ORMAT TECHNOLOGIES, INC. - Quarter Report: 2009 June (Form 10-Q)

e10vq

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, 2009
		or
o		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)

Registrant’s telephone number, including area code:

(775) 356-9029

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 o

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 o No o

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 þ	Accelerated filer o	Non-accelerated filer o	Smaller reporting company o
	(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). o Yes þ No

As of the date of this filing, the number of outstanding shares of common stock of Ormat Technologies, Inc. is 45,407,649 par value $0.001 per share.

ORMAT TECHNOLOGIES, INC

FORM 10-Q

FOR THE QUARTER ENDED JUNE 30, 2009


PART I — UNAUDITED FINANCIAL INFORMATION
ITEM 1.	CONDENSED CONSOLIDATED FINANCIAL STATEMENTS	4
ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	25
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	52
ITEM 4.	CONTROLS AND PROCEDURES	52

PART II — OTHER INFORMATION
ITEM 1.	LEGAL PROCEEDINGS	52
ITEM 1A.	RISK FACTORS	52
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	53
ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	53
ITEM 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS	53
ITEM 5.	OTHER INFORMATION	53
ITEM 6.	EXHIBITS	53
SIGNATURES		55
EX-31.1
EX-31.2
EX-32.1
EX-32.2

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 — UNAUDITED FINANCIAL INFORMATION


ITEM 1.	*CONDENSED CONSOLIDATED FINANCIAL STATEMENTS*

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)


	June 30,			December 31,
	2009			2008
	(In thousands)

ASSETS
Current assets:
Cash and cash equivalents	$	46,028		$	34,393
Restricted cash, cash equivalents and marketable securities		35,255			24,439
Receivables:
Trade		53,323			49,839
Related entity		477			338
Other		16,758			15,654
Due from Parent		1,951			1,085
Inventories, net		14,609			13,724
Costs and estimated earnings in excess of billings on uncompleted contracts		14,622			6,982
Deferred income taxes		3,746			3,003
Prepaid expenses and other		8,451			16,222

Total current assets		195,220			165,679
Long-term marketable securities		2,053			1,994
Restricted cash, cash equivalents and marketable securities		2,983			2,951
Unconsolidated investments		33,425			30,559
Deposits and other		17,209			16,876
Deferred income taxes		14,157			13,965
Property, plant and equipment, net		972,433			958,186
Construction-in-process		469,069			386,501
Deferred financing and lease costs, net		22,911			19,240
Intangible assets, net		43,297			44,853

Total assets	$	1,772,757		$	1,640,804

LIABILITIES AND EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	79,367		$	103,336
Billings in excess of costs and estimated earnings on uncompleted contracts		14,584			15,670
Current portion of long-term debt:
Limited and non-recourse		18,290			6,676
Senior secured notes (non-recourse)		19,896			20,085
Due to Parent, including current portion of notes payable to Parent		9,650			16,616

Total current liabilities		141,787			162,383
Long-term debt, net of current portion:
Limited and non-recourse		124,912			7,814
Revolving credit lines with banks (full recourse)		120,000			100,000
Senior secured notes (non-recourse)		244,588			252,060
Notes payable to Parent, net of current portion		—			9,600
Liability associated with sale of equity interests		108,616			113,327
Deferred lease income		73,809			74,427
Deferred income taxes		41,431			33,231
Liability for unrecognized tax benefits		4,077			3,425
Liabilities for severance pay		17,454			17,640
Asset retirement obligation		13,958			13,438

Total liabilities		890,632			787,345

Commitments and contingencies

Equity:
The Company’s stockholders’ equity:
Common stock, par value $0.001 per share; 200,000,000 shares authorized; 45,407,649 and 45,353,120 shares issued and outstanding, respectively		46			45
Additional paid-in capital		704,854			701,273
Retained earnings		170,409			144,465
Accumulated other comprehensive income (loss)		(59	)		645

		875,250			846,428
Noncontrolling interest		6,875			7,031

Total equity		882,125			853,459

Total liabilities and equity	$	1,772,757		$	1,640,804

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

(Unaudited)


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
	(In thousands, except per share data)						(In thousands, except
							per share data)

Revenues:
Electricity	$	60,562		$	61,774		$	123,200		$	121,293
Product		39,673			18,447			76,924			28,315

Total revenues		100,235			80,221			200,124			149,608

Cost of revenues:
Electricity	$	44,958			41,506			88,842			80,182
Product		27,242			15,704			51,485			23,754

Total cost of revenues		72,200			57,210			140,327			103,936

Gross margin		28,035			23,011			59,797			45,672
Operating expenses:
Research and development expenses		2,487			785			3,288			1,481
Selling and marketing expenses		3,215			2,020			7,516			5,539
General and administrative expenses		5,582			5,925			13,117			11,952

Operating income		16,751			14,281			35,876			26,700
Other income (expense):
Interest income		276			1,052			428			2,098
Interest expense, net		(4,415	)		(4,851	)		(7,705	)		(9,637	)
Foreign currency translation and transaction gains (losses)		2,569			(1,359	)		9			(1,542	)
Income attributable to sale of equity interests		4,366			4,848			8,534			8,164
Other non-operating income, net		550			309			400			21

Income before income taxes and equity in income of investees		20,097			14,280			37,542			25,804
Income tax provision		(4,478	)		(2,613	)		(7,967	)		(4,684	)
Equity in income of investees, net		355			408			905			947

Net income		15,974			12,075			30,480			22,067
Net loss attributable to noncontrolling interest		77			86			156			158

Net income attributable to the Company’s stockholders	$	16,051		$	12,161		$	30,636		$	22,225

Comprehensive income:
Net income	$	15,974		$	12,075		$	30,480		$	22,067
Other comprehensive income (loss), net of related taxes:
Currency translation adjustment		423			—			371			—
Amortization of unrealized gains in respect of derivative instruments
designated for cash flow hedge		(65	)		(74	)		(130	)		(149	)
Change in unrealized gains or losses on marketable securities available-for-sale		260			(136	)		260			(410	)

Comprehensive income		16,592			11,865			30,981			21,508
Comprehensive loss attributable to noncontrolling interest		77			86			156			158

Comprehensive income attributable to the Company’s stockholders	$	16,669		$	11,951		$	31,137		$	21,666

Earnings per share attributable to the Company’s stockholders:
Basic	$	0.35		$	0.28		$	0.68		$	0.52

Diluted	$	0.35		$	0.28		$	0.67		$	0.52

Weighted average number of shares used in computation of earnings per share attributable to the Company’s stockholders:
Basic		45,369			43,828			45,361			42,995

Diluted		45,451			43,978			45,425			43,127

Dividend per share declared	$	0.06		$	0.05		$	0.13		$	0.10

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

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY
(Unaudited)


	The Company’s Stockholders’ Equity
										Accumulated
					Additional					Other
	Common Stock				Paid-in		Retained			Comprehensive						Noncontrolling			Total
	Shares		Amount		Capital		Earnings			Income (Loss)			Total			Interest			Equity
							(In thousands, except per share data)

Balance at December 31, 2007		41,530	$	41	$	513,109	$	103,545		$	1,388		$	618,083		$	4,682		$	622,765
Stock-based compensation		—		—		2,074		—			—			2,074			—			2,074
Cash dividend declared, $0.10 per share		—		—		—		(4,377	)		—			(4,377	)		—			(4,377	)
Issuance of shares of common stock in a block trade transaction		3,100		3		149,652		—			—			149,655			—			149,655
Issuance of unregistered shares of common stock to the Parent in a private placement		694		1		33,314		—			—			33,315			—			33,315
Exercise of options by employees		7				216								216			—			216
Tax benefit on exercise of options by employees		—		—		68		—			—			68			—			68
Increase in noncontrolling interest due to sale of equity interest in OPC LLC		—		—		—		—			—			—			2,598			2,598
Net income (loss)		—		—		—		22,225			—			22,225			(158	)		22,067
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 $92,000)		—		—		—		—			(149	)		(149	)		—			(149	)
Change in unrealized gains or losses on marketable securities available-for-sale (net of related tax of $251,000)		—		—		—		—			(410	)		(410	)		—			(410	)

Balance at June 30, 2008		45,331	$	45	$	698,433	$	121,393		$	829		$	820,700		$	7,122		$	827,822


Balance at December 31, 2008		45,353	$	45	$	701,273	$	144,465		$	645		$	846,428		$	7,031		$	853,459
Stock-based compensation		—		—		2,728		—			—			2,728			—			2,728
Cumulative effect of adopting FSP FAS 115-2 and FAS 124-2 as of April 1, 2009 (net of related tax of $650,000)		—		—		—		1,205			(1,205	)		—			—			—
Cash dividend declared, $0.13 per share		—		—		—		(5,897	)		—			(5,897	)		—			(5,897	)
Exercise of options by employees		55		1		853		—			—			854			—			854
Net income (loss)		—		—		—		30,636			—			30,636			(156	)		30,480
Other comprehensive income (loss), net of related taxes:
Currency translation adjustment		—		—		—		—			371			371			—			371
Amortization of unrealized gains in respect of derivative instruments designated for cash flow hedge (net of related tax of $80,000)		—		—		—		—			(130	)		(130	)		—			(130	)
Change in unrealized gains or losses on marketable securities available-for-sale (net of related tax of $144,000)		—		—		—		—			260			260			—			260

