Edgar Filing: ORMAT TECHNOLOGIES, INC.

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 June 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):


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

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

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 August 4, 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 JUNE 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	23
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	53
ITEM 4.	CONTROLS AND PROCEDURES	53

PART II — OTHER INFORMATION
ITEM 1.	LEGAL PROCEEDINGS	55
ITEM 1A.	RISK FACTORS	57
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	57
ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	57
ITEM 4.	MINE SAFETY DISCLOSURES	57
ITEM 5.	OTHER INFORMATION	57
ITEM 6.	EXHIBITS	58
SIGNATURES		60

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)


	June 30, 2012		December 31, 2011
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	66,684	$	99,886
Marketable securities		5,221		18,521
Restricted cash, cash equivalents and marketable securities (all related to VIEs)		97,792		75,521
Receivables:
Trade		42,315		51,274
Related entity		329		287
Other		8,064		9,415
Due from Parent		161		260
Inventories		18,119		12,541
Costs and estimated earnings in excess of billings on uncompleted contracts		10,051		3,966
Deferred income taxes		2,260		1,842
Prepaid expenses and other		24,467		18,672

Total current assets		275,463		292,185
Unconsolidated investments		3,783		3,757
Deposits and other		25,477		22,194
Deferred charges		39,711		40,236
Property, plant and equipment, net ($1,479,345 and $1,477,580 related to VIEs, respectively)		1,560,127		1,518,532
Construction-in-process ($201,222 and $271,859 related to VIEs, respectively)		325,206		370,551
Deferred financing and lease costs, net		27,188		28,482
Intangible assets, net		37,145		38,781

Total assets	$	2,294,100	$	2,314,718

LIABILITIES AND EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	106,264	$	105,112
Billings in excess of costs and estimated earnings on uncompleted contracts		25,272		33,104
Current portion of long-term debt:
Limited and non-recourse (all related to VIEs):
Senior secured notes		32,460		21,464
Other loans		13,677		13,547
Full recourse		20,647		20,543

Total current liabilities		198,320		193,770
Long-term debt, net of current portion:
Limited and non-recourse (all related to VIEs):
Senior secured notes		330,161		341,157
Other loans		93,714		100,585
Full recourse:
Senior unsecured bonds (plus unamortized premium based upon 7% of $1,591)		249,888		250,042
Other loans		53,273		63,623
Revolving credit lines with banks		203,369		214,049
Liability associated with sale of tax benefits		60,247		69,269
Deferred lease income		67,686		68,955
Deferred income taxes		59,755		54,665
Liability for unrecognized tax benefits		6,712		5,875
Liabilities for severance pay		20,857		20,547
Asset retirement obligation		22,118		21,284
Other long-term liabilities		3,789		4,253

Total liabilities		1,369,889		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		46		46
Additional paid-in capital		728,873		725,746
Retained earnings		187,048		172,331
Accumulated other comprehensive income		482		595

		916,449		898,718
Noncontrolling interest		7,762		7,926

Total equity		924,211		906,644

Total liabilities and equity	$	2,294,100	$	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 June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(In thousands, except per share data)						(In thousands, except per share data)
Revenues:
Electricity	$	85,011		$	81,190		$	167,258		$	159,458
Product		44,826			23,424			94,931			42,976

Total revenues		129,837			104,614			262,189			202,434

Cost of revenues:
Electricity		57,953			62,212			115,884			128,149
Product		31,818			9,249			66,445			26,139

Total cost of revenues		89,771			71,461			182,329			154,288

Gross margin		40,066			33,153			79,860			48,146
Operating expenses:
Research and development expenses		1,464			2,575			2,512			4,782
Selling and marketing expenses		4,666			3,725			9,588			6,385
General and administrative expenses		6,793			7,479			14,107			14,486
Write-off of unsuccessful exploration activities		1,151			—			1,919			—

Operating income		25,992			19,374			51,734			22,493
Other income (expense):
Interest income		336			716			724			851
Interest expense, net		(14,263	)		(17,442	)		(29,141	)		(30,522	)
Foreign currency translation and transaction gains (losses)		(1,756	)		596			(1,742	)		1,113
Income attributable to sale of tax benefits		2,589			3,141			5,106			5,280
Other non-operating income, net		290			915			129			118

Income (loss), before income taxes and equity in losses of investees		13,188			7,300			26,810			(667	)
Income tax benefit (provision)		(4,309	)		1,007			(9,766	)		421
Equity in losses of investees		(157	)		(69	)		(297	)		(481	)

Net income (loss)		8,722			8,238			16,747			(727	)
Net income attributable to noncontrolling interest		(81	)		(105	)		(211	)		(115	)

Net income (loss) attributable to the Company’s stockholders	$	8,641		$	8,133		$	16,536		$	(842	)

Comprehensive income (loss):
Net income (loss)		8,722			8,238			16,747			(727	)
Other comprehensive loss, net of related taxes:
Amortization of unrealized gains or losses in respect of derivative instruments designated for cash flow hedge		(47	)		(53	)		(93	)		(106	)
Change in unrealized gains or losses on marketable securities available-for-sale		10			(186	)		(20	)		(209	)

Comprehensive income (loss)		8,685			7,999			16,634			(1,042	)
Comprehensive income attributable to noncontrolling interest		(81	)		(105	)		(211	)		(115	)

Comprehensive income (loss) attributable to the Company’s stockholders	$	8,604		$	7,894		$	16,423		$	(1,157	)

Earnings (loss) per share attributable to the Company’s stockholders — basic and diluted	$	0.19		$	0.18		$	0.36		$	(0.02	)

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		45,438			45,443			45,438			45,431

Dividend per share declared	$	0.04		$	0.04		$	0.04		$	0.09

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
	Common Stock				Additional Paid-in		Retained			Accumulated Other Comprehensive						Noncontrolling			Total
	Shares		Amount		Capital		Earnings			Income			Total			Interest			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		—		—		3,448		—			—			3,448			—			3,448
Increase in noncontrolling interest due to sale of equity interest in OPC LLC		—		—		2,343		—			—			2,343			1,848			4,191
Cash dividend declared, $0.09 per share		—		—		—		(4,107	)		—			(4,107	)		—			(4,107	)
Net income (loss)		—		—		—		(842	)		—			(842	)		115			(727	)
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 $64)		—		—		—		—			(106	)		(106	)		—			(106	)
Change in unrealized gains or losses on marketable securities available-for-sale (net of related tax of $0)		—		—		—		—			(209	)		(209	)		—			(209	)

Balance at June 30, 2011		45,431	$	46	$	722,522	$	216,362		$	729		$	939,659		$	8,058		$	947,717


Balance at December 31, 2011		45,431	$	46	$	725,746	$	172,331		$	595		$	898,718		$	7,926		$	906,644
Stock-based compensation		—		—		3,127		—			—			3,127			—			3,127
Cash paid to non-controlling interest		—		—		—		—			—			—			(375	)		(375	)
Cash dividend declared, $0.04 per share		—		—		—		(1,819	)		—			(1,819	)		—			(1,819	)
Net income		—		—		—		16,536			—			16,536			211			16,747
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 $57)		—		—		—		—			(93	)		(93	)		—			(93	)
Change in unrealized gains or losses on marketable securities available-for-sale (net of related tax of $0)		—		—		—		—			(20	)		(20	)		—			(20	)

