in losses from futures contracts to reduce our economic exposure to fluctuations in prices of natural gas and oil under our SO#4 and Puna PPAs, which were not accounted for as hedge transactions. Derivatives and foreign currency transaction losses for the nine months ended September 30, 2015 were attributable primarily to losses on foreign currency forward contracts which were not accounted for as hedge transactions.

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, 2016 was $12.4 million, compared to $18.9 million for the nine months ended September 30, 2015. This income represents mainly the value of PTCs and taxable income or loss generated by ORTP and allocated to the investors. This decrease was primarily attributable to a lower taxable loss in ORTP.

Other non-operating loss for the nine months ended September 30, 2016 were $5.3 million compared to $1.5 million for the nine months ended September 30, 2015. Other non-operating loss for the nine months ended September 30, 2016 includes: (i) prepayment fees of approximately $5.0 million due to the repayment of the senior unsecured bonds in September 2016, as discussed above; and (ii) a make whole premium of $0.6 million resulting from the repurchase of $6.8 million aggregate principal amount of our OFC Senior Secured Notes. 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 tax provision for the nine months ended September 30, 2016 was $29.4 million, compared to income tax benefit of $26.7 million for the nine months ended September 30, 2015. 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 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 nine months ended September 30, 2015, excluding the $49.4 million, was $22.7 million. The increase in income tax provision from $22.7 million, excluding the $49.4 million, in the nine months ended September 30, 2015 to $29.4 million in the nine months ended September 30, 2016 primarily resulted from the increase in income before taxes in jurisdictions outside the U.S. Our effective tax rate for the nine months ended September 30, 2016 and the nine months ended September 30, 2015, excluding the $49.4 million, was 28.1% and 29.3%, respectively. Our effective tax rate is principally based upon the composition of the income in different countries and changes related to valuation allowances for certain countries. Our aggregate effective tax rate is lower than the 35% U.S. federal statutory tax rate as a substantial portion of our income is derived in Israel which is taxed at the corporate tax rate of 16%, partially offset by taxes on earnings in Kenya which are taxed at a statutory rate of 37.5%. There is no impact on the Company’s income tax expense (benefit) related to U.S. earnings (losses) due to the offsetting impact on the provision related to the change in the valuation allowance on the Company’s U.S. net deferred tax asset position.

Equity in losses of investees, net for the nine months ended September 30, 2016 was $4.7 million, compared to $4.9 million for the nine months ended September 30, 2015. Equity in losses of investees, net are derived from our 12.75% share in the losses of the Sarulla project and from profits elimination.

Net income for the nine months ended September 30, 2016 was $70.3 million, compared to $99.2 million for the nine months ended September 30, 2015, which represents a decrease of $28.9 million. This decrease in net income was principally attributable to $11 million one-time expenses in general and administrative expenses related to settlement, as discussed above, the increase of $56.1 million in income tax provision, a decrease of $6.5 million in income attributable to sale of tax benefits, and $3.8 million increase in other non-operating loss, partially offset by an increase in operating income of $35.7 million, all as discussed above.

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 in one or more of our projects and cash grants we received under the American Recovery and Reinvestment Act of 2009 (“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, 2016, we had access to (i) $90.1 million in cash and cash equivalents of which $59.6 million is related to foreign jurisdictions; and (ii) $171.1 million of unused corporate borrowing capacity under existing lines of credit with different commercial banks.

Our estimated capital needs for the remainder of 2016 include approximately $77.0 million for capital expenditures on new projects under development or construction, exploration activity, operating projects, and machinery and equipment including $6.0 million for expected investments in activities under our new strategic plan, as well as $21.2 million for debt repayment.

We expect to finance these requirements 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, based on the current stage of implementation of the new strategic plan, the sources of liquidity and capital resources described above will address our anticipated liquidity, capital expenditures, and other investment requirements.

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.

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.”