Balance at June 30, 2009		45,408	$	46	$	704,854	$	170,409		$	(59	)	$	875,250		$	6,875		$	882,125

The accompanying notes are in 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,
	2009			2008
	(In thousands)

Cash flows from operating activities:
Net income	$	30,480		$	22,067
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		31,193			27,840
Accretion of asset retirement obligation		520			509
Stock-based compensation		2,728			2,074
Amortization of deferred lease income		(1,343	)		(1,342	)
Income attributable to sale of equity interests, net of interest expense		(4,711	)		(4,997	)
Equity in income of investees		(905	)		(947	)
Distributions from unconsolidated investments		—			1,317
Gain (loss) on severance pay fund asset		106			(2,740	)
Deferred income tax provision		6,620			1,934
Liability for unrecognized tax benefits		652			487
Deferred lease revenues		725			—
Other		(70	)		328
Changes in operating assets and liabilities:
Receivables		(6,683	)		(10,110	)
Costs and estimated earnings in excess of billings on uncompleted contracts		(7,640	)		2,048
Inventories, net		(885	)		(3,079	)
Prepaid expenses and other		7,771			(1,662	)
Deposits and other		(21	)		(178	)
Accounts payable and accrued expenses		(962	)		1,938
Due from/to related entities, net		(139	)		(217	)
Billings in excess of costs and estimated earnings on uncompleted contracts		(1,086	)		10,591
Liabilities for severance pay		(186	)		4,003
Due from/to Parent		(832	)		(240	)

Net cash provided by operating activities		55,332			49,624

Cash flows from investing activities:
Distributions from unconsolidated investments		—			1,433
Marketable securities, net		200			12,589
Net change in restricted cash, cash equivalents and marketable securities		(10,633	)		(3,101	)
Capital expenditures		(147,613	)		(177,905	)
Increase in severance pay fund asset, net		(418	)		(457	)
Repayment from unconsolidated investment		62			64

Net cash used in investing activities		(158,402	)		(167,377	)

Cash flows from financing activities:
Due to Parent, net		(16,600	)		(16,600	)
Proceeds from long-term loan		132,000			—
Proceeds from public offerings, net of issuance costs		—			149,655
Proceeds from issuance of unregistered shares of common stock to the Parent		—			33,315
Proceeds from exercise of options by employees		854			216
Proceeds from the sale of limited liability company interest in OPC LLC, net of transaction costs		—			63,079
Proceeds from revolving credit lines with banks		577,000			—
Repayments of revolving credit lines with banks		(557,000	)		—
Repayments of long-term debt		(10,949	)		(16,995	)
Deferred financing costs		(4,889	)		—
Cash dividends paid		(5,897	)		(4,377	)

Net cash provided by financing activities		114,519			208,293

Effect of exchange rate changes on cash and cash equivalents		186			—

Net change in cash and cash equivalents		11,635			90,540
Cash and cash equivalents at beginning of period		34,393			47,227

Cash and cash equivalents at end of period	$	46,028		$	137,767

Supplemental non-cash investing and financing activities:
Increase (decrease) in accounts payable related to purchases of property, plant and equipment	$	(23,713	)	$	10,004

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

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTE 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 (the “Company”) have been prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”) and pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”) for interim financial statements. Accordingly, they do not contain all information and notes required by U.S. GAAP for annual financial statements. In the opinion of management, the unaudited condensed consolidated interim financial statements reflect all adjustments, which include normal recurring adjustments, necessary for a fair statement of the Company’s consolidated financial position as of June 30, 2009, the consolidated results of operations and comprehensive income for the three and six-month periods ended June 30, 2009 and 2008, and the consolidated cash flows for the six-month periods ended June 30, 2009 and 2008.

The financial data and other information disclosed in the notes to the condensed consolidated interim financial statements related to these periods are unaudited. The results for the three and six-month periods ended June 30, 2009 are not necessarily indicative of the results to be expected for the year ending December 31, 2009.

These condensed consolidated interim 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, 2008. The condensed consolidated balance sheet data as of December 31, 2008 was derived from the audited consolidated financial statements for the year ended December 31, 2008, 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.

Certain comparative figures have been reclassified to conform to the current period presentation (see Note 6).

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, 2009 and December 31, 2008, the Company had deposits totaling $28,939,000 and $23,120,000, respectively, in seven U.S. financial institutions that were federally insured up to $250,000 per account (after December 31, 2009, the deposits will be insured up to $100,000 per account). At June 30, 2009 and December 31, 2008, the Company’s deposits in foreign countries amounted to approximately $29,283,000 and $20,377,000, respectively.

At June 30, 2009 and December 31, 2008, accounts receivable related to operations in foreign countries amounted to approximately $16,168,000 and $14,867,000, respectively. At June 30, 2009 and December 31, 2008, accounts receivable from the Company’s major customers that have generated 10% or more of its revenues amounted to approximately 64% and 45% of the Company’s accounts receivable, respectively.

Southern California Edison Company (“SCE”) accounted for 21.1% and 30.7% of the Company’s total revenues for the three months ended June 30, 2009 and 2008, respectively, and 19.5% and 30.5% of the Company’s total revenues for the six months ended June 30, 2009 and 2008, respectively. SCE is also the power purchaser and revenue source for the Company’s Mammoth power plant, which is accounted for separately under the equity method.

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTE TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

Hawaii Electric Light Company accounted for 4.9% and 16.5% of the Company’s total revenues for the three months ended June 30, 2009 and 2008, respectively, and 7.4% and 18.6% of the Company’s total revenues for the six months ended June 30, 2009 and 2008, respectively.

Sierra Pacific Power Company and Nevada Power Company (subsidiaries of NV Energy, Inc.) accounted for 12.0% and 12.4% of the Company’s total revenues for the three months ended June 30, 2009 and 2008, respectively, and 12.8% and 13.5% of the Company’s total revenues for the six months ended June 30, 2009 and 2008, respectively.

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


NOTE 2 —	NEW ACCOUNTING PRONOUNCEMENTS

New accounting pronouncements effective in the six-month period ended June 30, 2009

SFAS No. 157 — Fair Value Measurements

Effective January 1, 2008, the Company adopted the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 157, Fair Value Measurements. In February 2008, the Financial Accounting Standards Board (“FASB”) staff issued FASB Staff Position (“FSP”) FAS No. 157-2, Effective Date of FASB Statement No. 157, which deferred the effective date of SFAS No. 157 for all non-financial assets and liabilities that are recognized and disclosed at fair value on a nonrecurring basis in the financial statements until January 1, 2009. The adoption of FSP FAS No. 157-2, effective January 1, 2009 did not have a material impact on the Company’s consolidated financial statements.

SFAS No. 160 — Noncontrolling Interests in Consolidated Financial Statements — an amendment of ARB No. 51

In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements — an amendment of ARB No. 51. SFAS No. 160 establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. SFAS No. 160 requires retroactive adoption of the presentation and disclosure requirements for existing minority interests. All other requirements of SFAS No. 160 are applied prospectively. The Company adopted SFAS No. 160 on January 1, 2009 and amended its presentation and disclosures accordingly (see Note 6).

SFAS No. 141 (revised 2007) — Business Combinations

In December 2007, the FASB issued SFAS No. 141 (revised 2007), Business Combinations (“SFAS No. 141R”). SFAS No. 141R establishes principles and requirements for how the acquirer of a business recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree. SFAS No. 141R also provides guidance for recognizing and measuring the goodwill acquired in the business combination and determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. SFAS No. 141R is effective for fiscal years beginning after December 15, 2008 (January 1, 2009 for the Company). The adoption by the Company of SFAS No. 141R did not have an impact on its consolidated financial statements; however, it could impact future transactions entered into by the Company.

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTE TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

In April 2009, the FASB issued FSP FAS No. 141R-1, Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies. FSP FAS No. 141R-1 amends the provisions related to the initial recognition and measurement, subsequent measurement and disclosure of assets and liabilities arising from contingencies in a business combination under SFAS No. 141R, Business Combinations. The FSP will carry forward the requirements in SFAS No. 141, Business Combinations, for acquired contingencies, thereby requiring that such contingencies be recognized at fair value on the acquisition date if fair value can be reasonably estimated during the allocation period. Otherwise, entities would typically account for the acquired contingencies in accordance with SFAS No. 5, Accounting for Contingencies. The FSP has the same effective date as SFAS No. 141R, and its adoption by the Company did not have an impact on its consolidated financial statements.

