Edgar Filing: ORMAT TECHNOLOGIES, INC.

Large accelerated filer ¨

Accelerated filer þ

Non-accelerated filer ¨

Smaller reporting company ¨

(Do not check if a smaller reporting company)

Form 10-Q

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

For the quarterly period ended September 30, 2012

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

For the transition period from to

Commission file number: 001-32347

ORMAT TECHNOLOGIES, INC.

(Exact name of registrant as specified in its charter)

DELAWARE

88-0326081

(State or other jurisdiction of

incorporation or organization)

(I.R.S. Employer

Identification Number)

6225 Neil Road, Reno, Nevada 89511-1136

(Address of principal executive offices, including zip code)

(775) 356-9029

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes 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

Indicate the number of shares outstanding shares of each of the registrant’s classes of common stock as of the latest practicable date: As of November 6, 2012, the number of outstanding shares of common stock, par value $0.001 per share was 45,430,886.

ORMAT TECHNOLOGIES, INC.

FORM 10-Q

FOR THE QUARTER ENDED SEPTEMBER 30, 2012



PART I — FINANCIAL INFORMATION
ITEM 1.	FINANCIAL STATEMENTS	4
ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	24
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	57
ITEM 4.	CONTROLS AND PROCEDURES	57

PART II — OTHER INFORMATION
ITEM 1.	LEGAL PROCEEDINGS	59
ITEM 1A.	RISK FACTORS	61
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	61
ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	61
ITEM 4.	MINE SAFETY DISCLOSURES	61
ITEM 5.	OTHER INFORMATION	61
ITEM 6.	EXHIBITS	62
SIGNATURES		64

Certain Definitions

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

PART I — FINANCIAL INFORMATION

ITEM 1.

FINANCIAL STATEMENTS

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)


	September 30, 2012		December 31, 2011
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	37,524	$	99,886
Marketable securities		—		18,521
Short-term bank deposit		3,008		—
Restricted cash, cash equivalents and marketable securities (all related to VIEs)		76,296		75,521
Receivables:
Trade		80,166		51,274
Related entity		351		287
Other		10,265		9,415
Due from parent		196		260
Inventories		17,786		12,541
Costs and estimated earnings in excess of billings on uncompleted contracts		7,704		3,966
Deferred income taxes		1,729		1,842
Prepaid expenses and other		31,497		18,672

Total current assets		266,522		292,185
Unconsolidated investments		3,476		3,757
Deposits and other		27,416		22,194
Deferred charges		38,636		40,236
Property, plant and equipment, net ($1,424,544 and $1,477,580 related to VIEs, respectively)		1,491,411		1,518,532
Construction-in-process ($248,754 and $271,859 related to VIEs, respectively)		367,762		370,551
Deferred financing and lease costs, net		26,821		28,482
Intangible assets, net		36,319		38,781

Total assets	$	2,258,363	$	2,314,718

LIABILITIES AND EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	96,516	$	105,112
Billings in excess of costs and estimated earnings on uncompleted contracts		32,546		33,104
Current portion of long-term debt:
Limited and non-recourse (all related to VIEs):
Senior secured notes		25,609		21,464
Other loans		13,744		13,547
Full recourse		20,755		20,543

Total current liabilities		189,170		193,770
Long-term debt, net of current portion:
Limited and non-recourse (all related to VIEs):
Senior secured notes		329,000		341,157
Other loans		93,015		100,585
Full recourse:
Senior unsecured bonds (plus unamortized premium based upon 7% of $1,514)		250,982		250,042
Other loans		49,869		63,623
Revolving credit lines with banks		187,474		214,049
Liability associated with sale of tax benefits		56,528		69,269
Deferred lease income		67,051		68,955
Deferred income taxes		58,758		54,665
Liability for unrecognized tax benefits		7,139		5,875
Liabilities for severance pay		20,818		20,547
Asset retirement obligation		22,548		21,284
Other long-term liabilities		2,857		4,253

Total liabilities		1,335,209		1,408,074

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 as of September 30, 2012 and December 31, 2011		46		46
Additional paid-in capital		730,583		725,746
Retained earnings		184,649		172,331
Accumulated other comprehensive income		697		595

		915,975		898,718
Noncontrolling interest		7,179		7,926

Total equity		923,154		906,644

Total liabilities and equity	$	2,258,363	$	2,314,718

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

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND

COMPREHENSIVE INCOME (LOSS)

(Unaudited)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
	(In thousands, except per share data)
Revenues:
Electricity	$	81,452		$	86,815		$	248,710		$	246,273
Product		54,685			24,026			149,616			67,002

Total revenues		136,137			110,841			398,326			313,275

Cost of revenues:
Electricity		61,466			57,941			177,350			186,090
Product		42,130			17,137			108,575			43,276

Total cost of revenues		103,596			75,078			285,925			229,366

Gross margin		32,541			35,763			112,401			83,909
Operating expenses:
Research and development expenses		1,436			2,346			3,948			7,128
Selling and marketing expenses		3,445			2,940			13,033			9,325
General and administrative expenses		6,208			6,269			20,315			20,755
Impairment charge		7,264			—			7,264			—
Write-off of unsuccessful exploration activities		—			—			1,919			—

Operating income		14,188			24,208			65,922			46,701
Other income (expense):
Interest income		280			438			1,004			1,289
Interest expense, net		(15,400	)		(23,909	)		(44,541	)		(54,431	)
Foreign currency translation and transaction gains (losses)		615			(2,659	)		(1,127	)		(1,546	)
Income attributable to sale of tax benefits		2,311			2,344			7,417			7,624
Other non-operating income, net		215			347			344			465

Income before income taxes and equity in losses of investees		2,209			769			29,019			102
Income tax benefit (provision)		(1,479	)		305			(11,245	)		726
Equity in losses of investees		(1,245	)		(71	)		(1,542	)		(552	)

Net income (loss)		(515	)		1,003			16,232			276
Net income attributable to noncontrolling interest		(67	)		(137	)		(278	)		(252	)

Net income (loss) attributable to the Company’s stockholders	$	(582	)	$	866		$	15,954		$	24

Comprehensive income (loss):
Net income (loss)	$	(515	)	$	1,003		$	16,232		$	276
Other comprehensive income (loss), net of related taxes:
Amortization of unrealized gains or losses in respect of derivative instruments designated for cash flow hedge		(47	)		(53	)		(140	)		(159	)
Change in unrealized gains or losses on marketable securities available-for-sale		262			(111	)		242			(320	)

Comprehensive income (loss)		(300	)		839			16,334			(203	)
Comprehensive income attributable to noncontrolling interest		(67	)		(137	)		(278	)		(252	)

Comprehensive income (loss) attributable to the Company’s stockholders	$	(367	)	$	702		$	16,056		$	(455	)

Earnings (loss) per share attributable to the Company’s stockholders — basic and diluted	$	(0.01	)	$	0.02		$	0.35		$	0.00

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

Diluted		45,431			45,440			45,438			45,442

Dividend per share declared	$	0.04		$	0.04		$	0.08		$	0.13

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

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY

(Unaudited)


	The Company’s Stockholders’ Equity
					Additional Paid-in Capital					Accumulated Other Comprehensive Income
	Common Stock						Retained Earnings									Noncontrolling Interest			Total Equity
	Shares		Amount				Retained Earnings						Total			Noncontrolling Interest			Total Equity
	(In thousands, except per share data)
Balance at December 31, 2010		45,431	$	46	$	716,731	$	221,311		$	1,044		$	939,132		$	6,095		$	945,227
Stock-based compensation		—		—		5,000		—			—			5,000			—			5,000
Increase in noncontrolling interest due to sale of equity interest in OPC LLC		—		—		2,343		—			—			2,343			1,662			4,005
Cash dividend declared, $0.13 per share		—		—		—		(5,924	)		—			(5,924	)		—			(5,924	)
Net income		—		—		—		24			—			24			252			276
Other comprehensive loss, net of related taxes:
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)		—		—		—		—			(320	)		(320	)		—			(320	)

Balance at September 30, 2011		45,431	$	46	$	724,074	$	215,411		$	565		$	940,096		$	8,009		$	948,105


Balance at December 31, 2011		45,431	$	46	$	725,746	$	172,331		$	595		$	898,718		$	7,926		$	906,644
Stock-based compensation		—		—		4,837		—			—			4,837			—			4,837
Cash paid to non-controlling interest		—		—		—		—			—			—			(1,025	)		(1,025	)
Cash dividend declared, $0.08 per share		—		—		—		(3,636	)		—			(3,636	)		—			(3,636	)
Net income		—		—		—		15,954			—			15,954			278			16,232
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 $88)		—		—		—		—			(140	)		(140	)		—			(140	)
Change in unrealized gains or losses on marketable securities available-for-sale (net of related tax of $0)		—		—		—		—			242			242			—			242

Balance at September 30, 2012		45,431	$	46	$	730,583	$	184,649		$	697		$	915,975		$	7,179		$	923,154

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

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Nine Months Ended September 30,
	2012			2011
	(In thousands)
Cash flows from operating activities:
Net income	$	16,232		$	276
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		75,812			71,261
Amortization of premium from senior unsecured bonds		(231	)		(72	)
Accretion of asset retirement obligation		1,264			1,183
Stock-based compensation		4,837			5,000
Amortization of deferred lease income		(2,014	)		(2,014	)
Income attributable to sale of tax benefits, net of interest expense		(2,775	)		(2,243	)
Equity in losses of investees		442			552
Impairment of auction rate securities		—			205
Write-off of unconsolidated investment		1,100			—
Write-off of unsuccessful exploration activities		1,919			—
Impairment charge		7,264			—
Unrealized loss on interest rate lock transactions		—			11,052
Loss on severance pay fund asset		332			282
Premium from issuance senior unsecured bonds		—			1,957
Deferred income tax provision (benefit)		5,894			(1,805	)
Liability for unrecognized tax benefits		1,264			(1,186	)
Deferred lease revenues		110			233
Changes in operating assets and liabilities, net of amounts acquired:
Receivables		(29,742	)		2,556
Costs and estimated earnings in excess of billings on uncompleted contracts		(3,738	)		2,628
Inventories		(5,245	)		(5,361	)
Prepaid expenses and other		(12,825	)		(8,043	)
Deposits and other		(5,356	)		(471	)
Accounts payable and accrued expenses		9,523			(9,592	)
Due from/to related entities, net		(64	)		(78	)
Billings in excess of costs and estimated earnings on uncompleted contracts		(558	)		32,511
Liabilities for severance pay		271			281
Other long-term liabilities		(1,396	)		(719	)
Due from/to parent		64			121

Net cash provided by operating activities		62,384			98,514

Cash flows from investing activities:
Marketable securities, net		18,763			(20,287	)
Short-term bank deposit		(3,008	)		—
Net change in restricted cash, cash equivalents and marketable securities		(775	)		(36,884	)
Capital expenditures		(186,332	)		(180,771	)
Cash grant received		119,199			—
Investment in unconsolidated companies		(1,260	)		(305	)
Increase (decrease) in severance pay fund asset, net of payments made to retired employees		(198	)		61

Net cash used in investing activities		(53,611	)		(238,186	)

Cash flows from financing activities:
Proceeds from issuance of senior unsecured bonds		1,171			107,447
Proceeds from the sale of limited liability company interest in OPC LLC, net of transaction costs		—			24,878
Proceeds from revolving credit lines with banks		2,134,887			419,156
Repayment of revolving credit lines with banks		(2,161,462	)		(387,300	)
Repayments of long-term debt		(28,927	)		(26,002	)
Cash paid to non-controlling interest		(10,991	)		(10,769	)
Deferred debt issuance costs		(2,177	)		(5,552	)
Cash dividends paid		(3,636	)		(5,924	)

Net cash provided by (used in) financing activities		(71,135	)		115,934

Net change in cash and cash equivalents		(62,362	)		(23,738	)
Cash and cash equivalents at beginning of period		99,886			82,815

Cash and cash equivalents at end of period	$	37,524		$	59,077

Supplemental non-cash investing and financing activities:
Increase (decrease) in accounts payable related to purchases of property, plant and equipment	$	(18,119	)	$	11,046

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

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

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1 — GENERAL AND BASIS OF PRESENTATION

These unaudited condensed consolidated interim financial statements of Ormat Technologies, Inc. and its subsidiaries (collectively, the “Company”) have been prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”) and pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”) for interim financial statements. Accordingly, they do not contain all information and notes required by U.S. GAAP for annual financial statements. In the opinion of management, these unaudited condensed consolidated interim financial statements reflect all adjustments, which include normal recurring adjustments, necessary for a fair statement of the Company’s consolidated financial position as of September 30, 2012, the consolidated results of operations and comprehensive income (loss) for the three and nine-month periods ended September 30, 2012 and 2011 and the consolidated cash flows for the nine-month periods ended September 30, 2012 and 2011.

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 nine-month periods ended September 30, 2012 are not necessarily indicative of the results to be expected for the year ending December 31, 2012.

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, 2011. The condensed consolidated balance sheet data as of December 31, 2011 was derived from the audited consolidated financial statements for the year ended December 31, 2011, 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.

Concentration of Credit Risk

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 September 30, 2012 and December 31, 2011, the Company had deposits totaling $9,554,000 and $39,569,000, respectively, in seven U.S. financial institutions that were federally insured up to $250,000 per account. At September 30, 2012 and December 31, 2011, the Company’s deposits in foreign countries amounted to approximately $36,557,000 and $57,838,000, respectively.

At September 30, 2012 and December 31, 2011, accounts receivable related to operations in foreign countries amounted to approximately $38,281,000 and $21,453,000, respectively. At September 30, 2012 and December 31, 2011, accounts receivable from the Company’s major customers that have generated 10% or more of its revenues amounted to approximately 47% and 58% of the Company’s accounts receivable, respectively.

Southern California Edison Company (“Southern California Edison”) accounted for 19.8% and 34.5% of the Company’s total revenues for the three months ended September 30, 2012 and 2011, respectively, and 18.8% and 30.5% for the nine months ended September 30, 2012 and 2011, respectively.

Sierra Pacific Power Company and Nevada Power Company (subsidiaries of NV Energy, Inc.) accounted for 14.1% and 10.5% of the Company’s total revenues for the three months ended September 30, 2012 and 2011, respectively, and 13.8% and 12.8% for the nine months ended September 30, 2012 and 2011, respectively.

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Hawaii Electric Light Company (“HELCO”) accounted for 8.1% and 10.3% of the Company’s total revenues for the three months ended September 30, 2012 and 2011, respectively, and 9.1% and 10.9% for the nine months ended September 30, 2012 and 2011, respectively.

Kenya Power and Lighting Co. Ltd. accounted for 8.6% and 8.0% of the Company’s total revenues for the three months ended September 30, 2012 and 2011, respectively, and 7.8% and 8.4% for the nine months ended September 30, 2012 and 2011, 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.

Letters of Credit

Some of the Company’s customers require the Company’s project subsidiaries to post letters of credit in order to guarantee their respective performance under relevant contracts. The Company is also required to post letters of credit to secure its 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, the Company is required from time to time to post performance letters of credit in favor of its customers with respect to orders of products. As of September 30, 2012, letters of credit in the aggregate amount of $248.2 million remained issued and outstanding.

NOTE 2 — NEW ACCOUNTING PRONOUNCEMENTS

New Accounting Pronouncements Effective in the Nine-Month Period Ended September 30, 2012

Fair Value Measurement

In May 2011, the Financial Accounting Standards Board (“FASB”) issued authoritative guidance regarding fair value measurements and disclosures. Required disclosures were expanded under the new guidance, particularly for fair value measurements that are categorized within Level 3 of the fair value hierarchy, for which quantitative information about the unobservable inputs, the valuation processes used by the entity, and the sensitivity of the measurement to the unobservable inputs are required. In addition, entities are required to disclose the categorization by level of the fair value hierarchy for items that are not measured at fair value in the balance sheet but for which the fair value is required to be disclosed. The adoption of this guidance by the Company on January 1, 2012 did not have a material impact on the Company’s consolidated financial statements. See Note 5 for these and other fair value related disclosures.

Presentation of Comprehensive Income in the Financial Statements

In June 2011, the FASB issued authoritative guidance intended to increase the prominence of items reported in other comprehensive income. The guidance eliminates the option to present components of other comprehensive income as part of the statement of changes in equity and requires that the total of comprehensive income, the components of net income, and the components of other comprehensive income be presented in a single continuous statement of comprehensive income or in two separate but consecutive statements. The guidance also required presentation of adjustments for items that are reclassified from other comprehensive income in the statement where the components of net income and the components of other comprehensive income are presented, which was indefinitely deferred by the FASB in December 2011. The guidance (other than the portion regarding the presentation of reclassification adjustments which, as noted above, has been deferred indefinitely) became effective on January 1, 2012. The adoption of this guidance by the Company on January 1, 2012 did not have a material impact on the Company’s consolidated financial statements.

