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 þ 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 þ 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 þ No

As of the date of this filing, the number of outstanding shares of common stock of Ormat Technologies, Inc. is 45,430,886 par value of $0.001 per share.

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.


	June 30, 2011		December 31, 2010		September 30, 2011		December 31, 2010
	(In thousands)				(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	44,338	$	82,815	$	59,077	$	82,815
Marketable securities		23,097		—		21,189		—
Restricted cash, cash equivalents and marketable securities (all related to VIEs)		28,713		23,309		61,791		23,309
Receivables:
Trade		72,185		54,495		53,084		54,495
Related entity		355		303		381		303
Other		7,795		8,173		7,028		8,173
Due from Parent		122		272		151		272
Inventories		14,408		12,538		17,899		12,538
Costs and estimated earnings in excess of billings on uncompleted contracts		570		6,146		3,518		6,146
Deferred income taxes		1,361		1,674		1,582		1,674
Prepaid expenses and other		22,481		14,929		22,972		14,929

Total current assets		215,425		204,654		248,672		204,654
Long-term marketable securities		—		1,287		—		1,287
Restricted cash, cash equivalents and marketable securities (all related to VIEs)		—		1,740		—		1,740
Unconsolidated investments		4,068		4,244		3,997		4,244
Deposits and other		22,989		21,353		21,481		21,353
Deferred income taxes		17,087		17,087		17,087		17,087
Deferred charges		37,059		37,571		36,930		37,571
Property, plant and equipment, net ($1,358,330 and $1,371,400 related to VIEs, respectively)		1,417,931		1,425,467
Construction-in-process ($206,109 and $149,851 related to VIEs, respectively)		337,969		270,634
Property, plant and equipment, net ($1,365,870 and $1,371,400 related to VIEs, respectively)						1,422,450		1,425,467
Construction-in-process ($295,422 and $149,851 related to VIEs, respectively)						399,002		270,634
Deferred financing and lease costs, net		19,609		19,017		23,238		19,017
Intangible assets, net		38,676		40,274		37,864		40,274

Total assets	$	2,110,813	$	2,043,328	$	2,210,721	$	2,043,328

LIABILITIES AND EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	76,607	$	85,549	$	99,362	$	85,549
Billings in excess of costs and estimated earnings on uncompleted contracts		18,818		3,153		35,664		3,153
Current portion of long-term debt:
Limited and non-recourse (all related to VIEs)		14,304		15,020		13,485		15,020
Full recourse		14,775		13,010		18,543		13,010
Senior secured notes (non-recourse) (all related to VIEs)		20,622		20,990		20,622		20,990

Total current liabilities		145,126		137,722		187,676		137,722
Long-term debt, net of current portion:
Limited and non-recourse (all related to VIEs)		107,390		114,132		106,759		114,132
Full recourse:
Senior unsecured bonds (plus unamortized premium based upon 7% of $1,892,000)		250,189		142,003
Senior unsecured bonds (plus unamortized premium based upon 7% of $1,822)						250,119		142,003
Other		75,920		84,166		70,623		84,166
Revolving credit lines with banks (full recourse)		151,461		189,466		221,322		189,466
Senior secured notes (non-recourse) (all related to VIEs)		203,382		210,882		203,382		210,882
Liability associated with sale of tax benefits		78,519		66,587		74,448		66,587
Deferred lease income		70,010		71,264		69,483		71,264
Deferred income taxes		28,997		30,878		28,244		30,878
Liability for unrecognized tax benefits		4,380		5,431		4,245		5,431
Liabilities for severance pay		22,565		20,706		20,987		20,706
Asset retirement obligation		20,684		19,903		21,086		19,903
Other long-term liabilities		4,473		4,961		4,242		4,961

Total liabilities		1,163,096		1,098,101		1,262,616		1,098,101

Commitments and contingencies
Equity:
The Company’s stockholders’ equity:
Common stock, par value $0.001 per share; 200,000,000 shares authorized; 45,430,886 shares issued and outstanding, respectively		46		46		46		46
Additional paid-in capital		722,522		716,731		724,074		716,731
Retained earnings		216,362		221,311		215,411		221,311
Accumulated other comprehensive income		729		1,044		565		1,044

		939,659		939,132		940,096		939,132
Noncontrolling interest		8,058		6,095		8,009		6,095

Total equity		947,717		945,227		948,105		945,227

Total liabilities and equity	$	2,110,813	$	2,043,328	$	2,210,721	$	2,043,328

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


	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010			2011			2010			2011			2010
	(In thousands, except per share data)						(In thousands, except per share data)						(In thousands, except per share data)						(In thousands, except per share data)
Revenues:
Electricity	$	81,190		$	68,807		$	159,458		$	134,912		$	86,815		$	83,357		$	246,273		$	218,269
Product		23,424			27,459			42,976			44,008			24,026			18,120			67,002			62,128

Total revenues		104,614			96,266			202,434			178,920			110,841			101,477			313,275			280,397

Cost of revenues:
Electricity		62,212			63,498			128,149			118,021			57,941			61,530			186,090			179,551
Product		9,249			14,115			26,139			26,552			17,137			14,764			43,276			41,316

Total cost of revenues		71,461			77,613			154,288			144,573			75,078			76,294			229,366			220,867

Gross margin		33,153			18,653			48,146			34,347			35,763			25,183			83,909			59,530
Operating expenses:
Research and development expenses		2,575			3,614			4,782			6,881			2,346			1,252			7,128			8,133
Selling and marketing expenses		3,725			2,686			6,385			5,888			2,940			3,333			9,325			9,221
General and administrative expenses		7,479			6,996			14,486			14,016			6,269			5,780			20,755			19,796
Write-off of unsuccessful exploration activities		—			3,050			—			3,050			—			—			—			3,050

Operating income		19,374			2,307			22,493			4,512			24,208			14,818			46,701			19,330
Other income (expense):
Interest income		716			95			851			292			438			140			1,289			432
Interest expense, net		(17,442	)		(9,426	)		(30,522	)		(19,140	)		(23,909	)		(10,961	)		(54,431	)		(30,101	)
Foreign currency translation and transaction gains (losses)		596			(1,033	)		1,113			(599	)		(2,659	)		1,074			(1,546	)		475
Income attributable to sale of tax benefits		3,141			2,070			5,280			4,209			2,344			2,183			7,624			6,392
Gain on acquisition of controlling interest														—			36,928			—			36,928
Other non-operating income (expense), net		915			79			118			(280	)		347			233			465			(47	)

Income (loss) from continuing operations, before income taxes and equity in income (losses) of investees		7,300			(5,908	)		(667	)		(11,006	)
Income tax benefit		1,007			3,365			421			5,922
Income from continuing operations, before income taxes and equity in income (losses) of investees														769			44,415			102			33,409
Income tax benefit (expense)														305			(11,931	)		726			(6,009	)
Equity in income (losses) of investees, net		(69	)		479			(481	)		1,025			(71	)		(83	)		(552	)		942

Income (loss) from continuing operations		8,238			(2,064	)		(727	)		(4,059	)
Income from continuing operations														1,003			32,401			276			28,342
Discontinued operations:
Income from discontinued operations, net of related tax of $0, $0, $0 and $6, respectively		—			—			—			14			—			—			—			14
Gain on sale of a subsidiary in New Zealand, net of related tax of $0, $(570), $0 and $2,000, respectively		—			570			—			4,336
Gain on sale of a subsidiary in New Zealand, net of related tax of $0, $0, $0 and $2,000, respectively														—			—			—			4,336

Net income (loss)		8,238			(1,494	)		(727	)		291
Net loss (income) attributable to noncontrolling interest		(105	)		57			(115	)		110
Net income														1,003			32,401			276			32,692
Net (income) loss attributable to noncontrolling interest														(137	)		58			(252	)		168

Net income (loss) attributable to the Company’s stockholders	$	8,133		$	(1,437	)	$	(842	)	$	401
Net income attributable to the Company’s stockholders													$	866		$	32,459		$	24		$	32,860

Comprehensive income (loss):
Net income (loss)		8,238			(1,494	)		(727	)		291
Net income														1,003			32,401			276			32,692
Other comprehensive income (loss), net of related taxes:
Currency translation adjustment		—			—			—			43			—			—			—			43
Amortization of unrealized gains in respect of derivative instruments designated for cash flow hedge		(53	)		(58	)		(106	)		(116	)		(53	)		(61	)		(159	)		(177	)
Change in unrealized gains or losses on marketable securities available-for-sale		(186	)		(18	)		(209	)		(80	)		(111	)		—			(320	)		(80	)

Comprehensive income (loss)		7,999			(1,570	)		(1,042	)		138			839			32,340			(203	)		32,478
Comprehensive loss (income) attributable to noncontrolling interest		(105	)		57			(115	)		110
Comprehensive (income) loss attributable to noncontrolling interest														(137	)		58			(252	)		168

Comprehensive income (loss) attributable to the Company’s stockholders	$	7,894		$	(1,513	)	$	(1,157	)	$	248		$	702		$	32,398		$	(455	)	$	32,646

Earnings (loss) per share attributable to the Company’s stockholders — basic and diluted:
Income (loss) from continuing operations	$	0.18		$	(0.05	)	$	(0.02	)	$	(0.09	)
Earnings per share attributable to the Company’s stockholders — basic and diluted:
Income from continuing operations													$	0.02		$	0.71		$	0.00		$	0.62
Discontinued operations		—			0.02			—			0.10			—			—			—			0.10

Net income (loss)	$	0.18		$	(0.03	)	$	(0.02	)	$	0.01
Net income													$	0.02		$	0.71		$	0.00		$	0.72

Weighted average number of shares used in computation of earnings (loss) per share attributable to the Company’s stockholders:
Weighted average number of shares used in computation of earnings per share attributable to the Company’s stockholders:
Basic		45,431			45,431			45,431			45,431			45,431			45,431			45,431			45,431

Diluted		45,443			45,431			45,431			45,431			45,440			45,450			45,442			45,452

Dividend per share declared	$	0.04		$	0.05		$	0.09		$	0.17		$	0.04		$	0.05		$	0.13		$	0.22

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


	The Company’s Stockholders’ Equity
					Additional Paid-in Capital			Retained Earnings			Accumulated Other Comprehensive Income				Total				Noncontrolling Interest				Total Equity
														The Company’s Stockholders’ Equity
	Common Stock													Common Stock												Additional Paid-in Capital				Retained Earnings				Accumulated Other Comprehensive Income				Total				Noncontrolling Interest				Total Equity
	Shares		Amount											Shares								Amount				Additional Paid-in Capital												Total				Noncontrolling Interest				Total Equity
	(In thousands, except per share data)																											(In thousands, except per share data)
Balance at December 31, 2009		45,431	$	46			$		709,354		$	196,950						$				622					$	906,972		Retained Earnings				Accumulated Other Comprehensive Income		$	4,723			$	911,695				45,431			$	46		$	709,354		$	196,950	$	622	$	906,972	$	4,723	$	911,695
Stock-based compensation		—		—					2,970			—								—					2,970				—				2,970				—				—				4,637				—			—			4,637		—		4,637
Cash dividend declared, $0.17 per share		—		—					—			(7,724	)				—					(7,724		)			—				(7,724	)
Cumulative effect of adopting the guidance on evaluation of credit derivatives embedded in beneficial interests in securitized financial assets as of July 1, 2010 (net of related tax of $370)																												—				—				—				(693	)			693				—			—			—
Cash dividend declared, $0.22 per share																												—				—				—				(9,995	)			—				(9,995	)		—			(9,995	)
Net income (loss)		—		—		—			401			—				401				(110	)			291				—				—				—				32,860				—				32,860			(168	)		32,692
Other comprehensive income (loss), net of related taxes:
Currency translation adjustment		—		—		—			—			43				43				—				43				—				—				—				—				43				43			—			43
Amortization of unrealized gains in respect of derivative instruments designated for cash flow hedge (net of related tax of $73)		—		—		—			—			(116	)			(116	)			—				(116	)
Amortization of unrealized gains in respect of derivative instruments designated for cash flow hedge (net of related tax of $108)																												—				—				—				—				(177	)			(177	)		—			(177	)
Change in unrealized gains or losses on marketable securities available-for-sale (net of related tax of $43)		—		—		—			—			(80	)			(80	)			—				(80	)			—				—				—				—				(80	)			(80	)		—			(80	)

Balance at June 30, 2010		45,431	$	46	$	712,324		$	189,627		$	469			$	902,466			$	4,613			$	907,079
Balance at September 30, 2010																												45,431			$	46			$	713,991			$	219,122			$	1,101			$	934,260		$	4,555		$	938,815

Balance at December 31, 2010		45,431	$	46	$	716,731		$	221,311		$	1,044			$	939,132			$	6,095			$	945,227				45,431			$	46			$	716,731			$	221,311			$	1,044			$	939,132		$	6,095		$	945,227
Stock-based compensation		—		—		3,448			—			—				3,448				—				3,448				—				—				5,000				—				—				5,000			—			5,000
Increase in noncontrolling interest due to sale of equity interest in OPC LLC		—		—		2,343			—			—				2,343				1,848				4,191				—				—				2,343				—				—				2,343			1,662			4,005
Cash dividend declared, $0.09 per share		—		—		—			(4,107	)		—				(4,107	)			—				(4,107	)
Net income (loss)		—		—		—			(842	)		—				(842	)			115				(727	)
Cash dividend declared, $0.13 per share																												—				—				—				(5,924	)			—				(5,924	)		—			(5,924	)
Net income																												—				—				—				24				—				24			252			276
Other comprehensive income (loss), net of related taxes:
Amortization of unrealized gains in respect of derivative instruments designated for cash flow hedge (net of related tax of $64)		—		—		—			—			(106	)			(106	)			—				(106	)
Amortization of unrealized gains in respect of derivative instruments designated for cash flow hedge (net of related tax of $96)																												—				—				—				—				(159	)			(159	)		—			(159	)
Change in unrealized gains or losses on marketable securities available-for-sale (net of related tax of $0)		—		—		—			—			(209	)			(209	)			—				(209	)			—				—				—				—				(320	)			(320	)		—			(320	)

Balance at June 30, 2011		45,431	$	46	$	722,522		$	216,362		$	729			$	939,659			$	8,058			$	947,717
Balance at September 30, 2011																												45,431			$	46			$	724,074			$	215,411			$	565			$	940,096		$	8,009		$	948,105

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


	Six Months Ended June 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	(In thousands)						(In thousands)
Cash flows from operating activities:
Net income (loss)	$	(727	)	$	291
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Net income							$	276		$	32,692
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		48,005			40,329			71,261			64,461
Amortization of premium from senior unsecured bonds		(65	)		—			(72	)		—
Accretion of asset retirement obligation		781			556			1,183			888
Stock-based compensation		3,448			2,970			5,000			4,637
Amortization of deferred lease income		(1,343	)		(1,343	)		(2,014	)		(2,014	)
Income attributable to sale of tax benefits, net of interest expense		(1,720	)		(1,481	)		(2,243	)		(2,281	)
Equity in income (losses) of investees		481			(1,025	)		552			(942	)
Impairment of auction rate securities		205			—			205			—
Loss on disposal of property, plant and equipment		—			571			—			571
Write-off of unsuccessful exploration activities		—			3,050			—			3,050
Return on investment in unconsolidated investments		—			3,734			—			3,734
Unrealized loss on interest rate lock transactions		4,735			—
Changes in unrealized loss in respect of derivative instruments, net								11,052			—
Gain (loss) on severance pay fund asset		(1,219	)		515			282			(1,099	)
Premium from issuance of senior unsecured bonds		1,957			—
Premium from issuance Senior Unsecured Bonds								1,957			—
Gain on sale of a subsidiary		—			(6,350	)		—			(6,350	)
Deferred income tax benefit		(992	)		(5,365	)
Gain on acquisition of controlling interest								—			(36,928	)
Deferred income tax provision (benefit)								(1,805	)		5,717
Liability for unrecognized tax benefits		(1,051	)		434			(1,186	)		717
Deferred lease revenues		89			669			233			820
Changes in operating assets and liabilities, net of amounts acquired:
Receivables		(17,312	)		4,160			2,556			(5,691	)
Costs and estimated earnings in excess of billings on uncompleted contracts		5,576			2,007			2,628			13,869
Inventories		(1,870	)		311			(5,361	)		871
Prepaid expenses and other		(7,552	)		(38	)		(8,043	)		(3,995	)
Deposits and other		(485	)		(209	)		(471	)		(253	)
Accounts payable and accrued expenses		(8,569	)		9,376			(9,592	)		5,571
Due from/to related entities, net		(52	)		(77	)		(78	)		(60	)
Billings in excess of costs and estimated earnings on uncompleted contracts		15,665			8,195			32,511			1,420
Liabilities for severance pay		1,859			240			281			1,508
Other long-term liabilities		(488	)		(1,243	)		(719	)		(1,091	)
Due from/to Parent		150			(1,343	)		121			(178	)

Net cash provided by operating activities		39,506			58,934			98,514			79,644

Cash flows from investing activities:
Return of investment in unconsolidated investments		—			3,516			—			3,516
Purchases of marketable securities		(22,084	)		—
Purchases of marketable securities, net								(20,287	)		—
Net change in restricted cash, cash equivalents and marketable securities		(3,806	)		7,735			(36,884	)		(23,352	)
Cash received from sale of a subsidiary		—			19,594			—			19,594
Capital expenditures		(109,614	)		(139,171	)		(180,771	)		(194,926	)
Cash grant received from the U.S. Treasury under Section 1603 of the ARRA								—			108,286
Investment in unconsolidated companies		(305	)		(281	)		(305	)		(511	)
Cash paid for acquisition of controlling interest in a subsidiary, net of cash acquired								—			(64,517	)
Intangible assets acquired								—			(875	)
Increase (decrease) in severance pay fund asset, net of payments made to retired employees		68			(407	)		61			(235	)

Net cash used in investing activities		(135,741	)		(109,014	)		(238,186	)		(153,020	)

Cash flows from financing activities:
Proceeds from issuance of senior unsecured bonds		107,447			—			107,447			142,003
Proceeds from the sale of limited liability company interest in OPC LLC, net of transaction costs		24,878			—			24,878			—
Proceeds from revolving credit lines with banks		199,295			132,095			419,156			518,064
Repayment of revolving credit lines with banks		(237,300	)		(31,700	)		(387,300	)		(535,600	)
Repayments of long-term debt		(23,043	)		(34,656	)		(26,002	)		(37,670	)
Cash paid to non-controlling interest		(7,035	)		—			(10,769	)		—
Deferred debt issuance costs		(2,377	)		(47	)		(5,552	)		(493	)
Cash dividends paid		(4,107	)		(7,724	)		(5,924	)		(9,995	)

Net cash provided by financing activities		57,758			57,968			115,934			76,309

Net change in cash and cash equivalents		(38,477	)		7,888			(23,738	)		2,933
Cash and cash equivalents at beginning of period		82,815			46,307			82,815			46,307

Cash and cash equivalents at end of period	$	44,338		$	54,195		$	59,077		$	49,240

Supplemental non-cash investing and financing activities:
Increase (decrease) in accounts payable related to purchases of property, plant and equipment	$	(5,106	)	$	7,117
Increase in accounts payable related to purchases of property, plant and equipment							$	11,046		$	6,153

Accrued liabilities related to financing activities							$	1,309		$	—

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

These unaudited condensed consolidated financial statements of Ormat Technologies, Inc. and its subsidiaries (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, the 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 ~~June~~September 30, 2011, the consolidated results of operations and comprehensive income (loss) for the three and ~~six-month~~nine-month periods ended ~~June~~September 30, 2011 and 2010, and the consolidated cash flows for the ~~six-month~~nine-month periods ended ~~June~~September 30, 2011 and 2010.

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 three and ~~six-month~~nine-month periods ended ~~June~~September 30, 2011 are not necessarily indicative of the results to be expected for the year ending December 31, 2011.

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, 2010. The condensed consolidated balance sheet data as of December 31, 2010 was derived from the audited consolidated financial statements for the year ended December 31, 2010, 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.