Balance at June 30, 2012		45,431	$	46	$	728,873	$	187,048		$	482		$	916,449		$	7,762		$	924,211

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)


	Six Months Ended June 30,
	2012			2011
	(In thousands)
Cash flows from operating activities:
Net income (loss)	$	16,747		$	(727	)
Adjustments to reconcile net income or loss to net cash provided by operating activities:
Depreciation and amortization		49,757			48,005
Amortization of premium from senior unsecured bonds		(154	)		(65	)
Accretion of asset retirement obligation		834			781
Stock-based compensation		3,127			3,448
Amortization of deferred lease income		(1,343	)		(1,343	)
Income attributable to sale of tax benefits, net of interest expense		(1,900	)		(1,720	)
Equity in losses of investees		297			481
Impairment of auction rate securities		—			205
Write-off of unsuccessful exploration activities		1,919			—
Unrealized loss on interest rate lock transactions		—			4,735
Loss (Gain) on severance pay fund asset		364			(1,219	)
Premium from issuance senior unsecured bonds		—			1,957
Deferred income tax provision (benefit)		5,256			(992	)
Liability for unrecognized tax benefits		837			(1,051	)
Deferred lease revenues		74			89
Changes in operating assets and liabilities, net of amounts acquired:
Receivables		10,310			(17,312	)
Costs and estimated earnings in excess of billings on uncompleted contracts		(6,085	)		5,576
Inventories		(5,578	)		(1,870	)
Prepaid expenses and other		(5,795	)		(7,552	)
Deposits and other		(3,560	)		(485	)
Accounts payable and accrued expenses		14,901			(8,569	)
Due from/to related entities, net		(42	)		(52	)
Billings in excess of costs and estimated earnings on uncompleted contracts		(7,832	)		15,665
Liabilities for severance pay		310			1,859
Other long-term liabilities		(464	)		(488	)
Due from/to Parent		99			150

Net cash provided by operating activities		72,079			39,506

Cash flows from investing activities:
Marketable securities, net		13,280			(22,084	)
Net change in restricted cash, cash equivalents and marketable securities		(22,271	)		(3,806	)
Capital expenditures		(129,879	)		(109,614	)
Cash grant received		72,252			—
Investment in unconsolidated companies		(323	)		(305	)
Increase (decrease) in severance pay fund asset, net of payments made to retired employees		(87	)		68

Net cash used in investing activities		(67,028	)		(135,741	)

Cash flows from financing activities:
Proceeds from issuance of senior unsecured bonds		—			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		1,083,754			199,295
Repayment of revolving credit lines with banks		(1,094,434	)		(237,300	)
Repayments of long-term debt		(16,987	)		(23,043	)
Cash paid to non-controlling interest		(7,497	)		(7,035	)
Deferred debt issuance costs		(1,270	)		(2,377	)
Cash dividends paid		(1,819	)		(4,107	)

Net cash provided by (used in) financing activities		(38,253	)		57,758

Net change in cash and cash equivalents		(33,202	)		(38,477	)
Cash and cash equivalents at beginning of period		99,886			82,815

Cash and cash equivalents at end of period	$	66,684		$	44,338

Supplemental non-cash investing and financing activities:
Decrease in accounts payable related to purchases of property, plant and equipment	$	(13,749	)	$	(5,106	)

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 June 30, 2012, the consolidated results of operations and comprehensive income (loss) for the three and six-month periods ended June 30, 2012 and 2011 and the consolidated cash flows for the six-month periods ended June 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 six-month period ended June 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 June 30, 2012 and December 31, 2011, the Company had deposits totaling $16,056,000 and $39,569,000, respectively, in seven U.S. financial institutions that were federally insured up to $250,000 per account. At June 30, 2012 and December 31, 2011, the Company’s deposits in foreign countries amounted to approximately $51,493,000 and $57,838,000, respectively.

At June 30, 2012 and December 31, 2011, accounts receivable related to operations in foreign countries amounted to approximately $16,447,000 and $21,453,000, respectively. At June 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 54% and 58% of the Company’s accounts receivable, respectively.

Southern California Edison Company (“Southern California Edison”) accounted for 16.6% and 29.5% of the Company’s total revenues for the three months ended June 30, 2012 and 2011, respectively, and 18.2% and 28.3% for the six months ended June 30, 2012 and 2011, respectively.

Sierra Pacific Power Company and Nevada Power Company (subsidiaries of NV Energy, Inc.) accounted for 14.3% and 12.0% of the Company’s total revenues for the three months ended June 30, 2012 and 2011, respectively, and 13.6% and 14.1% for the six months ended June 30, 2012 and 2011, respectively.

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Hawaii Electric Light Company (“HELCO”) accounted for 10.0% and 11.8% of the Company’s total revenues for the three months ended June 30, 2012 and 2011, respectively, and 9.6% and 11.2% for the six months ended June 30, 2012 and 2011, respectively.

Kenya Power and Lighting Co. Ltd. accounted for 7.6% and 8.4% of the Company’s total revenues for the three months ended June 30, 2012 and 2011, respectively, and 7.4% and 8.6% for the six months ended June 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 June 30, 2012, letters of credit in the aggregate amount of $247.2 million remained issued and outstanding.

NOTE 2 — NEW ACCOUNTING PRONOUNCEMENTS

New Accounting Pronouncements Effective in the Six-Month Period Ended June 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 statement of financial position 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 Pronouncements 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:


	June 30, 2012		December 31, 2011
	(Dollars in thousands)
Raw materials and purchased parts for assembly	$	9,460	$	6,058
Self-manufactured assembly parts and finished products		8,659		6,483

Total	$	18,119	$	12,541

NOTE 4 — UNCONSOLIDATED INVESTMENTS

Unconsolidated investments consist of the following:


	June 30, 2012		December 31, 2011
	(Dollars in thousands)
Sarulla	$	2,438	$	2,215
Watts & More Ltd.		1,345		1,542

	$	3,783	$	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.

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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.

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. As of June 30, 2012, the Company held approximately 28.6% of W&M’s outstanding ordinary shares.

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 W&M will repay the loans (principal and interest) 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 the Company holds 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.

NOTE 5 — FAIR VALUE OF FINANCIAL INSTRUMENTS

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

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

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

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

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The following table sets forth certain fair value information at June 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 June 30, 2012		Fair Value at June 30, 2012
	Cost or Amortized Cost at June 30, 2012		Total			Level 1		Level 2			Level 3
	(Dollars in thousands)
Assets
Current assets:
Cash equivalents (including restricted cash accounts)	$	44,024	$	44,024		$	44,024	$	—		$	—
Marketable securities (including restricted accounts)		5,477		5,221			5,221		—			—
Derivatives⁽¹⁾		1,586		5,266			—		5,266			—
Liabilities:
Current liabilities:
Derivatives⁽²⁾		—		(785	)		—		(785	)		—

	$	51,087	$	53,726		$	49,245	$	4,481		$	—


	Cost or Amortized Cost at December 31, 2011		Fair Value at December 31, 2011
	Cost or Amortized Cost 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⁾

Amounts relating to a derivative that represents a European put option on natural gas 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⁾

Amounts relating to derivatives that 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).