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

New Accounting Pronouncement Effective in Future Periods

Disclosures about Offsetting Assets and Liabilities

In December 2011, the FASB issued authoritative guidance that revises the manner in which entities disclose the offsetting of assets and liabilities. The new guidance requires entities to disclose both gross information and net information about instruments and transactions eligible for offset in the balance sheet and those that are subject to an agreement similar to a master netting arrangement. The guidance will be applicable retrospectively effective for fiscal years, and interim periods within those years, beginning on or after January 1, 2013. The adoption of this amendment is not expected to have a material effect on the Company’s consolidated financial statements.

NOTE 3 — INVENTORIES

Inventories consist of the following:


	September 30, 2012		December 31, 2011
	(Dollars in thousands)
Raw materials and purchased parts for assembly	$	11,966	$	6,058
Self-manufactured assembly parts and finished products		5,820		6,483

Total	$	17,786	$	12,541

NOTE 4 — UNCONSOLIDATED INVESTMENTS

Unconsolidated investments consist of the following:


	September 30, 2012		December 31, 2011
	(Dollars in thousands)
Sarulla	$	2,496	$	2,215
Watts & More Ltd.		980		1,542

	$	3,476	$	3,757

The Sarulla Project

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 megawatts (“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. The project will be constructed in three phases over a period of 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 in the process of 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.

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Watts & More Ltd.

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. During June and July 2012, the Company granted W&M loans in a total principal amount of approximately $1.0 million. The loans bear interest of 9% and are repayable (principal and interest) by W&M at any time upon 14 days prior written notice. At any time prior to the repayment of the loans, the Company may convert the outstanding principal and interest (or any part thereof) to ordinary shares of W&M. In connection with the loans, in July 2012, W&M issued to the Company ordinary shares at par value, such that, as of September 30, 2012, the Company held approximately 36.1% of W&M’s outstanding ordinary shares.

The Company’s share in the results of operations of W&M was not significant for each of the periods presented in these condensed consolidated financial statements. See also below.

In the third quarter of 2012, the Company wrote off its investment in the ordinary shares of W&M, since the Company will not continue to invest in W&M. The amount of the remaining investment represents the loans granted by the Company to W&M, which are secured by the intellectual property of W&M.

NOTE 5 — FAIR VALUE MEASUREMENTS

The fair value measurement guidance clarifies that fair value is an exit price, representing the amount that would be received upon selling an asset or paid upon transferring a liability in an orderly transaction between market participants. As such, fair value is a market-based measurement that should be determined based on assumptions that market participants would use in pricing an asset or liability. The guidance establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of the fair value hierarchy under the fair value measurement guidance are described below:

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

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

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

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The following table sets forth certain fair value information at September 30, 2012 and December 31, 2011 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 September 30, 2012
			Fair Value at September 30, 2012
			Total			Level 1		Level 2			Level 3
	(Dollars in thousands)
Assets
Current assets:
Cash equivalents (including restricted cash accounts)	$	20,837	$	20,837		$	20,837	$	—		$	—
Derivatives⁽¹⁾		2,892		2,980			—		2,980			—
Liabilities:
Current liabilities:
Derivatives⁽²⁾		—		(77	)		—		(77	)		—

	$	23,729	$	23,740		$	20,837	$	2,903		$	—


	Cost or Amortized Cost at December 31, 2011
			Fair Value at December 31, 2011
			Total			Level 1		Level 2			Level 3
	(Dollars in thousands)
Assets
Current assets:
Cash equivalents (including restricted cash accounts)	$	61,649	$	61,649		$	61,649	$	—		$	—
Marketable securities (including restricted accounts)		18,284		18,521			18,521		—			—
Liabilities:
Current liabilities:
Derivatives⁽²⁾		—		(890	)		—		(890	)		—

	$	79,933	$	79,280		$	80,170	$	(890	)	$	—

⁽¹⁾

This amount relates to derivatives which represent European put options on natural gas and oil and swap contracts on crude oil, valued primarily based on observable inputs, including forward and spot prices for related commodity indices, and are included within “prepaid expenses and other” in the condensed consolidated balance sheet with the corresponding gain or loss being recognized within “electricity revenues” in the condensed consolidated statement of operations and comprehensive income (loss).

⁽²⁾

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

The Company’s financial assets measured at fair value (including restricted cash accounts) at September 30, 2012 and December 31, 2011 include investments in debt instruments (which are included in marketable

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

securities) and money market funds (which are included in cash equivalents). Those 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 were associated with failed auctions. Such securities had par values totaling $4.5 million, all of which had been in a loss position since the fourth quarter of 2007. The Company’s auction rate securities at December 31, 2010, 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 utilized 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 classified as Level 3 (i.e., illiquid auction rate securities) for the nine months ended September 30, 2011:


	(Dollars in thousands)
Balance at beginning of period	$	3,027
Total unrealized losses:
Included in net income		(205	)
Transferred to Level 2		(2,822	)

Balance at end of period	$	—

In April 2012, the Company entered into a NYMEX Heating Oil swap contract (85%) and an ICE Brent swap contract (15%) for notional volume of 241,250 BBL with a bank effective from May 1, 2012 until March 31, 2013 to reduce the Company’s exposure to fluctuations in the energy rate caused by fluctuations in oil prices under the 25 MW PPA for the Puna complex. The Company entered into these contracts because both swaps had a high correlation with the avoided costs (which are the incremental costs that the power purchaser avoids by not having to generate such electrical energy itself or purchase it from others) that HELCO uses to calculate the energy rate. The contracts did not have up-front costs. Under the terms of these contracts, the Company will make floating rate payments to the bank and receive fixed rate payments from the bank on each settlement date ($130.50 per BBL in respect of NYMEX Heating Oil and $115.50 per BBL in respect of ICE Brent). The swap contracts have monthly settlements whereby the difference between the fixed price and the monthly average market price will be settled on a cash basis.

In May 2012, the Company entered into a European put transaction with a bank effective from July 1, 2012 until December 31, 2012, pursuant to which the Company purchased a natural gas put option for 4.4 million MMbtus that settles against Natural Gas — California SoCal — NGI (“NGI”). The Company entered into this transaction in order to reduce its exposure to NGI below $3.08 per MMbtu under its PPAs with Southern California Edison. The Company paid an up-front premium of approximately $1.6 million that was recorded on May 24, 2012 as a current asset and is marked to market on each balance sheet date. Under this transaction, the

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Company will receive from the bank on each settlement date the difference between the strike price of $3.08 per MMbtu and the market price on the first commodity business day on which the relevant commodity reference price is published in the relevant calculation period (July 1, 2012 to December 1, 2012). If the strike price is lower than the market price, no payment will be made.

In July 2012, the Company entered into another European put transaction with the same bank for settlement effective from August 1, 2012 until December 31, 2012, pursuant to which the Company purchased a natural gas put option for 0.7 million MMbtus that settles against NGI. The Company entered into this transaction in order to reduce its exposure to NGI below $3.19 per MMbtu under its PPAs with Southern California Edison. The Company paid an up-front premium of approximately $0.2 million that was recorded on July 23, 2012 as a current asset and is marked to market on each balance sheet date. Under this transaction, the Company will receive from the bank on each settlement date the difference between the strike price of $3.19 per MMbtu and the market price on the first commodity business day on which the relevant commodity reference price is published in the relevant calculation period (August 1, 2012 to December 1, 2012). If the strike price is lower than the market price, no payment will be made.

On September 27, 2012, the Company entered into European put transactions with two banks effective from January 1, 2013 until December 31, 2013, pursuant to which the Company purchased NYMEX Heating Oil put options for notional volume of 191,250 BBL, and ICE Brent put options for notional volume of 33,750 BBL. The Company entered into these transactions to reduce its exposure to fluctuations in the energy rate caused by fluctuations in oil prices under the 25 MW PPA for the Puna complex. The Company entered into these transactions because both transactions had a high correlation with the avoided costs that HELCO uses to calculate the energy rate. The Company paid up-front premiums in the total amount of approximately $2.6 million that were recorded on September 27, 2012 as current assets and are marked to market on each balance sheet date. Under these transactions, the Company will receive from the banks on each settlement date the difference between the strike price of $126.63 per BBL in respect of NYMEX Heating Oil and $106.80 in respect of ICE Brent and the respective monthly average market price of the relevant commodity. If the strike price is lower than the monthly average market price, no payment will be made.

These transactions have not been designated as hedge transactions and are marked to market with the corresponding gains or losses recognized within “electricity revenues” in the condensed consolidated statements of operations and comprehensive income (loss). The Company recognized a loss from these transactions of $3.8 million and $0.0 million, respectively, in the three and nine months ended September 30, 2012.

On October 11, 2012, the Company entered into NGI swap contracts for notional volume of 8.9 million MMbtus with a bank effective from January 1, 2013 until December 31, 2013 (see Note 13 for discussion of these contracts).

There were no transfers of assets or liabilities between Level 1 and Level 2 during the nine months ended September 30, 2012.

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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


	Fair Value				Carrying Amount
	September 30, 2012		December 31, 2011		September 30, 2012		December 31, 2011
	(Dollars in millions)				(Dollars in millions)
Olkaria III loan	$	73.1	$	79.2	$	71.8	$	77.4
Amatitlan loan		39.9		37.2		34.9		36.8
Senior secured notes:
Ormat Funding Corp. (“OFC”)		113.7		114.8		119.7		125.0
OrCal Geothermal Inc. (“OrCal”)		80.5		84.4		83.7		85.9
OFC 2 LLC (“OFC 2”)		121.3		131.0		151.2		151.7
Senior unsecured bonds		250.7		252.8		249.5		248.3
Loans from institutional investors		28.9		34.2		29.0		34.2

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

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

The following table presents the fair value of financial instruments as of September 30, 2012:


	Level 1		Level 2		Level 3		Total
	(Dollars in millions)
Olkaria III loan	$	—	$	—	$	73.1	$	73.1
Amatitlan loan		—		—		39.9		39.9
Senior secured notes:
OFC		—		113.7		—		113.7
OrCal		—		—		80.5		80.5
OFC 2		—		—		121.3		121.3
Senior unsecured bonds		—		—		250.7		250.7
Loan from institutional investors		—		—		28.9		28.9
Other long-term debt		—		43.1		—		43.1
Revolving lines of credit		—		187.5		—		187.5
Deposits		20.3		—		—		20.3

Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis

During the third quarter of 2012, the OREG 4 power plant (“OREG 4”), which generates electricity using recovered heat and has a carrying value of $10.9 million, was tested for recoverability due to continued low output and written down to its fair value of $3.6 million. The fair value was determined from a cash flow model (a Level 3 measure) using internally developed cash flows including assumptions about generation capacity and operating expenses and a discount rate of 8%. The impairment loss of $7.3 million is presented in the Company’s condensed consolidated statement of operations and comprehensive income (loss) under “Impairment Charge”.

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

NOTE 6 — STOCK-BASED COMPENSATION

The 2004 Incentive Compensation Plan

On April 2, 2012, the Company granted its employees 602,000 stock appreciation rights (“SARs”) under the Company’s 2004 Incentive Compensation Plan. The exercise price of each such SAR is $20.13, 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 vest and become exercisable as follows: 25% vest 24 months after the grant date, an additional 25% vest 36 months after the grant date, and the remaining 50% vest 48 months after the grant date. 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 $7.98. 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:


Risk-free interest rates	1.05	%
Expected lives (in years)	5.125
Dividend yield	0.80	%
Expected volatility	47.50	%
Forfeiture rate	7.46	%

The 2012 Incentive Compensation Plan

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

On August 1, 2012, the Company granted to each of its four new non-employee directors options to purchase 7,500 shares of common stock under the Company’s 2012 Incentive Plan at an exercise price of $19.69 per share. Such options will expire seven years from the date of grant and will vest on the first anniversary of the date of grant.

The fair value of each option on the date of grant was $7.06. The Company calculated the fair value of each option on the date of grant using the Black-Scholes valuation model based on the following assumptions:


Risk-free interest rates	0.48	%
Expected lives (in years)	4.00
Dividend yield	0.80	%
Expected volatility	48.76	%
Forfeiture rate	0.00	%

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

On November 6, 2012, the Company granted to each of its six non-employee directors options to purchase 7,500 shares of common stock under the Company’s 2012 Incentive Plan (see Note 13).

NOTE 7 — INTEREST EXPENSE, NET

The components of interest expense, net, are as follows:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
	(Dollars in thousands)						(Dollars in thousands)
Interest related to sale of tax benefits	$	1,580		$	1,360		$	5,140		$	5,236
Loss on interest rate lock transactions*		—			11,645			—			16,380
Other interest expense		16,301			14,266			48,968			41,364
Less — amount capitalized		(2,481	)		(3,362	)		(9,567	)		(8,549	)

	$	15,400		$	23,909		$	44,541		$	54,431

*	The interest rate lock transactions are related to the OFC 2 Senior Secured Notes and were not accounted for using hedge accounting.

NOTE 8 — EARNINGS (LOSS) PER SHARE

Basic earnings (loss) per share attributable to the Company’s stockholders (“earnings (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 stock-based awards.

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
	(In thousands)				(In thousands)
Weighted average number of shares used in computation of basic earnings (loss) per share		45,431		45,431		45,431		45,431
Add:
Additional shares from the assumed exercise of stock-based awards		—		9		7		11

Weighted average number of shares used in computation of diluted earnings (loss) per share		45,431		45,440		45,438		45,442

In the three months ended September 30, 2012, the stock-based awards were anti-dilutive because of the Company’s net loss, and therefore they have been excluded from the diluted earnings (loss) per share calculation.

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The number of stock-based awards that could potentially dilute future earnings per share and that were not included in the computation of diluted earnings (loss) per share (because to do so would have been anti-dilutive) was 5,423,548 and 4,816,079 for the three months ended September 30, 2012 and 2011, respectively, and 5,663,796 and 4,116,282 for the nine months ended September 30, 2012 and 2011, respectively.

NOTE 9 — BUSINESS SEGMENTS

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 PPAs. The Product Segment is engaged in the manufacture, including design and development, of turbines and power units for the supply of electrical energy and in the associated construction of power plants utilizing the power units manufactured by the Company to supply energy from geothermal fields and other alternative energy sources. Transfer prices between the operating segments are determined based on current market values or cost plus markup of the seller’s business segment.

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


	Electricity		Product		Consolidated
	(Dollars in thousands)
Three Months Ended September 30, 2012:
Net revenues from external customers	$	81,452	$	54,685	$	136,137
Intersegment revenues		—		11,063		11,063
Operating income		6,804		7,384		14,188
Segment assets at period end *		2,150,533		107,830		2,258,363
* Including unconsolidated investments		2,496		980		3,476
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


Nine Months Ended September 30, 2012:
Net revenues from external customers	$	248,710	$	149,616	$	398,326
Intersegment revenues		—		32,970		32,970
Operating income		40,855		25,067		65,922
Segment assets at period end *		2,150,533		107,830		2,258,363
* Including unconsolidated investments		2,496		980		3,476
Nine Months Ended September 30, 2011:
Net revenues from external customers	$	246,273	$	67,002	$	313,275
Intersegment revenues		—		46,013		46,013
Operating income		34,917		11,784		46,701
Segment assets at period end *		2,121,932		88,789		2,210,721
* Including unconsolidated investments		2,287		1,710		3,997

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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


	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
	(Dollars in thousands)						(Dollars in thousands)
Operating income	$	14,188		$	24,208		$	65,922		$	46,701
Interest income		280			438			1,004			1,289
Interest expense, net		(15,400	)		(23,909	)		(44,541	)		(54,431	)
Foreign currency translation and transaction gains		615			(2,659	)		(1,127	)		(1,546	)
Income attributable to sale of equity interest		2,311			2,344			7,417			7,624
Other non-operating income (expense), net		215			347			344			465

Income (loss), before income taxes and equity in losses of investees	$	2,209		$	769		$	29,019		$	102

NOTE 10 — CONTINGENCIES

Securities Class Actions

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 asserted claims against the Company and certain directors and officers for alleged violations of Sections 10(b) and 20(a) of the Securities Exchange Act of 1934 (the “Exchange Act”). One complaint also asserted claims for alleged violations of Sections 11, 12(a)(2) and 15 of the Securities Act. All three complaints alleged claims on behalf of a putative class of purchasers of the Company’s 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 asserted claims under Sections 10(b) and 20(a) of the Exchange Act on behalf of a putative class of purchasers of the Company’s common stock between May 7, 2008 and February 24, 2010. The CAC alleged 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 alleged that certain of the Company’s statements concerning the North Brawley project were false and misleading. The CAC sought compensatory damages, expenses, and such further relief as the Court may deem proper.