Financial instruments that potentially subject the Company to a concentration of credit risk consist principally of temporary cash investments, marketable securities 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 ~~June~~September 30, 2011 and December 31, 2010, the Company had deposits totaling ~~$17,247,000~~$19,834,000 and $55,537,000, respectively, in seven U.S. financial institutions that were federally insured up to $250,000 per account. At ~~June~~September 30, 2011 and December 31, 2010, the Company’s deposits in foreign countries amounted to approximately ~~$33,166,000~~$47,302,000 and $37,929,000, respectively.

At ~~June~~September 30, 2011 and December 31, 2010, accounts receivable related to operations in foreign countries amounted to approximately ~~$42,230,000~~$24,786,000 and $26,128,000, respectively. At ~~June~~September 30, 2011 and December 31, 2010, accounts receivable from the Company’s major customers that have generated 10% or more of its revenues amounted to approximately ~~41%~~57% and 40% of the Company’s accounts receivable, respectively.

Southern California Edison Company (“SCE”) accounted for ~~29.5%~~34.5% and ~~25.5%~~35.9% of the Company’s total revenues for the three months ended ~~June~~September 30, 2011 and 2010, respectively, and ~~28.3%~~30.5% and ~~25.5%~~29.6% of the Company’s total revenues for the ~~six~~nine months ended ~~June~~September 30, 2011 and 2010, respectively. SCE is the ~~power purchaser and revenue source for the Mammoth complex, which was accounted for under the equity method~~

power purchaser and revenue source for the Mammoth complex, which was accounted for under the equity method through August 1, 2010. Following the Company’s acquisition of the remaining 50% interest in the Mammoth complex, as described in Note 3, the Company has included the results of the Mammoth complex in its consolidated financial statements.

Sierra Pacific Power Company and Nevada Power Company (subsidiaries of NV Energy, Inc.) accounted for ~~12.0%~~10.5% and ~~13.7%~~12.2% of the Company’s total revenues for the three months ended ~~June~~September 30, 2011 and 2010, respectively, and ~~14.1%~~12.8% and ~~16.2%~~14.7% of the Company’s total revenues for the ~~six~~nine months ended ~~June~~September 30, 2011 and 2010, respectively.

Hawaii Electric Light Company accounted for ~~11.8%~~10.3% and ~~8.0%~~10.1% of the Company’s total revenues for the three months ended ~~June~~September 30, 2011 and 2010, respectively, and ~~11.2%~~10.9% and ~~7.6%~~8.3% of the Company’s total revenues for the ~~six~~nine months ended ~~June~~September 30, 2011 and 2010, respectively.

Kenya Power and Lighting Co. Ltd. accounted for ~~8.4%~~8.0% and ~~9.2%~~8.7% of the Company’s total revenues for the three months ended ~~June~~September 30, 2011 and 2010, respectively, and ~~8.6%~~8.4% and ~~9.9%~~9.4% of the Company’s total revenues for the ~~six~~nine months ended ~~June~~September 30, 2011 and 2010, 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.

New accounting pronouncements effective in the ~~six-month~~nine-month period ended ~~June~~September 30, 2011

In October 2009, the Financial Accounting Standards Board (“FASB”) issued amendments to the accounting and disclosures for revenue recognition. These amendments modify the criteria for recognizing revenue in multiple element arrangements and require companies to develop a best estimate of the selling price to separate deliverables and allocate arrangement consideration using the relative selling price method. Additionally, the amendments eliminate the residual method for allocating arrangement considerations. The adoption by the Company on January 1, 2011 did not have a material impact on the Company’s consolidated financial statements.

In April 2010, the FASB issued guidance for revenue recognition — milestone method, which provides guidance on the criteria that should be met for determining whether the milestone method of revenue recognition is appropriate. A vendor can recognize consideration that is contingent upon achievement of a milestone in its entirety as revenue in the period in which the milestone is achieved only if the milestone meets all criteria to be considered substantive. A milestone should be considered substantive in its entirety. An individual milestone may not be bifurcated. This guidance is effective on a prospective basis for milestones achieved in fiscal years, and interim periods within those years, beginning on or after the effective date of the guidance. The adoption by the Company on January 1, 2011 did not have a material impact on the Company’s consolidated financial statements.

In April 2010, the FASB issued an accounting standards update, which addresses the classification of an employee share-based payment award with an exercise price denominated in the currency of a market in which

the underlying equity securities trades. This update clarifies that an employee share-based payment award with an exercise price denominated in the currency of a market in which a substantial portion of the entity’s equity securities trades should not be considered to contain a condition that is not a market, performance, or service condition. Therefore, an entity should not classify such an award as a liability if it otherwise qualifies as equity. The adoption by the Company on January 1, 2011 did not have a material impact on the Company’s consolidated financial statements.

In May 2011, the FASB amended authoritative accounting guidance regarding fair value measurement. The amendment prohibits the application of block discounts for all fair value measurements, permits the fair value of certain financial instruments to be measured on the basis of the net risk exposure and allows the application of premiums or discounts to the extent consistent with the applicable unit of account. The amendment clarifies that the highest-and-best use and valuation-premise concepts are not relevant to financial instruments. Expanded disclosures are required under the amendment, including quantitative information about significant unobservable inputs used for Level 3 measurements, a qualitative discussion about the sensitivity of recurring Level 3 measurements to changes in unobservable inputs disclosed, a discussion of the Level 3 valuation processes, any transfers between Levels 1 and 2 and the classification of items whose fair value is not recorded but is disclosed in the notes. The amendment is effective prospectively during interim and annual periods beginning after December 15, 2011 (January 1, 2012 for the Company). The adoption of this amendment is not expected to have a material effect on the Company’s consolidated financial statements.

Update on Presentation of Comprehensive Income in the Financial Statements

In June 2011, the FASB issued new accounting guidance that revises the manner in which entities present comprehensive income in their financial statements. The new guidance requires entities to report components of comprehensive income in either a continuous statement of comprehensive income or two separate but consecutive statements. The new guidance does not change the items that must be reported in other comprehensive income and does not affect the calculation or reporting of earnings per share. The amendment is applicable retrospectively effective for fiscal years, and interim periods within those years, beginning after December 15, 2011 (January 1, 2012 for the Company). Early adoption is permitted. The adoption of this amendment is not expected to have a material effect on the Company’s consolidated financial statements.

On August 2, 2010, the Company acquired the remaining 50% interest in Mammoth-Pacific, L.P. (“Mammoth Pacific”), which owns the Mammoth complex located near the city of Mammoth, California, for a purchase price of $72.5 million in cash. The Company acquired the remaining interest in Mammoth Pacific to increase its geothermal power plant operations in the United States.

Prior to the acquisition, the Company had a 50% interest in Mammoth Pacific that was accounted for under the equity method of accounting. Following the acquisition, the Company became the sole owner of the

Mammoth complex, as well as the sole owner of rights to over 10,000 acres of undeveloped federal lands.

As a result of the acquisition of the remaining 50% interest in Mammoth Pacific, the financial statements of Mammoth Pacific have been consolidated with the Company’s financial ~~statements.~~

statements effective August 2, 2010. The acquisition date fair value of the previously held 50% equity interest was $64.9 million, which takes into account a “control premium” of $7.6 million. In the three and nine-month periods ended September 30, 2010, the Company recognized a pre-tax gain of $36.9 million, which is equal to the difference between the acquisition date fair value of the previously held 50% equity interest in Mammoth Pacific and the acquisition date carrying value of such investment. The gain is included in “gain on acquisition of controlling interest” in the condensed consolidated statements of operations and comprehensive income (loss).

Revenues and net ~~loss~~income of the Mammoth complex were ~~$4,729,000~~$5,257,000 and ~~$24,000~~$597,000 for the three months ended ~~June~~September 30, 2011, respectively. Revenues and net income of the Mammoth complex were ~~$9,439,000~~$14,696,000 and ~~$432,000~~$1,029,000 for the ~~six~~nine months ended ~~June~~September 30, 2011, respectively.

The following unaudited consolidated pro forma financial information for the three and ~~six-month~~nine-month periods ended ~~June~~September 30, 2010 assumes the Mammoth Pacific acquisition occurred as of January 1, 2010, after giving effect to certain adjustments, including the depreciation based on the adjustments to the fair market value of the property, plant and equipment acquired, and related income tax effects. The pro forma results have been prepared for comparative purposes only and are not necessarily indicative of the results of operations that may occur in the future or that would have occurred had the acquisition of Mammoth Pacific been effected on the date indicated.

~~Unconsolidated investments, mainly in power plants, consist of the following:~~

Prior to August 2, 2010, the Company had a 50% interest in Mammoth Pacific, which owns the Mammoth complex. The Company’s 50% ownership interest in Mammoth Pacific was accounted for under the equity method of accounting as the Company had the ability to exercise significant influence, but not control, over Mammoth Pacific. On August 2, 2010, the Company acquired the remaining 50% interest in Mammoth Pacific (see Note 3).

The condensed results of operations of Mammoth Pacific for the ~~six months ended June 30,~~period from January 1, 2010 to August 1, 2010 are summarized below:


	(Dollars in thousands)			(Dollars in thousands)
Condensed statements of operations:
Revenues	$	9,806		$	11,484
Gross margin		2,842			2,670
Net income		2,720			2,528
Company’s equity in income of Mammoth:
50% of Mammoth net income	$	1,360		$	1,264
Plus amortization of basis difference		296			345

		1,656			1,609
Less income taxes		(629	)		(611	)

Total	$	1,027		$	998

The Company is a 12.75% member of a consortium which is in the process of developing a geothermal power project in Indonesia with expected generating capacity of approximately 330 MW. The 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 with PT Pertamina Geothermal Energy (“PGE”). The project will be constructed in three phases over five years, with each phase utilizing the Company’s 110 MW to 120 MW combined cycle geothermal plants in which the steam first produces power in a backpressure steam turbine and is subsequently condensed in a vaporizer of a binary plant, which produces additional power. The consortium is still negotiating certain contractual amendments for facilitation of project financing and for signing the resulting amended energy sales contract, and intends to proceed with the project after those amendments have become effective.

The Company’s share in the results of operations of the Sarulla project was not significant for each of the periods presented in these condensed consolidated financial statements.

In October 2010, the Company invested $2.0 million in Watts & More Ltd. (“W&M”), an early stage start-up company, engaged in the development of energy harvesting and system balancing solutions for electrical sources and, in particular, solar photovoltaic systems. The Company holds approximately 28.6% of W&M’s shares.

The Company’s share in the results of operations of W&M was not significant for the three and ~~six-month~~nine-month periods ended ~~June~~September 30, 2011.

The fair value measurement guidance clarifies that fair value is an exit price, representing the amount that would be received to sell an asset or paid to transfer 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. It establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of the fair value hierarchy under the fair value measurement guidance are described below:

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

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

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

The following table sets forth certain fair value information at ~~June~~September 30, 2011 and December 31, 2010 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.


	Cost or Amortized Cost at June 30, 2011			Fair Value at June 30, 2011													Cost or Amortized Cost at September 30, 2011			Fair Value at September 30, 2011
			Total				Level 1			Level 2				Level 3			Cost or Amortized Cost at September 30, 2011		Total				Level 1			Level 2				Level 3
	Cost or Amortized Cost at June 30, 2011				(Dollars in thousands)													(Dollars in thousands)
Assets
Current assets:
Cash equivalents (including restricted cash accounts)	$	23,208		$	23,208			$	23,208		$	—			$	—	$	45,274		$	45,274			$	45,274		$	—			$	—
Marketable securities		22,889			23,098				23,098			—				—
Derivatives⁽¹⁾		—			1,031				—			1,031				—
Marketable Securities																		20,867			21,190				21,190			—				—
Liabilities:
Current liabilities:
Derivatives⁽²⁾		—			(4,735	)			—			(4,735	)			—
Derivatives⁽¹⁾																		—			(12,227	)			—			(12,227	)			—

	$	46,097		$	42,602			$	46,306		$	(3,704	)		$	—	$	66,141		$	54,237			$	66,464		$	(12,227	)		$	—


	Cost or Amortized Cost at December 31, 2010			Fair Value at December 31, 2010											Cost or Amortized Cost at December 31, 2010			Fair Value at December 31, 2010
			Total			Level 1			Level 2			Level 3			Cost or Amortized Cost at December 31, 2010		Total			Level 1			Level 2			Level 3
	Cost or Amortized Cost at December 31, 2010				(Dollars in thousands)											(Dollars in thousands)
Assets
Current assets:
Cash equivalents (including restricted cash accounts)	$	14,370		$	14,370		$	14,370		$	—		$	—	$	14,370		$	14,370		$	14,370		$	—		$	—
Derivatives⁽¹⁾⁽²⁾		—			1,030			—			1,030			—		—			1,030			—			1,030			—
Non-current assets:
Illiquid auction rate securities (including restricted cash accounts) ($4.5 million par value), see below⁽³⁾		4,011			3,027			—			—			3,027		4,011			3,027			—			—			3,027

	$	18,381		$	18,427		$	14,370		$	1,030		$	3,027	$	18,381		$	18,427		$	14,370		$	1,030		$	3,027

On July 12 and 13, 2011, the Company paid an aggregate amount of $5,328,000 in respect of two interest rate lock transactions it entered into in February 25, 2011. The Company will recognize a loss of $1,633,000 in respect of such transactions in the third quarter of 2011.

The Company’s financial assets measured at fair value (including restricted cash accounts) at ~~June~~September 30, 2011 include investments in debt instruments (which are included in marketable securities) and money market funds (which are included in cash equivalents). The Company’s financial assets measured at fair value (including restricted cash accounts) at December 31, 2010 include investments in auction rate securities and money market funds (which are included in cash equivalents). Those securities, except for the auction rate securities, are classified within Level 1 of the fair value hierarchy because they are valued using quoted market prices in an active market.

As of December 31, 2010, all of the Company’s auction rate securities are associated with failed auctions. Such securities have par values totaling $4.5 million, all of which have been in a loss position since the fourth quarter of 2007. Such auction rate securities were valued using Level 3 inputs. Historically, the carrying value of auction rate

securities approximated fair value due to the frequent resetting of the interest rates. While the Company continued to earn interest on these investments at the contractual rates, the estimated market value of these auction rate securities no longer approximated par value. Due to the lack of observable market quotes on the Company’s illiquid auction rate securities, the Company utilizes valuation models that relied exclusively on Level 3 inputs including, among other things: (i) the underlying structure of each security; (ii) the present value of future principal and interest payments discounted at rates considered to reflect the uncertainty of current market conditions; (iii) consideration of the probabilities of default, auction failure, or repurchase at par for each period; (iv) assessments of counterparty credit quality; (v) estimates of the recovery rates in the event of default for each security; and (vi) overall capital market liquidity. These estimated fair values were subject to uncertainties that were difficult to predict. Therefore, such auction rate securities were classified as of December 31, 2010 as Level 3 in the fair value hierarchy.

In the first quarter of 2011, the Company identified a buyer outside of the auction process, and in April 2011, it sold the balance of the auction rate securities for consideration of $2,822,000.

The table below sets forth a summary of the changes in the fair value of the Company’s financial assets as Level 3 (~~i.e~~i.e.., illiquid auction rate securities) for the ~~six-month~~nine-month periods ended ~~June~~September 30, 2011 and 2010:


	Six Months Ended June 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	(Dollars in thousands)						(Dollars in thousands)
Balance at beginning of period	$	3,027		$	3,164		$	3,027		$	3,164
Total unrealized losses:
Included in net income		(205	)		—			(205	)		—
Included in other comprehensive income		—			(117	)
Included in other comprehensive income (loss)								—			(135	)
Transferred to Level 2		(2,822	)		—			(2,822	)		—

Balance at end of period	$	—		$	3,047		$	—		$	3,029

Effective July 1, 2010, the Company adopted an accounting standards update that amends and clarifies the guidance on how entities should evaluate credit derivatives embedded in beneficial interests in securitized financial assets. The updated guidance eliminates the scope exception for bifurcation of embedded credit derivatives in interests in securitized financial assets unless they are created solely by subordination of one beneficial interest to another. The auction rate securities held by the Company are considered securitized financial assets. Based on the abovementioned guidance, the Company elected the fair value option for its auction rate securities and reclassified $693,000 (net of income taxes of $377,000) to retained earnings with an offset to other comprehensive income. Effective with the adoption of this new guidance, all changes in the fair value of auction rate securities are recognized in earnings.

The funds invested in auction rate securities that have experienced failed auctions are not accessible until a successful auction occurs, a buyer is found outside of the auction process or the underlying securities reach maturity. As a result, the Company classified those securities with failed auctions as long-term assets in the consolidated balance sheets as of December 31, 2010.

There were no transfers of assets or liabilities between Level 1 and Level 2 during the ~~six~~nine months ended ~~June~~September 30, 2011.

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


	Fair Value				Carrying Amount				Fair Value				Carrying Amount
	June 30, 2011		December 31, 2010		June 30, 2011		December 31, 2010		September 30, 2011		December 31, 2010		September 30, 2011		December 31, 2010
	(Dollars in millions)				(Dollars in millions)				(Dollars in millions)				(Dollars in millions)
Olkaria III Loan	$	83.1	$	88.7	$	82.9	$	88.4	$	83.2	$	88.7	$	82.9	$	88.4
Amatitlan Loan		38.4		39.5		37.9		39.0		37.8		39.5		37.3		39.0
Senior Secured Notes:
Ormat Funding Corp. (“OFC”)		129.5		129.5		130.8		136.3		129.5		129.5		130.8		136.3
OrCal Geothermal Inc. (“OrCal”)		91.3		93.5		93.2		95.6		92.8		93.5		93.2		95.6
Senior Unsecured Bonds		252.8		144.8		248.3		142.0		252.8		144.8		248.3		142.0
Loans from institutional investors		35.7		37.1		35.7		37.2		34.2		37.1		34.2		37.2

The fair value of OFC Senior Secured Notes is determined using observable market prices as these securities are traded. The fair value of 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 market pricing curves.

On August 3, 2010, the Company entered into a trust instrument governing the issuance of, and accepted subscriptions for, an aggregate principal amount of approximately $142.0 million of Senior Unsecured Bonds (the “Bonds”). The Company issued the Bonds outside of the United States to investors who are not “U.S. persons” in an unregistered offering pursuant to, and subject to the requirements of, Regulation S under the Securities Act of 1933, as amended (the “Securities Act”).

Subject to early redemption, the principal of the Bonds is repayable in a single bullet payment upon the final maturity of the Bonds on August 1, 2017. The Bonds bear interest at a fixed rate of 7% per annum, payable semi-annually.

In February 2011, the Company accepted subscriptions for an aggregate principal amount of approximately $108.0 million of additional Senior Unsecured Bonds (the “Additional Bonds”) under two addendums to the trust instrument. The Company issued the Additional Bonds outside of the United States to investors who are not “U.S. persons” in an unregistered offering pursuant to, and subject to the requirements of, Regulation S under the Securities Act. The terms and conditions of the Additional Bonds are identical to the Bonds. The Additional Bonds were issued at a premium which reflects an effective fixed interest of 6.75% per annum.

On September 23, 2011, the Company’s subsidiary OFC 2 LLC (“OFC 2”) and its wholly owned subsidiaries (collectively, the “Issuers”) entered into a note purchase agreement (the “Note Purchase Agreement”) with OFC 2 Noteholder Trust, as purchaser, John Hancock Life Insurance Company (U.S.A.), as administrative agent, and the United States Department of Energy (“DOE”), as guarantor, in connection with the offer and sale of up to $350 million aggregate principal amount of OFC 2’s Senior Secured Notes (“OFC 2 Senior Secured Notes”) due December 31, 2034.

Subject to the fulfillment of customary and other specified conditions precedent, the OFC 2 Senior Secured Notes will 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 facilities (collectively, the “Project”) owned by the Issuers, as follows: Series A Notes, Series B Notes, Series C Notes, Series D Notes, and, if the Issuers so elect, Series E Notes and Series F Notes. The Phase I tranche, comprised of the Series A Notes and the Series B Notes, will be issued in an aggregate principal amount not to exceed $180 million, of which up to $155 million will be allocated to the Series A Notes, and up to $25 million will be allocated to the Series B Notes. Issuance of the Series B Notes is dependent on the Jersey Valley facility reaching certain operational targets in addition to the other conditions precedent noted above. Proceeds of the Series A Notes will be used to finance a portion of the construction costs of Phase I of the McGinness Hills and the Tuscarora facilities. Proceeds of the Series B Notes, if issued, will be used to finance a portion of the construction costs of Phase I of the Jersey Valley facility.