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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

On April 18, 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 power purchase agreement (“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. 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. These contracts 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 gain from this transaction of $4.3 million in the six and three months ended June 30, 2012, resulting from the mark-to-market impact of these contracts.

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

On May 24, 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 economically hedge 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 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. This transaction has not been designated as a hedge transaction and is 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 this transaction of $0.5 million in the six and three months ended June 30, 2012.

On July 23, 2012, the Company entered into an additional European put contract. (See Note 13)

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

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


	Fair Value				Carrying Amount
	June 30, 2012		December 31, 2011		June 30, 2012		December 31, 2011
	(Dollars in millions)				(Dollars in millions)
Olkaria III loan	$	73.4	$	79.2	$	71.8	$	77.4
Amatitlan loan		35.9		37.2		35.5		36.8
Senior secured notes:
Ormat Funding Corp. (“OFC”)		118.7		114.8		125.0		125.0
OrCal Geothermal Inc. (“OrCal”)		80.1		84.4		85.9		85.9
OFC 2 LLC (“OFC 2”)		124.4		131.0		151.7		151.7
Senior unsecured bonds		238.7		252.8		248.3		248.3
Loans from institutional investors		30.2		34.2		30.6		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.

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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


	Level 1		Level 2		Level 3		Total
	(Dollars in millions)
Olkaria III loan	$	—	$	—	$	73.4	$	73.4
Amatitlan loan		—		—		35.9		35.9
Senior secured notes:
OFC		—		118.7		—		118.7
OrCal		—		—		80.1		80.1
OFC 2		—		—		124.4		124.4
Senior unsecured bonds		—		—		238.7		238.7
Loan from institutional investors		—		—		30.2		30.2
Other long-term debt		—		44.9		—		44.9
Revolving lines of credit		—		203.4		—		203.4
Deposits		20.3		—		—		20.3

NOTE 6 — STOCK-BASED COMPENSATION

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.

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

On August 1, 2012, the Company granted to four of its non-employee directors options to purchase 30,000 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 June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(Dollars in thousands)						(Dollars in thousands)
Interest related to sale of tax benefits		1,723			2,166		$	3,560		$	3,876
Loss on interest rate lock transactions*		—			4,002			—			4,735
Other interest expense		16,199			14,180			32,667			27,098
Less — amount capitalized		(3,659	)		(2,906	)		(7,086	)		(5,187	)

	$	14,263		$	17,442		$	29,141		$	30,522

*	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 employee 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 June 30,				Six Months Ended June 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 employee stock-based awards		7		12		7		—

Weighted average number of shares used in computation of diluted earnings (loss) per share		45,438		45,443		45,438		45,431

In the six months ended June 30, 2011, the employee 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.

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 5,337,772 and 4,272,124 for the three months ended June 30, 2012 and 2011, respectively, and 5,410,278 and 3,679,336 for the six months ended June 30, 2012 and 2011, respectively.

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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 June 30, 2012:
Net revenues from external customers	$	85,011	$	44,826	$	129,837
Intersegment revenues		—		8,941		8,941
Operating income		18,176		7,816		25,992
Segment assets at period end*		2,204,421		89,679		2,294,100
* Including unconsolidated investments		2,438		1,345		3,783
Three Months Ended June 30, 2011:
Net revenues from external customers	$	81,190	$	23,424	$	104,614
Intersegment revenues		—		17,387		17,387
Operating income		9,827		9,547		19,374
Segment assets at period end*		2,017,476		93,337		2,110,813
* Including unconsolidated investments		2,287		1,781		4,068
Six Months Ended June 30, 2012:
Net revenues from external customers	$	167,258	$	94,931	$	262,189
Intersegment revenues		—		21,907		21,907
Operating income		34,051		17,683		51,734
Segment assets at period end*		2,204,421		89,679		2,294,100
* Including unconsolidated investments		2,438		1,345		3,783
Six Months Ended June 30, 2011:
Net revenues from external customers	$	159,458	$	42,976	$	202,434
Intersegment revenues		—		30,749		30,749
Operating income		13,831		8,662		22,493
Segment assets at period end*		2,017,476		93,337		2,110,813
* Including unconsolidated investments		2,287		1,781		4,068

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 June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(Dollars in thousands)						(Dollars in thousands)
Operating income	$	25,992		$	19,374		$	51,734		$	22,493
Interest income		336			716			724			851
Interest expense, net		(14,263	)		(17,442	)		(29,141	)		(30,522	)
Foreign currency translation and transaction gains		(1,756	)		596			(1,742	)		1,113
Income attributable to sale of equity interest		2,589			3,141			5,106			5,280
Other non-operating income, net		290			915			129			118

Total income (loss), before income taxes and equity in losses of investees	$	13,188		$	7,300		$	26,810		$	(667	)

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. It still remains subject to final approval by the Court following notice to members of the class.

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 Company cannot make an estimate of the reasonably possible loss or range of reasonably possible loss for the state derivative case.

The two stockholder derivative cases filed in the United States District Court for the District of Nevada were consolidated by the Court in an order dated August 31, 2010, and plaintiffs filed a consolidated derivative complaint on October 28, 2010. The Company filed a motion to dismiss on December 13, 2010. On March 7, 2011, the Court 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 Company cannot make an estimate of the reasonably possible loss or range of reasonably possible loss for the federal derivative case.

The Company believes the allegations in these purported derivative actions are without merit.

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

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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.

NOTE 12 — INCOME TAXES

The Company’s effective tax rate for the three months ended June 30, 2012 and 2011 was 32.7% and 13.8%, respectively. The Company’s effective tax rate for the six months ended June 30, 2012 and 2011 was 36.4% and 63.1%, 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.

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.

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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 $85.1 million as of June 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.

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 six months ended June 30, 2011 by such amount.

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


	Six Months Ended June 30,
	2012		2011
	(Dollars in thousands)
Balance at beginning of period	$	5,875	$	5,431
Additions based on tax positions taken in prior years		837		325
Decrease for settlements with taxing authorities		—		(1,376	)

Balance at end of period	$	6,712	$	4,380

NOTE 13 — SUBSEQUENT EVENTS

Put Transaction on Natural Gas Prices

On July 23, 2012, the Company entered into a European put transaction with a 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

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

economically hedge 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 will be recorded as a current asset and will be 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 will be lower than the market price, no payment will be made. This transaction will not be designated as a hedge transaction 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).

Cash Dividend

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. The dividend will be payable on August 23, 2012.

Options Grant

On August 1, 2012, the Company granted to four non-employee directors non-qualified stock options, under the Company’s 2012 Incentive Plan (see Note 6), to purchase 30,000 shares of common stock (7,500 shares each) 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.

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:

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

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

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

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financial market conditions and the results of financing efforts;

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

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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;

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construction or other project delays or cancellations;

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

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

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contract counterparty risk;

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weather and other natural phenomena;

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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 and incentives for the production of renewable energy at the federal and state level in the United States and elsewhere, and carbon-related legislation;

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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;

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current and future litigation;

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our ability to successfully identify, integrate and complete acquisitions;

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

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

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

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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;

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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;

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

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

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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:

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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 six months ended June 30, 2012, our total revenues increased by 29.5% (from $202.4 million to $262.2 million) over the same period last year.