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 2008 restatement. Defendants answered the remaining allegations in the CAC regarding the restatement on April 8, 2011, and the case 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 the Company’s common stock between February 25, 2009 and February 24, 2010, and defendants filed an opposition to the motion for class certification on October 4, 2011.

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Subsequently, the parties participated in mediation where they reached an agreement in principle to settle the securities class action lawsuits. The parties thereafter filed a stipulation of settlement with the U.S. District Court for the District of Nevada on March 27, 2012, providing that the claims against the Company and its directors and officers will be dismissed with prejudice and plaintiffs will release the defendants from all claims in exchange for a cash payment of $3.1 million to be funded by the Company’s insurers. The stipulation of settlement received preliminary approval by the Court on March 30, 2012, and final approval on October 16, 2012.

The Company and the individual defendants have steadfastly maintained that the claims raised in the securities class action lawsuits were without merit, and have vigorously contested those claims. As part of the settlement, the Company and the individual defendants continue to deny any liability or wrongdoing under the securities laws or otherwise.

Stockholder Derivative Cases

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 directors and officers 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 lawsuits.

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 transferred the federal derivative case to the 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 lawsuits.

The parties to all the stockholder derivative cases executed a stipulation of settlement to resolve all cases on September 25, 2012. The stipulation provides that: (i) all claims asserted in the derivative cases will be dismissed with prejudice and that plaintiffs will release the defendants from all claims; (ii) the Company will implement and/or maintain certain corporate governance measures for no less than five years; and (iii) plaintiffs’ counsel will receive attorneys’ fees of $700,000 to be funded by the Company’s insurers. The stipulation of settlement received preliminary approval on October 22, 2012. It still remains subject to final approval following notice to the Company’s stockholders.

The Company believes the allegations in these purported derivative actions are without merit and, as part of the settlement, continues to deny any liability or wrongdoing.

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Other

On January 4, 2012, the California Unions for Reliable Energy (“CURE”) filed a petition in the Alameda Superior Court, naming the California Energy Commission (“CEC”) and the Company as defendant and real party in interest, respectively. The petition asks the Court to order the CEC to vacate its decision which denied, with prejudice, the complaint filed by CURE against the Company with the CEC. The CURE complaint alleged that the Company’s North Brawley project and East Brawley project both exceed the CEC’s 50 MW jurisdictional threshold and therefore are subject to the CEC licensing authority rather than the Imperial County licensing authority. In addition, the CURE petition asks the Court to investigate and halt any ongoing violation of the Warren Alquist Act by the Company, and to award CURE attorney’s fees and costs. As to North Brawley, CURE alleges that the CEC decision violated the Warren Alquist Act because it failed to consider provisions of the County permit for North Brawley, which CURE contends authorizes the Company to build a generating facility with a number of Ormat Energy Converters (“OECs”) capable of generating more than 50 MW. As to East Brawley, CURE alleges that the CEC decision violated the Warren Alquist Act because it failed to consider the conditional use permit application for East Brawley, which CURE contends shows that the Company requested authorization to build a facility with a number of OECs capable of generating more than 50 MW.

The Company believes that the petition is without merit and intends to respond and take necessary legal action to dismiss the proceedings. The parties have filed briefs in the proceeding, and the matter is set for hearing. The filing of the petition in and of itself does not have any immediate adverse implications for the North Brawley or East Brawley projects and the Company continues to operate the North Brawley project in the ordinary course of business and is proceeding with its development work on the East Brawley project.

From time to time, the Company is named as a party in various other 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 be material to the Company’s consolidated financial statements as a whole.

NOTE 11 — CASH DIVIDENDS

On May 8, 2012, 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 21, 2012. Such dividend was paid on May 30, 2012.

On August 1, 2012, 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 14, 2012. Such dividend was paid on August 23, 2012.

NOTE 12 — INCOME TAXES

The Company’s effective tax rate for the three months ended September 30, 2012 and 2011 was 67.0% and 39.7%, respectively. The Company’s effective tax rate for the nine months ended September 30, 2012 and 2011 was 38.8% and 711.8%, respectively. The effective tax rate differs from the federal statutory rate of 35% primarily due to the increase in the valuation allowance against the Company’s U.S. deferred tax assets in respect of net operating loss (“NOL”) carryforwards and unutilized tax credits (see below), offset by: (i) lower tax rates in Israel; and (ii) a tax credit and tax exemption related to the Company’s subsidiaries in Guatemala.

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

At December 31, 2011, the Company had U.S. NOL carryforwards of approximately $349.5 million and state NOL carryforwards of approximately $159.0 million available to reduce future taxable income, which expire between 2021 and 2031 for federal NOLs and between 2015 and 2031 for state NOLs. Investment tax credits in the amount of $2.0 million at December 31, 2011 are available for a 20-year period and expire between 2022 and 2024. Production tax credits in the amount of $59.9 million at December 31, 2011 are available for a 20-year period and expire between 2026 and 2031.

Realization of the deferred tax assets is dependent on generating sufficient taxable income in appropriate jurisdictions prior to expiration of the NOL carryforwards and tax credits. The scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies were considered in determining the amount of valuation allowance. A valuation allowance in the amount of $61.5 million was recorded against the U.S. deferred tax assets as of December 31, 2011 because, at this point in time, it is more likely than not that the deferred tax assets will not be realized. Such valuation allowance was increased to $97.3 million as of September 30, 2012. If sufficient evidence of the Company’s ability to generate taxable income is established in the future, the Company may be required to reduce this valuation allowance, resulting in income tax benefits in its consolidated statement of operations and comprehensive income (loss).

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 was subject to reduced Israeli income tax rates, which will not exceed 25% for an additional five years until 2010. Ormat Systems was 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 was subject to reduced Israeli income tax rates, which will not exceed 25% for an additional five years until 2013 (see also below). 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 had the option either to irrevocably comply with the new law while waiving benefits provided under the previous law or to continue to comply with the previous law during a transition period with the option to move from the previous law to the new law 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 nine months ended September 30, 2011 by such amount.

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


	Nine Months Ended September 30,
	2012		2011
	(Dollars in thousands)
Balance at beginning of period	$	5,875	$	5,431
Additions based on tax positions taken in prior years		1,264		190
Decrease for settlements with taxing authorities		—		(1,376	)

Balance at end of period	$	7,139	$	4,245

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

NOTE 13 — SUBSEQUENT EVENTS

Swap Contracts on Natural Gas Prices

On October 11, 2012, the Company entered into NGI swap contracts for notional volume of approximately 8.9 million MMbtus with a bank for settlement effective from January 1, 2013 until December 31, 2013, in order to reduce its exposure to NGI below $4.00 per MMbtu under its PPAs with Southern California Edison. The contracts did not have up-front costs. Under the terms of these contracts, the Company will make floating rate payments to the bank and receive fixed rate payments from the bank on each settlement date. The swap contracts have monthly settlements whereby the difference between the fixed price of $4.00 per MMbtu and the market price on the first commodity business day on which the relevant commodity reference price is published in the relevant calculation period (January 1, 2013 to December 1, 2013) will be settled on a cash basis. These contracts will not be designated as hedge transactions and will be marked to market with the corresponding gains or losses recognized within “electricity revenues” in the condensed consolidated statements of operations and comprehensive income (loss).

Options Grant

On November 6, 2012, the Company granted to each of its six non-employee directors options to purchase 7,500 shares of common stock, under the Company’s 2012 Incentive Plan at an exercise price of $18.56 per share. Such options will expire seven years from the date of grant and will vest on the first anniversary of the date of grant.

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Cautionary Note Regarding Forward-Looking Statements

This quarterly report on Form 10-Q includes “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical facts, included in this quarterly report that address activities, events or developments that we expect or anticipate will or may occur in the future, including such matters as our projections of annual 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. Other than as required by law, 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:

•

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

•

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

•

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

•

financial market conditions and the results of financing efforts;

•

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

•

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

•

construction or other project delays or cancellations;

•

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

•

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

•

contract counterparty risk;

•

weather and other natural phenomena;

•

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

•

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

•

current and future litigation;

•

our ability to successfully identify, integrate and complete acquisitions;

•

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

•

the effect of and changes in economic conditions in the areas in which we operate;

•

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

•

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

•

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

•

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

•

the risk factors set forth in our Annual Report on Form 10-K for the year ended December 31, 2011 and any update contained herein and other risks and uncertainties detailed from time to time in our filings with the Securities and Exchange Commission (SEC); and

•

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

Investors are cautioned that these forward-looking statements are inherently uncertain. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results or outcomes may vary materially from those described herein. Given these risks and uncertainties, readers are cautioned not to place undue reliance on such forward-looking statements.

General

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. See also “Cautionary Note Regarding Forward-Looking Statements” above and Item 1A — “Risk Factors” below for a discussion of important factors that could cause actual results to differ materially from the results described herein or implied by such forward-looking statements.

Overview

We are a leading vertically integrated company engaged primarily 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:

•

The Electricity Segment — in this segment, we develop, build, own and operate geothermal and recovered energy-based power plants in the United States and geothermal power plants in other countries around the world, and sell the electricity they generate. We have expanded our activities in the Electricity Segment to include the ownership and operation of power plants that produce electricity generated by Solar PV systems that we do not manufacture; and

•

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

Both our Electricity Segment and Product Segment operations are conducted in the United States and 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) plants in the United States.

For the nine months ended September 30, 2012, our total revenues increased by 27.1% (from $313.3 million to $398.3 million) over the same period last year.

For the nine months ended September 30, 2012, total Electricity Segment revenues were $248.7 million, compared to $246.3 million for the nine months ended September 30, 2011, an increase of 1.0%, while Product Segment revenues were $149.6 million for the nine months ended September 30, 2012, compared to $67.0 million for the nine months ended September 30, 2011, an increase of 123.3%.

For the nine months ended September 30, 2012, our Electricity Segment revenues represented approximately 62.4% of our total revenues, while our Product Segment revenues represented approximately 37.6% of our total revenues. For the nine months ended September 30, 2011, our Electricity Segment revenues represented approximately 78.6% of our total revenues, while our Product Segment revenues represented approximately 21.4% of our total revenues. The increase in Product Segment revenues reflects the increase in new customer orders that we secured in 2011, particularly the $130.0 million order we received from Mighty River Power Limited for the Ngatamariki Geothermal Field in New Zealand, which project is underway in 2012 and is expected to be completed in 2013.

Revenues from our Electricity Segment are derived from sales of electricity generated by our power plants pursuant to long-term PPAs. We have variable price PPAs in California, Hawaii and Guatemala:

•

The energy rate under the PPAs in California for the Ormesa complex, the Mammoth complex, and the Heber 1 and Heber 2 power plants (the California SO#4 PPAs), changed in the beginning of May 2012, from a fixed to a variable rate that is subject to the impact of fluctuations in natural gas prices.

•

The prices paid for the electricity pursuant to the 25 megawatts (MW) PPA for the Puna complex in Hawaii are variable and 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. The prices, which are calculated on a monthly basis, are mainly impacted by the price of oil.

•

The energy price under the Amatitlan PPA in Guatemala is fixed, but we have the option to sell the power with advance notice to the spot market.

We have reduced our exposure to fluctuations in the price of natural gas and oil until December 31, 2013 by entering into derivative contracts, as described below under the heading “Recent Developments”.

In the nine months ended September 30, 2012, approximately 79.9% of our Electricity Segment revenues were derived from PPAs with fixed energy rates, which are not affected by the fluctuations in energy commodity prices. Electricity Segment revenues are also 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 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.

Recent Developments

The most significant recent developments in our company and business are described below.

•

Since the beginning of the year we entered into two new PPAs with Pacific Gas and Electric Company (PG&E) under the Renewable Auction Mechanism (RAM) program in California (discussed below under the heading “Trends and Uncertainties”) to replace existing SO#4 PPAs:

•

We signed a 20-year PPA that was approved by the California Public Utilities Commission (CPUC), for the sale of up to 14 MW of energy to be produced from the G3 power plant in the Mammoth complex in California. Subject to final agreement with the current offtaker, Southern California Edison Company (Southern California Edison), we expect to start selling the electricity under the new PPA at the very end of 2012.

•

We signed a 20-year PPA for the sale of up to 7.5 MW of energy to be produced from the G1 power plant in the Mammoth complex in California. The PPA is subject to the approval of the CPUC and to final agreement with Southern California Edison. We expect to start selling the electricity under the new PPA toward the end of 2013.

•

Since April 2012, we have entered into several derivatives transactions to reduce our exposure to fluctuations in the price of natural gas and oil under our PPAs with Southern California Edison and under the 25 MW PPA for the Puna complex. These transactions have not been designated as hedge transactions and are marked to market with the corresponding gains or losses recognized within electricity revenues.

•

In October 2012, we entered into Natural Gas — California SoCal — NGI (NGI) swap contracts for settlement effective from January 1, 2013 until December 31, 2013. The swap contracts have monthly settlements whereby the difference between the NGI and fixed price of $4.00 per MMbtu will be settled on a cash basis. Under the terms of these contracts, we will make floating rate payments to the bank and receive fixed rate payments from the bank on each settlement date. These swap contracts fix the energy rates under the SO#4 PPAs. The capacity payments under these PPAs remain fixed.

•

In September 2012, we entered into European put transactions with two banks for settlement effective from January 1, 2013 until December 31, 2013, pursuant to which we purchased NYMEX Heating Oil and ICE Brent put options. We entered into these transactions because both options had a high correlation with the avoided costs that Hawaii Electric Light Company (HELCO) uses to calculate the energy rate for the 25 MW PPA for the Puna complex. Under these transactions, we will receive on each settlement date the difference between the strike price and the respective monthly average market price of the relevant commodity. If the strike price is lower than the monthly average market price, no payment will be made. These transactions ensure a minimum on-peak energy rate and the capacity payments under these PPAs remain fixed.

•

In July 2012, we entered into a European put transaction with a bank for settlement effective from August 1, 2012 until December 31, 2012, pursuant to which we purchased a natural gas put option for 0.7 million MMbtus that settles against NGI. We entered into this transaction in order to reduce our exposure to NGI below $3.19 per MMbtu under our California SO#4 PPAs with Southern California Edison. We paid an up-front premium of approximately $0.2 million that was recorded as a current asset and is marked to market on each balance sheet date. Under this

transaction we will receive from the bank on each settlement date the difference between the strike price of $3.19 per MMbtu and the market price on the first commodity business day on which the relevant commodity reference price is published in the relevant calculation period (July 1, 2012 to December 1, 2012). If the strike price is lower than the market price, no payment will be made.

•

In May 2012, we entered into a European put transaction with a bank for settlement effective from July 1, 2012 until December 31, 2012, pursuant to which we purchased a natural gas put option for 4.4 million MMbtus that settles against NGI. We entered into this transaction in order to reduce our exposure to NGI below $3.08 per MMbtu under our California SO#4 PPAs with Southern California Edison. We paid an up-front premium of approximately $1.6 million that was recorded as a current asset and is marked to market on each balance sheet date. Under this transaction we will receive from the bank on each settlement date the difference between the strike price of $3.08 per MMbtu and the market price on the first commodity business day on which the relevant commodity reference price is published in the relevant calculation period (July 1, 2012 to December 1, 2012). If the strike price is lower than the market price, no payment will be made.

•

In April 2012, we entered into a NYMEX Heating Oil swap contract (85%) and an ICE Brent swap contract (15%) with a bank, each of which is effective from May 1, 2012 until March 31, 2013. We entered into these contracts because both swaps had a high correlation with the avoided costs that HELCO uses to calculate the energy rate for the 25 MW PPA for the Puna complex. Fuel prices in April 2012 were at historically high levels and we wanted to protect ourselves from a decrease in prices over the next twelve months. The contracts did not have up-front costs. Under the terms of these contracts, we will make floating rate payments to the bank and receive fixed rate payments from the bank on each settlement date. The swap contracts have monthly settlements whereby the difference between the fixed price and the monthly average price will be settled on a cash basis.