The Issuers have sole discretion regarding whether to commence construction of Phase II of any of the Jersey Valley, McGinness Hills and Tuscarora facilities. If a facility Phase II is undertaken for any of the facilities, the Issuers may issue Phase II tranches of Notes, comprised of one or more of the Series C Notes, the Series D Notes, the Series E Notes and the Series F Notes, to finance a portion of the construction costs of such Phase II of any facility. The aggregate principal amount of all Phase II Notes may not exceed $170 million. The aggregate principal amount of each series of Notes comprising a Phase II tranche will be determined by the Issuers in their sole discretion provided that certain financial ratios are satisfied pursuant to the terms of the Note Purchase Agreement and subject to the aggregate limit noted above.

The DOE will guarantee payment of 80% of principal and interest on the Notes (the “DOE Guarantee”) 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 the DOE Guarantee.

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 and payment of dividends.

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

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 in accordance with an amortization schedule attached to such Notes 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 Treasury yield curve that will be set at least ten business days prior to theissuance of such Series of Notes. Interest will be payable quarterly in arrears.

On October 31, 2011, OFC 2 and the Issuers completed the sale of $151.7 million aggregate principal amount of 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 $147.4 million, and will be used to finance a portion of the construction costs of Phase I of the McGinness Hills and Tuscarora facilities. The Issuers will pay 4.687% interest on the Series A Notes quarterly in arrears on the last day of each of March, June, September and December in each year, commencing on December 31, 2011.

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

The first closing under the agreements occurred in 2007 and covered the Company’s 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 production tax credits (“PTC”) and taxable income or loss (together, the “Economic Benefits”). Once it recovered the capital that it has invested in the power plants, which occurred in the fourth quarter of 2010, the investors receive both the distributable cash flow and the Economic Benefits. The investors’ return is limited by the term of the transaction. Once the investors reach a target after-tax yield on their investment in OPC (the “Flip Date”), Ormat Nevada will receive 95% of both distributable cash and taxable income, on a going forward basis. Following the Flip Date, Ormat Nevada also has the option to buy out the investors’ remaining interest in OPC at the then-current fair market value or, if greater, the investors’ capital account balances in OPC. Should Ormat Nevada exercise this purchase option, it would thereupon revert to being sole owner of the power plants.

The Class B membership units are provided with a 5% residual economic interest in OPC. The 5% residual interest commences on achievement by the investors of a contractually stipulated return that triggers the Flip Date. The actual Flip Date is not known with certainty and is determined by the operating results of OPC. This residual 5% interest represents a noncontrolling interest and is not subject to mandatory redemption or guaranteed payments. Cash is distributed each period in accordance with the cash allocation percentages stipulated in the agreements. Until the fourth quarter of 2010, Ormat Nevada was allocated the cash earnings in OPC and therefore, the amount allocated to the 5% residual interest represented the noncash loss of OPC which principally represented depreciation on the property, plant and equipment. As from the fourth quarter of 2010, the distributable cash is allocated to the Class B membership units.

The Company’s voting rights in OPC are based on a capital structure that is comprised of Class A and Class B membership units. The Company owns, through its subsidiary, Ormat Nevada, all of the Class A membership units, which represent 75% of the voting rights in OPC. The investors own all of the Class B membership units, which represent 25% of the voting rights ofin 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 Flip Date, Ormat Nevada’s voting rights will increase to 95% and the investors’ voting rights will decrease to 5%. Ormat Nevada retains the controlling voting interest in OPC both before and after the Flip Date and therefore continues to consolidate OPC.

On October 30, 2009, Ormat Nevada acquired from Lehman-OPC all of the Class B membership units of OPC held by Lehman-OPC pursuant to a right of first offer for a price of $18.5 million. A substantial portion of the initial sale of the Class B membership units by Ormat Nevada was accounted for as a financing transaction. As a result, the repurchase of these interests ~~atv~~at a discount resulted in a pre-tax gain of $13.3 million in the year ended December 31, 2009. In addition, an amount of approximately $1.1 million has been reclassified from noncontrolling interest to additional paid-in capital representing the 1.5% residual interest of Lehman-OPC’s Class B membership units.

On February 3, 2011, Ormat Nevada sold to JPM Capital Corporation (“JPM”) all of the Class B membership units of OPC that it had acquired on October 30, 2009 for a sale price of $24.9 million in cash. The Company did not record any gain from the sale of its Class B membership interests in OPC to JPM. A substantial portion of the Class B membership units are accounted for as a financing transaction. As a result, the majority of these proceeds were recorded as a liability. In addition, $2.3 million has been reclassified from additional paid-in capital to noncontrolling interest representing the 1.5% residual interest of JPM’s Class B membership units.

On March 31, 2011, the Company granted to employees 622,150 stock appreciation rights (“SAR”) under the Company’s 2004 Incentive Plan. The exercise price of each SAR is $25.65, which represented the fair market value of the Company’s common stock on the date of grant. Such SARs will expire seven years from the date of grant and will 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. Upon exercise, SARs entitle the recipient to receive shares of common stock equal to the increase in value of the award between the grant date and the exercise date. The fair value of each SAR on the date of grant was $9.82.

The Company calculated the fair value of each SAR on the date of grant using the Black-Scholes valuation model based on the following assumptions:

On November 3, 2011, the Company granted to its non-employee directors options to purchase 30,000 shares of common stock under the Company’s 2004 Incentive Plan (see Note 18).

In January 2010, a former shareholder of Geothermal Development Limited (“GDL”) exercised a call option to purchase from the Company its shares in GDL for approximately $2.8 million. In addition, the Company received $17.7 million to repay the loan a subsidiary of the Company provided to GDL to build the plant. The Company did not exercise its right of first refusal and, therefore, the Company transferred its shares in GDL to the former shareholder after the former shareholder paid all of GDL’s obligations to the Company. As a result, the Company recorded a pre-tax gain of approximately $6.3 million in the ~~six~~nine months ended ~~June~~September 30, 2010 ($4.3 million after-tax).

Included in income from discontinued operations in the three months ended June 30, 2010 is an out-of-period adjustment of $570,000 that increased the after-tax gain on the sale of GDL. Such adjustment related to an error in income taxes associated with the gain on sale of GDL in the three-month period ended March 31, 2010. The Company has determined that the impact of this out-of-period adjustment recorded in the three-month period ended June 30, 2010 was immaterial to the condensed consolidated statement of operations and comprehensive income (loss) in the three-month period ended March 31, 2010 and has no impact on the six months ended June 30, 2010.

The operations and gain on sale of GDL have been included in discontinued operations in the condensed consolidated statements of operations and comprehensive income (loss) for all periods prior to the sale of GDL in January 2010. Electricity revenues related to GDL were $0 and $64,000 during the three and ~~six-month~~nine-month periods ended ~~June~~September 30, 2010, respectively. Basic and diluted earnings per share related to a $4.3 million after-tax gain on sale of GDL was $0.02 and $0.10 during the three and ~~six-month~~nine-month periods ended ~~June~~September 30, 2010, respectively.


	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010		2011		2010		2011		2010
	(Dollars in thousands)				(Dollars in thousands)				(Dollars in thousands)				(Dollars in thousands)
Revenues:
Energy and capacity	$	28,726	$	25,628	$	59,881	$	50,346	$	33,313	$	30,113	$	93,194	$	80,460
Lease portion of energy and capacity		51,792		42,507		98,234		83,223		52,831		52,573		151,065		135,795
Lease income		672		672		1,343		1,343		671		671		2,014		2,014

	$	81,190	$	68,807	$	159,458	$	134,912	$	86,815	$	83,357	$	246,273	$	218,269

Cost of revenues:
Energy and capacity	$	32,371	$	36,702	$	67,892	$	63,957	$	28,840	$	31,752	$	96,732	$	95,710
Lease portion of energy and capacity		28,531		25,486		57,636		51,443		27,790		28,467		85,426		79,909
Lease income		1,310		1,310		2,621		2,621		1,311		1,311		3,932		3,932
												��
	$	62,212	$	63,498	$	128,149	$	118,021	$	57,941	$	61,530	$	186,090	$	179,551

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

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

For the six-month period ended June 30, 2011 and for the three and six-month periods ended June 30, 2010, the employee stock options are anti-dilutive because of the Company’s net loss from continuing operations, and therefore, they have been excluded from the diluted earnings (loss) per share calculation

The number of stock options that could potentially dilute future earnings per share and that were not included in the computation of diluted earnings per share because to do so would have been anti-dilutive was ~~4,272,124~~2,884,314 and ~~2,791,204, respectively,~~2,245,190 for the three months ended ~~June~~September 30, 2011 and 2010, respectively, and ~~3,679,336~~2,699,790 and ~~2,461,984, respectively,~~2,022,549 for the ~~six~~nine months ended ~~June~~September 30, 2011 and ~~2010.~~2010, respectively.

The Company has two reporting segments: Electricity and Product Segments. 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 power purchase agreements (“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:

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

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

Following the Company’s public announcement that it would restate certain of its financial results due to a change in the Company’s accounting treatment for certain exploration and development costs, three securities class action lawsuits were filed in the United States District Court for the District of Nevada on March 9, 2010, March 18, 2010 and April 7, 2010. These complaints assert claims against the Company and certain officers and directors for alleged violation of Sections 10(b) and 20(a) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). One complaint also asserts claims for alleged violations of Sections 11, 12(a)(2) and 15 of the Securities Act. All three complaints allege claims on behalf of a putative class of purchasers of Company common stock between May 6, 2008 or May 7, 2008 and February 23, 2010 or February 24, 2010. These three lawsuits were consolidated by the court in an order issued on June 3, 2010, and the court appointed three of the Company’s stockholders to serve as lead plaintiffs.

Lead plaintiffs filed a consolidated amended class action complaint (“CAC”) on July 9, 2010 that asserts claims under Sections 10(b) and 20(a) of the Exchange Act on behalf of a putative class of purchasers of Company common stock between May 7, 2008 and February 24, 2010. The CAC alleges that certain of the Company’s public statements were false and misleading for failing to account properly for the Company’s exploration and development costs based on the Company’s announcement on February 24, 2010 that it was going to restate certain of its financial results to change its method of accounting for exploration and development costs in certain respects. The CAC also alleges that certain of the Company’s statements concerning the North Brawley project were false and misleading. The CAC seeks compensatory damages, expenses, and such further relief as the court may deem proper. The Company cannot make an estimate of the possible loss or range of loss.

Defendants filed a motion to dismiss the CAC on August 13, 2010. On March 3, 2011, the court granted in part and denied in part defendants’ motion to dismiss. The court dismissed plaintiffs’ allegations that the Company’s statements regarding the North Brawley project were false or misleading, but did not dismiss plaintiffs’ allegations regarding the restatement. Defendants answered the remaining allegations in the CAC regarding the restatement on April 8, 2011 and the case has now entered the discovery phase. On July 22, 2011, plaintiffs filed a motion to certify the case as a class action on behalf of a class of purchasers of Company common stock between February 25, 2009 and February 24, ~~2010.~~2010, and defendants filed an opposition to the motion for class certification on October 4, 2011.

The Company ~~does not believe~~believes that these lawsuits have no merit and is defending the actions vigorously.

Four stockholder derivative lawsuits have also been filed in connection with the Company’s public announcement that it would restate certain of its financial results due to a change in the Company’s accounting treatment for certain exploration and development costs. Two cases were filed in the Second Judicial District Court of the State of Nevada in and for the County of Washoe on March 16, 2010 and April 21, 2010 and two cases were filed in the United States District Court for the District of Nevada on March 29, 2010 and June 7, 2010. All four lawsuits assert claims brought derivatively on behalf of the Company against certain of its officers and directors for alleged breach of fiduciary duty and other claims, including waste of corporate assets and unjust enrichment.

The two stockholder derivative cases filed in the Second Judicial District Court of the State of Nevada in and for the County of Washoe were consolidated by the Court in an order dated May 27, 2010 and the plaintiffs filed a consolidated derivative complaint on September 7, 2010. In accordance with a stipulation between the

parties, defendants filed a motion to dismiss on November 16, 2010. On April 18, 2011, the court stayed the state derivative case pending the resolution of the securities class action. The Company cannot make an estimate of the possible loss or range of loss on the state derivative case.

The two stockholder derivative cases filed in the United States District Court for the District of Nevada were consolidated by the Court in an order dated August 31, 2010 and plaintiffs filed a consolidated derivative complaint on October 28, 2010. The Company filed a motion to dismiss on December 13, 2010. On March 7, 2011, the ~~court~~Court transferred the federal derivative case to the ~~court~~Court presiding over the securities class action, and on August 29, 2011, the Court stayed the federal derivative case pending the resolution of the securities class action.

The Company believes the allegations in these purported derivative actions are without merit and is defending the actions vigorously.

On May 19, 2011, the Federal Energy Regulatory Commission (“FERC”) issued an order which denied the Company’s exemptions for requirements relating to Sections 205 and 206 of the Federal Power Act and directed the Company’s ~~REG~~recovered energy generation facilities to make refunds to their customers, equaling “the time value of the revenues collected during the periods of non-compliance with the qualifying facilities”, ~~which approximate~~in an amount of approximately $1.6 million. On June 17, 2011, the Company requested a rehearing to obtain relief on this refund payment. On July 18, 2011, FERC issued an Order Granting Rehearing for Further Consideration in order to afford additional time for consideration of the matters raised. To date, FERC has not taken further action on the rehearing.

The Company believes that it is not probable ~~but reasonably possible~~ that a refund payment will ultimately need to be made.

From time to time, the Company is named as a party in various lawsuits, claims and other legal and regulatory proceedings that arise in the ordinary course of its 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 materially affect its business, financial condition, financial results or cash flow.

On February 22, 2011, the Company’s Board of Directors declared, approved and authorized payment of a quarterly dividend of $2.3 million ($0.05 per share) to all holders of the Company’s issued and outstanding shares of common stock on March 15, 2011. Such dividend was paid on March 24, 2011.

On May 4, 2011, the Company’s Board of Directors declared, approved and authorized payment of a quarterly dividend of $1.8 million ($0.04 per share) to all holders of the Company’s issued and outstanding shares of common stock on May 18, 2011. Such dividend was paid on May 25, 2011.

On August 3, 2011, the Company’s Board of Directors declared, approved and authorized payment of a quarterly dividend of $1.8 million ($0.04 per share) to all holders of the Company’s issued and outstanding shares of common stock on August 16, 2011. Such dividend was paid on August 25, 2011.

The Company’s effective tax rate for the three months ended ~~June~~September 30, 2011 and 2010 was ~~13.8%~~39.7% and ~~57.0%~~26.9%, respectively. The Company’s effective tax rate for the ~~six~~nine months ended ~~June~~September 30, 2011 and 2010 was ~~63.1%~~711.8% and ~~53.8%~~18.0%, respectively. The effective tax rate differs from the federal statutory rate of 35% for the ~~six~~nine months ended ~~June~~September 30, 2011 primarily due to: (i) the benefit of production tax credits for qualified power plants placed in service since 2005; (ii) lower tax rates in Israel; (iii) a tax credit and tax exemption related to the Company’s subsidiaries in Guatemala; and (iv) provision to return adjustments related to foreign activities.

The anticipated annual production tax credits (“PTCs”) associated with the Class B membership interest in OPC (see Note 8), an entity the Company is consolidating, had a significant impact on the Company’s expected overall annual tax benefit in 2010. During 2010, the Company was negotiating to sell such interest to a third party, which ~~the~~ sale occurred in February 2011. Upon the sale of the Class B membership interest, the Company was no longer eligible to receive PTCs associated with the Class B membership interest. Due to uncertainties in the timing of selling its Class B membership interest and the significance of the PTCs to the Company’s overall tax benefit in 2010, the Company recognized in 2010 PTCs as they were earned rather than including forecasted PTCs in the annual effective tax rate estimate from continuing operations.

Realization of the U.S. deferred tax assets in the amount of approximately $18.1 million as of December 31, 2010 is dependent on generating sufficient taxable income prior to expiration of the U.S net operating loss carryforwards and U.S. tax credits. Although realization is not assured, management believes it is more likely than not that all of the deferred tax asset will be realized. The amount of the deferred tax asset considered realizable, however, could be reduced in the near term if estimates of future taxable income during the carryforward period are reduced.

The Company’s subsidiary, Ormat Systems Ltd. (“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. As a Benefited Enterprise, Ormat Systems was exempt from Israeli income taxes with respect to income derived from the first benefited investment for a period of two years beginning in 2004, and thereafter such income is subject to reduced Israeli income tax rates, which will not exceed 25% for an additional five years. Ormat Systems is also exempt from Israeli income taxes with respect to income derived from the second benefited investment for a period of two years beginning in 2007, and thereafter such income is subject to reduced Israeli income tax rates, which will not exceed 25% for an additional five years. These benefits are subject to certain conditions, including among other things, that all transactions between Ormat Systems and its affiliates are at arm’s length, and that the management and control of Ormat Systems will be from Israel during the entire period of the tax benefits. A change in control should be reported to the Israel Tax Authority in order to maintain the tax benefits. In January 2011, new legislation amending the Investment Law was enacted. Under the new legislation, a uniform rate of corporate tax would apply to all qualified income of certain industrial companies, as opposed to the current law’s incentives that are limited to income from a “Benefited Enterprise” during ~~their~~its benefits period. According to the amendment, the uniform tax rate applicable to the zone where the production facilities of Ormat Systems are located would be 15% in 2011 and 2012, 12.5% in 2013 and 2014, and 12% in 2015 and thereafter. Under the transitory provisions of the new legislation, Ormat Systems may opt to irrevocably comply with the new law while waiving benefits provided under the current law or continue to comply with the current law during the next years. Changing from the current law to the new law is permissible at any stage. Ormat Systems decided to irrevocably comply with the new law starting in 2011. As a result, the deferred taxes as of December 31, 2010 have been reduced by $0.5 million. This amount reduced the tax provision for the ~~six~~nine months ended ~~June~~September 30, 2011 by such amount.

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


	Six Months Ended June 30,					Nine Months Ended September 30,
	2011			2010		2011			2010
	(Dollars in thousands)					(Dollars in thousands)
Balance at beginning of period	$	5,431		$	4,931	$	5,431		$	4,931
Additions based on tax positions taken in prior years		325			434		190			717
Decrease for settlements with taxing authorities		(1,376	)		—		(1,376	)		—

Balance at end of period	$	4,380		$	5,365	$	4,245		$	5,648

On ~~August~~November 3, 2011, the ~~Company’s Board of Directors declared, approved and authorized payment of a quarterly dividend of $1.8 million ($0.04 per share)~~Company granted to ~~all holders of~~its four non-employee directors non-qualified stock options, under the Company’s ~~issued and outstanding~~2004 Incentive Plan, to purchase 30,000 shares of common stock (7,500 shares each) at an exercise price equal to the closing price of the Company’s common stock on ~~August 16~~November 4, 2011 ~~payable~~(since the Company released its quarterly results on ~~August 25, 2011.~~November 2, 2011). Such options will expire seven years from the date of grant and will vest on the first anniversary of the date of grant.

On October 31, 2011, OFC 2 and the Issuers completed the sale of $151.7 million aggregate principal amount of the Series A Notes due 2032 (see Note 7).

ITEM 2.2.

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. We will not update forward-looking statements even though our situation may change in the future.

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. 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, 2010 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. We design, develop, build, sell, own and operate clean, environmentally friendly geothermal and recovered energy-based power plants, in most cases 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 all of our recovered energy-based plants have been constructed by us. We conduct our business

activities in two business segments, which we refer to as our Electricity Segment and Product Segment. In our

Electricity Segment, we develop, build, own and operate geothermal and recovered energy-based power plants in the United States and geothermal power plants in other countries around the world, and sell the electricity they generate. We have ~~decided to expand~~recently expanded our activities in the Electricity Segment to include the ownership and operation of power plants that produce electricity generated by solar photovoltaic (Solar PV) systems that we do not manufacture. In our Product Segment, we design, manufacture and sell equipment for geothermal and recovered energy-based electricity generation, remote power units and other power generating units and provide services relating to the engineering, procurement, construction, operation and maintenance of geothermal and recovered energy-based power plants. Both our Electricity Segment and Product Segment operations are conducted in the United States and throughout the world. Our current generating portfolio includes geothermal power plants in the United States, Guatemala, Kenya, and Nicaragua, as well as recovered energy generation (REG) power plants in the United States. During the ~~six~~nine months ended ~~June~~September 30, 2011, and 2010, our consolidated power plants generated ~~2,026,800~~2,935,854 MWh and ~~1,797,616~~2,735,018 MWh, respectively.