For the six months ended June 30, 2012, total Electricity Segment revenues were $167.3 million, compared to $159.5 million for the six months ended June 30, 2011, an increase of 4.9%, while Product Segment revenues were $94.9 million for the six months ended June 30, 2012, compared to $43.0 million for the six months ended June 30, 2011, an increase of 120.9%.

For the six months ended June 30, 2012, our Electricity Segment revenues represented approximately 63.8% of our total revenues, while our Product Segment revenues represented approximately 36.2% of our total revenues. For the six months ended June 30, 2011, our Electricity Segment revenues represented approximately 78.8% of our total revenues, while our Product Segment revenues represented approximately 21.2% of our total revenues.

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:

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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.

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The prices paid for the electricity pursuant to the 25 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 hedged our exposure to fluctuations in the price of natural gas and oil until December 31, 2012 and March 31, 2013, respectively, as described below under the heading “Recent Developments”.

In the six months ended June 30, 2012, approximately 76.2% of our Electricity Segment revenues were derived from contracts 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.

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On July 23, 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 Natural Gas — California SoCal — NGI (NGI). We entered into this transaction in order to economically hedge our exposure to NGI below $3.19 per MMbtu under our California SO#4 PPAs with Southern California Edison Company (Southern California Edison). We paid an up-front premium of approximately $0.2 million that will be recorded as a current asset and will be 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. This transaction will not be designated as a hedge transaction and will be marked to market with the corresponding gains or losses recognized within electricity revenues.

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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.

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In July 2012, our 30 MW McGinness Hills geothermal power plant in Nevada is in full operation under the OFC 2 Senior Secured Notes requirements. We expect that the full energy price under the PPA will be paid retroactive from July 1, 2012 once we receive the off-taker’s commercial operation date approval.

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In the second quarter of 2012, we received approximately $72.3 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 and Tuscarora geothermal power plants.

•

On May 25, 2012, NV Energy, Inc. (NV Energy) approved the commercial operation date of our 18 MW Tuscarora power plant in Nevada and the full energy price under the PPA will be paid retroactive to January 1, 2012.

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On May 24, 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 economically hedge 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. This transaction has not been designated as a hedge transaction and is marked to market with the corresponding gains or losses recognized within electricity revenues.

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On May 22, 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, 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.

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On April 18, 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, to reduce our exposure to fluctuations in the energy rate under our 25 MW PPA for the Puna complex as a result of fluctuations in oil prices. We 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 Hawaii Electric Light Company (HELCO) uses to calculate the energy rate. 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. These contracts have not been designated as hedge transactions and are marked to market with the corresponding gains or losses recognized within electricity revenues.

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On February 16, 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 megawatts (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.

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On January 30, 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.

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In our Product Segment, we expect our increased backlog to have a positive impact on our revenues in that segment over the next couple of years.

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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.

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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 California Public Utilities Commission (CPUC) recently authorized the utilities to procure 1,299 MW through a Renewable Auction Mechanism (RAM), 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 increased demand in California in the short term driven by the RAM program and after 2016 driven by the impact of the increase in California’s RPS, as one of the most significant opportunities for us to expand existing power plants and develop new power plants.

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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.

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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.

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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. However, we believe that this is a temporary market condition and remain confident in our ability to secure new long-term PPAs.

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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.

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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, we have entered into swap contracts to reduce our exposure to fluctuations in the energy rate caused by fluctuations in oil prices through March 31, 2013.

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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.

•

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

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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.

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

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

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Our foreign operations are subject to significant political, 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.

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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 contracts 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 quarter of 2012, we economically hedged our exposure to 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, 2012 and March 31, 2013, respectively.

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. 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 increase over the next two years 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 June 30,				Six Months Ended June 30,				Three Months Ended June 30,						Six Months Ended June 30,
	2012		2011		2012		2011		2012			2011			2012			2011
Revenues:
Electricity	$	85,011	$	81,190	$	167,258	$	159,458		65.5	%		77.6	%		63.8	%		78.8	%
Product		44,826		23,424		94,931		42,976		34.5			22.4			36.2			21.2

Total	$	129,837	$	104,614	$	262,189	$	202,434		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 Segment for the periods indicated:


	Revenues in Thousands								% of Revenues for Period Indicated
	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended June 30,						Six Months Ended June 30,
	2012		2011		2012		2011		2012			2011			2012			2011
United States	$	64,487	$	61,958	$	126,731	$	121,449		75.9	%		76.3	%		75.8	%		76.2	%
Foreign		20,524		19,232		40,527		38,009		24.1			23.7			24.2			23.8

Total	$	85,011	$	81,190	$	167,258	$	159,458		100.0	%		100.0	%		100.0	%		100.0	%

For the three and six-month periods ended June 30, 2012 and 2011, all of our revenues attributable to our Product Segment were generated outside of the United States.

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 4.4% and 3.4%, respectively, of total Electricity Segment revenues for the six months ended June 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 and Marketable Securities

Our cash, cash equivalents and marketable securities as of June 30, 2012 decreased to $71.9 million from $118.4 million as of December 31, 2011. This decrease was principally due to: (i) our use of $129.9 million to fund capital expenditures; (ii) repayment of $17.0 million of long-term debt; (iii) $7.5 million of cash paid to the Class B membership units of OPC LLC (OPC) (see “OPC Transaction” below); (iv) net repayment of $10.7 million to borrowers under our revolving credit lines with commercial banks; and (v) net increase of $22.3 million in restricted cash, cash equivalents and marketable securities, restricted for a debt service payment of $15.4 million under the OFC and OrCal Senior Secured Notes on July 2, 2012. The decrease in our cash resources was partially offset by: (i) $72.1 million derived from operating activities during the six months ended June 30, 2012; and (ii) cash grants in the total amount of $72.3 million received from the U.S. Treasury under Section 1603 of the ARRA in the second quarter of 2012 relating to the enhancement of our Puna geothermal complex and to our Jersey Valley and Tuscarora geothermal power plants. Our corporate borrowing capacity under committed lines of credit with different commercial banks as of June 30, 2012 was $466.8 million, as described below in the section entitled “Liquidity and Capital Resources,” of which we utilized $402.0 million (including $213.8 million of letters of credit) as of June 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 acquired power plants; and (ii) fluctuation in revenues from our Product Segment.