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, 2016, (the last measurement date of the covenants) the actual historical 12-month debt service coverage ratio was 1.27 and the pro-forma 12-month debt service coverage ratio was 1.29 (on a semi-annual basis and as of June 30, 2016). There was $19.7 million aggregate principal amount of OFC Senior Secured Notes outstanding as of September 30, 2016.

In September 2016, we repurchased from OFC noteholders $6.8 million of the aggregate principal amount of our OFC Senior Secured Notes. We recognized a loss of approximately $0.6 million in the three and nine months ended September 30, 2016 as a result of that repurchase. 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 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, 2016, (the last measurement date of the covenants) the actual historical 12-month debt service coverage ratio was 1.25, and the pro-forma 12-month debt service coverage ratio was 1.91. There were $40.1 million of OrCal Senior Secured Notes outstanding as of September 30, 2016.

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, 2016, 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 as 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 debt service coverage ratio requirement of at least 1.2 (on a blended basis for all OFC 2 power plants), measured, at the time of any proposed distribution, over each of the two six-months periods comprised of distinct consecutive fiscal quarters immediately preceding the proposed distribution, and a projected future debt service coverage ratio requirement of at least 1.5 (on a blended basis for all OFC 2 power plants), measured, at the time of any proposed distribution, over each of the two six-months periods comprised of distinct consecutive fiscal quarters immediately following such proposed distribution. As of September 30, 2016, our historical debt service coverage ratio was 2.03 and 2.54, respectively for each of the two six-month periods, and our projected future debt service coverage ratio was 2.07 and 1.89, respectively for each of the two six-month periods.

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. The trigger event is any loss, liability, damage, expense or cost to the Jersey Valley facility caused by the interconnection under the various interconnection related agreements of the Dixie Meadows (Phase 2) project that we may develop in the future.

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.

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 $67.3 million and matures on December 15, 2030 and Tranche II, which has an outstanding balance of $145.5 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 $38.3 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 $19.7 million as of September 30, 2016, 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, 2016, the actual historical and projected 12-month debt service coverage ratio was 2.62 and 2.93, respectively.

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.

The loan is payable in 48 quarterly payments commencing March 31, 2016. 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.

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, 2016, the actual historical and projected 12-month Debt Service Coverage Ratio was 1.85 and 1.98, 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.

Union Bank. In February 2012, Ormat Nevada, our wholly owned subsidiary, entered into an amended and restated credit agreement with Union Bank. Under credit agreement as amended and restated and further amended through the date of this report, the credit termination date is June 30, 2017. On June 30, 2016, the aggregate amount available under the credit agreement was increased by $10 million to $60.0 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) a 12-month debt service coverage ratio of not less than 1.35; and (iii) a distribution leverage ratio not to exceed 2.0. As of September 30, 2016: (i) the actual 12-month debt to EBITDA ratio was 2.41; (ii) the 12-month debt service coverage ratio was 2.29; and (iii) the distribution leverage ratio was 0.86. 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, 2016, letters of credit in the aggregate amount of $32.5 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. The current expiration date of the facility under this credit agreement is December 31, 2017. The aggregate amount available under the credit agreement was increased by $10 million to $35.0 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) a 12-month debt service coverage ratio of not less than 1.35; and (iii) a distribution leverage ratio not to exceed 2.0. As of September 30, 2016: (i) the actual 12-month debt to EBITDA ratio was 2.41; (ii) the 12-month debt service coverage ratio was 2.29; and (iii) the distribution leverage ratio was 0.86. 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, 2016, letters of credit in the aggregate amount of $23.2 million remain issued and outstanding under this committed credit agreement.

Other Banks. We also have committed credit agreements with five other commercial banks for an aggregate amount of $429.8 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 $215.0 million and (ii) the issuance of one or more letters of credit in the amount of up to $214.8 million. The credit agreements mature between February 2017 and June 2019. 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, 2016, there was no outstanding loan balance.

As of September 30, 2016, letters of credit with an aggregate stated amount of $260.7 million were issued and outstanding under these credit agreements.