SFAS No. 161 — Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133

In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133. SFAS No. 161 amends SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, and requires companies with derivative instruments to disclose information that should enable financial statement users to understand how and why a company uses derivative instruments, how derivative instruments and related hedged items are accounted for under SFAS No. 133, and how derivative instruments and related hedged items affect a company’s financial position, financial performance, and cash flows. The required disclosures include the fair value of derivative instruments and their gains or losses in tabular format, information about credit-risk-related contingent features in derivative agreements, counterparty credit risk, and the company’s strategies and objectives for using derivative instruments. SFAS No. 161 expands the current disclosure framework in SFAS No. 133. SFAS No. 161 is effective prospectively for fiscal years and interim periods beginning after November 15, 2008 (January 1, 2009 for the Company). The adoption by the Company of FAS No. 161, effective January 1, 2009, did not have an impact on its financial position, results of operations and cash flows.

FSP FAS No. 157-4 — Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly

In April 2009, the FASB issued FSP FAS No. 157-4, Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly . FSP FAS No. 157-4 provides guidelines for making fair value measurements more consistent with the principles presented in SFAS No. 157, Fair Value Measurements. The FSP provides guidance to determine fair values when there is no active market or where the price inputs being used represent distressed sales. It reaffirms what SFAS No. 157 states is the objective of fair value measurement, to reflect how much an asset would be sold for in an orderly transaction (as opposed to a distressed or forced transaction) at the date of the financial statements under current market conditions. Specifically, it reaffirms the need to use judgment to ascertain if a formerly active market has become inactive and in determining fair values when markets have become inactive. The FSP is effective for the Company’s interim reporting periods ending on June 30, 2009. The adoption by the Company of FSP FAS No. 157-4, effective April 1, 2009, did not have an impact on its financial position, results of operations and cash flows.

FSP FAS No. 115-2 and FAS No. 124-2 — Recognition and Presentation of Other-Than-Temporary Impairments

In April 2009, the FASB issued FSP FAS No. 115-2 and FAS No. 124-2, Recognition and Presentation of Other-Than-Temporary Impairments. FSP FAS No. 115-2 and FAS No. 124-2 provides additional guidance on accounting and presenting impairment losses on securities. The FSP is intended to bring greater consistency to

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTE TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

the timing of impairment recognition, and provide greater clarity to investors about the credit and noncredit components of impaired debt securities that are not expected to be sold. The measure of impairment remains fair value. The FSP also requires increased and more timely disclosures regarding expected cash flows, credit losses, and an aging of securities with unrealized losses. The FSP is effective for the Company’s interim reporting periods ending on June 30, 2009. The effect of adopting this FSP on April 1, 2009 is disclosed in Note 5.

FSP FAS No. 107-1 and APB 28-1 — Interim Disclosures about Fair Value of Financial Instruments

In April 2009, the FASB issued FSP FAS No. 107-1 and APB 28-1, Interim Disclosures about Fair Value of Financial Instruments. FSP FAS No. 107-1 and APB 28-1 enhance consistency in financial reporting by increasing the frequency of fair value disclosures. The FSP provides guidance for fair value disclosures for any financial instruments that are not currently reflected on a company’s balance sheet at fair value. Prior to the effective date of this FSP, fair values for these assets and liabilities have only been disclosed once a year. The FSP will now require these disclosures on a quarterly basis, providing qualitative and quantitative information about fair value estimates for all those financial instruments not measured on the balance sheet at fair value. The FSP is effective for the Company’s interim reporting periods ending on June 30, 2009. The disclosures required under this FSP are provided in Note 5.

SFAS No. 165 — Subsequent Events

In May 2009, the FASB issued SFAS No. 165, Subsequent Events. SFAS No. 165 establishes standards of accounting for and disclosures of events that occur after the balance sheet date but before financial statements are issued. This statement also requires disclosure of the date through which an entity has evaluated subsequent events and the basis for the date. SFAS No. 165 is effective for interim and annual financial periods ending after June 15, 2009 (June 30, 2009 for the Company). The Company has evaluated events through August 5, 2009, the date of issuance of the financial statements (See Note 16). The adoption by the Company of SFAS No. 165 did not have an impact on the Company’s consolidated financial statements.

New accounting pronouncements effective in future periods

SFAS No. 166 — Accounting for Transfers of Financial Assets — an amendment of FASB Statement No. 140

In June 2009, the FASB issued SFAS No. 166, Accounting for Transfers of Financial Assets — an amendment of FASB Statement No. 140, amending the guidance on transfers of financial assets in order to address practice issues highlighted most recently by events related to the economic downturn. The amendments include: (i) eliminating the qualifying special-purpose entity concept; (ii) a new unit of account definition that must be met for transfers of portions of financial assets to be eligible for sale accounting; (iii) clarifications and changes to the derecognition criteria for a transfer to be accounted for as a sale; (iv) a change to the amount of recognized gain or loss on a transfer of financial assets accounted for as a sale when beneficial interests are received by the transferor; and (v) extensive new disclosures. SFAS No. 166 is effective for fiscal years beginning after November 15, 2009 (January 1, 2010 for the Company) for new transfers of financial assets occurring from that date. The Company is currently evaluating the potential impact, if any, of the adoption of SFAS No. 166 on its consolidated financial statements.

SFAS No. 167 — Amendments to FASB Interpretation No. 46(R)

In June 2009, the FASB issued SFAS No. 167, Amendments to FASB Interpretation No. 46(R), which amends the consolidation guidance for variable-interest entities under FIN 46(R). The amendments include: (i) the elimination of the exemption for qualifying special purpose entities; (ii) a new approach for determining who should consolidate a variable-interest entity; and (iii) changes to when it is necessary to reassess who

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTE TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

should consolidate a variable-interest entity. SFAS No. 167 is effective for annual and interim periods beginning after November 15, 2009 (January 1, 2010 for the Company). The Company is currently evaluating the potential impact, if any, of the adoption of SFAS No. 167 on its consolidated financial statements.

SFAS No. 168 — The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles — A Replacement of FASB Statement No. 162

In June 2009, the FASB issued SFAS No. 168, The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles — A Replacement of FASB Statement No. 162. SFAS No. 168 establishes the FASB Accounting Standards Codification as the single source of authoritative U.S. generally accepted accounting principles recognized by the FASB to be applied by nongovernmental entities. SFAS No. 168 is effective for interim and annual periods ending after September 15, 2009 (September 30, 2009 for the Company). The Company is currently evaluating the potential impact of the adoption of SFAS No. 168 on its consolidated financial statements.


NOTE 3 —	INVENTORIES

Inventories consist of the following:


	June 30,		December 31,
	2009		2008
	(Dollars in thousands)

Raw materials and purchased parts for assembly	$	7,427	$	7,649
Self-manufactured assembly parts and finished products		7,182		6,075

Total	$	14,609	$	13,724


NOTE 4 —	UNCONSOLIDATED INVESTMENTS

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


	June 30,		December 31,
	2009		2008
	(Dollars in thousands)

Mammoth	$	31,595	$	30,131
Sarulla		1,443		—
OLCL		387		428

Total	$	33,425	$	30,559

The Mammoth Power Plant

The Company has a 50% interest in the Mammoth Power Plant (“Mammoth”), located near the city of Mammoth, California. The purchase price was less than the underlying net equity of Mammoth by approximately $9.3 million. As such, the basis difference will be amortized over the remaining useful life of the property, plant and equipment and the power purchase agreements (“PPAs”), which range from 12 to 17 years. The Company operates and maintains the geothermal power plants under an operating and maintenance (“O&M”) agreement. The Company’s 50% ownership interest in Mammoth is accounted for under the equity method of accounting as the Company has the ability to exercise significant influence, but not control, over Mammoth.

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTE TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

The condensed financial position and results of operations of Mammoth are summarized below:


	June 30,		December 31,
	2009		2008
	(Dollars in thousands)

Condensed balance sheets:
Current assets	$	13,656	$	8,251
Non-current assets		67,686		69,784
Current liabilities		1,445		721
Non-current liabilities		3,302		3,177
Partners’ capital		76,595		74,137


	Six Months Ended
	June 30,
	2009			2008
	(Dollars in thousands)

Condensed statements of operations:
Revenues	$	9,455		$	9,493
Gross margin		2,568			2,781
Net income		2,458			2,636
Company’s equity in income of Mammoth:
50% of Mammoth net income	$	1,229		$	1,318
Plus amortization of basis difference		297			297

		1,526			1,615
Less income taxes		(580	)		(613	)

Total	$	946		$	1,002

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 340 MW. The project is located in Tapanuli Utara, North Sumatra, Indonesia and will be owned and operated by the consortium members under the framework of a Joint Operating Contract with PT Pertamina Geothermal Energy PGE. The project will be constructed in three phases over five years, with each phase utilizing the Company’s designed and supplied power generation units of 110 MW to 120 MW. The consortium is currently negotiating certain amendments to the PPA, including an adjustment of commercial terms, and intends to proceed with the project after those amendments have become effective.