•

In the second and third quarters of 2012, we received approximately $119.2 million in cash grants from the U.S. Department of the Treasury (U.S. Treasury) under Section 1603 of the American Recovery and Reinvestment Act of 2009 (ARRA) for specified energy property in lieu of tax credits relating to the enhancement of our Puna geothermal complex, and to our Jersey Valley, Tuscarora and McGinness Hills geothermal power plants.

•

In September 2012, we entered into European put transactions with two banks for settlement effective from January 1, 2013 until December 31, 2013, pursuant to which we purchased NYMEX Heating Oil and ICE Brent put options to reduce the Company’s exposure to fluctuations in the energy rate caused by fluctuations in oil prices under the 25 MW PPA for the Puna complex. We entered into these transactions because both options had a high correlation with the avoided costs that HELCO uses to calculate the energy rate. Under these transactions, we will receive on each settlement date the difference between the strike price and the respective monthly average market price of the relevant commodity. If the strike price is lower than the monthly average market price, no payment will be made. These transactions ensure a minimum on-peak energy rate of approximately $182 per MWh. The capacity payment under these PPAs remains fixed. These transactions have not been designated as hedge transactions and are marked to market with the corresponding gains or losses recognized within electricity revenues.

•

In August 2012, our indirect wholly owned subsidiary, OrPower 4, Inc. (OrPower 4), and the Overseas Private Investment Corporation (OPIC), an agency of the United States Government, signed a finance agreement for limited-recourse project financing (Finance Agreement) totaling up to $310 million for the Olkaria III geothermal power complex located in Naivasha, Kenya. The OPIC loan is comprised of up to three tranches. The first two tranches totaled up to $265 million, with a final maturity of approximately 18 years. The loan will be used to pay costs of the existing facility and fund construction and well field drilling for the expansion of the Olkaria III geothermal power complex which could generate up to 84 MW. The Finance Agreement also includes a standby tranche of up to $45 million in

the event OrPower 4 elects to construct a further expansion of up to 16 MW. Disbursements of the OPIC loan are subject to fulfillment of customary conditions precedent for funding, which we expect will be satisfied before December 31, 2012.

•

In August 2012, NV Energy, Inc. (NV Energy) approved the commercial operation date of our 30 MW McGinness Hills power plant in Nevada and the full energy price under the PPA has been paid retroactive to July 1, 2012.

•

In July 2012, our wholly owned subsidiary, Ormat Nevada Inc. (Ormat Nevada), entered into a $61.4 million engineering, procurement and construction (EPC) contract with Enel Green Power North America (Enel). Under the terms of the EPC contract, we will provide two air-cooled Ormat Energy Converters at Enel’s Cove Fort geothermal power plant project in southern Utah. Previously, on April 25, 2012, we entered into an interim agreement in the amount of $9.1 million to ensure timely completion of the project.

•

In May 2012, NV Energy approved the commercial operation date of our 18 MW Tuscarora power plant in Nevada, and the full energy price under the PPA has been paid retroactive to January 1, 2012.

•

In May 2012, Bronicki Investments Ltd. (Bronicki Investments), the controlling shareholder of our parent company, Ormat Industries Ltd. (Ormat Industries), completed the sale of part of its interest in Ormat Industries to FIMI ENRG Limited Partnership, a newly formed Israeli partnership, and FIMI ENRG, L.P., a newly formed Delaware partnership, both controlled by FIMI Opportunity IV (collectively, FIMI), whereby Bronicki Investments sold to FIMI approximately 11.7% of the issued and outstanding shares of Ormat Industries. Following consummation of the transaction, each of Bronicki Investments and FIMI now holds 22.499% of the issued and outstanding shares of Ormat Industries, and the parties collectively own 44.999% of the issued and outstanding shares of Ormat Industries. In addition, effective May 22, 2012, Gillon Beck, a senior partner in FIMI, was appointed as the chairman of our Board of Directors; Ami Boehm, David Granot and Robert E. Joyal were appointed to our Board; and Lucien Y. Bronicki (our former Chairman), Roger W. Gale and David Wagener (former members of our Board) resigned from their respective positions on our Board of Directors.

•

In February 2012, Geothermal Development Company (GDC), a company owned by the Government of Kenya, awarded our subsidiary the first well head power plant project in the Menengai geothermal field in Kenya on a Build-Own-Transfer basis. The award was the result of an international tender for the design, manufacturing, procurement, construction and commissioning of a 6 MW geothermal well head power plant. GDC will supply the steam for conversion to electricity by our power plant. The Menengai geothermal field is located on the outskirts of the town of Nakuru, about 110 miles west of Nairobi.

•

In January 2012, the Public Utilities Commission of Nevada (PUCN) approved the 20-year PPA that we signed in February 2011 with NV Energy to sell 30 MW from the Dixie Meadows geothermal project that we are developing in Churchill County, Nevada.

Trends and Uncertainties

The geothermal industry in the United States has historically experienced significant growth followed by a consolidation of owners and operators of geothermal power plants. 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 been partly 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 tax credits (PTCs) or investment tax credits (ITCs) as well as cash grants (which are discussed in more detail in the section entitled “Government Grants and

Tax Benefits” below). In response, the geothermal industry in the United States has seen a wave of new entrants and, over the last several years, consolidation involving smaller developers. We 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.

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:

•

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 long-term PPAs related to fully-contracted power plants. We also intend to continue to pursue opportunities, as they arise, in our recovered energy business and in the Solar PV sector.

•

Our primary focus continues to be our organic growth through exploration, development, and construction of new projects and enhancements of existing power plants. We expect that this investment in organic growth will increase our total generating capacity, consolidated revenues and operating income attributable to our Electricity Segment from year to year. In addition, we routinely look at acquisition opportunities.

•

The continued awareness of climate change may result in significant changes in the business and regulatory environments, which may create business opportunities for us. In 2011, the first phase of the U.S. Environmental Protection Agency’s (EPA) “Tailoring Rule” took effect. The Tailoring Rule sets thresholds addressing the applicability of the permitting requirements under the Clean Air Act’s Prevention of Significant Deterioration and Title V programs to certain major sources of greenhouse gas (GHG) emissions. Federal legislation or additional federal regulations addressing climate change are possible. Several states and regions are already addressing climate change. For example, California’s state climate change law, AB 32, which was signed into law in September 2006, regulates most sources of GHG emissions and aims to reduce GHG emissions to 1990 levels by 2020. On October 20, 2011 the California Air Resources Board (CARB) adopted cap-and-trade regulations to reduce California’s greenhouse gas emissions under AB 32. In addition to California, twenty-two other states have set GHG emissions targets or goals. Regional initiatives, such as the Western Climate Initiative (which includes California and four Canadian provinces) and the Midwest GHG Reduction Accord (which includes six U.S. states and one Canadian province), are also being developed to reduce GHG emissions and develop trading systems for renewable energy credits. In addition, twenty-nine U.S. states and the District of Columbia have adopted Renewable Portfolio Standards (RPS) and eight other states have adopted renewable portfolio goals. On April 12, 2011, Governor Jerry Brown signed California Senate Bill X1-2 (SBX1-2) which increased California’s RPS to 33% by December 31, 2020 and instituted a tradable Renewable Energy Credit (REC) program. SBX1-2 is expected to foster a liquid tradable REC market and lead to more creative off-take arrangements. Although we cannot predict at this time whether the tradable REC program under SBX1-2 and its implementing regulations will have a significant impact on our operations or revenue, it may facilitate additional options when negotiating PPAs and selling electricity from our projects. The CPUC recently authorized the utilities to procure 1,299 MW through the RAM program, a procurement mechanism for renewable distributed generation projects greater than 3 MW and up to 20 MW, by holding four auctions over two years. We expect that the additional demand for renewable energy from utilities in California will outpace a possible reduction in general demand for energy (if any) due to the effect of economic conditions. We see this demand in California after 2016 driven by the impact of the increase in California’s RPS. This may create opportunities for us to replace the remainder of our existing SO#4 PPAs, expand existing power plants and develop new power plants.

•

Outside of the United States, we expect that a variety of government initiatives will create new opportunities for the development of new projects, as well as create additional markets for our products. These initiatives include the award of long-term contracts to independent power generators, the creation of competitive wholesale markets for selling and trading energy, capacity and related energy products, and the adoption of programs designed to encourage “clean” renewable and sustainable energy sources.

•

We expect competition from the wind and solar power generation industry to continue. While the expected demand for renewable energy is large enough to accommodate increased competition, the increase in competition and the amount of renewable energy under contract may contribute to a reduction in electricity prices. Despite increased competition from the wind and solar power generation industry, we believe that baseload electricity, such as geothermal-based energy, will continue to be a leading source of renewable energy in areas with commercially viable geothermal resources.

•

The business environment for obtaining new PPAs in California has become more difficult. Currently, the three investor-owned utilities in California appear to have sufficient renewable energy under contract to satisfy their RPS goals over the next few years.

•

In the Product Segment, we expect increased competition from binary power plant equipment suppliers. While we believe that we have a distinct competitive advantage based on our accumulated experience and current worldwide share of installed binary generation capacity, which is in excess of 90%, an increase in competition may impact our ability to secure new purchase orders from potential customers. The increased competition may also lead to a reduction in the prices that we are able to charge for our binary equipment, which in turn may impact our profitability.

•

North America is the largest and most developed natural gas market in the world. As recently as five years ago, the region was considered to be short on supply, with an expected need to import significant volumes of liquefied natural gas (LNG) from the international gas market to balance supply with expected demand. The rise of shale gas production over the last three years has completely changed the natural gas market landscape in North America. The unexpected growth in supply at increasingly lower costs has come at a time when the U.S. economy has been facing constrained demand growth for natural gas. Among other things, this has led to an increased interest in exporting natural gas from the U.S., in the form of LNG. Various natural gas companies and other project sponsors have recently applied, and in some cases, have already received an export license to export LNG to countries with which the U.S. has a free trade agreement providing comity in trading natural gas (FTA-nations) and to other non-FTA nations. At the same time, environmentalists, regulators, natural gas companies and the public have been focusing more attention on the potential environmental impacts associated with natural gas fracking, including possible chemical leakage, ground water contamination and other effects, which may slow development in some areas. The changing natural gas landscape, and the resulting effect on natural gas pricing (in either direction) and the corresponding implications for electric utilities and other producers of electricity in terms of planning for and choosing a source of fuel, all combine to affect the pricing under our PPAs that have short run avoided costs (SRAC) pricing or that are otherwise tied to natural gas prices. In addition, the current low natural gas price level is causing some producers to shut-in wells, which in turn may increase natural gas prices.

•

Our 25 MW PPA for the Puna complex has a monthly variable energy rate based on the local utility’s avoided costs, which is the incremental cost that the power purchaser avoids by not having to generate such electrical energy itself or purchase it from others. A decrease in the price of oil will result in a decrease in the incremental cost that the power purchaser avoids by not generating its electrical energy needs from oil, which will result in a reduction of the energy rate that we may charge under this PPA and under any other variable energy rate in PPAs that we may enter into in the future. As described above under the heading “Recent Developments”, we have entered into swap and put contracts to reduce our exposure to fluctuations in the energy rate caused by fluctuations in oil prices through December 31, 2013.

•

Our PPAs for the Ormesa complex, the Mammoth complex and the Heber 1 and 2 power plants were fixed until May 1, 2012. As of this date, the energy price component under these PPAs has changed from a fixed rate to a variable rate based on SRAC pricing, as required under a global settlement relating primarily to purchase and payment obligations of investor-owned utilities in California. These PPAs are impacted by fluctuations in natural gas prices. As described above under the heading “Recent Developments”, we have entered into put and swap transactions to reduce our exposure to fluctuations in natural gas prices through December 31, 2013. Our use of derivative instruments for this purpose has increased, and likely will continue to increase, volatility in revenues and certain other line items in our financial statements due to applicable accounting standards.

•

We are experiencing a notable decrease in competition in the U.S. geothermal industry, specifically in the acquisition of geothermal leases. The reduced level of competition has contributed to a decrease in lease costs.

•

In the United States, we have noticed increased activity from union organizers to encourage employees to join unions that will act as bargaining representatives. We currently do not have employees represented by unions under collective bargaining agreements. However, a union has recently filed a petition with the National Labor Relations Board (NLRB) in an attempt to organize our employees in our Puna complex in Hawaii. The matter is being processed and adjudicated under NLRB procedures.

•

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

•

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

•

Our foreign operations are subject to significant political, economic and financial risks, which vary by country. As of today, those risks include the partial privatization of the electricity sector in Guatemala, labor unrest in Nicaragua and the political uncertainty currently prevailing in some of the countries in which we operate. Although we maintain political risk insurance for most of our foreign power plants to mitigate these risks, insurance does not provide complete coverage with respect to all such risks.

•

The Energy Policy Act of 2005 authorizes the Federal Energy Regulatory Commission (FERC) to revise the Public Utility Regulatory Policies Act (PURPA) so as to terminate the obligation of electric utilities to purchase the output of a Qualifying Facility if FERC finds that there is an accessible competitive market 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 PPAs are long-term. FERC recently granted the California investor-owned utilities a waiver of the mandatory purchase obligations from Qualifying Facilities above 20 MW. If the utilities in the regions in which our domestic power plants operate were to be relieved of the mandatory purchase obligation, they would not be required to purchase energy from us upon termination of the existing PPA, which could have an adverse effect on our revenues.

Revenues

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

Revenues attributable to our Electricity Segment are derived from the sale of electricity from our power plants pursuant to long-term PPAs. We have variable price PPAs in California, Hawaii and Guatemala. Our

California SO#4 PPAs are subject to the impact of fluctuations in natural gas prices. The prices paid for electricity pursuant to the 25 MW PPA for the Puna complex in Hawaii are impacted by the price of oil. The energy price under the Amatitlan PPA in Guatemala is fixed, but we have the option to sell the power with an advance notice to the spot market. Accordingly, our revenues from those power plants may fluctuate. As discussed above in the section entitled “Recent Developments,” in the second, third and fourth quarters of 2012, we entered into swap contracts and put transactions to reduce our exposure to fluctuations in the prices of natural gas and oil, under the California SO#4 PPAs and under the 25 MW PPA for the Puna complex, until December 31, 2013.

Our Electricity Segment revenues are also subject to seasonal variations, as more fully described in the section entitled “Seasonality” below, and may also be affected by higher-than-average ambient temperature, 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 capacity levels and the potential forfeiture of payments if we fail to meet certain minimum target capacity levels. Energy payments, on the other hand, are payments calculated based on the amount of electrical energy delivered to the relevant power purchaser at a designated delivery point. The rates applicable to such payments are either fixed (subject, in certain cases, to certain adjustments) or are based on the relevant power purchaser’s avoided cost, its alternative cost of obtaining energy. Our more recent PPAs generally provide for energy payments alone with an obligation to compensate the off-taker for its incremental costs as a result of shortfalls in our supply.

Revenues attributable to our Product Segment fluctuate between periods, mainly based on our ability to win customer orders and the status and timing of such orders. Larger customer orders for our products are typically the result of our participating in, and winning, tenders or requests for proposals issued by potential customers in connection with projects they are developing. Such projects often take a significant amount of time to design and develop and are 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 existing 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. In 2011, we experienced a significant increase in our Product Segment customer orders, which has increased our Product Segment backlog. We expect that our Product Segment revenues will remain robust until the end of 2013 as a result of these 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
	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended September 30,						Nine Months Ended September 30,
	2012		2011		2012		2011		2012			2011			2012			2011
Revenues:
Electricity	$	81,452	$	86,815	$	248,710	$	246,273		59.8	%		78.3	%		62.4	%		78.6	%
Product		54,685		24,026		149,616		67,002		40.2			21.7			37.6			21.4

Total	$	136,137	$	110,841	$	398,326	$	313,275		100.0	%		100.0	%		100.0	%		100.0	%

Geographical Breakdown of Revenues

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
	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended September 30,						Nine Months Ended September 30,
	2012		2011		2012		2011		2012			2011			2012			2011
Electricity Segment:
United States	$	59,179	$	66,951	$	185,910	$	188,400		72.7	%		77.1	%		74.7	%		76.5	%
Foreign		22,273		19,864		62,800		57,873		27.3			22.9			25.3			23.5

Total	$	81,452	$	86,815	$	248,710	$	246,273		100.0	%		100.0	%		100.0	%		100.0	%

Product Segment:
United States	$	11,417	$	—	$	11,417	$	—		20.9	%		0.0	%		7.6	%		0.0	%
Foreign		43,268		24,026		138,199		67,002		79.1			100.0			92.4			100.0

Total	$	54,685	$	24,026	$	149,616	$	67,002		100.0	%		100.0	%		100.0	%		100.0	%

Seasonality

The prices paid for the electricity generated by some of our domestic power plants pursuant to our PPAs are subject to seasonal variations. The prices paid for electricity under the PPAs with Southern California Edison in California 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 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.