For the ~~six~~nine months ended ~~June~~September 30, 2011, our Electricity Segment revenues represented approximately ~~78.8%~~78.6% of our total revenues, while our Product Segment revenues represented approximately ~~21.2%~~21.4% of our total revenues ~~during such period.~~.

For the ~~six~~nine months ended ~~June~~September 30, 2011, our total revenues increased by ~~13.1%~~11.7% (from ~~$178.9~~$280.4 million to ~~$202.4~~$313.3 million) over the same period last year. Revenues from the Electricity Segment increased by ~~18.2%~~12.8% and revenues from the Product Segment ~~decreased~~increased by ~~2.3%~~7.8%.

For the ~~six~~nine months ended ~~June~~September 30, 2011, total Electricity Segment revenues from the sale of electricity by our consolidated power plants were ~~$159.5~~$246.3 million, compared to ~~$134.9~~$218.3 million for the ~~six~~nine months ended ~~June~~September 30, ~~2010.~~2010, an increase of 12.8%.

For the ~~six~~nine months ended ~~June~~September 30, 2011, revenues attributable to our Product Segment were ~~$43.0~~$67.0 million, compared to ~~$44.0~~$62.1 million for the ~~six~~nine months ended ~~June~~September 30, 2010, ~~a decrease~~an increase of ~~2.3%~~7.8%.

Revenues from our Electricity Segment are relatively predictable, as they are derived from sales of electricity generated by our power plants pursuant to long-term PPAs. The price for electricity under all but one of our PPAs is effectively a fixed price at least through April 2012. The exception is the PPA of the Puna power plant. It has a monthly variable energy rate based on the local utility’s 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. In the ~~six~~nine months ended ~~June~~September 30, 2011, approximately ~~83.4%~~82.7% of our electricity revenues were derived from contracts with fixed energy rates, and therefore most of our electricity revenues were not affected by the fluctuations in energy commodity prices. However, electricity revenues are subject to seasonal variations and can be affected by higher-than average ambient temperatures, as described below under the heading “Seasonality”.

Revenues attributable to our Product Segment are based on the sale of equipment and the provision of various services to our customers. These revenues may vary significantly from period to period because of the timing of our receipt of purchase orders and the progress of our execution of each project.

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

The geothermal industry in the United States has historically experienced significant growth followed by a consolidation of owners and operators of geothermal power plants. During the 1990s, growth and development in the geothermal industry occurred primarily in foreign markets and only minimal growth and development

occurred in the United States. Since 2001, there has been increased demand for energy generated from geothermal resources in the United States as costs for electricity generated from geothermal resources have become more competitive relative to fossil fuel generation. This has partly been due to increasing natural gas and oil prices during much of this period and, equally important, to newly enacted legislative and regulatory requirements and incentives, such as state renewable portfolio standards and federal tax credits. The ARRA further encourages the use of geothermal energy through production or Investment Tax Credits (ITCs) as well as cash grants (which are discussed in more detail in the section entitled “Government Grants and Tax Benefits”). We see the increasing demand for energy generated from geothermal and other renewable resources in the United States and the further introduction of renewable portfolio standards as significant trends affecting our industry today and in the immediate future. Our operations and the trends that from time to time impact our operations are subject to market cycles.

We expect to continue to generate the majority of our revenues from our Electricity Segment through the sale of electricity from our power plants. Substantially all of our current revenues from the sale of electricity are derived from payments under fully-contracted long-term PPAs. We also intend to continue to pursue growth in our recovered energy business and in the solar sector.

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 affected by the following trends, factors and uncertainties:

New Hampshire, New Jersey, New Mexico, New York, Oregon, Rhode Island, Utah, Vermont, Virginia and Washington). Regional initiatives, such as the Western Climate Initiative (which includes seven U.S. states and four Canadian provinces) and the Midwest Greenhouse Gas Reduction Accord (which includes six U.S. states and one Canadian province), are also being developed to reduce greenhouse gas emissions and develop trading systems for renewable energy credits. In September 2008, the first-in-the-nation auction of CO₂ allowances was held under the RGGI, a regional cap-and-trade system, which includes ten Northeast and Mid-Atlantic States (though New Jersey will withdraw by the end of 2011). Under RGGI, the participating states plan to stabilize power section carbon emissions at their capped level, and then reduce the cap by 10% at a rate of 2.5% each year between 2015 and 2018. In addition, twenty-nine states and the District of Columbia have all adopted renewable portfolio standards (RPS) and eight other states have adopted renewable portfolio goals. In California, on April 12, 2011, Governor Jerry Brown signed Senate Bill X1-2 (SBX1-2) to increase California’s RPS to 33% by December 31, 2020, among the most aggressive renewable energy goals in the United States. We expect that the additional demand for renewable energy from utilities in states with RPS will outpace a possible reduction in general demand for energy (if any) due to the effect of economic conditions. We see this increased demand and in particular the impact of the increase in California RPS, as one of the most significant opportunities for us to expand existing projects and build new power plants.

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 we face in connection with our growth expectations.

for energy and capacity from the Qualifying Facility. The legislation does not affect existing PPAs. We do not expect this change in law to affect our U.S. power plants significantly, as all except one of our current contracts (our Steamboat 1 power plant, which sells its electricity to Sierra Pacific Power Company on a year-by-year basis) are long-term. If the utilities in the regions in which our domestic power plants operate were to be relieved of the mandatory purchase obligation, they would not be required to purchase energy from us upon termination of the existing PPA, which could have an adverse effect on our revenues.

Notwithstanding the Global Settlement, each of Southern California Edison and Pacific Gas & Electric, two of the three California investor-owned utilities, recently separately filed with the CPUC to approve fixed energy price amendments or fixed energy price ~~power purchase agreements~~PPAs with different existing renewable energy qualifying facilities. While there can be no assurance that such utilities will agree to enter into further such contracts, a fixed energy price alternative will eliminate the uncertainties inherent in pricing based in large part on future natural gas prices, but may not necessarily compensate for any reduction in revenues that might otherwise result from the Global Settlement pricing.

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

Revenues attributable to our Electricity Segment are relatively predictable as they are derived from the sale of electricity from our power plants pursuant to long-term PPAs. However, such revenues are subject to seasonal variations, as more fully described below in the section entitled “Seasonality”. Electricity Segment revenues may also be affected by higher-than-average ambient temperatures, which could cause a decrease in the generating capacity of our power plants, and by unplanned major maintenance activities related to our power plants.

Our PPAs generally provide for the payment of 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 levels and the potential forfeiture of payments if we fail to meet minimum target 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 short run avoided costs (the incremental costs that the power purchaser avoids by not having to generate such electrical energy itself or purchase it from others). Our more recent PPAs generally provide for energy payments along with an obligation to compensate the off-taker for its incremental costs as a result of shortfalls in our supply.

The prices paid for electricity pursuant to the PPA of the Puna power plant are impacted by the price of oil. Accordingly, our revenues for that power plant, which accounted for approximately ~~11.2%~~10.9% and ~~7.6%~~8.3% of our total revenues for the ~~six-month~~nine-month periods ended ~~June~~September 30, 2011 and 2010, respectively, may be volatile.

Revenues attributable to our Product Segment are generally less predictable than revenues from our Electricity Segment. This is because 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 long time to design and develop and are often subject to various contingencies, such as the customer’s ability to raise the necessary financing for a project. As a result, we are generally unable to predict the timing of such orders for our products and may not be able to replace orders that we have completed with new ones. As a result, revenues from our Product Segment fluctuate (and at times, extensively) from period to period. However, we experienced a significant increase in our Product Segment customer orders in ~~the first half of~~ 2011, which increased our Product Segment backlog to ~~$225~~$200 million as of ~~June~~September 30, 2011. We expect that our Product Segment revenues will increase over the next two years as a result of the new orders and increased backlog.

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


	Revenues in Thousands								% of Revenues for Period Indicated												Revenues in Thousands								% of Revenues for Period Indicated
	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended September 30,						Nine Months Ended September 30,
	2011		2010		2011		2010		2011			2010			2011			2010			2011		2010		2011		2010		2011			2010			2011			2010
Revenues:
Electricity	$	81,190	$	68,807	$	159,458	$	134,912		77.6	%		71.5	%		78.8	%		75.4	%	$	86,815	$	83,357	$	246,273	$	218,269		78.3	%		82.1	%		78.6	%		77.8	%
Product		23,424		27,459		42,976		44,008		22.4			28.5			21.2			24.6			24,026		18,120		67,002		62,128		21.7			17.9			21.4			22.2

Total	$	104,614	$	96,266	$	202,434	$	178,920		100.0	%		100.0	%		100.0	%		100.0	%	$	110,841	$	101,477	$	313,275	$	280,397		100.0	%		100.0	%		100.0	%		100.0	%

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


	Revenues in Thousands								% of Revenues for Period Indicated												Revenues in Thousands								% of Revenues for Period Indicated
	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended September 30,						Nine Months Ended September 30,
	2011		2010		2011		2010		2011			2010			2011			2010			2011		2010		2011		2010		2011			2010			2011			2010
Electricity Segment:
United States	$	61,958	$	50,910	$	121,449	$	98,499		76.3	%		74.0	%		76.2	%		73.0	%	$	66,951	$	65,556	$	188,400	$	164,055		77.1	%		78.6	%		76.5	%		75.2	%
Foreign		19,232		17,897		38,009		36,413		23.7			26.0			23.8			27.0			19,864		17,801		57,873		54,214		22.9			21.4			23.5			24.8

Total	$	81,190	$	68,807	$	159,458	$	134,912		100.0	%		100.0	%		100.0	%		100.0	%	$	86,815	$	83,357	$	246,273	$	218,269		100.0	%		100.0	%		100.0	%		100.0	%

Product Segment:
United States	$	—	$	2,644	$	—	$	5,023		0.0	%		9.6	%		0.0	%		11.4	%	$	—	$	3,512	$	—	$	8,535		0.0	%		19.4	%		0.0	%		13.7	%
Foreign		23,424		24,815		42,976		38,985		100.0			90.4			100.0			88.6			24,026		14,608		67,002		53,593		100.0			80.6			100.0			86.3

Total	$	23,424	$	27,459	$	42,976	$	44,008		100.0	%		100.0	%		100.0	%		100.0	%	$	24,026	$	18,120	$	67,002	$	62,128		100.0	%		100.0	%		100.0	%		100.0	%

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 paid for electricity under the PPAs with Southern California Edison for the Heber 1 and 2 plants, the Mammoth complex, the Ormesa complex, and the North Brawley plant are higher in the months of June through September. As a result, we receive and will receive in the future higher revenues during such months. The prices paid for electricity pursuant to the PPAs of our power plants in Nevada have no significant changes during the year. In the winter, due principally to the lower ambient temperature, our power plants produce more energy and as a result we receive higher energy revenues. However, the higher capacity payments payable by Southern California Edison in California in the summer months have a more significant impact on our revenues than that of the higher energy revenues generally generated in winter due to increased efficiency. As a result, our electricity revenues are generally higher in the summer than in the winter.

The principal cost of revenues attributable to our operating power plants includes operation and maintenance expenses, such as depreciation and amortization, 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 and insurance. In our California power plants our principal cost of

revenues also includes transmission charges, scheduling charges and purchases of make-up water for use in our cooling towers. 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 projects from quarter to quarter. Payments made to government agencies and private entities relating to 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. For ~~each of~~ the ~~six~~nine months ended ~~June~~September 30, 2011, ~~and 2010, royalty payments~~royalties constituted approximately ~~3.4%~~3.5% of ~~the~~ Electricity Segment revenues,. compared to approximately 3.8% for the nine months ended September 30, 2010.

The principal cost of revenues attributable to our Product Segment includes materials, salaries and related employee benefits, expenses related to subcontracting activities, transportation expenses and sales commissions to sales representatives. 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, cash equivalents and marketable securities as of ~~June~~September 30, 2011 decreased to ~~$67.4~~$80.3 million from $82.8 million as of December 31, 2010. This decrease is principally due to: (i) our use of ~~$109.6~~$180.8 million to fund capital expenditures; (ii) repayment of ~~$23.0~~$26.0 million of long-term debt; ~~and~~ (iii) a net ~~repayment~~change in restricted cash, cash equivalents and marketable securities of ~~$38.0 million against our revolving credit lines with commercial banks.~~$36.9 million; and (iv) cash paid to non-controlling interest of $10.8 million. The decrease in our cash resources was partially offset by: (i) our issuance of an aggregate principal amount of approximately $107.4 million of Senior Unsecured Bonds in February 2011; (ii) $24.9 million of proceeds from the sale of Class B membership units of OPC to JPM Capital in February 2011; ~~and~~ (iii) ~~$39.5~~$98.5 million derived from operating activities during the ~~three~~nine months ended ~~June~~September 30, ~~2011.~~2011; and (iv) net proceeds of $31.9 million against our revolving credit lines with commercial banks. Our corporate borrowing capacity under committed lines of credit with different commercial banks as of ~~June~~September 30, 2011 was ~~$407.5~~$409.0 million, as described below in the section entitled “Liquidity and Capital Resources”, of which we utilized ~~$211.5~~$306.7 million (including ~~$68.6~~$97.4 million of letters of credit) as of ~~June~~September 30, 2011.

A comprehensive discussion of our critical accounting policies 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, 2010.

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 as a result of each of the following: (i) our recent construction of new power plants and enhancement of acquired power plants; and (ii) fluctuation in revenues from our Product Segment.


	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010			2011			2010			2011			2010
	(In thousands, except per share data)						(In thousands, except per share data)						(In thousands, except per share data)						(In thousands, except per share data)
Statements of Operations Historical Data:
Revenues:
Electricity	$	81,190		$	68,807		$	159,458		$	134,912		$	86,815		$	83,357		$	246,273		$	218,269
Product		23,424			27,459			42,976			44,008			24,026			18,120			67,002			62,128

		104,614			96,266			202,434			178,920			110,841			101,477			313,275			280,397

Cost of revenues:
Electricity		62,212			63,498			128,149			118,021			57,941			61,530			186,090			179,551
Product		9,249			14,115			26,139			26,552			17,137			14,764			43,276			41,316

		71,461			77,613			154,288			144,573			75,078			76,294			229,366			220,867

Gross margin:
Electricity		18,978			5,309			31,309			16,891			28,874			21,827			60,183			38,718
Product		14,175			13,344			16,837			17,456			6,889			3,356			23,726			20,812

		33,153			18,653			48,146			34,347			35,763			25,183			83,909			59,530
Operating expenses:
Research and development expenses		2,575			3,614			4,782			6,881			2,346			1,252			7,128			8,133
Selling and marketing expenses		3,725			2,686			6,385			5,888			2,940			3,333			9,325			9,221
General and administrative expenses		7,479			6,996			14,486			14,016			6,269			5,780			20,755			19,796
Write-off of unsuccessful exploration activities		—			3,050			—			3,050			—			—			—			3,050

Operating income		19,374			2,307			22,493			4,512			24,208			14,818			46,701			19,330
Other income (expense):
Interest income		716			95			851			292			438			140			1,289			432
Interest expense, net		(17,442	)		(9,426	)		(30,522	)		(19,140	)		(23,909	)		(10,961	)		(54,431	)		(30,101	)
Foreign currency translation and transaction gains (losses)		596			(1,033	)		1,113			(599	)		(2,659	)		1,074			(1,546	)		475
Income attributable to sale of tax benefits		3,141			2,070			5,280			4,209			2,344			2,183			7,624			6,392
Gain on acquisition of controlling interest														—			36,928			—			36,928
Other non-operating income (expense), net		915			79			118			(280	)		347			233			465			(47	)

Income (loss) from continuing operations, before income taxes and equity in income (losses) of investees		7,300			(5,908	)		(667	)		(11,006	)
Income tax benefit		1,007			3,365			421			5,922
Income from continuing operations, before income taxes and equity in income (losses) of investees														769			44,415			102			33,409
Income tax benefit (expense)														305			(11,931	)		726			(6,009	)
Equity in income (losses) of investees, net		(69	)		479			(481	)		1,025			(71	)		(83	)		(552	)		942

Income (loss) from continuing operations		8,238			(2,064	)		(727	)		(4,059	)
Income from continuing operations														1,003			32,401			276			28,342
Discontinued operations:
Income from discontinued operations, net of related tax		—			—			—			14			—			—			—			14
Gain on sale of a subsidiary in New Zealand, net of related tax		—			570			—			4,336			—			—			—			4,336

Net income (loss)		8,238			(1,494	)		(727	)		291
Net income														1,003			32,401			276			32,692
Net loss (income) attributable to noncontrolling interest		(105	)		57			(115	)		110			(137	)		58			(252	)		168

Net income (loss) attributable to the Company’s stockholders	$	8,133		$	(1,437	)	$	(842	)	$	401
Net income attributable to the Company’s stockholders													$	866		$	32,459		$	24		$	32,860

Earnings (loss) per share attributable to the Company’s stockholders—basic and diluted:
Income (loss) from continuing operations	$	0.18		$	(0.05	)	$	(0.02	)	$	(0.09	)
Earnings per share attributable to the Company’s stockholders— basic and diluted:
Income from continuing operations													$	0.02		$	0.71		$	0.00		$	0.62
Discontinued operations		—			0.02			—			0.10			—			—			—			0.10

Net Income (loss)	$	0.18		$	(0.03	)	$	(0.02	)	$	0.01
Net Income													$	0.02		$	0.71		$	0.00		$	0.72

Weighted average number of shares used in computation of earnings (loss) per share attributable to the Company’s stockholders:
Weighted average number of shares used in computation of earnings per share attributable to the Company’s stockholders:
Basic		45,431			45,431			45,431			45,431			45,431			45,431			45,431			45,431

Diluted		45,443			45,431			45,431			45,431			45,440			45,450			45,442			45,452


	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010			2011			2010			2011			2010
Statements of Operations Percentage Data:
Revenues:
Electricity		77.6	%		71.5	%		78.8	%		75.4	%		78.3	%		82.1	%		78.6	%		77.8	%
Product		22.4			28.5			21.2			24.6			21.7			17.9			21.4			22.2

		100.00			100.0			100.0			100.0			100.0			100.0			100.0			100.0

Cost of revenues:
Electricity		76.6			92.3			80.4			87.5			66.7			73.8			75.6			82.3
Product		39.5			51.4			60.8			60.3			71.3			81.5			64.6			66.5

		68.3			80.6			76.2			80.8			67.7			75.2			73.2			78.8

Gross margin:
Electricity		23.4			7.7			19.6			12.5			33.3			26.2			24.4			17.7
Product		60.5			48.6			39.2			39.7			28.7			18.5			35.4			33.5

		31.7			19.4			23.8			19.2			32.3			24.8			26.8			21.2
Operating expenses:
Research and development expenses		2.5			3.8			2.4			3.8			2.1			1.2			2.3			2.9
Selling and marketing expenses		3.6			2.8			3.2			3.3			2.6			3.3			3.0			3.3
General and administrative expenses		7.1			7.3			7.2			7.8			5.7			5.7			6.6			7.1
Write-off of unsuccessful exploration activities		0.0			3.2			0.0			1.7			0.0			0.0			0.0			1.1

Operating income		18.5			2.4			11.1			2.5			21.9			14.6			14.9			6.8
Other income (expense):
Interest income		0.7			0.1			0.4			0.2			0.4			0.1			0.4			0.2
Interest expense, net		(16.7	)		(9.8	)		(15.1	)		(10.7	)		(21.6	)		(10.8	)		(17.4	)		(10.7	)
Foreign currency translation and transaction gains (losses)		0.6			(1.1	)		0.5			(0.3	)		(2.4	)		1.1			(0.5	)		0.2
Income attributable to sale of tax benefits		3.0			2.2			2.6			2.4			2.1			2.2			2.5			2.3
Gain on acquisition of controlling interest														0.0			36.4			0.0			13.2
Other non-operating income (expense), net		0.9			0.1			0.1			(0.2	)		0.3			0.2			0.2			(0.0	)

Income (loss) from continuing operations, before income taxes and equity in income (losses) of investees		7.0			(6.1	)		(0.3	)		(6.2	)
Income tax benefit		1.0			3.5			0.2			3.3
Income from continuing operations, before income taxes and equity in income (losses) of investees														0.7			43.8			0.1			12.0
Income tax benefit (expense)														0.3			(11.8	)		0.2			(2.1	)
Equity in income (losses) of investees, net		(0.1	)		0.5			(0.2	)		0.6			(0.1	)		(0.1	)		(0.2	)		0.3

Income (loss) from continuing operations		7.9			(2.1	)		(0.4	)		(2.3	)
Income from continuing operations														0.9			31.9			0.1			10.2
Discontinued operations:
Income from discontinued operations, net of related tax		0.0			0.0			0.0			0.0			0.0			0.0			0.0			0.0
Gain on sale of a subsidiary in New Zealand, net of related tax		0.0			0.6			0.0			2.4			0.0			0.0			0.0			1.5

Net income (loss)		7.9			(1.6	)		(0.4	)		0.2
Net income														0.9			31.9			0.1			11.7
Net loss (income) attributable to noncontrolling interest		(0.1	)		0.1			(0.1	)		0.1			(0.1	)		0.1			(0.1	)		0.1

Net income (loss) attributable to the company’s stockholders		7.8	%		(1.5	)%		(0.4	)%		0.2	%
Net income attributable to the Company’s stockholders														0.8	%		32.0	%		0.0	%		11.8	%

Comparison of the Three Months Ended ~~June~~September 30, 2011 and the Three Months Ended ~~June~~September 30, 2010

Total revenues for the three months ended ~~June~~September 30, 2011 were ~~$104.6~~$110.8 million, compared to ~~$96.3~~$101.5 million for the three months ended ~~June~~September 30, 2010, which represented ~~an 8.7%~~a 9.2% increase in total revenues. This increase is attributable to both our Electricity ~~Segment~~and Product Segments whose revenues increased by ~~18.0%~~4.1% and 32.6%, respectively, over ~~the same period last year, while our revenues from the Product Segment decreased by 14.7% from~~ the same period last year.