	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(In thousands, except per share data)						(In thousands, except per share data)
Statements of Operations Historical Data:
Revenues:
Electricity	$	85,011		$	81,190		$	167,258		$	159,458
Product		44,826			23,424			94,931			42,976

		129,837			104,614			262,189			202,434

Cost of revenues:
Electricity		57,953			62,212			115,884			128,149
Product		31,818			9,249			66,445			26,139

		89,771			71,461			182,329			154,288

Gross margin:
Electricity		27,058			18,978			51,374			31,309
Product		13,008			14,175			28,486			16,837

		40,066			33,153			79,860			48,146
Operating expenses:
Research and development expenses		1,464			2,575			2,512			4,782
Selling and marketing expenses		4,666			3,725			9,588			6,385
General and administrative expenses		6,793			7,479			14,107			14,486
Write-off of unsuccessful exploration activities		1,151			—			1,919			—

Operating income		25,992			19,374			51,734			22,493
Other income (expense):
Interest income		336			716			724			851
Interest expense, net		(14,263	)		(17,442	)		(29,141	)		(30,522	)
Foreign currency translation and transaction gains (losses)		(1,756	)		596			(1,742	)		1,113
Income attributable to sale of tax benefits		2,589			3,141			5,106			5,280
Other non-operating income, net		290			915			129			118

Income (loss), before income taxes and equity in losses of investees		13,188			7,300			26,810			(667	)
Income tax benefit (provision)		(4,309	)		1,007			(9,766	)		421
Equity in losses of investees		(157	)		(69	)		(297	)		(481	)

Net income (loss)		8,722			8,238			16,747			(727	)
Net income attributable to noncontrolling interest		(81	)		(105	)		(211	)		(115	)

Net income (loss) attributable to the Company’s stockholders	$	8,641		$	8,133		$	16,536		$	(842	)

Earnings (loss) per share attributable to the Company’s stockholders — basic and diluted	$	0.19		$	0.18		$	0.36		$	(0.02	)

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		45,438			45,443			45,438			45,431


	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Statements of Operations Percentage Data:
Revenues:
Electricity		65.5	%		77.6	%		63.8	%		78.8	%
Product		34.5			22.4			36.2			21.2

		100.0			100.0			100.0			100.0

Cost of revenues:
Electricity		68.2			76.6			69.3			80.4
Product		71.0			39.5			70.0			60.8

		69.1			68.3			69.5			76.2

Gross margin:
Electricity		31.8			23.4			30.7			19.6
Product		29.0			60.5			30.0			39.2

		30.9			31.7			30.5			23.8
Operating expenses:
Research and development expenses		1.1			2.5			1.0			2.4
Selling and marketing expenses		3.6			3.6			3.7			3.2
General and administrative expenses		5.2			7.1			5.4			7.2
Write-off of unsuccessful exploration activities		0.9			0.0			0.7			0.0
Operating income		20.0			18.5			19.7			11.1
Other income (expense):
Interest income		0.3			0.7			0.3			0.4
Interest expense, net		(11.0	)		(16.7	)		(11.1	)		(15.1	)
Foreign currency translation and transaction gains (losses)		(1.4	)		0.6			(0.7	)		0.5
Income attributable to sale of tax benefits		2.0			3.0			1.9			2.6
Other non-operating income, net		0.2			0.9			0.0			0.1

Income (loss), before income taxes and equity in losses of investees		10.2			7.0			10.2			(0.3	)
Income tax benefit (provision)		(3.3	)		1.0			(3.7	)		0.2
Equity in losses of investees		(0.1	)		(0.1	)		(0.1	)		(0.2	)

Net income (loss)		6.7			7.9			6.4			(0.4	)
Net income attributable to noncontrolling interest		(0.1	)		(0.1	)		(0.1	)		(0.1	)

Net income (loss) attributable to the Company’s stockholders		6.7	%		7.8	%		6.3	%		(0.4	)%

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

Total Revenues

Total revenues for the three months ended June 30, 2012 were $129.8 million, compared to $104.6 million for the three months ended June 30, 2011, which represented a 24.1% increase in total revenues. This increase was principally attributable our Product Segment, in which revenues increased by 91.4% over the same period last year.

Electricity Segment

Revenues attributable to our Electricity Segment for the three months ended June 30, 2012 were $85.0 million, compared to $81.2 million for the three months ended June 30, 2011, which represented a 4.7% increase. This increase was primarily due to: (i) $4.1 million in revenues from our Tuscarora power plant which

commenced commercial operations in January 2012 (the amount includes $1.3 million of adjusted revenues from the first quarter of 2012 due to full energy rate payments retroactive to the commencement of commercial operation); (ii) $3.5 million net increase in revenues from other power plants, and (iii) a net gain of $3.8 million on two swap contracts on oil prices and a put transaction on natural gas prices, which are described above under the heading “Recent Developments”. These transactions are not designated as hedge transactions for accounting purposes. This increase was partially offset by a $7.6 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 subject to the impact of fluctuations in natural gas prices. The generation in our power plants increased by 3.9%, from 957,128 MWh in the three months ended June 30, 2011, to 994,399 MWh in the three months ended June 30, 2012, and the average revenue rate of our electricity portfolio was $85 per MWh in each of the three months ended June 30, 2011 and 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 in the second quarter of 2012 slightly decreased to $4.6 million from $4.8 million during the same quarter in 2011.

Product Segment

Revenues attributable to our Product Segment for the three months ended June 30, 2012 were $44.8 million, compared to $23.4 million for the three months ended June 30, 2011, which represented a 91.4% 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 three months ended June 30, 2012 was $89.8 million, compared to $71.5 million for the three months ended June 30, 2011, which represented an increase of 25.6%. 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 June 30, 2012 was 69.1%, compared to 68.3% for the same period in 2011. The increase in cost of revenues as a percentage of total revenues was attributable to our Product Segment, as described below. The increase was partially offset by a decrease in cost of revenues attributable to our Electricity Segment.

Electricity Segment

Total cost of revenues attributable to our Electricity Segment for the three months ended June 30, 2012 was $58.0 million, compared to $62.2 million for the three months ended June 30, 2011, which represented a 6.8% decrease. The cost per MWh in the current quarter was lower than in the second quarter of 2011 as a result of lower maintenance costs in most of our power plants and specifically at the North Brawley power plant, where we incurred costs of $7.3 million associated with operating and maintaining the plant in the second quarter of 2012, compared to $10.4 million in the second quarter of 2011. We were able to improve our operating efficiencies, specifically in the maintenance of our wellfield. As a percentage of total electricity revenues, the total cost of revenues attributable to our Electricity Segment for the three months ended June 30, 2012 was 68.2%, compared to 76.6% for the three months ended June 30, 2011.

Product Segment

Total cost of revenues attributable to our Product Segment for the three months ended June 30, 2012 was $31.8 million, compared to $9.2 million for the three months ended June 30, 2011, which represented a 244.0% 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 June 30, 2012 was 71.0%, compared to 39.5% for the three months ended June 30, 2011. The increase was mainly attributable to the recognition of revenues in the amount of $7.9 million relating to an LNG energy recovery unit in Spain in the three months ended June 30, 2011, with virtually no associated cost of revenues, since the related costs were included in research and development costs in previous periods.

Research and Development Expenses

Research and development expenses for the three months ended June 30, 2012 were $1.5 million, compared to $2.6 million for the three months ended June 30, 2011, which represented a 43.1% decrease. This decrease was primarily attributable to the costs incurred in the second quarter of 2011 in respect of an experimental LNG energy recovery unit which was completed in 2011. Our research and development activities during the three months ended June 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 June 30, 2012 were $4.7 million, compared to $3.7 million for the three months ended June 30, 2011, which represented a 25.3% 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 June 30, 2012 and June 30, 2011 constituted 3.6% of total revenues.