Breakdown of Cost of Revenues

Electricity Segment

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 power plants from quarter to quarter. Payments made to government agencies and private entities on account of site leases where plants are located are included in cost of revenues. Royalty payments, included in cost of revenues, are made as compensation for the right to use certain geothermal resources and are paid as a percentage of the revenues derived from the associated geothermal rights. Royalties constituted approximately 4.3% and 3.5%, respectively, of total Electricity Segment revenues for the nine months ended September 30, 2012 and 2011, respectively.

Product Segment

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

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

Our cash, cash equivalents, marketable securities, and short-term bank deposits as of September 30, 2012 decreased to $40.5 million from $118.4 million as of December 31, 2011. This decrease was principally due to: (i) our use of $186.3 million to fund capital expenditures; (ii) repayment of $28.9 million of long-term debt; (iii) $11.0 million of cash paid to the Class B membership units of OPC LLC (OPC) (see “OPC Transaction” below); and (iv) net repayment of $26.6 million to borrowers under our revolving credit lines with commercial banks. The decrease in our cash resources was partially offset by: (i) $62.4 million derived from operating activities during the nine months ended September 30, 2012; and (ii) cash grants in the total amount of $119.2 million received from the U.S. Treasury under Section 1603 of the ARRA in the second and third quarters of 2012 relating to the enhancement of our Puna geothermal complex and to our Jersey Valley, Tuscarora and McGinness Hills geothermal power plants. Our corporate borrowing capacity under committed lines of credit with different commercial banks as of September 30, 2012 was $487.2 million, as described below in the section entitled “Liquidity and Capital Resources,” of which we utilized $401.8 million (including $214.3 million of letters of credit) as of September 30, 2012.

Critical Accounting Estimates and Assumptions

A comprehensive discussion of our critical accounting estimates and assumptions is included in the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section in our annual report on Form 10-K for the year ended December 31, 2011.

New Accounting Pronouncements

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

Results of Operations

Our historical operating results in dollars and as a percentage of total revenues are presented below. A comparison of the different periods described below may be of limited utility mainly because of the following: (i) our recent construction of new power plants and enhancement of existing power plants; and (ii) fluctuation in revenues from our Product Segment.


	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
	(In thousands, except per share data)						(In thousands, except per share data)
Statements of Operations Historical Data:
Revenues:
Electricity	$	81,452		$	86,815		$	248,710		$	246,273
Product		54,685			24,026			149,616			67,002

		136,137			110,841			398,326			313,275

Cost of revenues:
Electricity		61,466			57,941			177,350			186,090
Product		42,130			17,137			108,575			43,276

		103,596			75,078			285,925			229,366

Gross margin:
Electricity		19,986			28,874			71,360			60,183
Product		12,555			6,889			41,041			23,726

		32,541			35,763			112,401			83,909
Operating expenses:
Research and development expenses		1,436			2,346			3,948			7,128
Selling and marketing expenses		3,445			2,940			13,033			9,325
General and administrative expenses		6,208			6,269			20,315			20,755
Impairment charge		7,264			—			7,264			—
Write-off of unsuccessful exploration activities		—			—			1,919			—

Operating income		14,188			24,208			65,922			46,701
Other income (expense):
Interest income		280			438			1,004			1,289
Interest expense, net		(15,400	)		(23,909	)		(44,541	)		(54,431	)
Foreign currency translation and transaction gains (losses)		615			(2,659	)		(1,127	)		(1,546	)
Income attributable to sale of tax benefits		2,311			2,344			7,417			7,624
Other non-operating income, net		215			347			344			465

Income before income taxes and equity in losses of investees		2,209			769			29,019			102
Income tax benefit (provision)		(1,479	)		305			(11,245	)		726
Equity in losses of investees		(1,245	)		(71	)		(1,542	)		(552	)

Net income (loss)		(515	)		1,003			16,232			276
Net income attributable to noncontrolling interest		(67	)		(137	)		(278	)		(252	)

Net income (loss) attributable to the Company’s stockholders	$	(582	)	$	866		$	15,954		$	24

Earnings (loss) per share attributable to the Company’s stockholders — basic and diluted	$	(0.01	)	$	0.02		$	0.35		$	0.00

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

Diluted		45,431			45,440			45,438			45,442


	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Statements of Operations Percentage Data:
Revenues:
Electricity		59.8	%		78.3	%		62.4	%		78.6	%
Product		40.2			21.7			37.6			21.4

		100.0			100.0			100.0			100.0

Cost of revenues:
Electricity		75.5			66.7			71.3			75.6
Product		77.0			71.3			72.6			64.6

		76.1			67.7			71.8			73.2

Gross margin:
Electricity		24.5			33.3			28.7			24.4
Product		23.0			28.7			27.4			35.4

		23.9			32.3			28.2			26.8
Operating expenses:
Research and development expenses		1.1			2.1			1.0			2.3
Selling and marketing expenses		2.5			2.7			3.3			3.0
General and administrative expenses		4.6			5.7			5.1			6.6
Impairment charge		5.3			0.0			1.8			0.0
Write-off of unsuccessful exploration activities		0.0			0.0			0.5			0.0

Operating income		10.4			21.8			16.5			14.9
Other income (expense):
Interest income		0.2			0.4			0.3			0.4
Interest expense, net		(11.3	)		(21.6	)		(11.2	)		(17.4	)
Foreign currency translation and transaction gains (losses)		0.5			(2.4	)		(0.3	)		(0.5	)
Income attributable to sale of tax benefits		1.7			2.1			1.9			2.4
Other non-operating income, net		0.2			0.3			0.1			0.1

Income before income taxes and equity in losses of investees		1.6			0.7			7.3			0.0
Income tax benefit (provision)		(1.1	)		0.3			(2.8	)		0.2
Equity in losses of investees		(0.9	)		(0.1	)		(0.4	)		(0.2	)

Net income (loss)		(0.4	)		0.9			4.1			0.1
Net income attributable to noncontrolling interest		(0.0	)		(0.1	)		(0.1	)		(0.1	)

Net income (loss) attributable to the Company’s stockholders		(0.4	)%		0.8	%		4.0	%		0.0	%

Comparison of the Three Months Ended September 30, 2012 and the Three Months Ended September 30, 2011

Total Revenues

Total revenues for the three months ended September 30, 2012 were $136.1 million, compared to $110.8 million for the three months ended September 30, 2011, which represented a 22.8% increase in total revenues. This increase was principally attributable to our Product Segment, in which revenues increased by 127.6% over the same period last year, principally because of the Mighty River Power Limited order for the Ngatamariki Geothermal Field in New Zealand project and the Enel order for the Cove Fort project referred to below. The increase was partially offset by a 6.2% decrease in our Electricity Segment revenues from the same period last year.

Electricity Segment

Revenues attributable to our Electricity Segment for the three months ended September 30, 2012 were $81.5 million, compared to $86.8 million for the three months ended September 30, 2011, which represented a 6.2% decrease. This decrease was primarily due to: (i) a $9.3 million decrease resulting from the impact of the low natural gas prices on the energy rates under our SO#4 PPAs in California, which in the beginning of May 2012 changed from a fixed rate to a variable rate that is impacted by natural gas prices; and (ii) a net loss of $3.8 million on swap contracts and put transactions on oil prices and put transactions on natural gas prices, which are described above under the heading “Recent Developments”. In the second quarter of 2012 we recorded a net gain in the amount of $3.8 million from these transactions. These transactions are not designated as hedge transactions for accounting purposes. This decrease was partially offset by $7.8 million in revenues from our Tuscarora and McGinness Hills power plants, which commenced commercial operations in January 2012 and July 2012, respectively. The generation in our power plants increased by 11.7%, from 887,069 MWh in the three months ended September 30, 2011, to 990,674 MWh in the three months ended September 30, 2012, and the average revenue rate of our electricity portfolio decreased from $98 per MWh in the three months ended September 30, 2011, to $82 per MWh in the three months ended September 30, 2012. We revised the calculation of the MWh for our Zunil power plant to reflect the change in the energy payment, which since September 2011 has been based on the actual generation of the power plant. The revenues from our North Brawley power plant both in the third quarter of 2012 and in the third quarter of 2011 were $4.0 million.

Product Segment

Revenues attributable to our Product Segment for the three months ended September 30, 2012 were $54.7 million, compared to $24.0 million for the three months ended September 30, 2011, which represented a 127.6% increase. The increase in our Product Segment revenues reflects the increase in new customer orders that we secured in 2011 and 2012, largely attributable to the $130.0 million order we received from Mighty River Power Limited for the Ngatamariki Geothermal Field in New Zealand project and to the $61.4 million order received from Enel for the Cove Fort project in Utah, as described above under the heading “Recent Developments”, both of which are expected to be completed in 2013.

Total Cost of Revenues

Total cost of revenues for the three months ended September 30, 2012 was $103.6 million, compared to $75.1 million for the three months ended September 30, 2011, which represented an increase of 38.0%. This was primarily due to the significant increase in revenues attributable to our Product Segment. As a percentage of total revenues, our total cost of revenues for the three months ended September 30, 2012 was 76.1%, compared to 67.7% for the same period in 2011. The increase in cost of revenues as a percentage of total revenues was attributable to both our Electricity and Product Segments, as described below.

Electricity Segment

Total cost of revenues attributable to our Electricity Segment for the three months ended September 30, 2012 was $61.5 million, compared to $57.9 million for the three months ended September 30, 2011, which represented a 6.1% increase. This increase was primarily due to: (i) additional cost of revenues from our Tuscarora and McGinness Hills power plants which commenced commercial operations in January 2012 and July 2012, respectively; and (ii) an increase of $1.1 million in operation and maintenance costs associated with our North Brawley power plant (from $7.5 million in the third quarter of 2011 to $8.6 million in the third quarter of 2012). As a percentage of total electricity revenues, the total cost of revenues attributable to our Electricity Segment for the three months ended September 30, 2012 was 75.5%, compared to 66.7% for the three months ended September 30, 2011. This increase in Electricity Segment cost of revenues as a percentage of total electricity revenues is mainly attributable to the decrease in the average rate of our electricity revenues as discussed above, and the increase in the volume of electricity produced.

Product Segment

Total cost of revenues attributable to our Product Segment for the three months ended September 30, 2012 was $42.1 million, compared to $17.1 million for the three months ended September 30, 2011, which represented a 145.8% increase. This increase is attributable to a significant increase in revenues in this segment. As a percentage of total Product Segment revenues, our total cost of revenues attributable to this segment for the three months ended September 30, 2012 was 77.0%, compared to 71.3% for the three months ended September 30, 2011. This increase in Product Segment cost of revenues as a percentage of total product revenues is mainly attributable to a different product mix and different margins in the various sales contracts.

Research and Development Expenses

Research and development expenses for the three months ended September 30, 2012 were $1.4 million, compared to $2.3 million for the three months ended September 30, 2011, which represented a 38.8% decrease. This decrease reflects normal fluctuations in our research and development activities. Our research and development activities during the three months ended September 30, 2012 included: (i) continued development of Enhanced Geothermal Systems (EGS); and (ii) activities intended to improve plant performance, reduce costs, and increase the breadth of product offerings. These activities include developing: (i) improvements to our Evaporative Cooling system; (ii) condensing equipment with improved performance and lower land usage; (iii) new turbine products; and (iv) specialized power units designed to reduce fuel consumption and associated costs during a project’s development phase.

Selling and Marketing Expenses

Selling and marketing expenses for the three months ended September 30, 2012 were $3.4 million, compared to $2.9 million for the three months ended September 30, 2011, which represented a 17.2% increase. The increase reflects additional selling and marketing expenses associated with the increased Product Segment revenues. Selling and marketing expenses for the three months ended September 30, 2012 constituted 2.5% of total revenues, compared to 2.7% for the three months ended September 30, 2011.

General and Administrative Expenses

General and administrative expenses for the three months ended September 30, 2012 were $6.2 million, compared to $6.3 million for the three months ended September 30, 2011, which represented a 1.0% decrease. General and administrative expenses for the three months ended September 30, 2012 constituted 4.6% of total revenues, compared to 5.7% for the three months ended September 30, 2011.

Impairment Charge

During the third quarter of 2012, OREG 4, which generates electricity using recovered heat and has a carrying value of $10.9 million, was tested for recoverability due to continued low output and was written down to its fair value of $3.6 million. The impairment loss of $7.3 million is presented in our condensed consolidated statement of operations and comprehensive income (loss) under “Impairment Charge”.

We evaluate long-lived assets, including power plants, for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Such evaluations include estimates of future cash flows. If actual cash flows differ significantly from our current estimates, a material impairment charge may be required in the future.

Operating Income

Operating income for the three months ended September 30, 2012 was $14.2 million, compared to $24.2 million for the three months ended September 30, 2011. The decrease of $10.0 million in operating income was principally attributable to: (i) impairment loss in the amount of $7.3 million as described above; and (ii) a decrease in our electricity gross margin. Operating income attributable to our Electricity Segment for the three months ended September 30, 2012 was $6.8 million, compared to $21.1 million for the three months ended

September 30, 2011. Operating income attributable to our Product Segment for the three months ended September 30, 2012 was $7.4 million, compared to $3.1 million for the three months ended September 30, 2011. The increase in operating income attributable to our Product Segment was primarily due to an increase in our product revenues, as described above.

Interest Expense, Net

Interest expense, net for the three months ended September 30, 2012 was $15.4 million, compared to $23.9 million for the three months ended September 30, 2011, which represented a 35.6% decrease. The decrease was primarily attributable to an $11.6 million loss in the three months ended September 30, 2011 on interest lock transactions relating to the OFC 2 Senior Secured Notes, which were not accounted for as hedge transactions. The decrease was partially offset by additional interest expense, mainly as a result of the issuance of Series A Senior Secured Notes in October 2011 by OFC 2 LLC (OFC 2).

Foreign Currency Translation and Transaction Gains (Losses)

Foreign currency translation and transaction gains for the three months ended September 30, 2012 were $0.6 million, compared to losses of $2.7 million for the three months ended September 30, 2011. The $3.3 million increase is primarily due to gains on forward foreign exchange transactions for the three months ended September 30, 2012, which were not accounted for as hedge transactions, compared to losses in the three months ended September 30, 2011.

Income Attributable to Sale of Tax Benefits

Income attributable to the sale of tax benefits to institutional equity investors (as described under the heading “OPC Transaction” below) for the three months ended September 30, 2012 and 2011 was $2.3 million. This income represents the value of PTCs and taxable income or loss generated by OPC and allocated to the investors.

Income Taxes

Income tax provision for the three months ended September 30, 2012 was $1.5 million, compared to income tax benefit of $0.3 million for the three months ended September 30, 2011. The increase in income tax provision primarily resulted from the increase in income before taxes and from the increase in the valuation allowance against our U.S. deferred tax assets in respect of net operating loss (NOL) carryforwards and unutilized tax credits. The effective tax rate for the three months ended September 30, 2012 was 67.0%, compared to 39.7% for the three months ended September 30, 2011. The increase in the effective tax rate primarily resulted from the increase in the valuation allowance referred to above.

Net Income (Loss)

Net loss for the three months ended September 30, 2012 was $0.5 million, compared to net income of $1.0 million for the three months ended September 30, 2011. The decrease in net income of $1.5 million was principally attributable to: (i) a $10.0 million decrease in operating income; (ii) a $1.8 million increase in income tax provision. The decrease was partially offset by: (i) a $3.3 million decrease in foreign currency transaction losses and (ii) an $8.5 million decrease in interest expense, net of capitalized interest.

Comparison of the Nine Months Ended September 30, 2012 and the Nine Months Ended September 30, 2011

Total Revenues

Total revenues for the nine months ended September 30, 2012 were $398.3 million, compared to $313.3 million for the nine months ended September 30, 2011, which represented a 27.1% increase in total revenues. This increase was principally attributable to our Product Segment, in which revenues increased by 123.3% over the same period last year, principally because of the Mighty River Power Limited order for the Ngatamariki Geothermal Field in New Zealand project referred to below.