Revenues attributable to our Electricity Segment for the three months ended ~~June~~September 30, 2011 were ~~$81.2~~$86.8 million, compared to ~~$68.8~~$83.4 million for the three months ended ~~June~~September 30, 2010, which represented ~~an 18.0%~~a 4.1% increase in such revenues. This ~~increase~~result is ~~a result of increased electricity generation of our power plants from 879,734 MWh in the three months ended June 30, 2010~~due to ~~978,514 MWh in the three months ended June 30, 2011. The most significant contributors to the increase in our electricity generation were: (i)~~ an increase in the ~~generation of~~electricity rates in our Amatitlan and Puna power plant due to repair work that was completed in the second quarter of 2010; (ii) an increase in the generation of our North Brawley power plant, with revenues of $4.8 million in the three months ended June 30, 2011, compared to $3.5 million in the three months ended June 30, 2010; (iii) the consolidation of the Mammoth complex effective August 2, 2010 with revenues of $4.7 million in the three months ended June 30, 2011, resulting from the acquisition of the remaining 50% interest in Mammoth Pacific in August 2010; and (iv) an increase in generation of the REG facilities due to the addition of one plant andplants. As a ~~higher availability of the pipeline providing the heat to most of our REG power plants. The increase in our Electricity Segment revenues is also attributable to an increase in~~result, the average revenue rate of our electricity portfolio increased from ~~$78~~$89 per MWh in the ~~second quarter of~~three months ended September 30, 2010 to ~~$83~~$95 per MWh in the ~~second~~three months ended September 30, 2011. The increase in our average rate did not fully impact our electricity revenues in the third quarter because the electricity generation in our power plants declined by 3% from 937,402 MWh in the three months ended September 30, 2010 to 909,054 MWh in the three months ended September 30, 2011 due to major maintenance activity in some of our power plants. The revenues from our North Brawley power plant in the third quarter of 2011 ~~which was mainly~~decreased to $4.0 million from $5.1 million during the same period in 2010 due to ~~higher rates under the PPA of the Puna power plant.~~our decision to mitigate losses at that plant by idling wells that have a negative impact on our margins.

Revenues attributable to our Product Segment for the three months ended ~~June~~September 30, 2011 were ~~$23.4~~$24.0 million, compared to ~~$27.5~~$18.1 million for the three months ended ~~June~~September 30, 2010, which represented a ~~14.7% decrease~~32.6% increase in such revenues. The ~~decrease relative to~~increase in our product revenues reflects the ~~second quarter of 2010 was primarily due to the completion of a large project~~increase in new customer orders that ~~significantly increased Product Segment revenues~~we secured in the second quarter of 2010. Product Segment revenues for the three months ended June 30, 2011 include $7.9 million relating to a liquified natural gas (LNG) energy recovery unit in Spain (See “Research and Development Expenses” below). As previously disclosed, Product Segment revenues are generally less predictable than revenues from our Electricity Segment.2011.

Total cost of revenues for the three months ended ~~June~~September 30, 2011 was ~~$71.5~~$75.1 million, compared to ~~$77.6~~$76.3 million for the three months ended ~~June~~September 30, 2010, which represented a ~~7.9%~~slight decrease of 1.6% in total cost of revenues. ~~The decrease is attributable to a decrease in the cost of revenues in both our Electricity and Product Segments.~~ As a percentage of total revenues, our total cost of revenues for the three months ended ~~June~~September 30, 2011 was ~~68.3%~~67.7%, compared to ~~80.6%~~75.2% for the same period in 2010.

Total cost of revenues attributable to our Electricity Segment for the three months ended ~~June~~September 30, 2011 was ~~$62.2~~$57.9 million, compared to ~~$63.5~~$61.5 million for the three months ended ~~June~~September 30, 2010, which represented a ~~2.0%~~5.8% decrease in total cost of revenues for such segment, while the increase in revenues was ~~18.0%~~4.1%. We incurred lower

costs associated with operating and maintaining the North Brawley power plant in the ~~second~~third quarter of 2011 ($~~10.4~~7.5 million), compared to the ~~second~~third quarter of 2010 ($~~11.9~~10.1 million). WeAlthough we expect the high level of operating expenses at the North Brawley power plant to continue, ~~however,~~ such expenses ~~will continue~~are expected to trend downward. ~~Nevertheless, the~~The cost per MWh in the current quarter ~~decreased compared to~~was the ~~second~~same as in the third quarter of 2010, and as ~~a result of~~noted below slightly higher for the nine months ended September 30, 2011 than the nine months ended September 30, 2010. The cost per MWh in the current quarter was impacted by lower maintenance costs in most of our other power plants inover the ~~second~~same quarter ~~of 2011,~~last year, which ~~was~~lower maintenance costs were offset by ~~higher~~increased depreciation costs in the Mammoth complex, resulting from ~~the plan~~our program to repower the complex by

replacing part of the old units with new ~~Ormat-manufactured~~ equipment. As a percentage of total electricity revenues, the total cost of revenues attributable to our Electricity Segment for the three months ended ~~June~~September 30, 2011 was ~~76.6%~~66.7%, compared to ~~92.3%~~73.8% for the three months ended ~~June~~September 30, 2010.

Total cost of revenues attributable to our Product Segment for the three months ended ~~June~~September 30, 2011 was ~~$9.2~~$17.1 million, compared to ~~$14.1~~$14.8 million for the three months ended ~~June~~September 30, 2010, which represented a ~~34.5% decrease~~16.1% increase in total cost of revenues related to such segment. As a percentage of total Product Segment revenues, our total cost of revenues attributable to this segment for the three months ended ~~June~~September 30, 2011 was ~~39.5%~~71.3%, compared to ~~51.4%~~81.5% for the three months ended ~~June~~September 30, 2010. Such decrease in the percentage of Product Segment cost of revenues from total Product Segment revenues is mainly attributable to: (i) revenues of $7.9 million relating to an experimental REG plant with virtually no associated cost of revenues, since the related costs have been included in research and development costs in previous periods;higher revenues; (ii) a different product mix; and (iii) different margins in the sales contracts.

Research and development expenses for the three months ended ~~June~~September 30, 2011 were ~~$2.6~~$2.3 million, compared to ~~$3.6~~$1.3 million for the three months ended ~~June~~September 30, 2010, which represented a 28.7% decrease. This decrease is primarily attributable to the costs related to an experimental REG plant specifically designed to use the residual energy from the vaporization process at LNG regasification terminals, including developing and building a unit at a customer’s premises in Spain, which decreased to $0.3 million in the three months ended June 30, 2011, from $2.4 million in the three months ended June 30, 2010. The decrease is due to the fact that the majority of the costs related to the experimental REG plant were incurred through the second quarter of 2010. Construction of the plant commenced in the third quarter of 2010 and was substantially completed in the second quarter of 2011. In the second quarter of 2011, we recognized $7.9 million as revenue representing the amount we received from the customer in July 2011, following deemed acceptance in the second quarter of 2011. Upon completion of final acceptance tests, we will be paid by the customer approximately $8.0 million for the remainder of the agreement, which we expect to recognize as revenue in the fourth quarter of 2011, or in 2012.87.4% increase. Our research and development activities during the three months ended ~~June~~September 30, 2011 ~~also~~ included: (i) continued development of enhanced geothermal systems (EGS); and (ii) development of a solar thermal system for the production of electricity.

Selling and marketing expenses for the three months ended ~~June~~September 30, 2011 were ~~$3.7~~$2.9 million, compared to ~~$2.7~~$3.3 million for the three months ended ~~June~~September 30, 2010, which represented ~~a 38.7% increase. Such increase is attributable to a different mix of the Product Segment customer orders, with higher selling and marketing expenses.~~an 11.8% decrease. Selling and marketing expenses for the three months ended ~~June~~September 30, 2011 constituted ~~3.6%~~2.6% of total revenues, compared to ~~2.8%~~3.3% for the three months ended ~~June~~September 30, 2010.

General and administrative expenses for the three months ended ~~June~~September 30, 2011 were ~~$7.5~~$6.3 million, compared to ~~$7.0~~$5.8 million for the three months ended ~~June~~September 30, 2010, which represented ~~a 6.9%~~an 8.5% increase. General and administrative expenses for each of the three months ended ~~June~~September 30, 2011 and September 30, 2010 constituted ~~7.1%~~5.7% of total ~~revenues, compared to 7.3% for the three months ended June 30, 2010.~~

Write-off of unsuccessful exploration activities for the three months ended June 30, 2010 was $3.1 million, which represented the write-off of exploration costs related to the Gabbs Valley project, which we determined in the second quarter of 2010 would not support commercial operations. We did not have a write-off of unsuccessful exploration activities in the three months ended June 30, 2011.revenues.

Operating income for the three months ended ~~June~~September 30, 2011 was ~~$19.4~~$24.2 million, compared to ~~$2.3~~$14.8 million for the three months ended ~~June~~September 30, 2010. Such increase of ~~$17.1~~$9.4 million in operating income was principally attributable to an increase in our ~~Electricity Segment~~ gross margin due to the increase in ~~the Electricity Segment~~ revenues, as described ~~above, and to a decrease in the write-off of unsuccessful exploration activities.~~above. Operating income attributable to our Electricity Segment for the three months ended ~~June~~September 30, 2011 was ~~$9.8~~$21.1 million, compared to ~~an operating loss of $5.1~~$13.5 million for the three months ended ~~June~~September 30, 2010. Operating income attributable to our Product Segment for the three months ended ~~June~~September 30, 2011 was ~~$9.5~~$3.1 million, compared to ~~$7.4~~$1.4 million for the three months ended ~~June~~September 30, 2010.

Interest expense, net for the three months ended ~~June~~September 30, 2011 was ~~$17.4~~$23.9 million, compared to ~~$9.4~~$11.0 million for the three months ended ~~June~~September 30, 2010, which represented ~~an 85.0%~~a 118.1% increase. The ~~$8.0~~$12.9 million increase is primarily due to: (i) an $11.6 million loss on interest rate lock transactions in the three months ended

September 30, 2011 relating to the DOE loan guarantee transaction that was consummated in September 2011, and which were not accounted for as hedge transactions; and (ii) the issuance of Senior Unsecured Bonds in August 2010 and February 2011, as discussed elsewhere in this report; and (ii) a $4.0 million loss on interest rate lock transactions relating to the proposed DOE loan guarantee transaction, which are not accounted for as hedge transactions in the three months ended June 30, 2011. The increase was partially offset by: (i) an increase of ~~$0.7~~$0.9 million in interest capitalized to projects as a result of increased aggregate investment in projects under construction; and (ii) a decrease in interest expense as a result of principal repayments.

Foreign currency translation and transaction losses for the three months ended September 30, 2011 were $2.7 million, compared to gains of $1.1 million for the three months ended September 30, 2010. The $3.7 million decrease is primarily due to losses on forward foreign exchange transactions for the three months ended September 30, 2011, which were not accounted for as hedge transactions, compared to gains in the three months ended September 30, 2010.

Income attributable to the sale of tax benefits to institutional equity investors (as described in “OPC Transaction” below) for the three months ended ~~June~~September 30, 2011 was ~~$3.1~~$2.3 million, compared to ~~$2.1~~$2.2 million for the three months ended ~~June~~September 30, 2010. This income represents the value of PTCs and taxable income or loss generated by OPC and allocated to the investors. The increase resulted from the sale of Class B membership units of OPC LLC to JPM Capital Corporation on February 3, 2011.

Gain on acquisition of controlling interest for the three months ended September 30, 2010 was $36.9 million. This gain relates to the acquisition of the remaining 50% interest in Mammoth Pacific as discussed above. The acquisition date fair value of the previous 50% equity interest was $64.9 million. In the three months ended September 30, 2010, we recognized a pre-tax gain of $36.9 million ($22.6 million after tax), which is equal to the difference between the acquisition date fair value of the initial investment in Mammoth Pacific and the acquisition date carrying value of such investment.

Income tax benefit for the three months ended ~~June~~September 30, 2011 was ~~$1.0~~$0.3 million, compared to ~~$3.4~~income tax expense of $11.9 million for the three months ended ~~June~~September 30, 2010. The effective tax rate for the three months ended ~~June~~September 30, 2011 was ~~13.8%~~39.7%, compared to ~~57.0%~~26.9% for the three months ended ~~June~~September 30, 2010. The change in the effective tax rate primarily resulted from a higher impact of PTCs on the effective tax rate due to a lower projected pre-tax annual income.

Income from continuing operations for the three months ended June 30, 2011 was $8.2 million, compared to a loss of $2.1 million for the three months ended June 30, 2010. Such increased income of $10.3 million was principally attributable to: (i) a $17.1 million increase in operating income; and (ii) a $1.0 million increase in income attributable to sale of tax benefits. The increase was partially offset by: (i) an $8.0 million increase in interest expense; and (ii) a $2.4 million decrease in income tax benefit.

In January 2010, a former shareholder of Geothermal Development Limited (GDL) exercised a call option to purchase from us our shares in GDL for approximately $2.8 million. In addition, we received $17.7 million to repay the loan our subsidiary provided to GDL to build the plant. We did not exercise our right of first refusal and, therefore, we transferred our shares in GDL to the former shareholder. The operations of GDL have been included in discontinued operations for all periods prior to the sale of GDL. Income from discontinued operations of $0.6 million in the three months ended June 30, 2010 represented an out-of-period adjustment that increased the after-tax gain on the sale of GDL in January 2010. Such adjustment related to an error in the calculation of the capital gain tax on such sale in the three-month period ended March 31, 2010. We have determined that the impact of this out-of-period adjustment recorded in the three-month period ended June 30, 2010 was immaterial to the condensed consolidated statement of operations and comprehensive income (loss) in the three-month period ended March 31, 2010 and has no impact on the six-month period ended June 30, 2010.

Net income for the three months ended ~~June~~September 30, 2011 was ~~$8.2~~$1.0 million, compared to ~~net loss of $1.5~~$32.4 million for the three months ended ~~June~~September 30, 2010. ~~The increase~~Such decrease in net income of $31.4 million was principally attributable toto: (i) a gain on acquisition of controlling interest of $36.9 million in the three months ended September 30, 2010; (ii) a $12.9 million increase in interest expense; and (iii) a $3.7 million increase in foreign currency translation and transaction losses. The decrease was partially offset by: (i) a $9.4 million increase in operating income; and (ii) an $12.2 million decrease in income ~~from continuing operations in the amount of $10.3 million, as discussed above.~~tax expense.

Comparison of the ~~Six~~Nine Months Ended ~~June~~September 30, 2011 and the ~~Six~~Nine Months Ended ~~June~~September 30, 2010

Total revenues for the ~~six~~nine months ended ~~June~~September 30, 2011 were ~~$202.4~~$313.3 million, compared to ~~$178.9~~$280.4 million for the ~~six~~nine months ended ~~June~~September 30, 2010, which represented ~~a 13.1%~~an 11.7% increase in total revenues. This increase is attributable to both our Electricity ~~Segment~~and Product Segments whose revenues increased by ~~18.2%. The increase was partially offset by a decrease of 2.3% in our Product Segment~~12.8% and 7.8%, respectively, over the same period last year.

Revenues attributable to our Electricity Segment for the ~~six~~nine months ended ~~June~~September 30, 2011 were ~~$159.5~~$246.3 million, compared to ~~$134.9~~$218.3 million for the ~~six~~nine months ended ~~June~~September 30, 2010, which represented ~~an 18.2%~~a 12.8% increase in such revenues. This ~~increase~~result is ~~a result of~~due to increased electricity generation of our power plants from ~~1,797,616~~2,735,018 MWh in the ~~six~~nine months ended ~~June~~September 30, 2010 to ~~2,026,800~~2,935,854 MWh in the ~~six~~nine months ended ~~June~~September 30, 2011. The most significant contributors to the increase in our electricity generation were: (i) an increase in the generation of the Puna power plant due to repair work that was completed in the second quarter of 2010; (ii) an increase in the generation of our North Brawley power plant, with revenues of ~~$8.7~~$12.7 million in the ~~six~~nine months ended ~~June~~September 30, 2011, compared to ~~$6.2~~$11.3 million in the ~~six~~nine months ended ~~June~~September 30, 2010; (iii) the consolidation of the Mammoth complex, effective August 2, 2010, with revenues of ~~$9.4~~$14.7 million in the ~~six~~nine months ended ~~June 30,2011,~~September 30, 2011, compared to $3.5 million in the nine months ended September 30, 2010, resulting from the acquisition of the remaining 50% interest in Mammoth Pacific in August 2010; and (iv) an increase in generation of ~~the~~our REG facilities due to the addition of one plant and a higher availability of the pipeline providing the heat to most of our REG power plants. The increase in our Electricity Segment revenues is also attributable to an increase in the average revenue rate of our electricity portfolio from ~~$75~~$80 per MWh in the ~~first quarter of~~nine months ended September 30, 2010 to ~~$79~~$84 per MWh in the ~~six~~nine months ended ~~June~~September 30, ~~2011, which~~2011. Such increase was mainly due to higher rates under the PPA of the Puna power plant.

Revenues attributable to our Product Segment for the ~~six~~nine months ended ~~June~~September 30, 2011 were ~~$43.0~~$67.0 million, compared to ~~$44.0~~$62.1 million for the ~~six~~nine months ended ~~June~~September 30, 2010, which represented a ~~2.3% decrease~~7.8% increase in such

revenues. The ~~decrease~~increase relative to the ~~six~~nine months ended ~~June~~September 30, ~~2010~~2011 was primarily due to ~~the completion of a large project that significantly increased Product Segment revenues in the six months ended June 30, 2010. Product Segment revenues for the six months ended June 30, 2011 include~~ $7.9 million in revenues relating to an LNG energy recovery unit in Spain (See “Research and Development Expenses” below). ~~As previously disclosed, Product Segment revenues are generally less predictable than revenues from our Electricity Segment.~~

Total cost of revenues for the ~~six~~nine months ended ~~June~~September 30, 2011 was ~~$154.3~~$229.4 million, compared to ~~$144.6~~$220.9 million for the ~~six~~nine months ended ~~June~~September 30, 2010, which represented a ~~6.7%~~3.8% increase in total cost of revenues. This increase is attributable mainly to our Electricity Segment. As a percentage of total revenues, our total cost of revenues for the ~~six~~nine months ended ~~June~~September 30, 2011 was ~~76.2%~~73.2%, compared to ~~80.8%~~78.8% for the same period in 2010. The decrease in total cost of revenues as a percentage of total revenues is due to the ~~18.2%~~12.8% increase in Electricity Segment revenues, which outpaced the ~~8.6%~~4.8% increase in Electricity Segment cost of revenues, and the 7.8% increase in Product Segment revenues, which outpaced the 3.4% increase in Product Segment cost of revenues.