General and Administrative Expenses

General and administrative expenses for the three months ended June 30, 2012 were $6.8 million, compared to $7.5 million for the three months ended June 30, 2011, which represented a 9.2% decrease. The decrease was mainly attributable to lower bonus payments to our officers and employees in the second quarter of 2012, compared to the second quarter of 2011. General and administrative expenses for the three months ended June 30, 2012 constituted 5.2% of total revenues, compared to 7.1% for the three months ended June 30, 2011.

Write-off of Unsuccessful Exploration Activities

Write-off of unsuccessful exploration activities for the three months ended June 30, 2012 was $1.2 million. This represented the write-off of exploration costs related to several projects in Nevada, which we determined in the second quarter of 2012 would not support commercial operations. We did not have a write-off of unsuccessful exploration activities in the three months ended June 30, 2011.

Operating Income

Operating income for the three months ended June 30, 2012 was $26.0 million, compared to $19.4 million for the three months ended June 30, 2011. The increase of $6.6 million in operating income was principally attributable to an increase in our gross margin due to the increase in revenues, as described above. Operating income attributable to our Electricity Segment for the three months ended June 30, 2012 was $18.2 million, compared to $9.8 million for the three months ended June 30, 2011. Operating income attributable to our Product Segment for the three months ended June 30, 2012 was $7.8 million, compared to $9.5 million for the three months ended June 30, 2011. This decrease was attributable to the fact that we did not record any costs associated with revenues of $7.9 million relating to the LNG energy project in the second quarter of 2011, as described above.

Interest Expense, Net

Interest expense, net for the three months ended June 30, 2012 was $14.3 million, compared to $17.4 million for the three months ended June 30, 2011, which represented an 18.2% decrease. The decrease was primarily attributable to: (i) a $4.0 million loss in the three months ended June 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 $0.8 million in interest capitalized to projects as a result of increased aggregate investment in projects under construction.

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 June 30, 2012 was $2.6 million, compared to $3.1 million for the three months ended June 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 three months ended June 30, 2012 was $4.3 million, compared to income tax benefit of $1.0 million for the three months ended June 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 June 30, 2012 was 32.7%, compared to 13.8% for the three months ended June 30, 2011. The increase in the effective tax rate primarily resulted from the increase in the valuation allowance referred to above.

Net Income

Net income for the three months ended June 30, 2012 was $8.7 million, compared to $8.2 million for the three months ended June 30, 2011. The increase in net income of $0.5 million was principally attributable to: (i) a $6.6 million increase in operating income; and (ii) a $3.2 million decrease in interest expense, net of capitalized interest . The increase was partially offset by: (i) a $5.3 million increase in income tax provision; and (ii) a $2.4 million increase in foreign currency transaction losses.

Comparison of the Six Months Ended June 30, 2012 and the Six Months Ended June 30, 2011

Total Revenues

Total revenues for the six months ended June 30, 2012 were $262.2 million, compared to $202.4 million for the six months ended June 30, 2011, which represented a 29.5% increase in total revenues. This increase was principally attributable to our Product Segment, in which revenues increased by 120.9% over the same period last year.

Electricity Segment

Revenues attributable to our Electricity Segment for the six months ended June 30, 2012 were $167.3 million, compared to $159.5 million for the six months ended June 30, 2011, which represented a 4.9% increase. This increase was primarily due to: (i) an increase in the electricity rates in our Puna complex and Amatitlan power plant, whose energy payments are variable; (ii) $5.4 million in revenues from our Tuscarora power plant which commenced commercial operations in January 2012; and (iii) a net gain of $3.8 million on two swap contracts on oil prices and a put transaction on natural gas prices, which are described above under the heading

“Recent Developments”. This increase was partially offset by a $7.6 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. As a result, the average revenue rate of our electricity portfolio increased from $80 per MWh in the six months ended June 30, 2011, to $82 per MWh in the six months ended June 30, 2012. The generation in our power plants increased by 2.5% from 1,984,750 MWh in the six months ended June 30, 2011, to 2,034,064 MWh in the six months ended June 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 six months ended June 30, 2012 decreased to $7.8 million from $8.7 million during the same period in 2011.

Product Segment

Revenues attributable to our Product Segment for the six months ended June 30, 2012 were $94.9 million, compared to $43.0 million for the six months ended June 30, 2011, which represented a 120.9% 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 six months ended June 30, 2012 was $182.3 million, compared to $154.3 million for the six months ended June 30, 2011, which represented an increase of 18.2%. 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 six months ended June 30, 2012 was 69.5%, compared to 76.2% 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 attributable to our Electricity Segment.

Electricity Segment

Total cost of revenues attributable to our Electricity Segment for the six months ended June 30, 2012 was $115.9 million, compared to $128.1 million for the six months ended June 30, 2011, which represented a 9.6% decrease. The cost per MWh in the six months ended June 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 $14.6 million associated with operating and maintaining the plant in the six months ended June 30, 2012, compared to $24.8 million in the six months ended June 30, 2011. We were able to improve our operating efficiencies specifically in the maintenance of our wellfields. As a percentage of total electricity revenues, the total cost of revenues attributable to our Electricity Segment for the six months ended June 30, 2012 was 69.3%, compared to 80.4% for the six months ended June 30, 2011.

Product Segment

Total cost of revenues attributable to our Product Segment for the six months ended June 30, 2012 was $66.4 million, compared to $26.1 million for the six months ended June 30, 2011, which represented a 154.2% increase. As a percentage of total Product Segment revenues, our total cost of revenues attributable to this segment for the six months ended June 30, 2012 was 70.0%, compared to 60.8% for the six months ended June 30, 2011. This increase in Product Segment cost of revenues as a percentage of total product revenues is mainly attributable to the recognition of revenues in the amount of $3.0 million relating to an LNG energy recovery unit in Spain in the six months ended June 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. The increase was partially offset by the impact of: (i) higher revenues; (ii) a different product mix; and (iii) different margins in the various sales contracts.

Research and Development Expenses

Research and development expenses for the six months ended June 30, 2012 were $2.5 million, compared to $4.8 million for the six months ended June 30, 2011, which represented a 47.5% decrease. This decrease was primarily attributable to the costs incurred in the six months ended June 30, 2011 in respect of an experimental LNG energy recovery unit which was completed in 2011. Our research and development activities during the six months ended June 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 six months ended June 30, 2012 were $9.6 million, compared to $6.4 million for the six months ended June 30, 2011, which represented a 50.2% increase. The increase reflects additional selling and marketing expenses associated with the increased Product Segment revenues. Selling and marketing expenses for the six months ended June 30, 2012 constituted 3.7% of total revenues, compared to 3.2% for the six months ended June 30, 2011.

General and Administrative Expenses

General and administrative expenses for the six months ended June 30, 2012 were $14.1 million, compared to $14.5 million for the six months ended June 30, 2011, which represented a 2.6% decrease. The decrease was mainly attributable to lower bonus payments to our officers and employees in the six months ended June 30, 2012, compared to the six months ended June 30, 2011. General and administrative expenses for the six months ended June 30, 2012 constituted 5.4% of total revenues, compared to 7.2% for the six months ended June 30, 2011.

Write-off of Unsuccessful Exploration Activities

Write-off of unsuccessful exploration activities for the six months ended June 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 six months ended June 30, 2012 would not support commercial operations. We did not have a write-off of unsuccessful exploration activities in the six months ended June 30, 2011.