Electricity Segment

Revenues attributable to our Electricity Segment for the nine months ended September 30, 2012 were $248.7 million, compared to $246.3 million for the nine months ended September 30, 2011, which represented a 1.0% increase. This increase was primarily due to: (i) $14.1 million in revenues from our Tuscarora and McGinness Hills power plants, which commenced commercial operations in January 2012 and July 2012, respectively; and (ii) an $5.2 million net increase in revenues from our other power plants. This increase was partially offset by a $16.9 million decrease resulting from the impact of low natural gas prices on the energy rates in our SO#4 PPAs in California, which in the beginning of May 2012 changed from a fixed rate to a variable rate that is subject to the impact of fluctuations in natural gas prices. The generation in our power plants increased by 5.3%, from 2,871,819 MWh in the nine months ended September 30, 2011, to 3,024,738 MWh in the nine months ended September 30, 2012, and the average revenue rate of our electricity portfolio decreased from $86 per MWh in the nine months ended September 30, 2011, to $82 per MWh in the nine months ended September 30, 2012. We revised the calculation of the MWh for our Zunil power plant to reflect the change in the energy payment, which is based, since September 2011, on the actual generation of the power plant. The revenues from our North Brawley power plant in the nine months ended September 30, 2012 decreased to $11.8 million from $12.7 million during the same period in 2011.

Product Segment

Revenues attributable to our Product Segment for the nine months ended September 30, 2012 were $149.6 million, compared to $67.0 million for the nine months ended September 30, 2011, which represented a 123.3% increase. The increase in our Product Segment revenues reflects the increase in new customer orders that we secured in 2011, largely attributable to the $130.0 million order we received from Mighty River Power Limited for the Ngatamariki Geothermal Field in New Zealand, which project is underway in 2012 and is expected to be completed in 2013.

Total Cost of Revenues

Total cost of revenues for the nine months ended September 30, 2012 was $285.9 million, compared to $229.4 million for the nine months ended September 30, 2011, which represented an increase of 24.7%. This was primarily due to the significant increase in revenues attributable to our Product Segment. As a percentage of total revenues, our total cost of revenues for the nine months ended September 30, 2012 was 71.8%, compared to 73.2% for the same period in 2011. The decrease in cost of revenues as a percentage of total revenues was attributable to the decrease in total cost of revenues in our Electricity Segment.

Electricity Segment

Total cost of revenues attributable to our Electricity Segment for the nine months ended September 30, 2012 was $177.4 million, compared to $186.1 million for the nine months ended September 30, 2011, which represented a 4.7% decrease. The cost per MWh in the nine months ended September 30, 2012 was lower than in the same period in 2011, as a result of lower maintenance costs in most of our power plants and specifically at

North Brawley, where we incurred costs of $23.2 million associated with operating and maintaining the plant in the nine months ended September 30, 2012, compared to $32.1 million in the nine months ended September 30, 2011. We were able to improve our operating efficiencies specifically in the maintenance of our well fields. As a percentage of total electricity revenues, the total cost of revenues attributable to our Electricity Segment for the nine months ended September 30, 2012 was 71.3%, compared to 75.6% for the nine months ended September 30, 2011.

Product Segment

Total cost of revenues attributable to our Product Segment for the nine months ended September 30, 2012 was $108.6 million, compared to $43.3 million for the nine months ended September 30, 2011, which represented a 150.9% increase. As a percentage of total Product Segment revenues, our total cost of revenues attributable to this segment for the nine months ended September 30, 2012 was 72.6%, compared to 64.6% for the nine months ended September 30, 2011. This increase in Product Segment cost of revenues as a percentage of total product revenues is mainly attributable to: (i) the recognition of revenues in the amount of $3.0 million relating to an LNG energy recovery unit in Spain in the nine months ended September 30, 2012, with virtually no associated cost of revenues, since the related costs were included in research and development costs in previous periods, compared to $7.9 million in the same period last year; (ii) a different product mix; and (iii) different margins in the various sales contracts.

Research and Development Expenses

Research and development expenses for the nine months ended September 30, 2012 were $3.9 million, compared to $7.1 million for the nine months ended September 30, 2011, which represented a 44.6% decrease. This decrease was primarily attributable to the costs incurred in the nine months ended September 30, 2011 in respect of an experimental LNG energy recovery unit which was completed in 2011. Our research and development activities during the nine months ended September 30, 2012 included: (i) continued development of Enhanced Geothermal Systems (EGS); and (ii) activities intended to improve plant performance, reduce costs, and increase the breadth of product offerings. These activities include developing: (i) improvements to our Evaporative Cooling system; (ii) condensing equipment with improved performance and lower land usage; (iii) new turbine products; and (iv) specialized power units designed to reduce fuel consumption and associated costs during a project’s development phase.

Selling and Marketing Expenses

Selling and marketing expenses for the nine months ended September 30, 2012 were $13.0 million, compared to $9.3 million for the nine months ended September 30, 2011, which represented a 39.8% increase. The increase reflects additional selling and marketing expenses associated with the increased Product Segment revenues. Selling and marketing expenses for the nine months ended September 30, 2012 constituted 3.3% of total revenues, compared to 3.0% for the nine months ended September 30, 2011.

General and Administrative Expenses

General and administrative expenses for the nine months ended September 30, 2012 were $20.3 million, compared to $20.8 million for the nine months ended September 30, 2011. General and administrative expenses for the nine months ended September 30, 2012 constituted 5.1% of total revenues, compared to 6.6% for the nine months ended September 30, 2011.

Impairment Charge

During the third quarter of 2012, the OREG 4 power plant (OREG 4), which generates electricity using recovered heat and has a carrying value of $10.9 million, was tested for recoverability due to continued low

output and was written down to its fair value of $3.6 million. The impairment loss of $7.3 million is presented in our condensed consolidated statement of operations and comprehensive income (loss) under “Impairment Charge”.

Write-off of Unsuccessful Exploration Activities

Write-off of unsuccessful exploration activities for the nine months ended September 30, 2012 was $1.9 million. This represented the write-off of exploration costs related to several projects in Nevada, which we determined in the nine months ended September 30, 2012 would not support commercial operations. We did not have a write-off of unsuccessful exploration activities in the nine months ended September 30, 2011.

Operating Income

Operating income for the nine months ended September 30, 2012 was $65.9 million, compared to $46.7 million for the nine months ended September 30, 2011. The increase of $19.2 million in operating income was principally attributable to an increase in our gross margin due to the increase in revenues, as described above, offset by the impairment loss in the amount of $7.3 million, as described above. Operating income attributable to our Electricity Segment for the nine months ended September 30, 2012 was $40.9 million, compared to $34.9 million for the nine months ended September 30, 2011. Operating income attributable to our Product Segment for the nine months ended September 30, 2012 was $25.1 million, compared to $11.8 million for the nine months ended September 30, 2011.

Interest Expense, Net

Interest expense, net for the nine months ended September 30, 2012 was $44.5 million, compared to $54.4 million for the nine months ended September 30, 2011, which represented an 18.2% decrease. The decrease is primarily due to: (i) a $16.4 million loss, in the nine months ended September 30, 2011, on interest lock transactions relating to the OFC 2 Senior Secured Notes, which were not accounted for as hedge transactions; and (ii) an increase of $1.0 million in interest capitalized to projects as a result of increased aggregate investment in projects under construction, offset by additional interest expense mainly as a result of the issuance of Series A Senior Secured Notes in October 2011 by OFC 2 LLC (OFC 2) and the full period impact in 2012 of the issuance of Senior Unsecured Bonds.

Foreign Currency Translation and Transaction Gains (Losses)

Foreign currency translation and transaction losses for the nine months ended September 30, 2012 were $1.1 million, compared to $1.5 million for the nine months ended September 30, 2011. The $0.4 million decrease is primarily due to a decrease in losses on forward foreign exchange transactions for the nine months ended September 30, 2012, which were not accounted for as hedge transactions, compared to the nine months ended September 30, 2011.

Income Attributable to Sale of Tax Benefits

Income attributable to the sale of tax benefits to institutional equity investors (as described under the heading “OPC Transaction” below) for the nine months ended September 30, 2012 was $7.4 million, compared to $7.6 million for the nine months ended September 30, 2011. This income represents the value of PTCs and taxable income or loss generated by OPC and allocated to the investors. The decrease is due to lower depreciation for tax purposes as a result of declining depreciation rates utilizing the Modified Accelerated Cost Recovery System (MACRS).

Income Taxes

Income tax provision for the nine months ended September 30, 2012 was $11.2 million, compared to income tax benefit of $0.7 million for the nine months ended September 30, 2011. The increase in income tax provision primarily resulted from the increase in income before taxes and from the increase in the valuation allowance against our U.S. deferred tax assets in respect of NOL carryforwards and unutilized tax credits. The effective tax rate for the nine months ended September 30, 2012 was 38.8%, compared to 711.8% for the nine months ended September 30, 2011. The decrease in the effective tax rate primarily resulted from the increase in the income before taxes, offset by the increase in the valuation allowance referred to above.

Net Income

Net income for the nine months ended September 30, 2012 was $16.2 million, compared to $0.3 million for the nine months ended September 30, 2011. The increase in net income of $16.0 million was principally attributable to: (i) a $19.2 million increase in operating income; and (ii) a $9.9 million decrease in interest expense, net of capitalized interest. The increase was partially offset by a $12.0 million increase in income tax provision.

Liquidity and Capital Resources

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, issuances by our subsidiaries, Ormat Funding Corp. (OFC), OrCal Geothermal Inc. (OrCal), and OFC 2 LLC (OFC 2), of their respective Senior Secured Notes, project financing (including the Puna lease and the OPC Transaction described below), and cash grants we received under the ARRA. We have utilized this cash to fund our acquisitions, to develop and construct power generation plants, and to meet our other cash and liquidity needs.

As of September 30, 2012, we have access to: (i) $40.5 million in cash, cash equivalents and marketable securities; and (ii) $85.4 million of unused corporate borrowing capacity under existing committed lines of credit with different commercial banks.

Our estimated capital needs for the remainder of 2012 are approximately $70.0 million for capital expenditures on new projects in development or construction, exploration activity, operating projects, and machinery and equipment, as well as $26.6 million for debt repayment.

We expect to finance these requirements with: (i) the sources of liquidity described above; (ii) positive cash flows from our operations; and (iii) future project financing and refinancing (including the OPIC Loan described below under the heading “New Financing of Our Projects”). Management believes that these sources will meet our anticipated liquidity, capital expenditures and other investment requirements.

Third-Party Debt

Our third-party debt is composed of two principal categories. The first category consists of project finance debt or acquisition financing that we or our subsidiaries have incurred for the purpose of developing and constructing, refinancing or acquiring our various projects, which are described below under 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”.

Non-Recourse and Limited-Recourse Third-Party Debt

OFC Senior Secured Notes — Non-Recourse

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 and 1A power plants, and the financing of the acquisition cost of the Steamboat 2 and 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. The OFC Senior Secured Notes are collateralized by substantially all of the assets of OFC and those of its wholly owned subsidiaries and are fully and unconditionally guaranteed by all of the wholly owned subsidiaries of OFC. There are various restrictive covenants under the OFC Senior Secured Notes, which include limitations on additional indebtedness of OFC and its wholly owned subsidiaries. Failure to comply with these and other covenants will, subject to customary cure rights, constitute an event of default by OFC. In addition, there are restrictions on the ability of OFC to make distributions to its shareholders, which include a required historical and projected 12-month debt service coverage ratio (DSCR) of not less than 1.25 (which are measured semi-annually as of June 30 and December 31 of each year). If OFC fails to comply with the DSCR ratios it will be precluded from making distributions to its shareholders. We expect that the transition to variable energy prices under the Ormesa and Mammoth PPAs and the impact of the currently low natural gas prices on our revenues will cause OFC to be below DSCR requirements for distributions, but we do not expect an event of default by OFC. As of June 30, 2012 (the last measurement date of the covenants), the actual historical 12-month DSCR was 1.66. As of September 30, 2012, there were $119.7 million of OFC Senior Secured Notes outstanding.

OrCal Secured Notes — Non-Recourse

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 Ratings. The OrCal Senior Secured Notes have a final maturity date of December 30, 2020. Principal and interest on the OrCal Senior Secured Notes are payable in semi-annual payments. The OrCal Senior Secured Notes are collateralized by substantially all of the assets of OrCal and those of its wholly owned subsidiaries and are fully and unconditionally guaranteed by all of the wholly owned subsidiaries of OrCal. There are various restrictive covenants under the OrCal Senior Secured Notes, which include limitations on additional indebtedness of OrCal and its wholly owned subsidiaries. Failure to comply with these and other covenants will, subject to customary cure rights, constitute an event of default by OrCal. In addition, there are restrictions on the ability of OrCal to make distributions to its shareholders, which include a required historical and projected 12-month DSCR of not less than 1.25 (which are measured semi-annually as of June 30 and December 31 of each year). If OrCal fails to comply with the DSCR ratios it will be precluded from making distributions to its shareholders. As of June 30, 2012 (the last measurement date of the covenants), the actual historical 12-month DSCR was 2.04. As of September 30, 2012, there were $83.7 million of OrCal Senior Secured Notes outstanding.

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

On September 23, 2011, OFC 2, one of our subsidiaries, and its wholly owned project subsidiaries (collectively, the OFC 2 Issuers) entered into a note purchase agreement (the Note Purchase Agreement) with OFC 2 Noteholder Trust, as purchaser, John Hancock, as administrative agent, and the U. S. Department of Energy (DOE), as guarantor, in connection with the offer and sale of up to $350.0 million aggregate principal amount of Senior Secured Notes due December 31, 2034 (OFC 2 Senior Secured Notes).

Subject to the fulfillment of customary and other specified conditions precedent, the OFC 2 Senior Secured Notes may be issued in up to six distinct series associated with the phased construction (Phase I and Phase II) of the Jersey Valley, McGinness Hills and Tuscarora geothermal power facilities owned by the Issuers. The OFC 2 Senior Secured Notes will mature and the principal amount of the OFC 2 Senior Secured Notes will be payable in equal quarterly installments 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. The DOE will guarantee payment of 80% of principal and

interest on the OFC 2 Senior Secured Notes pursuant to Section 1705 of Title XVII of the Energy Policy Act of 2005, as amended. The conditions precedent to the issuance of the OFC 2 Senior Secured Notes include certain specified conditions required by the DOE in connection with their guarantee of the OFC 2 Senior Secured Notes.

On October 31, 2011, the OFC 2 Issuers completed the sale of $151.7 million in aggregate principal amount of 4.687% Series A Notes due 2032 (the Series A Notes). The net proceeds from the sale of the Series A Notes, after deducting transaction fees and expenses, were approximately $147.4 million, and were used to finance a portion of the construction costs of Phase I of the McGinness Hills and Tuscarora facilities and to fund certain reserves. Principal and interest on the Series A Notes are payable quarterly in arrears on the last day of March, June, September and December of each year.

Issuance of the next series of notes, the Series B Notes, is dependent on the Jersey Valley facility reaching certain operational targets in addition to the other conditions precedent noted above. If issued, the aggregate principal amount of the Series B Notes will not exceed $28.0 million, and such proceeds will be used to finance a portion of the construction costs of Phase I of the Jersey Valley facility.

The OFC 2 Issuers have sole discretion regarding whether to commence construction of Phase II of any of the Jersey Valley, McGinness Hills and Tuscarora facilities. If Phase II construction is undertaken for any of the facilities, the OFC 2 Issuers may issue Phase II tranches of Notes, comprised of one or more of Series C Notes, Series D Notes, Series E Notes and 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 $170.0 million. The aggregate principal amount of each series of Notes comprising a Phase II tranche will be determined by the OFC 2 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 OFC 2 Senior Secured Notes are collateralized by substantially all of the assets of OFC 2 and those of its wholly owned subsidiaries and are fully and unconditionally guaranteed by all of the wholly owned subsidiaries of OFC 2. There are various restrictive covenants under the OFC 2 Senior Secured Notes, which include limitations on additional indebtedness of OFC 2 and its wholly owned subsidiaries. Failure to comply with these and other covenants will, subject to customary cure rights, constitute an event of default by OFC 2. In addition, there are restrictions on the ability of OFC 2 to make distributions to its shareholders. Among other things, the distribution restrictions include a DSCR requirement of at least 1.2 (on a blended basis for all of the OFC 2 facilities) and 1.5 on a pro forma basis (giving effect to the distributions). As of September 30, 2012, the actual DSCR from the operation date was 1.29 and the pro-forma 12-month DSCR was 2.15.