Total cost of revenues attributable to our Electricity Segment for the ~~six~~nine months ended ~~June~~September 30, 2011 was ~~$128.1~~$186.1 million, compared to ~~$118.0~~$179.6 million for the ~~six~~nine months ended ~~June~~September 30, 2010, which represented ~~an 8.6%~~a 3.6% increase in total cost of revenues for such segment. We incurred slightly higher costs

associated with operating and maintaining the North Brawley power plant in the ~~first half of~~nine months ended September 30, 2011 ($~~24.8~~32.1 million), compared to the ~~first half of~~nine months ended September 30, 2010 ($~~21.5~~31.5 million). ~~Nevertheless the~~The overall cost per MWh in the ~~six~~nine months ended ~~June~~September 30, 2011 decreased compared to the ~~six~~nine months ended ~~June~~September 30, 2010, as a result of lower maintenance costs, ~~in the second quarter of 2011,~~ which were offset by: (i) the higher costs in the North Brawley power plant, as described above; and (ii) ~~higher~~increased depreciation costs in the Mammoth complex, resulting from the ~~plan~~program to repower the complex by replacing part of the old units with new ~~Ormat-manufactured~~ equipment. As a percentage of total electricity revenues, the total cost of revenues attributable to our Electricity Segment for the ~~six~~nine months ended ~~June~~September 30, 2011 was ~~80.4%~~75.6%, compared to ~~87.5%~~82.3% for the ~~six~~nine months ended ~~June~~September 30, 2010.

Total cost of revenues attributable to our Product Segment for the ~~six~~nine months ended ~~June~~September 30, 2011 was ~~$26.1~~$43.3 million, compared to ~~$26.6~~$41.3 million for the ~~six~~nine months ended ~~June~~September 30, 2010, which represented a ~~1.6% decrease~~4.7% increase in total cost of revenues related to such segment. As a percentage of total Product Segment revenues, our total cost of revenues attributable to this segment for the ~~six~~nine months ended ~~June~~September 30, 2011 was ~~60.8%~~64.6%, compared to ~~60.3%~~66.5% for the ~~six~~nine months ended ~~June~~September 30, 2010.

Research and development expenses for the ~~six~~nine months ended ~~June~~September 30, 2011 were ~~$4.8~~$7.1 million, compared to ~~$6.9~~$8.1 million for the ~~six~~nine months ended ~~June~~September 30, 2010, which represented a ~~30.5%~~12.4% decrease. This decrease is primarily attributable to the costs related to an experimental REG plant specifically designed to use the residual energy from the vaporization process at LNG regasification terminals, including developing and building a unit at a customer’s premises in Spain, ~~which decreased to $0.8 million in the six months ended June 30, 2011, from $5.0 million in the six months ended June 30, 2010. The decrease is due to the fact that the majority of~~as the costs related to the experimental REG plant were incurred through the second quarter of 2010. Construction of the plant commenced in the third quarter of 2010 and was substantially completed in the second quarter of 2011. In the six months ended June 30, 2011, we recognized $7.9 million as revenue representing the amount we received

from the customer in July 2011 following deemed acceptance in the second quarter of 2011. Upon completion of final acceptance tests, we will be paid by the customer approximately $8.0 million for the remainder of the agreement, which we expect to recognize as revenue in the fourth quarter of 2011, or in 2012. Our research and development activities during the ~~six~~nine months ended ~~June~~September 30, 2011 also included: (i) continued development of EGS; and (ii) development of a solar thermal system for the production of electricity.

Selling and marketing expenses for the ~~six~~nine months ended ~~June~~September 30, 2011 were ~~$6.4~~$9.3 million, compared to ~~$5.9~~$9.2 million for the ~~six~~nine months ended ~~June~~September 30, 2010, which represented ~~an 8.4%~~a 1.1% increase. ~~Such increase is attributable to a different mix of the Product Segment customer orders, with higher selling and marketing expenses.~~ Selling and marketing expenses for the ~~six~~nine months ended ~~June~~September 30, 2011 constituted ~~3.2%~~3.0% of total revenues, compared to 3.3% for the ~~six~~nine months ended ~~June~~September 30, 2010.

General and administrative expenses for the ~~six~~nine months ended ~~June~~September 30, 2011 were ~~$14.5~~$20.8 million, compared to ~~$14.0~~$19.8 million for the ~~six~~nine months ended ~~June~~September 30, ~~2010.~~2010, which represented a 4.8% increase. General and administrative expenses for the ~~six~~nine months ended ~~June~~September 30, 2011 constituted ~~7.2%~~6.6% of total revenues, compared to ~~7.8%~~7.1% for the ~~six~~nine months ended ~~June~~September 30, 2010.

Write-off of unsuccessful exploration activities for the ~~six~~nine months ended ~~June~~September 30, 2010 was $3.1 million, which represented the write-off of exploration costs related to the Gabbs Valley project, which we determined in the second quarter of 2010 would not support commercial operations. We did not have a write-off of unsuccessful exploration activities in the ~~six~~nine months ended ~~June~~September 30, 2011.

Operating income for the ~~six~~nine months ended ~~June~~September 30, 2011 was ~~$22.5~~$46.7 million, compared to ~~$4.5~~$19.3 million for the ~~six~~nine months ended ~~June~~September 30, 2010. Such increase of ~~$18.0~~$27.4 million in operating income was principally attributable to an increase in our ~~Electricity Segment~~ gross margin due to the increase in ~~the Electricity Segment~~ revenues, as described above, and to a decrease in the write-off of unsuccessful exploration activities. Operating income attributable to our Electricity Segment for the ~~six~~nine months ended ~~June~~September 30, 2011 was ~~$13.8~~$34.9 million, compared to ~~an operating loss of $2.0~~$11.4 million for the ~~six~~nine months ended ~~June~~September 30, 2010. Operating income attributable to our Product Segment for the ~~six~~nine months ended ~~June~~September 30, 2011 was ~~$8.7~~$11.8 million, compared to ~~$6.5~~$7.9 million for the ~~six~~nine months ended ~~June~~September 30, 2010.

Interest expense, net, for the ~~six~~nine months ended ~~June~~September 30, 2011 was ~~$30.5~~$54.4 million, compared to ~~$19.1~~$30.1 million for the ~~six~~nine months ended ~~June~~September 30, 2010, which represented ~~a 59.5%~~an 80.3% increase. The ~~$11.4~~$24.3 million increase is primarily due to: (i) a $16.4 million loss on interest rate lock transactions in the nine months ended September 30, 2011, relating to the DOE loan guarantee transaction that was consummated in September 2011, and which are not accounted for as hedge transactions; and (ii) the issuance of Senior Unsecured Bonds in August 2010 and February 2011, as discussed elsewhere in this report; and (ii) a $4.7 million loss on interest rate lock transactions relating to the proposed DOE loan guarantee transaction, which are not accounted for as hedge transactions in the six months ended June 30, 2011. The increase was partially offset by: (i) an increase of ~~$1.4~~$2.2 million in interest capitalized to projects as a result of increased aggregate investment in projects under construction; and (ii) a decrease in interest expense as a result of principal repayments.

Foreign currency translation and transaction losses for the nine months ended September 30, 2011 were $1.5 million, compared to gains of $0.5 million for the nine months ended September 30, 2010. The $2.0 million decrease is primarily due to losses on forward foreign exchange transactions for the nine months ended September 30, 2011, which were not accounted for as hedge transactions, compared to gains in the nine months ended September 30, 2010.

Income attributable to the sale of tax benefits to institutional equity investors (as described in “OPC Transaction” below) for the ~~six~~nine months ended ~~June~~September 30, 2011 was ~~$5.3~~$7.6 million, compared to ~~$4.2~~$6.4 million for the ~~six~~nine months ended ~~June~~September 30, 2010. This income represents the value of PTCs and taxable income or loss generated by OPC and allocated to the investors. The increase resulted from the sale of Class B membership units of OPC LLC to JPM Capital Corporation on February 3, 2011.

Gain on acquisition of controlling interest for the nine months ended September 30, 2010 was $36.9 million. This gain relates to the acquisition of the remaining 50% interest in Mammoth Pacific as discussed above. The acquisition date fair value of the previous 50% equity interest was $64.9 million. In the nine months ended September 30, 2010, we recognized a pre-tax gain of $36.9 million ($22.4 million after tax), which is equal to the difference between the acquisition date fair value of the initial investment in Mammoth Pacific and the acquisition date carrying value of such investment.

Income tax benefit for the ~~six~~nine months ended ~~June~~September 30, 2011 was ~~$0.4~~$0.7 million, compared to income tax ~~benefit~~expense of ~~$5.9~~$6.0 million for the ~~six~~nine months ended ~~June~~September 30, 2010. The effective tax rate for the ~~six~~nine months ended ~~June~~September 30, 2011 was ~~63.1%~~711.8%, compared to ~~53.8%~~18.0% for the ~~six~~nine months ended ~~June~~September 30, 2010. The change in the effective tax rate resulted primarily ~~resulted~~ from a higher impact of PTCs on the effective tax rate due to a lower projected pre-tax annual income.

~~Loss~~Income from continuing operations for the ~~six~~nine months ended ~~June~~September 30, 2011 was ~~$0.7~~$0.3 million, compared to ~~$4.1~~$28.3 million for the ~~six~~nine months ended ~~June~~September 30, 2010. Such decrease of ~~$3.3~~$28.0 million was principally attributable to: (i) ~~an $18.0~~a gain on acquisition of controlling interest of $36.9 million in the nine months ended September 30, 2010; and (ii) a $24.3 million increase in interest expense. The decrease was partially offset by: (i) a $27.4 million increase in operating income; and (ii) a ~~$1.1 million increase in income attributable to the sale of tax benefits. The increase was partially offset by: (i) an $11.4 million increase in interest expense; and (ii) a $5.5~~$6.7 million decrease in income tax ~~benefit.~~expense.

In January 2010, a former shareholder of GDL exercised a call option to purchase from us our shares in GDL for approximately $2.8 million. In addition, we received $17.7 million to repay the loan our subsidiary provided to GDL to build the plant. We did not exercise our right of first refusal and, therefore, we transferred our shares in GDL to the former shareholder. As a result, we recorded an after-tax gain of $4.3 million in the ~~six~~nine months ended ~~June~~September 30, 2010. The operations of GDL have been included in discontinued operations for all periods prior to the sale of GDL in January 2010.

Net ~~loss~~income for the ~~six~~nine months ended ~~June~~September 30, 2011 was ~~$0.7~~$0.3 million, compared to ~~net income of $0.3~~$32.7 million for the ~~six~~nine months ended ~~June~~September 30, 2010. The decrease in net income was principally attributable to the decrease in income from ~~discontinued operations of $4.3 million, offset by the decrease in loss from~~ continuing operations in the amount of ~~$3.3~~$28.0 million, as discussed ~~above.~~above, and the decrease in income from discontinued operations of $4.3 million.

Our principal sources of liquidity have been derived from cash flows from operations, the issuance of our common stock in public and private offerings, proceeds from third party debt in the form of borrowings under credit facilities and private offerings, issuance by Ormat Funding Corp. (OFC) and OrCal Geothermal Inc. (OrCal) of their respective Senior Secured Notes, project financing (including the Puna lease and the OPC Transaction described below), and a cash grant we received under the ARRA relating to the North Brawley power plant. We have utilized this cash to fund our acquisitions, develop and construct power generation plants, and meet our other cash and liquidity needs.

As of ~~June~~September 30, 2011, we have access to the following sources of funds: (i) ~~$67.4~~$80.3 million in cash, cash equivalents and marketable securities; and (ii) ~~$196.0~~$102.3 million of unused corporate borrowing capacity under existing committed lines of credit with different commercial banks.

Our estimated capital needs for the remainder of 2011 include approximately ~~$208~~$108.0 million for capital expenditures on new projects in development or construction, exploration activity, operating projects, and machinery and equipment, as well as ~~$46.6~~$24.2 million for debt repayment.

We expect to finance these requirements with: (i) the sources of liquidity described above; (ii) cash flows from our operations; (iii) additional borrowing capacity under future lines of credit with commercial banks that are under negotiations; (iv) future project financing and refinancing; and (v) cash grants available to us under the ARRA relating to new projects that will be placed in service before the end of 2013. Management believes that these sources will meet our anticipated liquidity, capital expenditures and other investment requirements. ~~Our~~We intend to file a shelf registration statement on Form S-3 ~~which was~~that, pending effectiveness 95 declared ~~effective on October 2, 2008, provides~~by the SEC, will provide us with the ability to raise additional capital of up to $1.5 billion through the issuance of securities, subject to market conditions. ~~We intend to file a new shelf registration statement on Form S-3 that will replace the existing registration statement before its expiration date of October 1, 2011.~~

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 under the heading “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 under the heading “Full-Recourse Third Party Debt”.

On February 13, 2004, OFC, one of our subsidiaries, issued $190.0 million, 8¹/4% Senior Secured Notes (OFC Senior Secured Notes) in an offering subject to Rule 144A and Regulation S of the Securities Act of 1933, as amended (the Securities Act), for the purpose of refinancing the acquisition cost of the Brady, Ormesa and Steamboat 1/1A power plants, and the financing of the acquisition cost of the Steamboat 2/3 power plants. 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 which commenced on September 30, 2004. 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 and payment of dividends. As of ~~June~~September 30, 2011, OFC was in compliance with the covenants under the OFC Senior Secured Notes. As of ~~June~~September 30, 2011, there were $130.8 million of OFC Senior Secured Notes outstanding.

On December 8, 2005, OrCal, one of our subsidiaries, issued $165.0 million, 6.21% Senior Secured Notes (OrCal Senior Secured Notes) in an offering subject to Rule 144A and Regulation S of the Securities Act, for the purpose of refinancing the acquisition cost of the Heber power plants. The OrCal Senior Secured Notes have been rated BBB- by Fitch. 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 that commenced on September 30, 2006. 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 and payment of dividends. As of ~~June~~September 30, 2011, OrCal was in compliance with the covenants under the OrCal Senior Secured Notes. As of ~~June~~September 30, 2011, there were $93.2 million of OrCal Senior Secured Notes outstanding.

On September 23, 2011, OFC 2, one of our subsidiaries, and its wholly owned subsidiaries (collectively, the Issuers) entered into a note purchase agreement (the Note Purchase Agreement) with OFC 2 Noteholder Trust, as purchaser, John Hancock Life Insurance Company (U.S.A.), as administrative agent, and the United States Department of Energy (DOE), as guarantor, in connection with the offer and sale of up to $350 million aggregate principal amount of OFC 2’s Senior Secured Notes (OFC 2 Senior Secured Notes) due December 31, 2034.

by the Issuers, as follows: Series A Notes, Series B Notes, Series C Notes, Series D Notes, and, if the Issuers so elect, Series E Notes and Series F Notes. The Phase I tranche, comprised of the Series A Notes and the Series B Notes, will be issued in an aggregate principal amount not to exceed $180 million, of which up to $155 million will be allocated to the Series A Notes, and up to $25 million will be allocated to the Series B Notes. Issuance of the Series B Notes is dependent on the Jersey Valley facility reaching certain operational targets in addition to the other conditions precedent noted above. Proceeds of the Series A Notes will be used to finance a portion of the construction costs of Phase I of the McGinness Hills and the Tuscarora facilities. Proceeds of the Series B Notes, if issued, will be used to finance a portion of the construction costs of Phase I of the Jersey Valley facility.

The DOE will guarantee payment of 80% of principal and interest on the Notes (the DOE Guarantee) 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 the DOE Guarantee.

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

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 in accordance with an amortization schedule attached to such Notes 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 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.

On October 31, 2011, OFC 2 and the Issuers completed the sale of $151.7 million aggregate principal amount of 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 $147.4 million, and will be used to finance a portion of the construction costs of Phase I of the McGinness Hills and Tuscarora facilities. The Issuers will pay 4.687% interest on the Series A Notes quarterly in arrears on the last day of each of March, June, September and December in each year, commencing on December 31, 2011.

OrPower 4, Inc. (OrPower 4), has a project financing loan of $105.0 million which refinanced its investment in the 48 MW Olkaria III geothermal power plant located in Kenya. The loan was provided by a group of European Development Finance Institutions arranged by DEG — Deutsche Investitions- und Entwicklungsgesellschaft mbH (DEG). The 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 $77.0 million of the loan at 6.90% ~~per annum.~~. There are various restrictive covenants under the loan, which include limitations on OrPower 4’s ability to make distributions to its shareholders. As of ~~June~~September 30, 2011, OrPower 4 was in compliance with the covenants under the loan. As of ~~June~~September 30, 2011, $82.9 million of the Olkaria III loan was outstanding.

We plan to refinance the existing Olkaria III Loan as described under “New Financing of Our Projects” below.

Ortitlan Limitada (Ortitlan), entered into a note purchase agreement in an aggregate principal amount of $42.0 million which refinanced its investment in the 20 MW Amatitlan geothermal power plant located in Amatitlan, Guatemala. The loan was provided by TCW Global Project Fund II, Ltd. The loan will mature on June 15, 2016, and is payable in 28 quarterly installments, that commenced on September 15, 2009. The ~~annual~~ interest rate on the loan is 9.83%, but the effective cost for us is approximately 8%, due to the elimination, following the refinancing, of the political risk insurance premiums that we had been paying on our equity investment in the project. There are various restrictive covenants under the loan, which include limitations on Ortitlan’s ability to make distributions to its shareholders. As of ~~June~~September 30, 2011, Ortitlan was in compliance with the covenants under the loan. As of ~~June~~September 30, 2011, ~~$37.9~~$37.3 million of the Amatitlan loan was outstanding.

Senior Loan from International Finance Corporation (IFC) — (The Zunil Power Plant) — Non-Recourse

Orzunil I de Electricidad, Limitada (Orzunil), a wholly owned subsidiary in Guatemala, ~~has~~had a senior loan agreement with IFC. The loan was fully repaid in the third quarter of ~~which $0.9 million was outstanding as of June 30, 2011, has a fixed annual interest rate of 11.775%, and matures on November 15,~~ 2011. There are various restrictive covenants under the senior loan, which include limitations on Orzunil’s ability to make distributions to its shareholders. As of June 30, 2011, Orzunil was in compliance with the covenants under this senior loan.

Refinancing of the Olkaria III Loan and Financing of the ~~North Brawley Power Plant~~Construction of the Olkaria III Complex Expansion

~~We refinanced~~In September 2011, we signed a ~~portion of~~commitment letter issued by the ~~equity invested in the North Brawley power plant with the cash grant we received under the ARRA in September 2010. We expect that once we bring the power plant closer~~Overseas Private Investment Corporation (OPIC) to ~~its original design capacity, we will be able to refinance a portion of the remainder of the equity invested with long-term debt.~~

~~Financing for Jersey Valley, McGinness Hills and Tuscarora Projects in Nevada~~

~~Our subsidiary, Ormat Nevada, has engaged John Hancock to arrange senior secured construction and term loan facilities under a DOE loan guarantee program~~provide project financing of up to ~~$350~~$310 million ~~for three~~to refinance and expand our 48 MW Olkaria III geothermal ~~projects~~complex located in Naivasha, Kenya. Under the agreed term sheet attached to the commitment letter, the loan will be comprised of a refinancing tranche of up to $85 million to prepay the existing loan with DEG and fund transaction costs, a construction loan tranche of up to $165 million to finance the construction of an additional 36 MW expansion currently

~~under construction in Nevada. The three projects are~~ underway, and a $60 million stand-by facility to finance an optional additional 16 MW capacity expansion, that, if exercised by Ormat, could bring the ~~Jersey Valley, McGinness Hills and Tuscarora geothermal projects. Construction of all three projects has already commenced with commercial operation~~total capacity of the ~~first phase of each project expected between 2011 and 2013.~~

complex to approximately 100 MW. The ~~availability~~maturity dates of the ~~credit facilities is subject~~construction tranche and the refinancing tranche are expected to ~~various conditions, including execution of mutually satisfactory documentation~~be June 2030 and ~~approval~~December 2030, respectively. The maturity date and certain other terms of the ~~DOE.~~

~~In June 2011,~~stand-by facility will be finalized following ~~a due diligence review of~~our decision, if any, to exercise the ~~three projects conducted by John Hancock and~~option to construct the ~~DOE, we received an offer of a conditional commitment which may lead to a loan guarantee, although we have no assurance this will occur.~~additional 16 MW expansion.