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


NOTE 5 —	FAIR VALUE OF FINANCIAL INSTRUMENTS

As described in Note 1, the provisions of SFAS No. 157 were adopted by the Company on January 1, 2008 for financial assets and liabilities and on January 1, 2009 for non-financial assets and liabilities.

SFAS No. 157 clarifies that fair value is an exit price, representing the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. As such, fair value is a market-based measurement that should be determined based on assumptions that market participants would use in pricing an asset or liability. SFAS No. 157 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

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTE TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

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 SFAS No. 157 are described below:

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

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

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

The following table sets forth certain fair value information at June 30, 2009 and December 31, 2008 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 SFAS No. 157, 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,		Fair Value at June 30, 2009
	2009		Total		Level 1		Level 2		Level 3
	(Dollars in thousands)

Assets:
Current assets:
Cash equivalents (including restricted cash accounts)	$	12,347	$	12,347	$	12,347	$	—	$	—
Derivatives*		—		495		—		495		—
Non current assets:
Illiquid auction rate securities (including restricted cash accounts) ($7.3 million par value), see below		6,580		5,036		—		—		5,036

	$	18,927	$	17,878	$	12,347	$	495	$	5,036


	Cost or Amortized
	Cost at December 31,		Fair Value at December 31, 2008
	2008		Total			Level 1		Level 2			Level 3
	(Dollars in thousands)

Assets:
Current assets:
Cash equivalents (including restricted cash accounts)	$	18,891	$	18,891		$	18,891	$	—		$	—
Derivatives*		—		625			—		625			—
Non current assets:
Illiquid auction rate securities (including restricted cash accounts) ($11.2 million par value), see below		11,160		4,945			—		—			4,945
Liabilities:
Current liabilities:
Derivatives*		—		(721	)		—		(721	)		—

	$	30,051	$	23,740		$	18,891	$	(96	)	$	4,945


*		Derivatives represent foreign currency forward and option contracts which are valued primarily based on observable inputs including forward and spot prices for currencies.

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTE TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

The Company’s financial assets measured at fair value (including restricted cash accounts) at June 30, 2009 include investments in auction rate securities and money market funds (which are included in cash equivalents). Those securities, except for the illiquid auction rate securities, are classified within Level 1 of the fair value hierarchy because they are valued using quoted market prices in an active market.

The Company’s auction rate securities are valued using Level 3 inputs. As of June 30, 2009, all of the Company’s auction rate securities are associated with failed auctions. Such securities have par values totaling $7.3 million and $11.2 million at June 30, 2009 and December 31, 2008, respectively, all of which have been in a loss position since the fourth quarter of 2007. Historically, the carrying value of auction rate securities approximated fair value due to the frequent resetting of the interest rates. While the Company continues to earn interest on these investments at the contractual rates, the estimated market value of these auction rate securities no longer approximates par value. Due to the lack of observable market quotes on the Company’s illiquid auction rate securities, the Company utilizes valuation models that rely 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 are subject to uncertainties that are difficult to predict. Therefore, such auction rate securities have been classified as Level 3 in the fair value hierarchy.

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, 2009 and 2008:


	Six Months
	Ended June 30,
	2009			2008
	(Dollars in thousands)

Balance at beginning of period	$	4,945		$	8,367
Sale of auction rate securities		(40	)		—
Total unrealized gains (losses):
Included in net income		(280	)		(328	)
Included in other comprehensive income (loss)		411			(584	)

Balance at end of period	$	5,036		$	7,455

Effective April 1, 2009, the Company adopted the provisions of FSP FAS No. 115-2 and FAS No. 124-2 (the “FSP”) which requires an entity to separate an other-than-temporary impairment of a debt security into two components when there are credit-related losses associated with the impaired security for which management does not have the intent to sell the security, and it is not, more likely than not, that it will be required to sell the security before recovery of its cost basis. For those securities, the amount of the other-than-temporary impairment related to a credit loss is recognized in earnings and reflected as a reduction in the cost basis of the security, and the amount of the other-than-temporary impairment related to other factors is recorded in other comprehensive loss with no change to the cost basis of the security. For securities for which there is an intent to sell before recovery of the cost basis, the full amount of the other-than temporary impairment is recognized in earnings and reflected as a reduction in the cost basis of the security. Upon adoption of the FSP, the Company reclassified $1.2 million (net of taxes of $0.7 million) to other comprehensive loss with an offset to retained earnings related to other-than-temporary-impairment charges previously recognized in earnings. This cumulative effect adjustment relates to auction rate securities for

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTE TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

which the Company does not have the intent to sell and will not, more likely than not, be required to sell prior to recovery of its cost basis.

For the auction rate securities for which the Company had the intent to sell upon adoption of the FSP, no cumulative effect adjustment was required. The Company sold these securities ($3.9 million par value) for consideration of $0.4 million and recorded a gain of $0.3 million during the quarter ended June 30, 2009. The cumulative loss for these securities was $3.5 million as impairment charges of $3.8 million were recorded through earnings prior to the sale of the securities in the second quarter.

The amount of credit losses represents the difference between the present value of cash flows expected to be collected on these securities and the amortized cost. The credit loss was calculated as the difference between the current cash flows discounted at present value to the expected cash flows at the date of purchase. The analysis incorporates management’s best estimate of current key assumptions, including the default rate of such securities and probability of passing auction.

The change in other-than-temporary impairment losses during the three months ended June 30, 2009 was not material.

The funds invested in auction rate securities that have experienced failed auctions will not be accessible until a successful auction occurs, a buyer is found outside of the auction process or the underlying securities reach maturity. As a result, the Company has classified those securities with failed auctions as long-term assets on the consolidated balance sheets as of June 30, 2009 and December 31, 2008.

The Company continues to monitor the market for auction rate securities and to consider the market’s impact (if any) on the fair market value of the Company’s investments. If current market conditions deteriorate further, the Company may be required to record additional impairment charges in the rest of 2009.

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


	Fair Value				Carrying Amount
	June 30,		December 31,		June 30,		December 31,
	2009		2008		2009		2008
	(Dollars in millions)				(Dollars in millions)

Orzunil Senior Loans	$	7.3	$	9.2	$	7.2	$	9.0
Olkaria III Loan		86.6		—		90.0		—
Amatitlan Loan		42.9		—		42.0		—
Senior Secured Notes:
Ormat Funding Corp.(“OFC”)		116.2		114.9		150.9		155.3
OrCal Geothermal Inc.(“OrCal”)		106.7		103.6		113.6		116.8
Parent Loan		10.0		26.1		9.6		26.2

The fair value of OFC Senior Secured Notes is determined using observable market prices as these securities are traded. The fair value of other long-term debt is determined by a valuation model which is based on a conventional discounted cash flow methodology and utilizes assumptions of current market pricing curves.


NOTE 6 —	NONCONTROLLING INTEREST

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

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTE TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

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

Ormat Nevada will continue to operate and maintain the power plants and will receive initially all of the distributable cash flow generated by the power plants until it recovers the capital that it has invested in the power plants, while the investors will receive substantially all of the production tax credits and the taxable income or loss (together, the “Economic Benefits”), and the distributable cash flow after Ormat Nevada has recovered its capital. 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. Under the transaction, Ormat Nevada retained the controlling voting interest in the subsidiary and therefore continued to consolidate OPC.

The Company adopted SFAS No. 160 on January 1, 2009. The adoption of this standard resulted in retrospective presentation and disclosure changes to the consolidated balance sheet as of December 31, 2008 and the condensed consolidated statements of operations and comprehensive income for the three and six-month periods ended June 30, 2008. These changes are denoted in the table below:

Excerpts from Consolidated Balance Sheet


	Balance as of		Application of New			Revised Balance as of
	December 31, 2008		Accounting Standard			December 31, 2008
	(Dollars in thousands)

Deferred financing and lease costs, net	$	16,127	$	3,113	⁽¹⁾	$	19,240

Total assets	$	1,637,691	$	3,113		$	1,640,804

Liability associated with sale of equity interests	$	—	$	113,327	⁽²⁾	$	113,327

Total liabilities		674,018		113,327			787,345

Minority interest		117,245		(117,245	)		—

Equity:
The Company’s stockholders’ equity:
Common stock		45		—			45
Additional paid-in capital		701,273		—			701,273
Retained earnings		144,465		—			144,465
Accumulated other comprehensive income		645		—			645

		846,428		—			846,428
Noncontrolling interest		—		7,031	⁽³⁾		7,031

Total equity		846,428		7,031			853,459

Total liabilities and equity	$	1,637,691	$	3,113		$	1,640,804


(1)		Represents transaction costs that had previously been reflected as a component of minority interest on the consolidated balance sheets. Such costs are amortized using the effective interest method until the Flip Date.

(2)		Represents unamortized liability associated with sale of equity interests in OPC.

(3)		Represents noncontrolling interest in OPC.