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, 2016, committed letters of credit in the aggregate amount of $339.3 million remained issued and outstanding under the credit agreements with Union Bank, HSBC and five of the commercial banks as described under “Credit Agreements”.

In addition, we have a non-committed credit facility with HSBC. Under the terms of this facility we, or our Israeli subsidiary, Ormat Systems, can request assurance of letters of credit. As of September 30, 2016, letters of credit with an aggregated amount of $22.8 million were issued and outstanding under this credit facility.

Term Loans. 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, 2016, $3.3 million was outstanding under this loan.

Senior Unsecured Bonds. We had 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 was repayable in a single bullet payment upon the final maturity of the bonds on August 1, 2017. The bonds bore 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%.

On September 08, 2016, the Company concluded an auction tender and accepted subscriptions for $204 million aggregate principal amount of two tranches (Series 2 approximately $67 million and Series 3 approximately $137 million) of senior unsecured bonds. The proceeds from the senior unsecured bonds were used on September 29, 2016, to prepay the Company’s $250 million senior secured bonds that were payable on August 1, 2017.

The senior unsecured bonds, which were issued on September 14, 2016, have an outstanding aggregate principal amount of approximately $204.0 million consisting of two tranches (approximately $67 million principal amount of Series 2 and approximately $137 million principal amount of Series 3). The Series 2 Bonds will mature in September 2020 and bear interest at a fixed rate of 3.7% per annum, payable semi-annually. The Series 3 Bonds will mature in September 2022 and bear interest at a fixed rate of 4.45% per annum, payable semi-annually. The Bonds will be repaid at maturity in a single bullet payment, unless earlier prepaid by Ormat pursuant to the terms and conditions of the trust instrument that governs the Bonds. Both tranches received a rating of ilA+ from Maloot S&P in Israel with a stable outlook.

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, 2016, $19.7 million is outstanding under the DEG Loan (out of which $13.5 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, 2016: (i) total equity was $1,135.9 million and the actual equity to total assets ratio was 50.3% and (ii) the 12-month debt, net of cash and cash equivalents, to Adjusted EBITDA ratio was 2.33. During the nine months ended September 30, 2016, we distributed interim dividends in an aggregate amount of $22.5 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.

Future minimum payments under long-term obligations, excluding revolving credit lines with commercial banks and lease payments under the Puna lease transaction described below, as of September 30, 2016, are as follows:

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, 2016 amounted to $28.7 million, net of accumulated depreciation of $32.2 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 revenues 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 $5.4 million and $2.1 million as of September 30, 2016 and December 31, 2015, 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.

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. We expect the Flip Date to occur in the first quarter of 2017.

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.

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 $2.0 million and $1.7 million in the first quarters of 2016 and 2015, 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 expected to occur by the end of 2016. 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.

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 $10.3 million as of September 30, 2016. 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.

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

Net cash provided by operating activities for the nine months ended September 30, 2016 was $158.0 million, compared to $123.0 million for the nine months ended September 30, 2015. The net increase of $35.1 million resulted primarily from: (i) an increase in deferred income tax liabilities of $20.7 million in the nine months ended September 30, 2016, compared to a decrease of $34.6 million in the nine months ended September 30, 2015, due to the deferred tax asset in Kenya, as discussed above; and (ii) an increase in accounts payable and accrued expenses of $10.5 million in the nine months ended September 30, 2016, compared to a decrease of $21.9 million in the nine months ended September 30, 2015, as a result of timing in payments of our payables. The increase was partially offset by: (i) a decrease in cash inflow due to lower net income of $28.9 million, from $99.2 million for the nine months ended September 30, 2015 to $70.3 million for the nine months ended September 30, 2016, as described above; and (ii) a decrease in billing in excess of costs and estimated earnings on uncompleted contracts, net of $9.7 million in our Product segment in the nine months ended September 30, 2016, compared to a net increase of $11.2 million in the nine months ended September 30, 2015, as a result of timing in billing of our customers.