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 OFC 2 Senior Secured Notes, in each case that occurs prior to the date that the relevant facility financed by such OFC 2 Senior Secured Notes reaches completion and meets certain operational performance levels. A demand on our guarantee based on the non-performance trigger is limited to an amount equal to the prepayment amount on the OFC 2 Senior Secured Notes necessary to bring the OFC 2 Issuers into compliance with certain coverage ratios. A demand on our guarantee based on the other trigger event is not so limited.

As of September 30, 2012, there were $151.2 million of OFC 2 Senior Secured Notes outstanding.

Olkaria III Loan — Non-Recourse

One of our subsidiaries, OrPower 4, Inc. (OrPower 4), has a project financing loan of $105.0 million which refinanced its investment in the 48 MW Olkaria III complex located in Kenya. The loan was provided by a group

of European Development Finance Institutions (DFIs) 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%, except with respect to $77.0 million of the loan that has a fixed interest rate of 6.90% per annum. There are various restrictive covenants under the loan, including a requirement to comply with the following financial ratios for each calculation period (measured as of June 15 and December 15 of each year): (i) an historical and projected 6-month DSCR of not less than 1.15; (ii) a debt to equity (including shareholder’s loan) ratio which does not exceed 3.0; and (iii) an equity (including shareholder’s loan) to total assets ratio of not less than 0.25. If OrPower 4 fails to comply with these financial ratios it will be precluded from making distributions to its shareholders. In addition, subject to certain cure rights, such failure will constitute an event of default by OrPower 4. As of June 15, 2012 (the last measurement date of the covenants): (i) the actual 6-month historical DSCR was 2.37; (ii) the debt to equity ratio was 0.52; and (iii) the equity to total assets ratio was 0.56. As of September 30, 2012, $71.8 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.

Amatitlan Loan — Non-Recourse

One of our subsidiaries, 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 geothermal power plant located in Amatitlan, Guatemala. The loan was provided by TCW Global Project Fund II, Ltd. (TCW). The loan will mature on June 15, 2016, and is payable in 28 quarterly installments, which 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 this 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: (i) a projected 12-month DSCR of not less than 1.2; and (ii) a long-term debt to equity ratio not to exceed 4.0 (both of which are measured quarterly). If Ortitlan fails to comply with these financial ratios it will be precluded from making distributions to its shareholders. In addition, subject to certain cure rights, such failure will constitute an event of default by Ortitlan. As of September 30, 2012, the projected 12-month DSCR was 1.57 and the debt to equity ratio was 2.24. As of September 30, 2012, $34.9 million of the Amatitlan loan was outstanding.

New Financing of Our Projects

Refinancing of the Olkaria III Loan and Financing of the Construction of the Olkaria III Complex Expansion

On August 23, 2012, OrPower 4 entered into a Finance Agreement with the Overseas Private Investment Corporation (OPIC), an agency of the United States government, to provide limited-recourse senior secured debt financing in an aggregate principal amount of up to $310.0 million (the “OPIC Loan”) for the refinancing and financing of our Olkaria III geothermal power complex in Kenya.

The OPIC Loan is comprised of up to three tranches:

•

Tranche I in an aggregate principal amount of up to $85.0 million will be used to prepay approximately $20.5 million (plus associated prepayment penalty and breackage costs of $1.5 million) of the $71.8 million outstanding debt provided by a group of European DFIs arranged by DEG, which was incurred to finance a portion of the construction costs of the existing Plant 1 at the Olkaria III complex, as described under “Olkaria III Loan —Non-Recourse” above. The remainder of Tranche I proceeds will be used for reimbursement of prior capital costs and other corporate purposes.

•

Tranche II in an aggregate principal amount of up to $180.0 million, will be used to fund the construction and well field drilling for the expansion of the Olkaria III geothermal power complex to up to 84 MW (Plant 2).

•

Tranche III is a stand-by tranche in an aggregate principal amount of up to $45.0 million, and will be made available to OrPower 4 in the event it elects, in its discretion, to construct a further expansion of the Olkaria III complex of up to an additional 16 MW (Plant 3). Terms and conditions for Tranche III of the OPIC Loan will be agreed by OPIC and OrPower 4 in subsequent documentation.

It is expected that both Tranche I and Tranche II will initially bear interest at a floating rate from the date of disbursement until a conversion date selected by OrPower 4, whereupon interest on each Tranche will convert to a fixed rate. Interest, whether floating or fixed, will be payable quarterly in arrears on each March 15, June 15, September 15 and December 15, commencing with the first such date following the respective disbursement of a Tranche. OrPower 4 is required to select a conversion date that will be a date occurring between the commercial operation date of Plant 2 and the date that is 180 days after such commercial operation date.

In each case, the applicable Tranche interest rate will be determined at the time of the actual disbursement of loan proceeds based upon, and in connection with the issuance of certificates of participation in the OPIC Loan. The payment of principal and interest on the certificates of participation will be fully guaranteed to the purchasers thereof by OPIC. The OPIC guarantee is backed by the full faith and credit of the U.S. government.

The final maturity of Tranche I and Tranche II is approximately 18 years.

OrPower 4 has a right to make voluntary prepayments of all or a portion of the OPIC Loan subject to prior notice, minimum prepayment amounts, and a prepayment premium of 2% in the first two years after the Plant 2 commercial operation date, reducing to 1% in the third year after the Plant 2 commercial operation date, and without premium thereafter. In addition, the OPIC Loan is subject to customary mandatory prepayment requirements, including from insurance and condemnation proceeds and from asset sales above certain thresholds. The OPIC Loan is also subject to mandatory prepayment to the extent required to maintain a projected ratio of cash flow to debt service of 1.7:1, in the event of certain reductions in the generation capacity of the geothermal power plants.

The OPIC Loan is secured by a security interest over substantially all of OrPower 4’s assets and by a pledge of all of the equity interests in OrPower 4. The conditions to disbursement under the Finance Agreement include a requirement that the existing security interests in favor of the third party lenders that financed a portion of the construction costs of Plant 1 be discharged and released such that the security interests granted in favor of OPIC will constitute perfected first priority security interests.

The Finance Agreement contains customary representations and warranties, and customary affirmative and negative covenants applicable to OrPower 4. The affirmative covenants include, among others, a historic and projected ratio of cash flow to debt service of 1.1:1.0, maintenance of business, corporate existence, insurance, property rights, and books and records. The negative covenants, include, among others, limitations on OrPower 4’s ability to incur other indebtedness, pay dividends, make repurchases of equity, merge or consolidate with another person, or grant liens on the collateral securing the OPIC Loan.

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

The repayment of the remaining outstanding debt provided by the group of European DFIs, in the amount of approximately $51.3 million, has been subordinated to the OPIC Loan. OrPower 4 and the remaining DFI lenders have amended and restated the relevant loan and collateral security documents to effect the subordination and release the security previously supporting the DFI loans. In exchange, we have provided a corporate guaranty to the remaining DFI lenders, with respect to the payment obligations of OrPower 4 on the remaining subordinated loan.

Full-Recourse Third-Party Debt

Union Bank. On February 7, 2012, Ormat Nevada entered into an amended and restated credit agreement with Union Bank, N.A. (Union Bank). Under the amended and restated agreement, the credit termination date was extended to February 7, 2014 and the aggregate amount available under the credit agreement was increased to $50.0 million. The facility is limited to the issuance, extension, modification or amendment of letters of credit. Union Bank is currently the sole lender and issuing bank under the credit agreement, but is also designated as an administrative agent on behalf of banks that may, from time to time in the future, join the credit agreement as parties thereto. In connection with this transaction, we 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.

There are various restrictive covenants under the credit agreement, which include a requirement to comply with the following financial ratios, which are measured quarterly: (i) a 12-month debt to EBITDA ratio not to exceed 4.5; (ii) 12-month DSCR of not less than 1.35; and (iii) distribution leverage ratio not to exceed 2.0. As of September 30, 2012: (i) the actual 12-month debt to EBITDA ratio was 3.58; (ii) the 12-month DSCR was 2.07; and (iii) the distribution leverage ratio was 0.77. In addition, there are restrictions on dividend distributions in the event of a payment default or noncompliance with such ratios, and subject to specified carve-outs and exceptions, a negative pledge on the assets of Ormat Nevada in favor of Union Bank.

As of September 30, 2012, letters of credit in the aggregate amount of $42.3 million remain issued and outstanding under this credit agreement with Union Bank.

Credit Agreements. We also have credit agreements with five other commercial banks for an aggregate amount of $437.2 million. Under the terms of these credit agreements, we, or our Israeli subsidiary, Ormat Systems Ltd. (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 $332.2 million; and (ii) the issuance of one or more letters of credit in the amount of up to $105.0 million. The credit agreements mature between December 2012 and December 2014. 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 $65.0 million are due to expire in the fourth quarter of 2012. We are currently negotiating the extension of these credit agreements.

As of September 30, 2012, loans in the total amount of $187.5 million were outstanding, and letters of credit with an aggregate stated amount of $172.0 million were issued and outstanding under these credit agreements. The $187.5 million in loans are for terms of three months or less and bear interest at a weighted average rate of 2.9%.

Term Loans. 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 interest of 6.5%. As of September 30, 2012, $11.0 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 that commenced February 1, 2012, and bears interest at 6-month LIBOR plus 5.0%. As of September 30, 2012, $16.7 million was outstanding under this loan.

We have a $20.0 million term loan with a group of institutional investors, which matures on November 16, 2016, is payable in 10 semi-annual installments that commenced May 16, 2012, and bears interest of 5.75%. As of September 30, 2012, $18.0 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 interest at 6-month LIBOR plus 3.45%. As of September 30, 2012, $25.0 million was outstanding under this loan.

Senior Unsecured Bonds. We have an aggregate principal amount of approximately $250.0 million of Senior Unsecured Bonds issued and outstanding. We issued approximately $142.0 million 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 7.0%, 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 term loan agreements, and the trust instrument governing the bonds, described above, are unsecured, but we are subject to a negative pledge in favor of the banks and the other lenders and certain other restrictive covenants. These include, among other things, a prohibition on: (i) creating any floating charge or any permanent pledge, charge or lien over our assets without obtaining the prior written approval of the lender; (ii) guaranteeing the liabilities of any third party without obtaining the prior written approval of the lender; and (iii) selling, assigning, transferring, conveying or disposing of all or substantially all of our assets, or a change of control in our ownership structure. Some of the credit agreements, the term loan agreements, as well as the trust instrument contain cross-default provisions with respect to other material indebtedness owed by us to any third party. In some cases, we have agreed to maintain certain financial ratios, which are measured quarterly, such as: (i) equity of at least $600 million and in no event less than 30% of total assets; (ii) 12-month debt, net of cash, cash equivalents and marketable securities to Adjusted EBITDA ratio not to exceed 7.0; and (iii) dividend distributions not to exceed 35% of net income for that year. The failure to perform or observe any of the covenants set forth in such agreements, subject to various cure periods, would result in the occurrence of an event of default and would enable the lenders to accelerate all amounts due under each such agreement. As of September 30, 2012: (i) total equity was $923.2 million and the actual equity to total assets ratio was 40.9%; (ii) the 12-month debt, net of cash, cash equivalents and marketable securities to Adjusted EBITDA ratio was 4.8; and (iii) dividend distributions were less than 35% of net income for the first nine months of 2012.

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

Letters of Credit

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

As of September 30, 2012, letters of credit in the aggregate amount of $248.2 million remained issued and outstanding (out of which $214.3 million were issued under the credit agreements with Union Bank and five of the commercial banks as described under “Full-Recourse Third-Party Debt” above and $33.9 million were issued under non-committed lines of credit).

Puna Complex Lease Transactions

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. The transaction was concluded with financing parties by means of a leveraged lease transaction. A secondary stage of the lease transaction relating to

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

OPC Transaction

In June 2007, Ormat Nevada entered into agreements with affiliates of Morgan Stanley & Co. Incorporated and Lehman Brothers Inc. (Morgan Stanley Geothermal LLC and Lehman-OPC LLC, respectively), under which those investors purchased, for cash, interests in a newly formed subsidiary of Ormat Nevada, OPC LLC (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 Ormat Nevada 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.

The Class B membership units, as described in the paragraph below, 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. The Class B membership units are currently held by Morgan Stanley Geothermal LLC and JPM Capital Corporation.

Our voting rights in OPC are based on a capital structure that is comprised of Class A and Class B membership units. Through our subsidiary, Ormat Nevada, we own 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 consolidates OPC.

Liquidity Impact of Uncertain Tax Positions

As discussed in Note 10 to our condensed consolidated financial statements set forth in Item 1 of this quarterly report, we have a liability associated with unrecognized tax benefits and related interest and penalties in the amount of approximately $7.1 million as of September 30, 2012. 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.

Dividends

The following are the dividends declared by us during the past two years:


Date Declared	Dividend Amount per Share		Record Date	Payment Date
November 2, 2010	$	0.05	November 17, 2010	November 30, 2010
February 22, 2011	$	0.05	March 15, 2011	March 24, 2011
May 4, 2011	$	0.04	May 18, 2011	May 25, 2011
August 3, 2011	$	0.04	August 16, 2011	August 25, 2011
May 8, 2012	$	0.04	May 21, 2012	May 30, 2012
August 1, 2012	$	0.04	August 14, 2012	August 23, 2012

Historical Cash Flows

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


	Nine Months Ended September 30,
	2012			2011
	(In thousands)
Net cash provided by operating activities	$	62,384		$	98,514
Net cash used in investing activities		(53,611	)		(238,186	)
Net cash provided by (used in) financing activities		(71,135	)		115,934
Net change in cash and cash equivalents		(62,362	)		(23,738	)

For the Nine Months Ended September 30, 2012

Net cash provided by operating activities for the nine months ended September 30, 2012 was $62.4 million, compared to $98.5 million for the nine months ended September 30, 2011. The net decrease of $36.1 million resulted primarily from: (i) an increase in receivables of $29.7 million in the nine months ended September 30, 2012, compared to a decrease of $2.6 million in the nine months ended September 30, 2011, as a result of timing of collections from our customers; (ii) a decrease in billing in excess of costs and estimated earnings on uncompleted contracts, net of $4.3 million relating to our Product Segment in the nine months ended September 30, 2012, compared to an increase of $35.1 million in the nine months ended September 30, 2011, as a result of timing in billing of our customers; and (iii) an unrealized loss on interest rate lock transactions of $11.1 million in the nine months ended September 30, 2011. Such increase was partially offset by: (i) an increase in net income to $16.2 million in the nine months ended September 30, 2012, from $0.3 million in the nine months ended September 30, 2011, mainly as a result of an increase in our operating income as described above; (ii) an increase in accounts payable and accrued expenses of $9.5 million in the nine months ended September 30, 2012, compared to a decrease of $9.6 million in the nine months ended September 30, 2011, as a result of timing of payments to our vendors; (iii) an increase in deferred income tax provision, net of $5.9 million in the nine months ended September 30, 2012, compared to a decrease of $1.8 million in the nine months ended September 30, 2011; and (iv) an impairment charge of $7.3 million in the nine months ended September 30, 2012.

Net cash used in investing activities for the nine months ended September 30, 2012 was $53.6 million, compared to $238.2 million for the nine months ended September 30, 2011. The principal factors that affected our net cash used in investing activities during the nine months ended September 30, 2012 were capital expenditures of $186.3 million, primarily for our facilities under construction, offset by: (i) cash grant in the amount of $119.2 million received in the nine months ended September 30, 2012 from the U.S. Treasury under Section 1603 of the ARRA relating to the enhancement of our Puna geothermal complex and to our Jersey Valley, Tuscarora, and McGinness Hills geothermal power plants; and (ii) net decrease of $18.8 million in marketable securities. The principal factors that affected our net cash used in investing activities during the nine

months ended September 30, 2011 were: (i) capital expenditures of $180.8 million, primarily for our facilities under construction; (ii) net increase of $36.9 million in restricted cash, cash equivalents and marketable securities; and (iii) net increase of $20.3 million in marketable securities.

Net cash used in financing activities for the nine months ended September 30, 2012 was $71.1 million, compared to net cash provided by financing activities of $115.9 million for the nine months ended September 30, 2011. The principal factors that affected the net cash used in financing activities during the nine months ended September 30, 2012 were: (i) a net decrease of $26.6 million against our revolving lines of credit with commercial banks; (ii) the repayment of long-term debt in the amount of 28.9 million; (iii) $11.0 million of cash paid to the Class B membership units of OPC (see “OPC Transaction” above); and (iv) the payment of a dividend to our shareholders in the amount of $3.6 million. The principal factors that affected our net cash provided by financing activities during the nine months ended 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 $26.0 million; (ii) $10.8 million of cash paid to the Class B membership units of OPC; and (iii) the payment of a dividend to our shareholders in the amount of $5.9 million.