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTE TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

Excerpts from Consolidated Statements of Operations and Comprehensive Income


							Revised Three
	Three Months						Months Ended
	Ended June			Application of New			June 30,
	30, 2008			Accounting Standard			2008
	(Dollars in thousands)

Other income (expense):
Interest income	$	1,052		$	—		$	1,052
Interest expense, net		(2,867	)		(1,984	)⁽¹⁾		(4,851	)
Foreign currency translation and transaction losses		(1,359	)		—			(1,359	)
Income attributable to sale of equity interests		—			4,848	⁽²⁾		4,848
Other non-operating income, net		309						309

Income before income taxes and equity in income of investees		11,416			2,864			14,280
Income tax provision		(2,613	)		—			(2,613	)
Minority interest		2,950			(2,950	)		—
Equity in income of investees, net		408			—			408

Net income		12,161			(86	)		12,075
Net loss attributable to noncontrolling interest		—			86	⁽³⁾		86

Net income attributable to the Company’s stockholders	$	12,161		$	—		$	12,161

Comprehensive income:
Net income	$	12,161		$	(86	)	$	12,075
Other comprehensive income (loss), net of related taxes:
Amortization of unrealized gains in respect of derivative instruments designated for cash flow hedge		(74	)		—			(74	)
Change in unrealized gains or losses on marketable securities available-for-sale		(136	)		—			(136	)

Comprehensive income		11,951			(86	)		11,865
Comprehensive loss attributable to noncontrolling interest		—			86	⁽³⁾		86

Comprehensive income attributable to the Company’s stockholders	$	11,951		$	—		$	11,951


(1)		Represents interest on liability resulting from sale of equity interests in OPC.

(2)		Represents recognition of benefits attributed to investors in OPC.

(3)		Represents allocation of net loss to noncontrolling interest.

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NOTE TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)


							Revised Six
	Six Months						Months Ended
	Ended June			Application of New			June 30,
	30, 2008			Accounting Standard			2008
	(Dollars in thousands)

Other income (expense):
Interest income	$	2,098		$	—		$	2,098
Interest expense, net		(6,470	)		(3,167	)⁽¹⁾		(9,637	)
Foreign currency translation and transaction losses		(1,542	)		—			(1,542	)
Income attributable to sale of equity interests		—			8,164	⁽²⁾		8,164
Other non-operating income, net		21						21

Income before income taxes and equity in income of investees		20,807			4,997			25,804
Income tax provision		(4,684	)		—			(4,684	)
Minority interest		5,155			(5,155	)		—
Equity in income of investees, net		947			—			947

Net income		22,225			(158	)		22,067
Net loss attributable to noncontrolling interest		—			158	⁽³⁾		158

Net income attributable to the Company’s stockholders	$	22,225		$	—		$	22,225

Comprehensive income:
Net income	$	22,225		$	(158	)	$	22,067
Other comprehensive income (loss), net of related taxes:
Amortization of unrealized gains in respect of derivative instruments designated for cash flow hedge		(149	)		—			(149	)
Change in unrealized gains or losses on marketable securities available-for-sale		(410	)		—			(410	)

Comprehensive income		21,666			(158	)		21,508
Comprehensive loss attributable to noncontrolling interest		—			158	⁽³⁾		158

Comprehensive income attributable to the Company’s stockholders	$	21,666		$	—		$	21,666


(1)		Represents interest on liability resulting from sale of equity interests in OPC.

(2)		Represents recognition of benefits attributed to investors in OPC.

(3)		Represents allocation of net loss to noncontrolling interest.


NOTE 7 —	LONG-TERM DEBT

Loan Agreement (the Olkaria III Power Plant)

In March 2009, the Company’s wholly owned subsidiary, OrPower 4, Inc. (“OrPower 4”), entered into a project financing loan of $105.0 million to refinance its investment in the 48 MW Olkaria III geothermal

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTE TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

power plant located in Kenya (the “Olkaria Loan”). The Company initially financed construction of Phase I and Phase II of the project, as well as the drilling of wells with corporate funds. The Olkaria Loan is provided by a group of European Development Finance Institutions (“DFIs”) arranged by DEG — Deutsche Investitions- und Entwicklungsgesellschaft mbH (“DEG”). The first disbursement of $90.0 million occurred on March 23, 2009 and the second disbursement of $15.0 million occurred on July 10, 2009. The Olkaria Loan will mature on December 15, 2018, and is payable in 19 equal semi-annual installments, commencing December 15, 2009. Interest on the Olkaria Loan is variable based on 6-month LIBOR plus 4.0% and the Company had the option to fix the interest rate upon each disbursement. Upon the first disbursement, the Company fixed the interest rate on $77.0 million of the Olkaria Loan at 6.90% per annum.

There are various restrictive covenants under the Olkaria Loan, which include limitations on OrPower 4’s ability to make distributions to its shareholders. Management believes that as of June 30, 2009, OrPower 4 was in compliance with the covenants under the Olkaria Loan.

Future minimum payments

As of June 30, 2009, future minimum payments of the $90.0 million drawn under the Olkaria Loan are as follows:


	(Dollars in
	thousands)

Year ending December 31:
2009	$	4,737
2010		9,474
2011		9,474
2012		9,474
2013		9,474
2014		9,474
Thereafter		37,893

Total	$	90,000

Loan Agreement (the Amatitlan Power Plant)

In May 2009, the Company’s wholly owned subsidiary, Ortitlan Limitada (“Ortitlan”), entered into a note purchase agreement, in an aggregate principal amount of $42.0 million, to refinance its investment in the 20 MW Amatitlan geothermal power plant located in Amatitlan, Guatemala (the “Amatitlan Loan”). The Company initially financed the construction of the project, as well as the drilling of wells with corporate funds. The Amatitlan Loan is provided by TCW Global Project Fund II, Ltd. (“TCW”). The Amatitlan Loan will mature on June 15, 2016, and will be payable in 28 quarterly installments. The Amatitlan Loan bears annual interest at a rate of 9.83%.

There are various restrictive covenants under the Amatitlan Loan, which include limitations on Ortitlan’s ability to make distributions to its shareholders. Management believes that as of June 30, 2009, Ortitlan was in compliance with the covenants under the Amatitlan Loan.

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTE TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

Future minimum payments

As of June 30, 2009, future minimum payments of the $42.0 million drawn under the Amatitlan Loan, are as follows:


	(Dollars in
	thousands)

Year ending December 31:
2009	$	944
2010		2,037
2011		2,255
2012		2,495
2013		2,760
2014		3,054
Thereafter		28,455

Total	$	42,000


NOTE 8 —	STOCK-BASED COMPENSATION

On March 18, 2009, the Company granted to employees 573,150 stock appreciation rights (“SAR”) under the Company’s 2004 Incentive Plan. The exercise price of each SAR is $26.84, which amount represented the fair market value of the Company’s common stock on the date of grant. Such SARs will expire seven years from the date of grant and will cliff vest and are exercisable from the grant date as follows: 25% after 24 months, 25% after 36 months, and the remaining 50% after 48 months. The fair value of each SAR on the date of grant was $11.44. Under the plan, upon exercise of such SAR, the employee is entitled to receive shares of common stock equal to the amount by which the market value of the shares in respect of which the SAR is exercised exceeds the grant price set forth in the SAR, multiplied by the number of shares in respect of which the SAR is exercised.

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	1.54	%
Expected term (in years)	5.1
Dividend yield	0.37	%
Expected volatility	48.5	%
Forfeiture rate	13.0	%

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTE TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)


NOTE 9 —	ELECTRICITY REVENUES AND COST OF REVENUES

The components of electricity revenues and cost of revenues are as follows:


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2009		2008		2009		2008
	(Dollars in thousands)				(Dollars in thousands)

Revenues:
Energy and capacity	$	23,373	$	23,716	$	47,226	$	48,951
Lease portion of energy and capacity		36,517		37,386		74,631		70,999
Lease income		672		672		1,343		1,343

	$	60,562	$	61,774	$	123,200	$	121,293

Cost of revenues:
Energy and capacity	$	24,311	$	21,275		47,262		42,950
Lease portion of energy and capacity		19,337		18,921		38,959		34,611
Lease income		1,310		1,310		2,621		2,621

	$	44,958	$	41,506	$	88,842	$	80,182


NOTE 10 —	INTEREST EXPENSE

The components of interest expense are as follows:


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
	(Dollars in thousands)						(Dollars in thousands)

Parent	$	310		$	914			753			2,000
Interest related to sale of equity interest		2,151			1,984			4,081			3,167
Other		8,331			6,078			15,063			12,402
Less — amount capitalized		(6,377	)		(4,125	)		(12,192	)		(7,932	)

	$	4,415		$	4,851		$	7,705		$	9,637


NOTE 11 —	EARNINGS PER SHARE

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


NOTE 12 —	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 power purchase agreements. 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.