In December 2008, our wholly owned subsidiary, Ormat Nevada, entered into an amendment of its credit agreement with Union Bank, N.A. (Union Bank), extending the final maturity of the facility and increasing its total amount to $37.5 million. In August 2011 such line of credit was increased to $39.0 million. Under the credit agreement, Ormat Nevada can request extensions of credit in the form of loans and/or the issuance of one or

more 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 have 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 by any of its (or any of its subsidiaries’) assets.

Loans and draws under the letters of credit (if any) under the credit agreement will bear interest at a floating rate based on the Eurodollar plus a margin. There are various restrictive covenants under the credit agreement, which include maintaining certain levels of tangible net worth, leverage ratio, minimum coverage ratio, and a distribution coverage ratio. In addition, there are restrictions on dividend distributions in the event of a payment default or noncompliance with such ratios, and Ormat Nevada is subject to a negative pledge in favor of Union Bank.

As of ~~June~~September 30, 2011, letters of credit in the aggregate amount of ~~$33.2~~$38.5 million remain issued and outstanding under this credit agreement with Union Bank.

We also have credit agreements with five commercial banks for an aggregate amount of $370.0 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 $265.0 million; and (ii) the issuance of one or more letters of credit in the amount of up to ~~$105.0.~~$105.0 million. The credit agreements mature between October 2011 and September 2013. 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. Credit agreements in the amount of $115.0 million are due to expire in the fourth quarter of 2011. We are currently negotiating the extension of these credit agreements for up to three years. We anticipate that these extensions will include an increase in the annual average interest rates.

We have a $20.0 million term loan with a group of financial institutions, which matures on July 16, 2015, is payable in 12 semi-annual installments that commenced January 16, 2010, and bears ~~annual~~ interest of 6.5%. As of ~~June~~September 30, 2011, ~~$15.7~~$14.2 million was outstanding under this loan.

We have a $20.0 million term loan with a group of financial institutions, which matures on August 1, 2017, is payable in 12 semi-annual installments commencing February 1, 2012, and bears ~~annual~~ interest at 6-month LIBOR plus 5.0%. As of ~~June~~September 30, 2011, $20.0 million was outstanding under this loan.

We have a $20.0 million term loan with a group of institutional investors, which matures on November 16, 2016, is payable in 10 semi-annual installments commencing May 16, 2012, and bears ~~annual~~ interest of 5.75%. As of ~~June~~September 30, 2011, $20.0 million was outstanding under this loan.

We have a $50.0 million term loan with a commercial bank, which matures on November 10, 2014, is payable in 10 semi-annual installments that commenced May 10, 2010, and bears ~~annual~~ interest at 6-month LIBOR plus 3.25%. As of ~~June~~September 30, 2011, $35.0 million was outstanding under this loan.

We have an aggregate principal amount of approximately $250.0 million of Senior Unsecured Bonds issued and outstanding. We issued approximately $142.0 million of these bonds in August 2010 and an additional $107.5 million in February 2011. Subject to early redemption, the principal of the bonds is repayable in a single bullet payment upon the final maturity of the bonds on August 1, 2017. The bonds bear interest at a fixed rate of 7% ~~per annum,~~, 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% ~~per annum.~~. We issued the bonds outside the United States to investors who are not “U.S. persons” in an unregistered offering pursuant to, and subject to the requirements of, Regulation S under the Securities Act.

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~~Certain of the credit agreements, the 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 such as a debt service coverage ratio, a debt to equity ratio, and a debt to adjusted EBITDA ratio. There are also certain restrictions on distribution of dividends. The failure to perform or comply with 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.

We are currently in compliance with our covenants with respect to the credit agreements, the loan agreements and the trust instrument, and believe that compliance with 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 plan of operations.

~~Some~~Certain 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.

Three commercial banks have issued such performance letters of credit in favor of our customers from time to time. As of ~~June~~September 30, 2011, such banks have issued letters of credit totaling ~~$39.7~~$39.8 million. These letters of credit were not issued under the credit agreements discussed under “Full-Recourse Third Party Debt” above.

In addition, we and certain of our subsidiaries may request letters of credit under the credit agreements with Union Bank and five other commercial banks as described under “Full-Recourse Third Party Debt” above. As of ~~June~~September 30, 2011, letters of credit in the aggregate amount of ~~$68.6~~$97.4 million remained issued and outstanding under the Union Bank credit agreement and our other agreements with commercial banks.

On May 19, 2005, our subsidiary in Hawaii, Puna Geothermal Venture (PGV), entered into a transaction involving the Puna geothermal power plant located on the Big Island of Hawaii. 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 deferred lease payments by such financing parties to PGV in the aggregate amount of $83.0 million.

In June 2007, our wholly owned subsidiary, Ormat Nevada, entered into agreements with affiliates of Morgan Stanley & Co. Incorporated (Morgan Stanley Geothermal LLC) and Lehman Brothers Inc. (Lehman-OPC LLC (Lehman-OPC)), 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.

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 it recovers the capital that it invested in the power plants, which occurred in the fourth quarter of 2010, the investors receive both the distributable cash flow and the Economic Benefits. The investors’ return is limited by the term of the transaction. Once the investors reach a target after-tax yield on their investment in OPC (the Flip Date), Ormat Nevada will receive 95% of both distributable cash and taxable income, on a going forward basis. Following the Flip Date, Ormat Nevada also has the option to buy out the investors’ remaining interest in OPC at the then-current fair market value or, if greater, the investors’ capital account balances in OPC. Should Ormat Nevada exercise this purchase option, it would thereupon revert to being sole owner of the power plants.

Our voting rights in OPC are based on a capital structure that is comprised of Class A and Class B membership units. We own, through our subsidiary, Ormat Nevada, all of the Class A membership units, which represent 75% of the voting rights in OPC. The investors 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 Flip Date, Ormat Nevada’s voting rights will increase to 95% and the investors’ voting rights will decrease to 5%. Ormat Nevada retains the controlling voting interest in OPC both before and after the Flip Date and therefore continues to consolidate OPC.

On October 30, 2009, Ormat Nevada acquired from Lehman-OPC all of the Class B membership units of OPC held by Lehman-OPC pursuant to a right of first offer for a purchase price of $18.5 million.

On February 3, 2011, Ormat Nevada sold to JPM Capital Corporation (JPM) all of the Class B membership units of OPC that it had acquired on October 30, 2009 for a sale price of $24.9 million in cash.

As discussed in Note 17 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 ~~$4.4~~$4.2 million as of ~~June~~September 30, 2011. This liability is included in long-term liabilities in our 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, but believe that the ultimate settlement of our obligations will not materially affect our liquidity.


Date Declared	Dividend Amount per Share		Record Date	Payment Date	Dividend Amount per Share		Record Date	Payment Date
August 5, 2009	$	0.06	August 18, 2009	August 27, 2009
November 4, 2009	$	0.06	November 18, 2009	December 1, 2009	$	0.06	November 18, 2009	December 1, 2009
February 23, 2010	$	0.12	March 16, 2010	March 25, 2010	$	0.12	March 16, 2010	March 25, 2010
May 5, 2010	$	0.05	May 18, 2010	May 25, 2010	$	0.05	May 18, 2010	May 25, 2010
August 4, 2010	$	0.05	August 17, 2010	August 26, 2010	$	0.05	August 17, 2010	August 26, 2010
November 2, 2010	$	0.05	November 17, 2010	November 30, 2010	$	0.05	November 17, 2010	November 30, 2010
February 22, 2011	$	0.05	March 15, 2011	March 24, 2011	$	0.05	March 15, 2011	March 24, 2011
May 4, 2011	$	0.04	May 18, 2011	May 25, 2011	$	0.04	May 18, 2011	May 25, 2011
August 3, 2011	$	0.04	August 16, 2011	August 25, 2011	$	0.04	August 16, 2011	August 25, 2011

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


	Six Months Ended June 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	(In thousands)						(In thousands)
Net cash provided by operating activities	$	39,506		$	58,934		$	98,514		$	79,644
Net cash used in investing activities		(135,741	)		(109,014	)		(238,186	)		(153,020	)
Net cash provided by financing activities		57,758			57,968			115,934			76,309
Net change in cash and cash equivalents		(38,477	)		7,888			(23,738	)		2,933

Net cash provided by operating activities for the ~~six~~nine months ended ~~June~~September 30, 2011 was ~~$39.5~~$98.5 million, compared to ~~$58.9~~$79.6 million for the ~~six~~nine months ended ~~June~~September 30, 2010. The net ~~decrease~~increase of ~~$19.4~~$18.9 million resulted primarily from: (i) a decrease in net income to net loss of $0.7 million in the six months ended June 30, 2011, from net income of $0.3 million in the six months ended June 30, 2010, mainly as a result of the increase in interest expense, net and the decrease in income tax benefit, which was partially offset by the increase in operating income, as described above; (ii) an increase in receivables of $17.3 million in the six months ended June 30, 2011, compared to a decrease of $4.2 million in the six months ended June 30, 2010, as a result of timing of collections from our customers; and (iii) a decrease in accounts payable and accrued expenses of $8.6 million in the six months ended June 30, 2011, compared to an increase of ~~$9.4 million in the six months ended~~

~~June 30, 2010, as a result of timing of payments to our vendors. Such decrease was partially offset by: (i) an increase of $7.7~~$6.8 million in depreciation and amortization mainly due to the placement in service of our Jersey Valley power plant in January 2011, and higher depreciation in the Mammoth complex, resulting from the plan to repower the complex by replacing part of the old units with new Ormat-manufactured equipment, as described above; ~~and~~ (ii) a gain on acquisition of controlling interest of $36.9 million in the nine months ended September 30, 2010; (iii) a gain on sale of GDL of $6.3 million in the ~~six~~nine months ended ~~June~~September 30, 2010; (iv) a decrease in receivables of $2.6 million in the nine months ended September 30, 2011, compared to an increase of $5.7 million in the nine months ended September 30, 2010, as a result of timing of collections from our customers; and ~~(iii)~~(v) an increase in billing in excess of costs and estimated earnings on uncompleted contracts, net of ~~$21.2~~$35.1 million relating to our Product Segment in the ~~six~~nine months ended ~~June~~September 30, 2011, compared to $15.3 million in the nine months ended September 30, 2010, as a result of timing in billing of our ~~customers~~customers. Such decrease was partially offset by: (i) a decrease in net income to $0.3 million in the nine months ended September 30, 2011, from $32.7 million in the nine months ended September 30, 2010, mainly as a result of a gain on acquisition of controlling interest of $36.9 million in the nine months ended September 30, 2010 and the increase in interest expense, net offset by the increase in operating income, and the decrease in income tax expense as described above and (ii) a decrease in accounts payable and accrued expenses of $9.6 million in the nine months ended September 30, 2011, compared to an increase of ~~$10.2~~$5.6 million in the ~~six~~nine months ended ~~June~~September 30, ~~2010.~~2010, as a result of timing of payments to our vendors.

Net cash used in investing activities for the ~~six~~nine months ended ~~June~~September 30, 2011 was ~~$135.7~~$238.2 million, compared to ~~$109.0~~$153.0 million for the ~~six~~nine months ended ~~June~~September 30, 2010. The principal factors that affected our net cash used in investing activities during the ~~six~~nine months ended ~~June~~September 30, 2011 were: (i) capital

expenditures of ~~$109.6~~$180.8 million, primarily for our facilities under construction; (ii) net increase of ~~$3.8~~$36.9 million in restricted cash, cash equivalents and marketable securities; and (iii) net increase of ~~$22.1~~$20.3 million in marketable securities. The principal factors that affected our net cash used in investing activities during the ~~six~~nine months ended ~~June~~September 30, 2010 ~~were~~were: (i) capital expenditures of ~~$139.2~~$194.9 million, primarily for our power facilities under ~~construction, offset by: (i) a $7.7~~construction; (ii) net payment of $64.5 million ~~decrease~~for acquisition of controlling interest in Mammoth Pacific ($72.5 million purchase price less $8.0 million available cash in such subsidiary at the acquisition date); and (iii) net increase of $23.4 million in restricted cash, cash equivalents and marketable ~~securities;~~securities, offset by: (i) $108.3 million received in September 2010 for Specified Energy Property in Lieu of Tax Credits relating to our North Brawley geothermal power plant under Section 1603 of the ARRA; and (ii) $19.6 million received from the sale of GDL.

Net cash provided by financing activities for the ~~six~~nine months ended ~~June~~September 30, 2011 was ~~$57.8~~$115.9 million, compared to ~~$58.0~~$76.3 million for the ~~six~~nine months ended ~~June~~September 30, 2010. The principal factors that affected the net cash provided by financing activities during the ~~six~~nine months ended ~~June~~September 30, 2011 were: (i) the issuance of an aggregate amount of approximately $107.4 million Senior Unsecured Bonds in February 2011; and (ii) proceeds from the sale of all of the Class B membership units of OPC acquired on October 30, 2009 for a sale price of $24.9 million; and (iii) a net increase of $31.9 million against our revolving lines of credit with commercial banks, offset by: (i) the repayment of long-term debt in the amount of ~~$23.0~~$26.0 million; (ii) ~~a net decrease of $38.0 million against our revolving lines of credit with commercial banks; (iii)~~ cash paid to non-controlling interest in the amount of ~~$7.0~~$10.8 million; and ~~(iv)~~(iii) the payment of a dividend to our shareholders in the amount of ~~$4.1~~$5.9 million. The principal factor that affected our net cash provided by financing activities during the ~~six~~nine months ended ~~June~~September 30, 2010 was ~~$100.4~~the issuance of an aggregate amount of approximately $142.0 million ~~drawn under revolving lines of credit from commercial banks, which was~~senior unsecured bonds on August 3, 2010, offset by: (i) the repayment of long-term debt in the amount of ~~$34.7~~$37.7 million; (ii) a net decrease of $17.5 million against our revolving lines of credit with commercial banks; and ~~(ii)~~(iii) the payment of a dividend to our shareholders in the amount of ~~$7.7~~$10.0 million.

Adjusted EBITDA for the three months ended ~~June~~September 30, 2011 was ~~$47.7~~$46.7 million, compared to ~~$24.0~~$78.8 million in the three months ended ~~June~~September 30, 2010. Adjusted EBITDA for the ~~six~~nine months ended ~~June~~September 30, 2011 was ~~$74.8~~$121.6 million, compared to ~~$56.1~~$134.9 million for the ~~six~~nine months ended ~~June~~September 30, 2010. Adjusted EBITDA includes consolidated EBITDA and our share in the interest, taxes, depreciation and amortization related to our unconsolidated 50% interest in the Mammoth complex in California in the three and ~~six~~nine months ended ~~June~~September 30, 2010.

We calculate EBITDA as net income before interest, taxes, depreciation and amortization. We calculate adjusted EBITDA to include depreciation and amortization, interest and taxes attributable to our equity investments in the Mammoth complex. EBITDA and adjusted EBITDA are not measurements of financial performance or liquidity under 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 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~~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. This information should not be considered in isolation or as a substitute for, or superior to, measures of financial performance prepared in accordance with GAAP or other non-GAAP financial measures.

The following table reconciles net cash provided by operating activities to EBITDA and adjusted EBITDA, for the ~~six-month~~nine-month periods ended ~~June~~September 30, 2011 and 2010:


	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010			2011			2010			2011			2010
	(in thousands)						(in thousands)						(in thousands)						(in thousands)
Net cash provided by operating activities	$	26,440		$	10,694		$	39,506		$	58,934		$	59,008		$	20,710		$	98,514		$	79,644
Adjusted for:
Interest expense, net (excluding amortization of deferred financing costs)		16,528			8,754			28,824			17,775			23,222			10,271			52,046			28,046
Interest income		(716	)		(95	)		(851	)		(292	)		(438	)		(140	)		(1,289	)		(432	)
Income tax benefit		(1,007	)		(3,935	)		(421	)		(3,916	)
Income tax provision (benefit)														(305	)		11,931			(726	)		8,015
Adjustments to reconcile net income to net cash provided by operating activities (excluding depreciation and amortization)		6,433			7,692			7,772			(18,314	)		(34,749	)		35,823			(26,977	)		17,509

EBITDA		47,678			23,110			74,830			54,187			46,738			78,595			121,568			132,782
Interest, taxes, depreciation and amortization attributable to the Company’s equity interest in Mammoth-Pacific L.P.		—			939			—			1,912			—			203			—			2,115

Adjusted EBITDA	$	47,678		$	24,049		$	74,830		$	56,099		$	46,738		$	78,798		$	121,568		$	134,897

Net cash used in investing activities	$	(27,817	)	$	(44,033	)	$	(135,741	)	$	(109,014	)	$	(102,445	)	$	(44,006	)	$	(238,186	)	$	(153,020	)

Net cash provided by financing activities	$	5,040		$	44,423		$	57,758		$	57,968		$	58,176		$	18,341		$	115,934		$	76,309

Our capital expenditures primarily relate to two principal components: (i) the enhancement of our existing power plants and (ii) the development and construction of new power plants. WeGenerally we expect that ~~the following~~ enhancements of our existing power plants and the construction of new power plants will be funded initially from internally generated cash or other available corporate resources, which we expect to subsequently refinance with limited or non-recourse debt at the project level. For 2012, we expect that most of our capital expenditures requirements will be funded by construction loans.

McGinness Hills Project We are currently developing the first phase of the 30 MW McGinness Hills project on Bureau of Land Management leases located in Lander County, Nevada. Field development is still in process ~~the power plant equipment~~and construction is ~~in transit to the site, we have obtained part of the required construction permits and the environmental assessment is still in process.~~progressing. We signed a 20-year PPA with Nevada Power Company, which was approved by the PUCN on July 28, 2010. Commercial operation of the project’s first phase is expected in 2012. ~~The National Environmental Policy Act (NEPA) process is in progress in order to comply with the requirements~~We have secured financing under the DOE 1705 ~~loan guarantee program.~~Loan Guarantee Program.

Tuscarora Project We are currently developing the first phase (18 MW) of the Tuscarora project on private land located in Elko County, Nevada. ~~Field development has been completed, civil work~~Construction is in ~~process~~the final stage, and ~~mechanical work has begun. We have obtained most of the required construction permits.~~we are preparing for start-up. We signed a 20-year PPA with Nevada Power Company, which was approved by the PUCN on July 28, 2010. Commercial operation of the project’s first phase is expected in 2012. ~~The NEPA process is in progress in order to comply with the requirements~~We have secured financing under the DOE 1705 ~~loan guarantee program.~~Loan Guarantee Program.

Carson Lake Project We plan to develop the 20 MW Carson Lake project on Bureau of Land Management leases located in Churchill County, Nevada. ~~Approval by~~We received the approval of the Bureau of Land Management for the required Environmental Impact Study, ~~is pending,~~ and ~~therefore there is no certainty about~~we are evaluating a new schedule for the ~~completion date of this~~ project.

Mammoth Complex We plan to repower the Mammoth complex located in Mammoth Lakes, California, by replacing part of the old units with new Ormat-manufactured equipment. The replacement of the equipment

will optimize generation and add approximately 3 MW of generating capacity to the complex. We have started the equipment fabrication for the replacement of the old generating equipment with modern units designed and manufactured by ~~us.~~us, and we are awaiting the required permits to start construction.

CD 4 Project We are currently developing 30 MW of new capacity at the Mammoth complex, on land which is comprised mainly of BLM leases. We have commenced field development, and ~~have drilled a successful production well, and the~~ drilling of additional wells is ~~continuing.~~subject to permits. The project is expected to be completed in 2013.