Net cash used in investing activities for the nine months ended September 30, 2016 was $125.2 million, compared to $76.5 million for the nine months ended September 30, 2015. The principal factors that affected our net cash used in investing activities during the nine months ended September 30, 2016 were: (i) capital expenditures of $108.0 million, primarily for our facilities under construction, and $18.1 million net cash paid for the acquisition of GB. The principal factors that affected our net cash used in investing activities during the nine months ended September 30, 2015 were capital expenditures of $117.6 million, primarily for our facilities under construction; reduced by (i) a net decrease of $22.7 million in restricted cash and cash equivalents, due to timing of debt repayments; and (ii) $15.4 million derived from cash of Ormat Industries due to the share exchange transaction.

Net cash used in financing activities for the nine months ended September 30, 2016 was $128.7 million, compared to $84.9 million of cash provided by financing activities for the nine months ended September 30, 2015. The principal factors that affected the net cash used in financing activities during the nine months ended September 30, 2016 were: (i) early repayment of $249.5 million of Senior Unsecured Bonds; (ii) the repayment of long-term debt in the amount of $41.0 million; (iii) a $22.5 million cash dividend paid; (iv) $17.3 million cash paid to non-controlling interests; and (v) $6.8 million of cash paid to repurchase our OFC Senior Secured Notes, reduced by $203.5 million net proceeds from issuance of two new series of senior unsecured bonds. The principal factors that affected our net cash provided by financing activities during the nine months ended September 30, 2015 were: net proceeds from the issuance of shares to non-controlling 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) a $9.8 million cash dividend paid.

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, (vii) gains or losses from extinguishment of liability, and (viii) gain or loss on sale of subsidiary and property, plant and equipment. 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 and nine months ended September 30, 2016 were $85.4 million and $246.9 million, respectively, compared to $79.0 million and $213.5 million for the three and nine months ended September 30, 2015.

The following table reconciles net cash provided by operating activities to EBITDA and Adjusted EBITDA for the three-month and nine-month periods ended September 30, 2016 and 2015:

The following table reconciles Net income to EBITDA for the nine-month and three-month periods ended September 30, 2016 and 2015:

Our capital expenditures primarily relate to two principal components: (i) the development and construction of new power plants, (ii) the enhancement of our existing power plants; and (iii) the investment in new activities under the new strategic plan.

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

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 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 is currently in the commissioning and fine tuning stage but commercial operation date is expected to be delayed by few weeks. The delay is a result of local riots protesting the EPC contractor that caused a work stoppage. Work has resumed and we currently expect commercial operation of the first phase to begin in January 2017. For the second phase, engineering and procurement has been substantially completed, site construction is in progress and all of the equipment to be supplied by Ormat was delivered. For the third phase, engineering and procurement is still in progress, Construction work at the site is in progress and manufacturing of equipment to be supplied by Ormat is underway as planned. Drilling activities, for the second and third phases are still ongoing and the project has achieved to date, based on preliminary estimates, approximately 80% of the required production capacity and approximately 80% of the required injection capacity. The project has missed a few milestones defined under the loan documents, but has received waivers from the lenders and commercial operation of the second and third phases is still expected to commence within 18 months after the commercial operation of the first phase. As of September 30, 2016 the project is in compliance with milestones agreed with the lenders. The project is experiencing delays in the field development and certain cost overruns resulting from delays and excess drilling costs. Although estimated cost at completion is still within the approved budget (including contingencies), the lenders have requested that the sponsors commit additional equity. The sponsors have agreed and financing documents were revised to reflect this request. With respect to Ormat’s role as a supplier, all contractual milestones under the supply agreement were achieved.

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.

Ormat holds a 12.75% equity interest in the project, corresponding to an approximately $60 million equity commitment to invest based on the current project plan.