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTE TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

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, 2009
Net revenues from external customers	$	60,562	$	39,673	$	100,235
Intersegment revenues		—		4,386		4,386
Operating income		10,015		6,736		16,751
Segment assets at period end*		1,697,172		75,585		1,772,757
Three Months Ended June 30, 2008
Net revenues from external customers	$	61,774	$	18,447	$	80,221
Intersegment revenues		—		9,556		9,556
Operating income		14,098		183		14,281
Segment assets at period end*		1,472,091		61,622		1,533,713
Six Months Ended June 30, 2009
Net revenues from external customers	$	123,200	$	76,924	$	200,124
Intersegment revenues		—		17,221		17,221
Operating income		21,220		14,656		35,876
Segment assets at period end*		1,697,172		75,585		1,772,757
Six Months Ended June 30, 2008
Net revenues from external customers	$	121,293	$	28,315	$	149,608
Intersegment revenues		—		33,341		33,341
Operating income		26,672		28		26,700
Segment assets at period end*		1,472,091		61,622		1,533,713


*		Segment assets of the Electricity Segment include unconsolidated investments.

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


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
	(Dollars in thousands)						(Dollars in thousands)

Operating income	$	16,751		$	14,281		$	35,876		$	26,700
Interest income		276			1,052			428			2,098
Interest expense, net		(4,415	)		(4,851	)		(7,705	)		(9,637	)
Non-operating income and other, net		7,485			3,798			8,943			6,643

Total consolidated income before income taxes, and equity in income in investees	$	20,097		$	14,280		$	37,542		$	25,804


NOTE 13 —	CONTINGENCIES

The Company is a defendant in various legal and regulatory proceedings in the ordinary course of business. It is the opinion of the Company’s management that the expected outcome of these matters, individually or in the aggregate, will not have a material effect on the results of operations and financial condition of the Company.

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTE TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)


NOTE 14 —	CASH DIVIDEND

On February 24, 2009, the Company’s Board of Directors declared, approved and authorized payment of a quarterly dividend of $3.2 million ($0.07 per share) to all holders of the Company’s issued and outstanding shares of common stock on March 16, 2009. Such dividend was paid on March 26, 2009.

On May 8, 2009, the Company’s Board of Directors declared, approved and authorized payment of a quarterly dividend of $2.7 million ($0.06 per share) to all holders of the Company’s issued and outstanding shares of common stock on May 20, 2009. Such dividend was paid on May 27, 2009.


NOTE 15 —	INCOME TAXES

The Company’s effective tax rate for the three months ended June 30, 2009 and 2008 was 22.3% and 18.3%, respectively, and for the six months ended June 30, 2009 and 2008 was 21.2% and 18.2%, respectively, which differs from the federal statutory rate of 35% primarily due to: (i) the benefit of production tax credits for new power plants placed in service since 2005; (ii) lower tax rates in Israel; and (iii) tax credit and tax exemption related to the Company’s subsidiaries in Guatemala.


NOTE 16 —	SUBSEQUENT EVENTS

The Company has evaluated events through August 5, 2009, the date of issuance of the financial statements.

Loan Agreements

In July 2009, the Company entered into a 6-year loan agreement and an 8-year loan agreement of $20.0 million each with two groups of financial institutions. The 6-year loan matures on July 16, 2015, is payable in 12 semi-annual installments commencing January 16, 2010 and bears annual interest of 6.5%. The 8-year loan matures on August 1, 2017, is payable in 12 semi-annual installments commencing February 1, 2012 and bears interest at 6-month LIBOR plus 5.0%.

Cash dividend

On August 5, 2009, the Company’s Board of Directors declared, approved and authorized payment of a quarterly dividend of $2.7 million ($0.06 per share) to all holders of the Company’s issued and outstanding shares of common stock on August 18, 2009, payable on August 27, 2009.


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

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

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


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

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

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

	•	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 authorization;

	•	construction or other project delays or cancellations;

	•	financial market conditions and the results of financing efforts;

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

	•	the enforceability of the long-term power purchase agreements for our projects;

	•	contract counterparty risk;

	•	weather and other natural phenomena;

	•	the impact of recent and future federal and state regulatory proceedings and changes, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry and incentives for the production of renewable energy in the United States and elsewhere;

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

	•	current and future litigation;


	•	our ability to successfully identify, integrate and complete acquisitions;

	•	competition from other similar geothermal energy projects, including any such new geothermal energy projects developed in the future, and from alternative electricity producing technologies;

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

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

	•	the direct or indirect impact on our company’s business resulting from terrorist incidents or responses to such incidents, including the effect on the availability of and premiums on insurance;

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

	•	the risk factors set forth in our annual report on Form 10-K for the year ended December 31, 2008 and any updates contained herein which may have a significant impact on our business, operating results or financial condition;

	•	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; and

	•	other risks and uncertainties detailed from time to time in our filings with the Securities and Exchange Commission (SEC).

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

The following discussion and analysis of our financial condition and results of operations should be read together with our condensed consolidated financial statements and related notes included elsewhere in this report and the “Risk Factors” section of our annual report on Form 10-K for the year ended December 31, 2008 and any updates contained herein as well as those set forth in our reports and other filings made with the SEC.

General

Overview

We are a leading vertically integrated company engaged in the geothermal and recovered energy power business. We design, develop, build, own and operate clean, environmentally friendly geothermal and recovered energy-based power plants, in most cases using equipment that we design and manufacture.

Our geothermal power plants include both power plants that we have built and power plants that we have acquired, while all of our recovered energy-based plants have been constructed by us. We conduct our business activities in two business segments, which we refer to as our Electricity Segment and Product Segment. In our Electricity Segment, we develop, build, own and operate geothermal and recovered energy-based power plants in the United States and geothermal power plants in other countries around the world and sell the electricity they generate. In our Product Segment, we design, manufacture and sell equipment for geothermal and recovered energy-based electricity generation, remote power units and other power generating units and provide services relating to the engineering, procurement, construction, operation and maintenance of geothermal and recovered energy 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, Nicaragua and New Zealand, as well as recovered energy generation (REG) power plants in the United States. During the six months ended June 30,

2009 and 2008, our consolidated U.S. and international power plants generated 1,701,179 MWh and 1,444,060 MWh, respectively.

For the six months ended June 30, 2009, our Electricity Segment represented approximately 61.6% of our total revenues, while our Product Segment represented approximately 38.4% of our total revenues during such period. For the six months ended June 30, 2008, our Electricity Segment represented approximately 81.1% of our total revenues, while our Products Segment represented approximately 18.9% of our total revenues, during such period.

For the six months ended June 30, 2009, our total revenues increased by 33.8% (from $149.6 million to $200.1 million) over the same period last year. Revenues from the Electricity Segment increased by 1.6%, while revenues from the Product Segment increased by 171.7%. As discussed below, this increase is attributable to engineering, procurement and construction (EPC) contracts with third parties for the construction of two large geothermal projects, the Blue Mountain project in Nevada and the Centennial Binary Plant in New Zealand.

For the six months ended June 30, 2009, total Electricity Segment revenues from the sale of electricity by our consolidated power plants were $123.2 million, as compared to $121.3 million for the six months ended June 30, 2008. In addition, revenues from our 50% ownership of the Mammoth facility in each of the six months ended June 30, 2009 and 2008 were $4.7 million. This additional data is a Non-Generally Accepted Accounting Principles (Non-GAAP) financial measure, as defined by the SEC. There is no comparable GAAP measure. We believe that such Non-GAAP data is useful to the readers as it provides a more complete view of the scope of activities of the power plants that we operate. Our investment in the Mammoth facility is accounted for in our consolidated financial statements under the equity method and the revenues are not included in our consolidated revenues for the six months ended June 30, 2009 and 2008.

For the six months ended June 30, 2009, revenues attributable to our Product Segment were $76.9 million, as compared to $28.3 million for the six months ended June 30, 2008, an increase of 171.7%. Most of this increase in revenues was derived from EPC contracts with third parties for the construction of two large geothermal projects, the Blue Mountain project in Nevada and the Centennial Binary Plant in New Zealand.

Revenues from our Electricity Segment are relatively predictable, as they are derived from sales of electricity generated by our power plants pursuant to long-term power purchase agreements. The price for electricity under all but one of our power purchase agreements is effectively a fixed price at least through May 2012. The exception is the power purchase agreement of the Puna facility. It has a variable energy rate based on the local utility’s avoided cost, which is the incremental cost that the power purchaser avoids by not having to generate such electrical energy itself or purchase it from others. In the six months ended June 30, 2009, the variable energy rate in the Puna facility decreased significantly mainly as a result of lower oil prices, which in turn impacted the gross margin in our Electricity Segment. In the six months ended June 30, 2009, 89.3% of our electricity revenues were derived from contracts with fixed energy rates, and therefore most of our electricity revenues were not affected by the fluctuations in energy commodity prices. However, electricity revenues are subject to seasonal variations and can be affected by higher-than-average ambient temperatures, as described below under the heading “Seasonality”. Revenues attributable to our Product Segment are based on the sale of equipment and the provision of various services to our customers. These revenues may vary 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 projects 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 as compared to the costs originally budgeted for such orders.