Olkaria III Phase 3 ~~We are currently developing~~Development of Phase 3 of the Olkaria III complex located in Naivasha, ~~Kenya.~~Kenya is in process. Field development ~~has started, we are drilling three wells~~ and manufacturing of the power plant equipment is in progress. We amended and restated the PPA with KPLC, the off-taker of the Olkaria III complex. The amended and restated PPA governs our construction of, and KPLC’s purchase of electricity from, a new 36 MW power plant at the Olkaria III complex. The new power plant is scheduled to come online in 2013.

Wild Rose (formerly DH Wells) Project We are currently developing the 15 to 20 MW Wild Rose project located in Mineral County, Nevada. We ~~recently completed the drilling of two wells in the shallow resource and~~ are continuing with the drilling ~~activity.The~~activity. The new power plant is ~~scheduled~~expected to come online in 2013. The final output will be determined based on exploration results.

The Jersey Valley power plant is currently operating at a generation level below its design capacity, primarily as a result of the need to shut down one of the injection wells which has suffered interference from an old mining well that ~~was~~had been drilled on the property before we acquired the land and which we believe ~~was~~had not been adequately plugged and abandoned by the mining operator. We ~~plan to drill~~are in the process of drilling additional wells in order to add injection capacity for the power plant. We ~~have applied for the necessary permits and expect~~are in discussion with NV Energy to ~~receive such permits and complete the additional drilling by the end of 2011. Due~~prevent any penalties or contract default that we may be subject to due to the ~~delay in completing the power plant and reaching the design generation~~current capacity we will need to obtain an extension of time from the PPA offtaker to avoid missing the current completion milestone under the PPA and to be able to meet the electricity delivery obligations under the PPA.shortfall.

We have estimated approximately ~~$728~~$723 million in capital expenditures for construction of the abovementioned projects under construction and that are expected to be completed by 2013, of which we have invested approximately ~~$192.0~~$240 million as of ~~June~~September 30, 2011. We expect to invest an additional ~~$131~~$83 million during the remainder of 2011. The remaining ~~$405~~$400 million will be invested in 2012 and 2013.

In addition, we estimate approximately ~~$77~~$25 million in additional capital expenditures in the remainder of 2011 to be allocated as follows: (i) $7 million ~~in new projects under development; (ii) $18 million~~ for enhancement of our operating power plants; ~~(iii) $5 million in land acquisitions; (iv) $20 million in exploration activities pursuant to various leases for geothermal resources in which we have started the exploration activity; (v) $13~~(ii) $12 million in new project development, provided that part or all of the aforementioned exploration activities succeed; and ~~(vi) $14~~(iii) $6 million in other capital expenditures. Therefore, the total capital expenditure for the remainder of 2011 is estimated to be ~~$208~~$108 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. A prolonged economic slowdown could reduce worldwide demand for energy, including our geothermal energy, REG and other products.

One market risk to which power plants are typically exposed is the volatility of electricity prices. Our exposure to such market risk is currently limited because our long-term PPAs (except for Puna) have fixed or

escalating rate provisions that limit our exposure to changes in electricity prices. However, beginning in May 2012, the energy payments under the PPAs of the Heber 1 and 2 power plants, the Ormesa complex and the Mammoth complex will be determined by reference to the relevant power purchaser’s short run avoided costs. The Puna power plant is currently benefiting from energy prices which are higher than the floor under the Puna PPA as a result of the high fuel costs that impact Hawaii Electric Light Company’s avoided costs.

As of ~~June~~September 30, 2011, ~~72.7%~~67.0% of our consolidated long-term debt was in the form of fixed rate securities, and therefore, not subject to interest rate volatility risk. As of such date, ~~27.3%~~33.0% of our debt was in the form of a floating rate instrument, exposing us to changes in interest rates. As of ~~June~~September 30, 2011, ~~$228.5~~$298.3 million of our debt remained subject to some floating rate risk.

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

Our cash equivalents and our portfolio of marketable securities are subject to market risk due to changes in interest rates. Fixed rate securities may have their market value adversely impacted due to a rise in interest rates, while floating rate securities may produce less income than expected if interest rates fall. Due in part to these factors, our future investment income may fall short of ~~expectation~~expectations due to changes in interest rates or we may suffer losses in principal if we are forced to sell securities that decline in market value due to changes in interest rates. However, because we classify our debt securities as “available-for-sale”, no gains or losses are recognized in the statement of operations and comprehensive income (loss) due to changes in interest rates unless such securities are sold prior to maturity or declines in fair value are determined to be other-than-temporary.

Another market risk to which we are exposed is primarily related to potential adverse changes in foreign currency exchange rates, in particular the fluctuation of the U.S. dollar versus the New Israeli Shekel (NIS). Risks attributable to fluctuations in currency exchange rates can arise when we or any of our foreign subsidiaries borrows funds or incurs operating or other expenses in one type of currency but receives revenues in another. In such cases, an adverse change in exchange rates can reduce our or such subsidiary’s ability to meet its debt service obligations, reduce the amount of cash and income we receive from such foreign subsidiary, or increase such subsidiary’s overall expenses. Risks attributable to fluctuations in foreign currency exchange rates can also arise when the currency denomination of a particular contract is not the U.S. dollar. Substantially all of our PPAs in the international markets are either U.S. dollar-denominated or linked to the U.S. dollar. Our construction contracts from time to time contemplate costs which are incurred in local currencies. The way we often mitigate such risk is to receive part of the proceeds from the sale contract in the currency in which the expenses are incurred. Currently, we have forward and option 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.

Our credit risk is currently concentrated with a limited number of major customers: Southern California Edison, Hawaii Electric Light Company, Sierra Pacific Power Company and Nevada Power Company (subsidiaries of NV Energy), and Kenya Power and Lighting Co. Ltd. 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.

Southern California Edison accounted for ~~29.5%~~34.5% and ~~25.5%~~35.9% of the Company’s total revenues for the three months ended ~~June~~September 30, 2011 and 2010, respectively, and ~~28.3%~~30.5% and ~~25.5%~~29.6% of our total revenues for the ~~six~~nine months ended ~~June~~September 30, 2011 and 2010, respectively. Southern California Edison is the power purchaser and

revenue source for our Mammoth complex, which was accounted for under the equity method through August 1, 2010. Following our acquisition of the remaining 50% interest in the Mammoth complex we have included the results of the Mammoth complex in our consolidated financial statements.

Sierra Pacific Power Company and Nevada Power Company accounted for ~~12.0%~~10.5% and 12.2% of the Company’s total revenues for the three months ended ~~June~~September 30, 2011 and 2010, respectively, and ~~14.1%~~12.8% and ~~16.2%~~14.7% of our total revenues for the ~~six~~nine months ended ~~June~~September 30, 2011 and 2010, respectively.

Hawaii Electric Light Company accounted for ~~11.8%~~10.3% and ~~8.0%~~10.1% of the Company’s total revenues for the three months ended ~~June~~September 30, 2011 and 2010, respectively, and ~~11.2%~~10.9% and ~~7.6%~~8.3% of our total revenues for the ~~six~~nine months ended ~~June~~September 30, 2011 and 2010, respectively.

The U.S. government encourages production of electricity from geothermal resources through certain tax subsidies under the recently enacted ARRA. We are permitted to claim 30% of the eligible costs of each new geothermal power plant in the United States as an ITC against our federal income taxes. Alternatively, we are permitted to claim a PTC, which in 2011 was 2.2 cents per kWh and which is adjusted annually for inflation. The PTC may be claimed for ten years on the electricity output of new geothermal power plants put into service by December 31, 2013. The owner of the project must choose between the PTC and the 30% ITC described above. In either case, under current tax rules, any unused tax credit has a 1-year carry back and a 20-year carry forward. Whether we claim the PTC or the ITC, we are also permitted to depreciate most of the plant for tax purposes 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. If we claim the ITC, our “tax basis” in the plant that we can recover through depreciation must be reduced by half of the tax credit. If we claim a PTC, there is no reduction in the tax basis for depreciation. Companies that place qualifying renewable energy facilities in service, during 2009, 2010 or 2011 or that begin construction of qualifying renewable energy facilities during 2009, 2010 or 2011 and place them in service by December 31, 2013, may choose to apply for a cash grant from the U.S. Department of Treasury (U.S. Treasury) in an amount equal to the ITC. Under the ARRA, the U.S. Treasury is instructed to pay the cash grant within 60 days of the application or the date on which the qualifying facility is placed in service.

Production of electricity from geothermal resources is also supported under the ~~new~~ “Temporary Program For Rapid Deployment of Renewable Energy and Electric Power Transmission Projects” established with the DOE as part of the DOE’s ~~existing~~ Innovative Technology Loan Guarantee Program. ~~The new~~This program: (i) ~~extends~~extended the scope of the existing federal loan guarantee program to cover renewable energy projects, renewable energy component manufacturing facilities, and electricity transmission projects that embody established commercial, as well as innovative, technologies; and (ii) ~~provides~~provided an appropriation to cover the “credit subsidy costs” of such projects (meaning the estimated average costs to the federal government from issuing the loan guarantee, equivalent to a lending bank’s loan loss reserve).

~~To be eligible~~Guarantees under this program support projects that started construction, and for ~~a guarantee under the new program, a supported project must break ground, and~~which the guarantee ~~must be~~was issued, by September 30, 2011.

Our subsidiary, 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. As a Benefited Enterprise, Ormat Systems was exempt from Israeli income taxes with respect to income derived from the first benefited investment for a period of two years beginning in 2004, and thereafter such income is subject to reduced Israeli income tax rates, which will not exceed 25% for an additional five years. Ormat Systems is also exempt from Israeli income taxes with respect to income derived from the second benefited investment for a period of two years beginning in 2007, and thereafter such income is subject to reduced Israeli income tax rates, which will not exceed 25% for an additional five years. These benefits are subject to certain conditions, including among other things, that all transactions between Ormat Systems and our affiliates are at arm’s length, and that the management and control of Ormat Systems will be from Israel during the entire period of the tax benefits. A change in control should be reported to the Israel Tax Authority in order to

maintain the tax benefits. In January 2011, new legislation amending the Investment Law was enacted. Under the new legislation, a uniform rate of corporate tax would apply to all qualified income of certain industrial companies, as opposed to the current law’s incentives that are limited to income from a “Benefited Enterprise” during their benefits period. According to the amendment, the uniform tax rate applicable to the zone where the production facilities of Ormat Systems are located would be 15% in 2011 and 2012, 12.5% in 2013 and 2014, and 12% in 2015 and thereafter. Under the transitory provisions of the new legislation, Ormat Systems may opt to irrevocably comply with the new law while waiving benefits provided under the current law or continue to comply with the current law during the next years. Changing from the current law to the new law is permissible at any stage. Ormat Systems decided to irrevocably comply with the new law starting in 2011.

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 ~~June~~September 30, 2011, 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.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

There were no changes in our internal controls over financial reporting in the ~~second~~third quarter of 2011 that have materially affected or are reasonably likely to materially affect our internal controls over financial reporting.

Following the Company’s public announcement that it would restate certain of its financial results due to a change in the Company’s accounting treatment for certain exploration and development costs, three securities class action lawsuits were filed in the United States District Court for the District of Nevada on March 9, 2010, March 18, 2010 and April 7, 2010. These complaints assert claims against the Company and certain officers and directors for alleged violation of Sections 10(b) and 20(a) of the Securities Exchange Act of 1934, as amended (the Exchange Act). One complaint also asserts claims for alleged violations of Sections 11, 12(a)(2) and 15 of the Securities Act. All three complaints allege claims on behalf of a putative class of purchasers of Company common stock between May 6, 2008 or May 7, 2008 and February 23, 2010 or February 24, 2010. These three lawsuits were consolidated by the court in an order issued on June 3, 2010, and the court appointed three of the Company’s stockholders to serve as lead plaintiffs.

Lead plaintiffs filed a consolidated amended class action complaint (CAC) on July 9, 2010 that asserts claims under Sections 10(b) and 20(a) of the Exchange Act on behalf of a putative class of purchasers of Company common stock between May 7, 2008 and February 24, 2010. The CAC alleges that certain of the Company’s public statements were false and misleading for failing to account properly for the Company’s exploration and development costs based on the Company’s announcement on February 24, 2010 that it was going to restate certain of its financial results to change its method of accounting for exploration and development costs in certain respects. The CAC also alleges that certain of the Company’s statements concerning the North Brawley project were false and misleading. The CAC seeks compensatory damages, expenses, and such further relief as the court may deem proper. The Company cannot make an estimate of the possible loss or range of loss.

Defendants filed a motion to dismiss the CAC on August 13, 2010. On March 3, 2011, the court granted in part and denied in part defendants’ motion to dismiss. The court dismissed plaintiffs’ allegations that on the Company’s statements regarding the North Brawley project were false or misleading, but did not dismiss plaintiffs’ allegations regarding the 2008 restatement. Defendants answered the remaining allegations in the CAC regarding the restatement on April 8, 2011 and the case has now entered the discovery phase. On July 22, 2011, plaintiffs filed a motion to certify the case as a class action on behalf of a class of purchasers of Company common stock between February 25, 2009 and February 24, ~~2010.~~2010, and defendants filed an opposition to the motion for class certification on October 4, 2011.

The Company ~~does not believe~~believes that these lawsuits have no merit and is defending the actions vigorously.

The two stockholder derivative cases filed in the Second Judicial District Court of the State of Nevada in and for the County of Washoe were consolidated by the court in an order dated May 27, 2010 and the plaintiffs filed a consolidated derivative complaint on September 7, 2010. In accordance with a stipulation between the parties, defendants filed a motion to dismiss on November 16, 2010. On April 18, 2011, the court stayed the state derivative case pending the resolution of the securities class action. The Company cannot make an estimate of the possible loss or range of loss on the state derivative case.

The Company believes the allegations in these purported derivative actions are without merit and is defending the actions vigorously.

On May 19, 2011, the Federal Energy Regulatory Commission (FERC) issued an order which denied the Company’s exemptions for requirements relating to Sections 205 and 206 of the Federal Power Act and directed the Company’s REG facilities to make refunds to their customers, equaling “the time value of the revenues collected during the periods of non-compliance with the qualifying facilities”, ~~which approximate~~in an amount of approximately $1.6 million. On June 17, 2011, the Company requested a rehearing to obtain relief on this mandated refund payment. On July 18, 2011, FERC issued an Order Granting Rehearing for Further Consideration in order to afford additional time for consideration of the matters raised. To date, FERC has not taken further action on the rehearing.

The Company believes that it is not probable ~~but reasonably possible~~ that a refund payment will ultimately need to be made.

In addition, from time to time, the Company is named as a party in various lawsuits, claims and other legal and regulatory proceedings that arise in the ordinary course of its 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 materially affect its business, financial condition, financial results or cash flow.

A comprehensive discussion of our risk factors is included in the “Risk Factors” section of our annual report on Form 10-K for the year ended December 31, 2010 filed with the SEC on February 28, 2011.

There were no unregistered sales of equity securities of the Company during the ~~second~~third fiscal quarter of 2011.

Our management believes that we are currently in compliance with our covenants with respect to our third-party debt.


Exhibit No.		Document

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, filed 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, filed herewith.

101.INS		XBRL Instance Document

101.SCH		XBRL Taxonomy Extension Schema Document

101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF		XBRL Taxonomy Extension Definition Linkbase

101.LAB		XBRL Taxonomy Extension Label Linkbase Document

101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document

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.


Exhibit No.		Document

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, filed 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, filed herewith.

101.INS		XBRL Instance Document

101.SCH		XBRL Taxonomy Extension Schema Document

101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF		XBRL Taxonomy Extension Definition Linkbase

101.LAB		XBRL Taxonomy Extension Label Linkbase Document

101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document


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


PART I — UNAUDITED FINANCIAL INFORMATION

ITEM 1.	CONDENSED CONSOLIDATED FINANCIAL STATEMENTS	4

ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	2527

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	5660

ITEM 4.	CONTROLS AND PROCEDURES	5660

PART II — OTHER INFORMATION

ITEM 1.	LEGAL PROCEEDINGS	5761

ITEM 1A.	RISK FACTORS	5862

ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	5862

ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	5862

ITEM 5.	OTHER INFORMATION	5862

ITEM 6.	EXHIBITS	5963

SIGNATURES		6065


Risk-free interest rates			2.32%
Expected term (in years)			5.125
Dividend yield			0.80%
Expected volatility			46.29%
Forfeiture rate			5.69%


	Electricity			Product		Consolidated
	(Dollars in thousands)
Three Months Ended June 30, 2011:
Net revenues from external customers	$	81,190		$	23,424	$	104,614
Intersegment revenues		—			17,387		17,387
Operating income		9,827			9,547		19,374
Segment assets at period end *		2,017,476			93,337		2,110,813
* Including unconsolidated investments		2,287			1,781		4,068
Three Months Ended June 30, 2010:
Net revenues from external customers	$	68,807		$	27,459	$	96,266
Intersegment revenues		—			21,102		21,102
Operating income (loss)		(5,109	)		7,416		2,307
Segment assets at period end *		1,867,982			72,777		1,940,759
* Including unconsolidated investments		29,876			—		29,876

	Electricity			Product		Consolidated
	(Dollars in thousands)
Six Months Ended June 30, 2011:
Net revenues from external customers	$	159,458		$	42,976	$	202,434
Intersegment revenues		—			30,749		30,749
Operating income		13,831			8,662		22,493
Segment assets at period end *		2,017,476			93,337		2,110,813
* Including unconsolidated investments		2,287			1,781		4,068
Six Months Ended June 30, 2010:
Net revenues from external customers	$	134,912		$	44,008	$	178,920
Intersegment revenues		—			28,296		28,296
Operating income (loss)		(2,014	)		6,526		4,512
Segment assets at period end *		1,867,982			72,777		1,940,759
* Including unconsolidated investments		29,876			—		29,876


	Electricity		Product		Consolidated
	(Dollars in thousands)
Three Months Ended September 30, 2011:
Net revenues from external customers	$	86,815	$	24,026	$	110,841
Intersegment revenues		—		15,264		15,264
Operating income		21,087		3,121		24,208
Segment assets at period end *		2,121,932		88,789		2,210,721
* Including unconsolidated investments		2,287		1,710		3,997
Three Months Ended September 30, 2010:
Net revenues from external customers	$	83,357	$	18,120	$	101,477
Intersegment revenues		—		10,977		10,977
Operating income		13,461		1,357		14,818
Segment assets at period end *		1,895,469		69,240		1,964,709
* Including unconsolidated investments		2,040		—		2,040


	Three Months Ended June 30, 2010			Six Months Ended June 30, 2010
	(Dollars in thousands, except per share data)
Revenues	$	101,007		$	188,726
Loss from continuing operations		(2,013	)		(3,960	)

Net income (loss)	$	(1,443	)	$	390
Net loss attributable to noncontrolling interest		57			110

Net income (loss) attributable to the Company’s stockholders	$	(1,386	)	$	500

Earnings (loss) per share attributable to the Company’s stockholders — basic and diluted:
Loss from continuing operations	$	(0.05	)	$	(0.09	)
Income from discontinued operations		0.02			0.10

Net income (loss)	$	(0.03	)	$	0.01


	Three Months Ended September 30, 2010		Nine Months Ended September 30, 2010
	(Dollars in thousands, except per share data)
Revenues	$	103,155	$	291,881
Income from continuing operations		8,710		5,273

Net income	$	8,697	$	9,532
Net loss attributable to noncontrolling interest		58		168

Net income attributable to the Company’s stockholders	$	8,755	$	9,700

Earnings per share attributable to the Company’s stockholders — basic and diluted:
Income from continuing operations	$	0.19	$	0.12
Income from discontinued operations		—		0.10

Net income	$	0.19	$	0.22


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		Third 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 February 26, 2009.

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.

4.1		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.

4.2		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.

4.3		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.

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

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

4.6		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.

4.7		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.

4.8		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, filed herewith.

10.1		Note Purchase Agreement, dated September 23, 2011, among OFC 2 LLC, ORNI 15 LLC, ORNI 39 LLC, ORNI 42 LLC, and HSS II, LLC, as Issuers, OFC 2 Noteholder Trust, as Purchaser, John Hancock Life Insurance Company (U.S.A.), as Administrative Agent, and the United States Department of Energy (DOE), as Guarantor, filed herewith.


ORMAT TECHNOLOGIES, INC.

By:	/s/ JOSEPH TENNE
	Name:	Joseph Tenne
	Title:	Chief Financial Officer