Operating Income

Operating income for the six months ended June 30, 2012 was $51.7 million, compared to $22.5 million for the six months ended June 30, 2011. The increase of $29.2 million in operating income was principally attributable to an increase in our gross margin due to the increase in revenues, as described above. Operating income attributable to our Electricity Segment for the six months ended June 30, 2012 was $34.1 million, compared to $13.8 million for the six months ended June 30, 2011. Operating income attributable to our Product Segment for the six months ended June 30, 2012 was $17.7 million, compared to $8.7 million for the six months ended June 30, 2011.

Interest Expense, Net

Interest expense, net for the six months ended June 30, 2012 was $29.1 million, compared to $30.5 million for the six months ended June 30, 2011, which represented a 4.5% decrease. The decrease is primarily due to: (i) a $4.7 million loss in the six months ended June 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 $1.9 million in interest capitalized to projects as a result of increased aggregate investment in projects under

construction, offset by additional interest expense of $5.6 million 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.

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 six months ended June 30, 2012 was $5.1 million, compared to $5.3 million for the six months ended June 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 MACRS.

Income Taxes

Income tax provision for the six months ended June 30, 2012 was $9.8 million, compared to income tax benefit of $0.4 million for the six months ended June 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 six months ended June 30, 2012 was 36.4%, compared to 63.1% for the six months ended June 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 (Loss)

Net income for the six months ended June 30, 2012 was $16.7 million, compared to net loss of $0.7 million for the six months ended June 30, 2011. The increase in net income of $17.4 million was principally attributable to: (i) a $29.2 million increase in operating income; and (ii) a $1.4 million decrease in interest expense, net of capitalized interest. The increase was partially offset by: (i) a $2.9 million increase in foreign currency transaction losses; and (ii) a $10.2 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, 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 June 30, 2012, we have access to: (i) $71.9 million in cash, cash equivalents and marketable securities; and (ii) $64.8 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 $140.0 million for capital expenditures on new projects in development or construction, exploration activity, operating projects, and machinery and equipment, as well as $38.6 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; (iii) future project financing and refinancing (including construction loans); and (iv) cash grants available to us under the ARRA relating to new projects that will be placed in service before the end of 2013. Management believes that these sources will meet our anticipated liquidity, capital expenditures and other investment requirements.

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 which commenced on September 30, 2004. The OFC Senior Secured Notes are collateralized by substantially all of the assets of OFC and those of its wholly owned subsidiaries and are fully and unconditionally guaranteed by all of the wholly owned subsidiaries of OFC. There are various restrictive covenants under the OFC Senior Secured Notes, which include limitations on additional indebtedness 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 June 30, 2012, there were $125.0 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 that commenced on September 30, 2006. The OrCal Senior Secured Notes are collateralized by substantially all of the assets of OrCal and those of its wholly owned subsidiaries and are fully and unconditionally guaranteed by all of the wholly owned subsidiaries of OrCal. There are various restrictive covenants under the OrCal Senior Secured Notes, which include limitations on additional indebtedness 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 June 30, 2012, there were $85.9 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. Interest on the Series A Notes is payable quarterly in arrears on the last day of March, June, September and December, commencing December 31, 2011. Principal on the Series A Notes is payable on the same quarterly dates, commencing September 30, 2012.

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), which will be measured after the McGinness Hills and Tuscarora facilities have been constructed and have met certain completion requirements.

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 June 30, 2012, there were $151.7 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 30, 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 June 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. As a result of new tax regulations in Guatemala we need to gross up a 10% withholding tax on the interest paid to TCW, which increases the effective cost of the loan by approximately 1% during the period from March 13, 2012 to December 31, 2012. 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 June 30, 2012, the projected 12-month DSCR was 1.56 and the debt to equity ratio was 1.96. As of June 30, 2012, $35.5 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

In September 2011, one of our subsidiaries, Ormat International, Inc. (Ormat International), signed a commitment letter with the Overseas Private Investment Corporation (OPIC) to provide project financing of up to $310.0 million to refinance and expand our Olkaria III geothermal complex located in Kenya. Under the agreed term sheet attached to the commitment letter and subsequent negotiations, we expect the loan to be comprised of: (i) a refinancing tranche of up to $85.0 million to prepay or subordinate the existing loan with DEG and fund transaction costs; (ii) a construction loan tranche of up to $180.0 million to finance the construction of an additional 36 MW expansion, which is currently underway; and (iii) a $45.0 million stand-by facility to finance an optional additional capacity expansion of up to 16 MW, that, if exercised by Ormat International, could bring the total capacity of the complex to approximately 100 MW. The maturity dates of the construction tranche and the refinancing tranche are expected to be June 2030 and December 2030, respectively. The maturity date and certain other terms of the stand-by facility will be finalized following our decision, if any, to exercise the option to construct the additional capacity expansion of up to 16 MW.

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 June 30, 2012: (i) the actual 12-month debt to EBITDA ratio was 3.36; (ii) the 12-month DSCR was 2.65; and (iii) the distribution leverage ratio was 0.72. 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 June 30, 2012, letters of credit in the aggregate amount of $39.8 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 $416.8 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 $311.8 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.

As of June 30, 2012, loans in the total amount of $203.4 million (including $10.0 million under a non-committed line of credit with an additional commercial bank) were outstanding, and letters of credit with an aggregate stated amount of $178.9 million were issued and outstanding under these credit agreements. The $203.4 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 June 30, 2012, $12.6 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 June 30, 2012, $18.3 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 June 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 June 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 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 June 30, 2012: (i) total equity was $924.2 million and the actual equity to total assets ratio was 40.3%; (ii) the 12-month debt, net of cash, cash equivalents and marketable securities to EBITDA ratio was 4.8; and (iii) dividend distributions were less than 35% of net income for the first half 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 June 30, 2012, letters of credit in the aggregate amount of $247.2 million remained issued and outstanding (out of which $213.8 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 $33.4 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 $6.7 million as of June 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, but believe that the ultimate settlement of our obligations will not materially affect our liquidity.

Dividends

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


Date Declared	Dividend Amount per Share		Record Date	Payment Date
August 4, 2010	$	0.05	August 17, 2010	August 26, 2010
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:


	Six Months Ended June 30,
	2012			2011
	(In thousands)
Net cash provided by operating activities	$	72,079		$	39,506
Net cash used in investing activities		(67,028	)		(135,741	)
Net cash provided by (used in) financing activities		(38,253	)		57,758
Net change in cash and cash equivalents		(33,202	)		(38,477	)

For the Six Months Ended June 30, 2012

Net cash provided by operating activities for the six months ended June 30, 2012 was $72.1 million, compared to $39.5 million for the six months ended June 30, 2011. The net increase of $32.6 million resulted primarily from: (i) an increase in net income to $16.7 million in the six months ended June 30, 2012, from net loss of $0.7 million in the six months ended June 30, 2011, mainly as a result of an increase in our operating income as described above; (ii) a decrease in receivables of $10.3 million in the six months ended June 30, 2012, compared to an increase of $17.3 million in the six months ended June 30, 2011, as a result of timing of collections from our customers; (iii) an increase in accounts payable and accrued expenses of $14.9 million in the

six months ended June 30, 2012, compared to a decrease of $8.6 million in the six months ended June 30, 2011, as a result of timing of payments to our vendors; and (iv) an increase in deferred income tax provision, net of $5.3 million in the six months ended June 30, 2012, compared to a decrease of $1.0 million in the six months ended June 30, 2011. Such increase was partially offset by a decrease in billing in excess of costs and estimated earnings on uncompleted contracts, net of $13.9 million relating to our Product Segment in the six months ended June 30, 2012, compared to an increase of $21.2 million in the six months ended June 30, 2011, as a result of timing in billing of our customers.