Adjusted EBITDA

We calculate EBITDA as net income before interest, taxes, depreciation and amortization. We calculate adjusted EBITDA as net income before interest, taxes, depreciation and amortization, excluding impairment of long-lived assets. EBITDA and adjusted EBITDA are not measurements of financial performance or liquidity under accounting principles generally accepted in the United States of America (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 frequently used by securities analysts, investors and other interested parties in the evaluation of a company’s ability to service and/or incur debt. However, other companies in our industry may calculate EBITDA and adjusted EBITDA differently than we do. 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.

Adjusted EBITDA for the three months ended September 30, 2012 was $48.2 million, compared to $46.7 million for the three months ended September 30, 2011. Adjusted EBITDA for the nine months ended September 30, 2012 was $150.5 million, compared to $121.6 million for the nine months ended September 30, 2011.

The following table reconciles net cash provided by operating activities to EBITDA and adjusted EBITDA for the three and nine-month periods ended September 30, 2012 and 2011:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
	(In thousands)						(In thousands)
Net cash provided by (used in) operating activities	$	(9,695	)	$	59,008		$	62,384		$	98,514
Adjusted for:
Interest expense, net (excluding amortization of deferred financing costs)		14,202			23,222			40,931			52,046
Interest income		(280	)		(438	)		(1,004	)		(1,289	)
Income tax provision (benefit)		1,779			(305	)		11,545			(726	)
Adjustments to reconcile net income or loss to net cash provided by operating activities (excluding depreciation and amortization)		34,936			(34,749	)		29,361			(26,977	)

EBITDA		40,942			46,738			143,217			121,568
Impairment charge		7,264			—			7,264			—

Adjusted EBITDA	$	48,206		$	46,738		$	150,481		$	121,568

Net cash provided by (used in) investing activities	$	13,417		$	(102,445	)	$	(53,611	)	$	(238,186	)

Net cash provided by (used in) financing activities	$	(32,882	)	$	58,176		$	(71,135	)	$	115,934

Capital Expenditures

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

Carson Lake Project. We plan to develop the 20 MW Carson Lake project on Bureau of Land Management (BLM) leases located in Churchill County, Nevada. Permitting delays prevented substantial progress on the project site until late last year. However, we received approval from the BLM for the required Environmental Impact Study. We recently started the drilling activity in the project’s field, and we are evaluating the results.

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 the drilling of additional wells is subject to our obtaining the required permits.

Heber Solar PV Project. We are currently developing the 10 MW Heber Solar PV project located in Imperial County, California. We signed a 20-year PPA with the Imperial Irrigation District (IID). We expect to begin commercial operation in 2013, subject to timely completion of the interconnection that is to be provided by IID.

Mammoth Complex. We are currently in the process of repowering the Mammoth complex located in Mammoth Lakes, California, by replacing part of the old units with new Ormat-manufactured equipment. We expect the replacement of the equipment to optimize the operation of the complex. We have started manufacturing the equipment for the complex.

Olkaria III Phase 3. Development of Phase 3 of the Olkaria III complex located in Naivasha, Kenya is in process. Field development of the new 36 MW power plant at the Olkaria III complex is in advanced stages, power plant equipment is on site and site construction is in progress. The new power plant is scheduled to come online in mid-2013.

Wild Rose Project. We are currently developing the 16 MW Wild Rose project located in Mineral County, Nevada. Field development is in advanced stages; manufacturing of the power plant equipment is in process. The new power plant is expected to come online in 2013. Actual generation capacity will be determined based on field development results.

Heber 1 Power Plant. We plan to enhance the Heber complex located in Imperial Valley, California, by replacing part of the old equipment with new equipment. We expect the replacement of the equipment to optimize the operation of the Heber complex.

We have estimated approximately $319.0 million in capital expenditures for construction of new projects that are still under construction and that are expected to be completed by 2013, of which we have invested approximately $149.0 million as of September 30, 2012. We expect to invest an additional $48.0 million of such total during the remainder of 2012. The remaining $122.0 million will be invested in 2013.

In addition, we estimate approximately $22.0 million in additional capital expenditures during the remainder of 2012 to be allocated as follows: (i) $7.0 million for development of new projects; (ii) $10.0 million for enhancement of our operating power plants; and (iii) $9.0 million for exploration activities in various leases for geothermal resources in which we have started the exploration activity. In the aggregate, we estimate our total capital expenditures for the remainder of 2012 to be approximately $70.0 million.

Exposure to Market Risks

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

One market risk to which power plants are typically exposed is the volatility of electricity prices. Our exposure to such market risk is currently limited because many of our long-term PPAs (except for the 25 MW PPA for the Puna complex) 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 for the Heber 1 and 2 power plants, the Ormesa complex, and the Mammoth complex have been determined by reference to the relevant power purchaser’s SRAC. A decline in the price of natural gas will result in a decrease in the incremental cost that the power purchaser avoids by not generating its electrical energy needs from natural gas, which in turn will reduce the variable energy rate that we may charge under the relevant PPA for these power plants. In addition, as discussed in the section above entitled “Recent Developments”, in May and July 2012, we entered into put transactions, and in October 2012, we entered into swap contracts to reduce our exposure to the price of natural gas, under the above PPAs, until December 31, 2013. The Puna complex is currently benefiting from energy prices which are higher than the floor under the 25 MW PPA for the Puna complex as a result of the high fuel costs that impact HELCO’s avoided costs. Likewise, as discussed in the section above entitled “Recent Developments”, in April 2012, we entered into swap contracts, and in September 2012, we entered into put transactions to reduce our exposure to the price of oil, under the 25 MW PPA of the Puna complex, until December 31, 2013.

As of September 30, 2012, 74.4% 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, 25.6% of our debt was in the form of a floating rate instrument, exposing us to changes in interest rates in connection therewith. As of September 30, 2012, $248.2 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 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 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.

Concentration of Credit Risk

Our credit risk is currently concentrated with a limited number of major customers: Southern California Edison, HELCO, Sierra Pacific Power Company and Nevada Power Company (subsidiaries of NV Energy), and Kenya Power and Lighting Co. Ltd. (KPLC). 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 19.8% and 34.5% of our total revenues for the three months ended September 30, 2012 and 2011, respectively, and 18.8% and 30.5% for the nine months ended September 30, 2012 and 2011, respectively.

Sierra Pacific Power Company and Nevada Power Company (subsidiaries of NV Energy, Inc.) accounted for 14.1% and 10.5% of our total revenues for the three months ended September 30, 2012 and 2011, respectively, and 13.8% and 12.8% for the nine months ended September 30, 2012 and 2011, respectively.

HELCO accounted for 8.1% and 10.3% of our total revenues for the three months ended September 30, 2012 and 2011, respectively, and 9.1% and 10.9% for the nine months ended September 30, 2012 and 2011, respectively.

KPLC accounted for 8.6% and 8.0% of our total revenues for the three months ended September 30, 2012 and 2011, respectively, and 7.8% and 8.4% for the nine months ended September 30, 2012 and 2011, respectively.

Government Grants and Tax Benefits

The U.S. government encourages production of electricity from geothermal resources through certain tax subsidies under the 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.

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 that started in 2004, and thereafter such income was subject to reduced Israeli income tax rates, which will not exceed 25% for an additional five years until 2010. Ormat Systems was also exempt from Israeli income taxes with respect to income derived from the second benefited investment for a period of two years that started in 2007, and thereafter such income is subject to reduced Israeli income tax rates which will not exceed 25% for an additional five years until 2013 (see also below). 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 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 had the option either to irrevocably comply with the new law while waiving benefits provided under the previous law or to continue to comply with the previous law during the transition period, with an option to move from the previous law to the new law at any stage. Ormat Systems decided to irrevocably comply with the new law starting in 2011.

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

ITEM 4.

CONTROLS AND PROCEDURES

a. Evaluation of disclosure controls and procedures

Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures to ensure that the information required to be disclosed in our filings pursuant to Rule 13a-15 under the Securities and Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms and to ensure that such information is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. Based on that evaluation, as of September 30, 2012, 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.

b. Changes in internal controls over financial reporting

There were no changes in our internal controls over financial reporting in the third quarter of 2012 that have materially affected or are reasonably likely to materially affect our internal controls over financial reporting.

PART II — OTHER INFORMATION

ITEM 1.

LEGAL PROCEEDINGS

Securities Class Actions

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 asserted claims against the Company and certain directors and officers for alleged violations of Sections 10(b) and 20(a) of the Securities Exchange Act of 1934 (the Exchange Act). One complaint also asserted claims for alleged violations of Sections 11, 12(a)(2) and 15 of the Securities Act. All three complaints alleged claims on behalf of a putative class of purchasers of the Company’s 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 asserted claims under Sections 10(b) and 20(a) of the Exchange Act on behalf of a putative class of purchasers of the Company’s common stock between May 7, 2008 and February 24, 2010. The CAC alleged 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 alleged that certain of the Company’s statements concerning the North Brawley project were false and misleading. The CAC sought compensatory damages, expenses, and such further relief as the Court may deem proper.

Subsequently, the parties participated in a mediation where they reached an agreement in principle to settle the securities class action lawsuits. The parties thereafter filed a stipulation of settlement with the U.S. District Court for the District of Nevada on March 27, 2012, providing that the claims against the Company and its directors and officers will be dismissed with prejudice and plaintiffs will release the defendants from all claims in exchange for a cash payment of $3.1 million to be funded by the Company’s insurers. The stipulation of settlement received preliminary approval by the Court on March 30, 2012, and final approval on October 16, 2012.

Stockholder Derivative Cases

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 directors and officers 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 lawsuit.

The parties to all the stockholder derivative cases executed a stipulation of settlement to resolve all cases on September 25, 2012. The stipulation provides that: (i) all claims asserted in the derivative cases will be dismissed with prejudice and that plaintiffs will release the defendants from all claims; (i) the Company will implement and/or maintain certain corporate governance measures for no less than five years; and (iii) plaintiffs’ counsel will receive attorneys’ fees of $700,000 to be funded by the Company’s insurers. The stipulation of settlement received preliminary approval on October 22, 2012. It still remains subject to final approval following notice to the Company’s stockholders.

The Company believes the allegations in these purported derivative actions are without merit and, as part of the settlement, continues to deny any liability or wrongdoing.

Other

On January 4, 2012, the California Unions for Reliable Energy (CURE) filed a petition in the Alameda Superior Court, naming the California Energy Commission (CEC) and the Company as defendant and real party in interest, respectively. The petition asks the Court to order the CEC to vacate its decision which denied, with prejudice, the complaint filed by CURE against the Company with the CEC. The CURE complaint alleged that the Company’s North Brawley project and East Brawley project both exceed the CEC’s 50 MW jurisdictional threshold and therefore are subject to the CEC licensing authority rather than the Imperial County licensing authority. In addition, the CURE petition asks the Court to investigate and halt any ongoing violation of the Warren Alquist Act by the Company, and to award CURE attorney’s fees and costs. As to North Brawley, CURE alleges that the CEC decision violated the Warren Alquist Act because it failed to consider provisions of the County permit for North Brawley, which CURE contends authorizes the Company to build a generating facility with a number of Ormat Energy Converters (OECs) capable of generating more than 50 MW. As to East Brawley, CURE alleges that the CEC decision violated the Warren Alquist Act because it failed to consider the conditional use permit application for East Brawley, which CURE contends shows that the Company requested authorization to build a facility with a number of OECs capable of generating more than 50 MW.

The Company believes that the petition is without merit and intends to respond and take necessary legal action to dismiss the proceedings. The parties have filed briefs in the proceeding, and the matter is set for hearing. Filing of the petition in and of itself does not have any immediate adverse implications for the North Brawley or East Brawley projects and the Company continues to operate the North Brawley project in the ordinary course of business and is proceeding with its development work on the East Brawley project.

In addition, from time to time, the Company is named as a party to various other lawsuits, claims and other legal and regulatory proceedings that arise in the ordinary course of 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 be material to the Company’s consolidated financial statements as a whole.

ITEM 1A.

RISK FACTORS

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, 2011 filed with the SEC on February 29, 2012, which is further updated by the addition of the risk factor discussed below.

The reduction or elimination of government incentives could adversely affect our business, financial condition, future results and cash flows.

Construction and operation of our geothermal power plants, recovered energy-based power plants, and solar PV power plants have benefited, and may benefit in the future, from public policies and government incentives that support renewable energy and enhance the economic feasibility of these projects in regions and countries where we operate. Such policies and incentives include production and investment tax credits, cash grants, loan guaranties, accelerated depreciation tax benefits, renewable portfolio standards, carbon trading mechanisms, rebates, and mandated feed-in-tariffs, and may include similar or other incentives to end users, distributors, system integrators and manufacturers of solar and other power products. Some of these measures have been implemented at the federal level, while others have been implemented by different states or countries outside the U.S. where we operate.

The availability and continuation of these public policies and government incentives have a significant effect on the economics and viability of our development program and continued construction of new geothermal, recovered energy-based, and solar PV power plants. Any changes to such public policies, or any reduction in or elimination or expiration of such government incentives could affect us in different ways. For example, any reduction in, termination or expiration of renewable portfolio standards may result in less demand for generation from our geothermal, recovered energy-based, and solar PV power plants. Any reductions in, termination or expiration of other government incentives could reduce the economic viability of, and cause us to reduce, the construction of new geothermal, recovered energy-based, and solar PV power plants. Similarly, any such changes that affect the geothermal energy industry in a manner that is different from other sources of renewable energy, such as wind or solar, may put us at a competitive disadvantage compared to businesses engaged in the development, construction and operation of renewable power projects using such other resources. Any of the foregoing outcomes could have a material adverse effect on our business, financial condition, future results, and cash flows.

ITEM 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

There were no unregistered sales of equity securities of the Company during the third fiscal quarter of 2012.

ITEM 3.

DEFAULTS UPON SENIOR SECURITIES

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

ITEM 4.

MINE SAFETY DISCLOSURES

Not applicable

ITEM 5.

OTHER INFORMATION

None.

ITEM 6.

EXHIBITS


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, incorporated by reference to Exhibit 4.8 to Ormat Technologies, Inc. Quarterly Report on Form 10-Q to the Securities and Exchange Commission on November 4, 2011.


Exhibit No.		Document

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

10.1		Finance Agreement, dated as of August 23, 2012, by and between OrPower 4, Inc., an indirect wholly-owned subsidiary of Ormat Technologies, Inc., and the Overseas Private Investment Corporation, filed herewith.

10.2		Equity Contribution, Subordination, and Share Retention Agreement, dated as of August 23, 2012, by and among OrPower 4, Inc., Ormat Technologies, Inc., Ormat International Inc., Ormat Holding Corp., and the Overseas Private Investment Corporation, filed herewith.

10.3		Guaranty, dated as of October 25, 2012, by and between Ormat Technologies, Inc. and DEG—Deutsche Investitions-Und entwicklungsgesellschaft mbH, filed herewith.

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 Document.*

101.LAB		XBRL Taxonomy Extension Label Linkbase Document.*

101.PRE		XBRL Taxonomy Presentation Linkbase Document.*

Pursuant to Rule 406T of Regulation S-T, these interactive data files are deemed not “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section and shall not be deemed to be incorporated by reference into any filing under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended, except to the extent that the Company specifically incorporates such information by reference.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


ORMAT TECHNOLOGIES, INC.

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

Date: November 8, 2012

EXHIBIT INDEX


Exhibit No.		Document

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

3.2		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, incorporated by reference to Exhibit 4.8 to Ormat Technologies, Inc. Quarterly Report on Form 10-Q to the Securities and Exchange Commission on November 4, 2011.


Exhibit No.		Document

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

10.1		Finance Agreement, dated as of August 23, 2012, by and between OrPower 4, Inc., an indirect wholly-owned subsidiary of Ormat Technologies, Inc., and the Overseas Private Investment Corporation, filed herewith.

10.2		Equity Contribution, Subordination, and Share Retention Agreement, dated as of August 23, 2012, by and among OrPower 4, Inc., Ormat Technologies, Inc., Ormat International Inc., Ormat Holding Corp., and the Overseas Private Investment Corporation, filed herewith.

10.3		Guaranty, dated as of October 25, 2012, by and between Ormat Technologies, Inc. and DEG—Deutsche Investitions-Und entwicklungsgesellschaft mbH, filed herewith.

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 Document.*

101.LAB		XBRL Taxonomy Extension Label Linkbase Document.*

101.PRE		XBRL Taxonomy Presentation Linkbase Document.*