Recent Developments


	•	In July 2009, we entered into certain amendments to certain of our power purchase agreements for our projects in Nevada that among other things removed the provisions that had provided for the payment of liquidated damages if certain minimum performance or availability criteria were not met. These amendments are subject to the approval of the Public Utilities Commission of Nevada (PUCN).

	•	In July 2009, we entered into a 6-year loan agreement and an 8-year loan agreement of $20.0 million each with two separate groups of financial institutions.

	•	Since the beginning of the year, we secured new lease agreements covering approximately 3,700 acres of federal and private land in Nevada and California.

	•	In May 2009, our wholly owned subsidiary, Ortitlan Limitada, entered into a project financing loan of $42.0 million to refinance its investment in the 20.5 MW Amatitlan geothermal power plant. The loan was provided by TCW Global Project Fund II, Ltd.

	•	In the second quarter of 2009, we completed construction of a new 77,500 square foot manufacturing facility, which we lease from our parent, adjacent to our existing facility in Yavne, Israel. The new facility will enable us to expand our manufacturing capabilities.

	•	In March 2009, we declared commercial operation of the 4 MW recovered energy generation (REG) power plant that converts recovered waste heat from the exhaust of an existing gas turbine at a compressor station located along a natural gas pipeline near Denver, Colorado. The electricity produced by the power plant is sold under a 20-year power purchase agreement to Highline Electric Association Inc., a consumer owned cooperative in Colorado and Nebraska.

	•	In January 2009, we declared commercial operation of Phase II of the Olkaria III geothermal power plant in Kenya, the construction of which was completed in December 2008. The new power plant added 35 MW to the existing 13 MW power plant that has been in continuous operation since 2001. Following the declaration of commercial operation our wholly owned subsidiary, OrPower 4, Inc. closed a project financing loan of $105.0 million in March 2009 to refinance its investment in the 48 MW Olkaria III geothermal power plant. The loan was provided by a group of European Development Finance Institutions (DFIs) arranged by DEG — Deutsche Investitions- und Entwicklungsgesellschaft mbH (DEG). The first disbursement of $90.0 million occurred on March 23, 2009, and the second disbursement of $15.0 million occurred on July 10, 2009.

	•	In January 2009, we signed a contract with Banco Centroamericano de Integración Económica (BCIE) for the supply, supervision of installation, start-up and testing of the Las Pailas Geothermal Plant, a new geothermal power plant that is to be constructed in the Las Pailas Field, Costa Rica. The power plant will be utilized by Instituto Costarricense de Electricidad, the Costa Rican national electricity and telecommunications company. The contract is valued at approximately $65.0 million and the supply portion of the contract is expected to be completed within 18 months from the contract start date.

	•	In January 2009, we declared commercial operation of the second 5.5 MW REG unit of the OREG 2 power plants, located in North Dakota. The electricity produced by the power plants is sold to Basin Electric Power Cooperative under a 20-year power purchase agreement.

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 partly been due to increasing natural gas and oil prices during much of this period and, equally important, to newly enacted legislative and regulatory requirements and incentives, such as state renewable portfolio standards and federal tax credits. The

recently enacted American Recovery and Reinvestment Act (ARRA) further encourages the use of geothermal energy through production or investment tax credits as well as cash grants (which are discussed in more detail in the section entitled “Government Grants and Tax Benefits”). We see the increasing demand for energy generated from geothermal and other renewable resources in the United States and the further introduction of renewable portfolio standards as significant trends affecting our industry today and in the immediate future. Our operations and the trends that from time to time impact our operations are subject to market cycles.

We expect to continue to generate the majority of our revenues from our Electricity Segment through the sale of electricity from our power plants. All of our current revenues from the sale of electricity are derived from fully-contracted long-term power purchase agreements. We also intend to continue to pursue growth in our recovered energy business.

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:


	•	The global recession resulting from the recent disruption in the global credit markets, failures or material business deterioration of investment banks, commercial banks, and other financial institutions and intermediaries in the United States and elsewhere around the world, significant reductions in asset values across businesses, households and individuals, and the slowdown in manufacturing and other business activity has also resulted in reduced worldwide demand for energy. If these conditions continue or worsen, they may adversely affect both our Electricity and Product Segments. Among other things, we might face: (i) potential declines in revenues in our Products Segment due to reduced orders or other factors caused by economic challenges faced by our customers and prospective customers; (ii) potential declines in revenues from some of our existing geothermal power projects as a result of curtailed electricity demand and low oil and gas prices; and (iii) potential adverse impacts on our customers’ ability to pay, when due, amounts payable to us. In addition, we may experience related increases in our cost of capital associated with any increased working capital or borrowing needs we may have if our customers do not pay, or if we are unable to collect amounts payable to us in full (or at all) if any of our customers fail or seek protection under applicable bankruptcy or insolvency laws.

	•	The worldwide credit crisis has reduced the availability of liquidity and credit to fund the continuation and expansion of industrial business operations worldwide. While we have sufficient financial resources to fund our projected activities for 2009, if these conditions continue or worsen, the cost of obtaining financing for our project needs may increase or such financing may not be available at all.

	•	Our primary focus continues to be the implementation of our organic growth through exploration, development, the construction of new projects and enhancements of existing projects. We expect that this investment in organic growth will increase our total generating capacity, consolidated revenues and operating income attributable to our Electricity Segment year over year. We are also looking at acquisition opportunities that may arise.

	•	Until the end of the third quarter of 2008, we experienced increases in the cost of raw materials, labor and transportation costs associated with our manufacturing activities and with the equipment used in our power plants and sold to third parties. We also experienced an increase in drilling costs and a shortage in drilling equipment. We believe this was the result of the increased drilling activity in the marketplace that was due to the high oil price environment. The recent decrease in the price of oil and other commodities reduced such costs and may reduce them further in the future. The reduction in costs may serve to partially offset the negative impact of the increased financing cost as described above. The decrease in the price of oil will, however, reduce our revenues from the Puna power plant in 2009, since the energy prices payable to us by Hawaii Electric Light Company in that power plant are based on its avoided costs, which are influenced by the price of oil.

	•	In the United States, we expect to continue to benefit from the increasing demand for renewable energy. Thirty-six states and the District of Columbia, including California, Nevada and Hawaii (where we have been most active in geothermal development and in which all of our U.S. geothermal projects are


		located) have adopted renewable portfolio standards (RPS), renewable portfolio goals or other similar laws. These laws require that an increasing percentage of the electricity supplied by electric utility companies operating in such states be derived from renewable energy resources until certain pre-established goals are met. We expect that the additional demand for renewable energy from utilities in such states will outpace a possible reduction in general demand for energy due to the economic slow down and will continue to create opportunities for us to expand existing projects and build new power plants.


	•	We expect that the increased awareness of climate change may result in significant changes in the business and regulatory environments, which may create business opportunities for us going forward. Although federal legislation addressing climate change appears likely, several states and regions are already addressing climate change. For example, the California Global Warming Solutions Act of 2006 (the Act), which was signed into law in September 2006, regulates most sources of greenhouse gas emissions and aims to reduce greenhouse gas emissions to 1990 levels by 2020, representing an approximately 30% reduction in greenhouse gas emissions. The California Air Resources Board is expected to put in place measures for implementing the Act by 2012. California’s long-term climate change goals are reflected in Executive Order S-3-05, which requires an 80% reduction of greenhouse gases from 1990 levels by 2050. In addition to California, twenty-one other states have set greenhouse gas emissions targets (Arizona, Colorado, Connecticut, Florida, Hawaii, Illinois, Maine, Marryland, Massachusetts, Minnesota, Montana, New Hampshire, New Jersey, New Mexico, New York, Oregon, Rhode Island, Utah, Vermont, Virginia and Washington). Regional initiatives, such as the Western Climate Initiative (which includes seven U.S. states and four Canadian provinces) and the Midwest Greenhouse Gas Reduction Accord, are also being developed to reduce greenhouse gas emissions and develop trading systems for renewable energy credits. In September 2008, the first-in-the-nation auction of CO₂ allowances was held under the Regional Greenhouse Gas Initiative (RGGI), a regional cap-and-trade system, which includes ten Northeast and Mid -Atlantic States. Under RGGI, the ten participating states plan to stabilize power section carbon emissions at their capped level, and then reduce the cap by 10 percent at a rate of 2.5 percent each year between 2015 and 2018. In addition, thirty-six states and the District of Columbia have all adopted RPS, as discussed above. In November 2008, California, by Executive Order, adopted a goal for all retailers of electricity to serve 33% of their load with renewable energy by 2020. Although it is currently difficult to quantify the direct economic benefit of these efforts to reduce greenhouse gas emissions, we believe they will prove advantageous to us.

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

	•	We expect competition from the wind and solar power generation industry to continue. While the current demand for renewable energy is large enough that this increased competition has not materially impacted our ability to obtain new power purchase agreements, it 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 emerge as the preferred source of renewable energy.