Heber 1 Power Plant (California). We are currently in the process of enhancing the Heber 1 power plant of the Heber complex located in Imperial Valley, California. We are planning to convert artesian wells to pumped wells, add new water cooling unit and replace one of the OECs, following which we expect the capacity of the complex to reach 92 MW. Engineering and procurement is ongoing and completion is expected at the end of 2017. In December 2015, we started to sell power under a new fixed price PPA with SCPPA.

Platanares Project (Honduras). We are currently developing the Geotermica Platanares geothermal project in Honduras. Construction and drilling activities are ongoing and part of the equipment is already on site. In December 2015, we concluded the drilling activity as well as extensive tests that support the decision to construct a 35 MW project, which is larger than initially estimated. We hold the assets, including the project’s wells, land, permits and a PPA, under a Build, Operate, Transfer (“BOT”) structure for 15 years from the date of commercial operation. Commercial operation is expected before the end of 2017.

Tungsten (Nevada). We are currently developing the 24 MW Tungsten geothermal power plant in Churchill County, Nevada. Drilling is ongoing and we expect site construction to start in the fourth quarter. We already secured the interconnection agreement. The project is expected to be on-line by the end of 2017.

Brady Power Plant (Nevada). We are currently in the process of enhancing the Brady power plant located in Churchill County, Nevada. We are planning to replace its old equipment with new OECs, following which we expect the capacity of the complex to increase to approximately 12MW. Engineering and manufacturing is ongoing and enhancements are expected to be completed during 2018.

Rabitt Hill (Texas). We are currently jointly developing the Rabitt Hill energy storage located in Georgetown, Texas with Alevo Group SA. We will own and fund the majority of the costs associated with the 10 MW Rabbit Hill energy storage project and, under the terms of the agreement, will provide engineering and construction services and balance of plant equipment. Alevo will provide its innovative GridBank™ inorganic lithium ion energy storage system in conjunction with the power conversion systems. The project will consist of three GridBank™ enclosures and will provide FRRS as an open market participant in the ERCOT, an independent system operator that manages the flow of electric power to Texas customers. Construction of the project is ongoing. Progress and completion is pending the supply of batteries by from Alevo.

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

Dixie Meadows (Nevada). We are currently developing the 15-20 MW Dixie Meadows geothermal power plant in Churchill County, Nevada. Drilling is ongoing. The project is expected to be on-line by the end of 2018.

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. We completed the drilling of one well in the third quarter of 2016 and are currently analyzing the resource data.

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 a transmission line, we are participating in the Southern California Edison Wholesale Distribution Access Tariff Transition Cluster Generator Interconnection Process (WDAT LGIA) to deliver energy into the Southern California Edison system at the Casa Diablo Substation. Southern California Edison completed phase I and phase II cluster studies and the WDAT LGIA is being reviewed while re-evaluation of the system upgrades is being completed due to changes in the participants in the cluster study. We are not planning to make material capital expenditures in this project in 2016.

We have estimated approximately $365.0 million in capital expenditures for construction of new projects and enhancements to our existing power plants, of which we have invested approximately $138.0 million as of September 30, 2016. We expect to invest approximately $57.0 million of such total during the remainder of 2016 and the remaining approximately $170.0 million thereafter.

In addition, we estimate approximately $24.0 million in additional capital expenditures in the remainder of 2016 to be allocated as follows: (i) $10.0 million for maintenance capital expenditures to our operating power plants; (ii) $10.0 million for continued exploration activity under various leases for geothermal resources where we have already started exploration activity. In the aggregate, we estimate our total capital expenditures for the remainder of 2016 will be approximately $77.0 million.

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.

We, like other power plant operators, are exposed to electricity price volatility risk. 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 aggregate 90 MW PPAs for the Heber 2 power plant 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.