Net cash used in investing activities for the six months ended June 30, 2012 was $67.0 million, compared to $135.7 million for the six months ended June 30, 2011. The principal factors that affected our net cash used in investing activities during the six months ended June 30, 2012 were: (i) capital expenditures of $129.9 million, primarily for our facilities under construction; and (ii) net increase of $22.3 million in restricted cash, cash equivalents and marketable securities, offset by: (i) cash grant in the amount of $72.3 million received in the six months ended June 30, 2012 from the U.S. Treasury under Section 1603 of the ARRA in the second quarter of 2012 relating to the enhancement of our Puna geothermal complex and to our Jersey Valley and Tuscarora geothermal power plants; and (ii) net decrease of $13.3 million in marketable securities. The principal factors that affected our net cash used in investing activities during the six months ended June 30, 2011 were: (i) capital expenditures of $109.6 million, primarily for our power facilities under construction; (ii) net increase of $3.8 million in restricted cash, cash equivalents and marketable securities; and (iii) net increase of $22.1 million in marketable securities.

Net cash used in financing activities for the six months ended June 30, 2012 was $38.3 million, compared to net cash provided by financing activities of $57.8 million for the six months ended June 30, 2011. The principal factors that affected the net cash used in financing activities during the six months ended June 30, 2012 were: (i) a net decrease of $10.7 million against our revolving lines of credit with commercial banks; (ii) the repayment of long-term debt in the amount of $17.0 million; and (iii) $7.5 million of cash paid to the Class B membership units of OPC (see “OPC Transaction” above). The principal factors that affected our net cash provided by financing activities during the six months ended June 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, offset by: (i) the repayment of long-term debt in the amount of $23.0 million; (ii) a net decrease of $38.0 million against our revolving lines of credit with commercial banks; (iii) cash paid to non-controlling interest in the amount of $7.0 million; and (iv) the payment of a dividend to our shareholders in the amount of $4.1 million.

EBITDA

We calculate EBITDA as net income before interest, taxes, depreciation and amortization. EBITDA is not a measurement 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 is presented because we believe it is 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 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.

EBITDA for the three months ended June 30, 2012 was $50.8 million, compared to $47.7 million for the three months ended June 30, 2011. EBITDA for the six months ended June 30, 2012 was $102.3 million, compared to $74.8 million for the six months ended June 30, 2011.

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


	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(In thousands)						(In thousands)
Net cash provided by operating activities	$	30,205		$	26,440		$	72,079		$	39,506
Adjusted for:
Interest expense, net (excluding amortization of deferred financing costs)		13,082			16,528			26,729			28,824
Interest income		(336	)		(716	)		(724	)		(851	)
Income tax provision		4,309			(1,007	)		9,766			(421	)
Adjustments to reconcile net income or loss to net cash provided by operating activities (excluding depreciation and amortization)		3,530			6,433			(5,575	)		7,772

EBITDA		50,790			47,678		$	102,275		$	74,830

Net cash used in investing activities	$	(4,695	)	$	(27,817	)	$	(67,028	)	$	(135,741	)

Net cash provided by (used in) financing activities	$	(43,406	)	$	5,040		$	(38,253	)	$	57,758

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. We are evaluating the results of a core hole that we drilled and are waiting for permits for other drilling locations.

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 plan to repower the Mammoth complex located in Mammoth Lakes, California, by replacing part of the old units with new Ormat-manufactured equipment. The replacement of the equipment will optimize generation and add approximately 3 MW of generating capacity to the complex. We have not yet received the required permits to start construction. As a result, we suspended the equipment fabrication and expect delays in the execution of the project.

Olkaria III Phase 3. Development of Phase 3 of the Olkaria III complex located in Naivasha, Kenya is in process. Field development and manufacturing of the power plant equipment for a new 36 MW power plant at the Olkaria III complex are in advanced stages. 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. We are continuing with the drilling activity. The new power plant is expected to come online in 2013. Actual generation capacity will be determined based on field development results.

We have estimated approximately $597.0 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 $159.0 million as of June 30, 2012. We expect to invest an additional $90.0 million of such total during the remainder of 2012. The remaining $348.0 million will be invested in 2013.

In addition, we estimate approximately $50.0 million in additional capital expenditures during the remainder of 2012 to be allocated as follows: (i) $3.0 million for development of new projects; (ii) $34.0 million for enhancement of our operating power plants; (iii) $9.0 million for exploration activities in various leases for geothermal resources in which we have started the exploration activity; and (iv) $4.0 million for enhancement of our production facilities. In the aggregate, we estimate our total capital expenditures for the remainder of 2012 to be approximately $140.0 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. A prolonged economic slowdown could reduce worldwide demand for energy, including our geothermal energy, REG and other products.

One market risk to which power plants are typically exposed is the volatility of electricity prices. Our exposure to such market risk is currently limited because 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 2012, we entered into a put transaction to economically hedge our exposure to the price of natural gas, under the above PPAs, until December 31, 2012. 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 to economically hedge our exposure to the price of oil, under the 25 MW PPA of the Puna complex, until March 31, 2013.

As of June 30, 2012, 73.3% 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, 26.7% of our debt was in the form of a floating rate instrument, exposing us to changes in interest rates in connection therewith. As of June 30, 2012, $265.8 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 16.6% and 29.5% of the Company’s total revenues for the three months ended June 30, 2012 and 2011, respectively, and 18.2% and 28.3% for the six months ended June 30, 2012 and 2011, respectively.

HELCO accounted for 10.0% and 11.8% of the Company’s total revenues for the three months ended June 30, 2012 and 2011, respectively, and 9.6% and 11.2% for the six months ended June 30, 2012 and 2011, respectively.

KPLC accounted for 7.6% and 8.4% of the Company’s total revenues for the three months ended June 30, 2012 and 2011, respectively, and 7.4% and 8.6% for the six months ended June 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 June 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 second 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. It still remains subject to final approval by the Court following notice to members of the class.

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 Company cannot make an estimate of the reasonably possible loss or range of reasonably possible loss for the state derivative case.

The two stockholder derivative cases filed in the United States District Court for the District of Nevada were consolidated by the Court in an order dated August 31, 2010, and plaintiffs filed a consolidated derivative complaint on October 28, 2010. The Company filed a motion to dismiss on December 13, 2010. On March 7, 2011, the Court 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 lawsuit. The Company cannot make an estimate of the reasonably possible loss or range of reasonably possible loss for the federal derivative case.

The Company believes the allegations in these purported derivative actions are without merit.

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.

ITEM 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

There were no unregistered sales of equity securities of the Company during the second 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..

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.


Exhibit No.		Document

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

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

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

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

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: August 6, 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..

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.


Exhibit No.		Document

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

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

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

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