The energy payments under the PPAs of the Heber 2 power plant 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 short run avoided costs, or SRAC. A decline in the price of natural gas will result in a decrease in the incremental cost that the power purchaser avoids by not generating its electrical energy needs from natural gas, or by reducing the price of purchasing its electrical energy needs from natural gas power plants, which in turn will reduce the energy payments that we may charge under the relevant PPA for these power plants. In March 2014, May 2015 and February 2016, we entered into derivative transactions to reduce our exposure to the price of natural gas under these PPAs, until December 29, 2016. The Puna complex is currently benefiting from energy prices which are higher than the floor under the 25 MW PPA for the Puna complex as a result of the high fuel costs that impact HELCO’s avoided costs.

As of September 30, 2016, 94.4% of our consolidated long-term debt was fixed rate debt and therefore was not subject to interest rate volatility risk. As of such date, 5.6% of our long-term debt was floating rate debt, exposing us to interest rate risk in connection therewith. As of September 30, 2016, $47.2 million of our long-term debt remained subject to some interest 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 interest rate risk. Fixed rate securities may have their market value adversely impacted by a rise in interest rates, while floating rate securities may produce less income than expected if interest rates fall. As a result of these factors, our future investment income may fall short of expectations because of changes in interest rates or we may suffer losses in principal if we are forced to sell securities that decline in market value because of changes in interest rates.

We are also exposed to foreign currency exchange risk, 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 revenues 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 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, 2016 and December 31, 2015 by a hypothetical 10% and calculating the resulting change in the fair values.

At this time, the development of our new strategic plan has not exposed us to any additional market risk. However, as the implementation of the plan progresses, we may be exposed to additional or different market risks.

The results of the sensitivity analysis calculations as of September 30, 2016 and December 31, 2015 are presented below:

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

We do not expect that inflation will 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 provisions that mitigate inflation risk.

In connection with the Electricity segment, inflation may directly impact an expense we incur for the operation of our projects, thereby increasing our overall operating costs. 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 plants, 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 calculated as a percentage of revenues 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, thereby increasing our operating costs in the Product segment. We are more likely to be able to offset all or part of this inflationary impact through our project pricing. With respect to power plants that we build 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.

Our credit risk is currently concentrated with the following major customers: Southern California Public Power Authority, KPLC, 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. Also, by implementing our new multi-year strategic plan we may be exposed, by expanding our customer base, to different credit profile customers than our current customers.

Sierra Pacific Power Company and Nevada Power Company accounted for 14.4% and 15.3% of our total revenue for the three months ended September 30, 2016 and 2015, respectively and 18.6% and 19.3% for the nine months ended September 30, 2016 and 2015, respectively.

Southern California Public Power Authority accounted for 7.7% and 3.3% of our total revenue for the three months ended September 30, 2016 and 2015, respectively and 9.9% and 4.3% for the nine months ended June 30, 2016 and 2015, respectively.

KPLC accounted for 15.1% and 13.5% of our total revenue for the three months ended September 30, 2016 and 2015, respectively and 16.4% and 15.4% for the nine months ended September 30, 2016 and 2015, respectively.

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, 2016, 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 2015 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. New solar projects that are under construction by December 2019 will qualify for a 30% investment tax credit. The credit will fall to 26% for projects starting construction in 2020 and 22% for projects starting construction in 2021. Projects that are under construction before these deadlines must be placed in service by December 2023 to qualify. The investment credit will revert to its permanent 10% level after that.

We are also permitted to depreciate, or write off, most of the cost of the plant. In those cases where we claimed the one-time 30% (or 10%) tax credit or received the Treasury cash grant, our tax basis in the plant that we can recover through depreciation is reduced by one-half of the tax credit or cash grant; if in the future we claim other tax credits, there is no reduction in the tax basis for depreciation. For projects that are placed into service after December 31, 2011 and before January 1, 2017, a depreciation “bonus” will permit us to write off 50% of the cost of that equipment in the year the power plant is placed into service. New equipment put in service in 2018 would qualify for a 40% bonus. Equipment put in service in 2019 would qualify for a 30% bonus. After applying any depreciation bonus that is available, we can write off the remainder of our tax basis in the plant, if any, over five years on an accelerated basis, meaning that more of the cost may be deducted in the first few years than during the remainder of the depreciation period.

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.

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.

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, 2016, 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.

There were no changes in our internal controls over financial reporting in the third quarter of 2016 that have materially affected or are reasonably likely to materially affect our internal controls over financial reporting.

There were no material developments in any legal proceedings to which the Company is a party during the third quarter of 2016, other than as described below.

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, 2015 filed with the SEC on February 26, 2016.

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

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.

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

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

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

PART I — FINANCIAL INFORMATION
ITEM 1.	FINANCIAL STATEMENTS	4
ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	27
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	61
ITEM 4.	CONTROLS AND PROCEDURES	61
PART II — OTHER INFORMATION
ITEM 1.	LEGAL PROCEEDINGS	62
ITEM 1A.	RISK FACTORS	63
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	63
ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	63
ITEM 4.	MINE SAFETY DISCLOSURES	63
ITEM 5.	OTHER INFORMATION	64
ITEM 6.	EXHIBITS	65
SIGNATURES		66

	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015

Interest related to sale of tax benefits	$	2,565		$	2,375		$	6,269		$	7,062
Interest expense		15,726			16,510			47,214			50,430
Less — amount capitalized		(1,154	)		(1,137	)		(1,922	)		(3,057	)
	$	17,137		$	17,748		$	51,561		$	54,435

	(Dollars in thousands)


Year ending December 31:
2016	$	22,167
2017		61,707
2018		57,100
2019		48,878
2020		116,539
Thereafter		529,523
Total	$	835,914

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

	For the quarterly period ended September 30, 2016

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

	For the transition period from to

	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,
	2016		2015		2016		2015		2016			2015			2016			2015
Revenues:
Electricity	$	109,795	$	97,245	$	321,664	$	278,124		59.5	%		59.7	%		64.8	%		65.7	%
Product		74,822		65,607		174,408		145,446		40.5			40.3			35.2			34.3
Total	$	184,617	$	162,852	$	496,072	$	423,570		100	%		100	%		100	%		100	%

Date Declared	Dividend Amount per Share		Record Date	Payment Date
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
February 23, 2016	$	0.31	March 15, 2016	March 29, 2016
May 4, 2016	$	0.07	May 18, 2016	May 24, 2016
August 2, 2016	$	0.07	August 16, 2016	August 30, 2016
November 7, 2016	$	0.07	November 21, 2016	December 6, 2016

	Assuming a 10% Increase in Rates						Assuming a 10% Decrease in Rates
Risk	September 30, 2016			December 31, 2015			September 30, 2016			December 31, 2015			Change in the Fair Value of
	(Dollars in thousands)
Call options on natural gas price	$	525		$	-		$	(428	)	$	-		NGI futures
Call and put options on oil		980			-			(362	)		-		Brent oil futures
Foreign Currency		(3,702	)		(3,894	)		4,524			4,760		Foreign currency forward contracts
Interest Rate		(348	)		(408	)		353			417		OFC
Interest Rate		(450	)		(646	)		458			660		OrCal
Interest Rate		(8,388	)		(9,322	)		8,880			9,941		OFC 2
Interest Rate		(100	)		(175	)		102			172		Loan from DEG
Interest Rate		(7,957	)		(9,164	)		8,352			9,685		Loan from OPIC
Interest Rate		-			(1,888	)		-			1,907		Senior unsecured bonds
Interest Rate		(4,309	)		-			4,423			-		Senior unsecured bonds
Interest Rate		-	⁽¹⁾		-	⁽¹⁾		-	⁽¹⁾		-	⁽¹⁾	Amatitlan Loan
Interest Rate		(216	)		-			227			-		Other long-term loans

	ORMAT TECHNOLOGIES, INC.

	By:	/s/ DORON BLACHAR
		Name: Doron Blachar
		Title: Chief Financial Officer

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 Mishmeret Trust Company Limited (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 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 Mishmeret — Trusts Services Company Ltd (Formerly 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.