	•	We expect increased competition from new entrants to the geothermal industry, both in the power generation space and in the lease of geothermal resources. While the current demand for renewable energy is large enough that increased competition has not impacted our ability to obtain new power purchase agreements and new leases, increased competition in the power generation space may contribute to a reduction in electricity prices, and increased competition in geothermal leasing may contribute to an increase in lease costs.


	•	The viability of our geothermal power plants depends on various factors such as the heat content of the geothermal reservoir, useful life of the reservoir (the term during which such geothermal reservoir has sufficient extractable fluids for our operations) and operational factors relating to the extraction of the geothermal fluids. Our geothermal power plants may experience an unexpected decline in the capacity of their respective geothermal wells. Such factors, together with the possibility that we may fail to find commercially viable geothermal resources in the future, represent significant uncertainties we face in connection with our operations.

	•	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 power purchase agreements as a result of such decrease in availability.

	•	Our foreign operations are subject to significant political, economic and financial risks, which vary by country. These 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.

	•	On May 5, 2009, President Obama and the U.S. Treasury Department proposed changing certain of the U.S. tax rules for U.S. corporations doing business outside the United States. The proposed changes would limit the ability of U.S. corporations to deduct expenses attributable to offshore earnings, modify the foreign tax credit rules and further restrict the ability of U.S. corporations to transfer funds between foreign subsidiaries without triggering a requirement to pay U.S. income tax. Although the scope of the proposed changes is unclear, it is possible that these or other changes in the U.S. tax laws may increase our U.S. income tax liability and adversely affect our profitability.

	•	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 power purchase agreements. We do not expect this change in law to affect our U.S. projects significantly, as all except one of our current contracts (our Steamboat 1 facility, which sells its electricity to Sierra Pacific Power Company on a year-by-year basis) are long-term. FERC issued a final rule that makes it easier to eliminate the utilities’ purchase obligation in four regions of the country. None of those regions includes a state in which our current projects operate. However, FERC has the authority under the Energy Policy Act of 2005 to act, on a case-by-case basis, to eliminate the mandatory purchase obligation in other regions. If the utilities in the regions in which our domestic projects 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 power purchase agreements, 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, manufacturing and sale of equipment for electricity generation; and the construction, installation and engineering of power plant equipment.

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

Our power purchase agreements generally provide for the payment of energy payments, 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 power purchase agreements provide for bonus payments in the event that we are able to exceed certain target levels and the potential forfeiture of payments if we fail to meet minimum target levels. Energy payments, on the other hand, are payments calculated based on the amount of electrical energy delivered to the relevant power purchaser at a designated delivery point. The rates applicable to such payments are either fixed (subject, in certain cases, to certain adjustments) or are based on the relevant power purchaser’s short run avoided costs (the incremental costs that the power purchaser avoids by not having to generate such electrical energy itself or purchase it from others). Our more recent power purchase agreements provide generally 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 are generally less predictable than revenues from our Electricity Segment. This is because larger customer orders for our products are typically a result of our participating in, and winning, tenders or requests for proposals issued by potential customers in connection with projects they are developing. Such projects often take a long time to design and develop and are often subject to various contingencies such as the customer’s ability to raise the necessary financing for a project. As a result, we are generally unable to predict the timing of such orders for our products and may not be able to replace existing orders that we have completed with new ones. As a result, our revenues from our Product Segment fluctuate (and at times, extensively) from period to period. As discussed under “Trends and Uncertainties” above, we may experience declines in revenues in our Product Segment due to reduced orders or other factors caused by the global recession and economic challenges faced by our customers and prospective customers.

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				Six Months Ended				Three Months Ended						Six Months Ended
	June 30,				June 30,				June 30,						June 30,
	2009		2008		2009		2008		2009			2008			2009			2008

Revenues
Electricity Segment	$	60,562	$	61,774	$	123,200	$	121,293		60.4	%		77.0	%		61.6	%		81.1	%
Product Segment		39,673		18,447		76,924		28,315		39.6			23.0			38.4			18.9

Total	$	100,235	$	80,221	$	200,124	$	149,608		100.0	%		100.0	%		100.0	%		100.0	%

Geographical Breakdown of Revenues

For the three months ended June 30, 2009, 69.2% of our revenues attributable to our Electricity Segment were generated in the United States, as compared to 80.8% for the same period in 2008. For the six months ended June 30, 2009, 70.8% of our revenues attributable to our Electricity Segment were generated in the United States, as compared to 81.4% for the same period in 2008.

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				Six Months Ended				Three Months Ended						Six Months Ended
	June 30,				June 30,				June 30,						June 30,
	2009		2008		2009		2008		2009			2008			2009			2008

United States	$	41,926	$	49,937	$	87,283	$	98,763		69.2	%		80.8	%		70.8	%		81.4	%
Foreign		18,636		11,837		35,917		22,530		30.8			19.2			29.2			18.6

Total	$	60,562	$	61,774	$	123,200	$	121,293		100.0	%		100.0	%		100.0	%		100.0	%

For the three months ended June 30, 2009, 60.6% of our revenues attributable to our Product Segment were generated in the United States, as compared to 40.5% for the same period in 2008. For the six months ended June 30, 2009, 61.4% of our revenues attributable to our Product Segment were generated in the United States, as compared to 26.4% for the same period in 2008.

A discussion of the reasons for these changes in the geographical breakdown of our revenues is provided further below in this report.

Seasonality

The prices paid for the electricity generated by our domestic projects pursuant to our power purchase agreements are subject to seasonal variations. The prices paid for electricity under the power purchase agreements with Southern California Edison Company (Southern California Edison) for the Heber 1 and 2 plants, the Mammoth facility and the Ormesa complex and the prices that will be paid for the electricity under the power purchase agreement for the North Brawley project 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 power purchase agreements of our projects in Nevada have no significant changes during the year. In the winter, due principally to the lower ambient temperature, our power plants produce more energy and as a result we receive higher energy revenues. However, the higher capacity payments payable by Southern California Edison in California in the summer months have a more significant impact on our revenues than that of the higher energy revenues generally generated in winter due to increased efficiency. As a result, our revenues are generally higher in the summer than in the winter. The prices paid for electricity pursuant to the power purchase agreement of the Puna facility are tied to the price of oil. Accordingly, our revenues for that facility, which accounted for approximately 4.9% and 7.4% of our total revenues for the three and six-month periods ended June 30, 2009, respectively, may be volatile.

Breakdown of Cost of Revenues

Electricity Segment

The principal cost of revenues attributable to our operating projects include 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 and, for the California projects, transmission charges, scheduling charges and purchases of make-up water for use in our cooling towers. Some of these expenses, such as parts, third-party services and major maintenance, are not incurred on a regular basis. This results in fluctuations in our expenses and our results of operations for individual projects from quarter to quarter. The lease expense related to the Puna lease transactions is included as a separate line item in our Electricity Segment cost of revenues (See “Liquidity and Capital Resources”). For management purposes, we analyze such costs on a combined basis with other cost of revenues in our Electricity Segment.

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. For the six months ended June 30, 2009, royalties constituted approximately 4.0% of the Electricity Segment revenues, compared to approximately 5.3% for the same period in 2008.

Product Segment

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

Cash and Cash Equivalents

Our cash and cash equivalents as of June 30, 2009 increased to $46.0 million from $34.4 million as of December 31, 2008. This increase is principally due to the first disbursement in the amount of $90.0 million of the OrPower 4 Inc. financing, $42.0 million from the Amatitlan financing, $20 million from using revolving credit lines with banks, and $55.3 million derived from operating activities during the first six months of 2009. The increase in our cash resources was partially offset by our use of $147.6 million of cash resources to fund capital expenditures, $27.5 million to repay long-term debt to our parent and to third parties. Our corporate borrowing capacity under committed lines of credit with different commercial banks is $347.5 million, as described below in the section entitled “Liquidity and Capital Resources”, of which we utilized $146.4 million (including $26.4 million of letters of credit) as of June 30, 2009.

Critical Accounting Policies

A comprehensive discussion of our critical accounting policies is included in the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section in our annual report on Form 10-K for the year ended December 31, 2008.

New Accounting Pronouncements

On January 1, 2009, the Company adopted Statement of Financial Accounting Standards (SFAS) No. 160, Noncontrolling Interests in Consolidated Financial Statements — an amendment of ARS No. 51. The adoption of this standard resulted in retrospective presentation on the condensed consolidated balance sheet as of December 31, 2008 and the condensed consolidated statements of operations and comprehensive income for the three and six months ended June 30, 2008.

On April 1, 2009, the Company adopted FSP FAS 115-2 and FAS No. 124-2, Recognition and Presentation of Other-Than-Temporary Impairments. The adoption of this standard resulted in a reclassification to other comprehensive loss with an offset to retained earnings effective April 1, 2009.

See Note 2 to our condensed consolidated financial statements set forth in Item 1 of this quarterly report for additional 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 as a result of each of the following: (i) our recent construction of new projects and enhancement of acquired projects; and (ii) fluctuation in revenues from our Product Segment.


	Three Months						Six Months
	Ended						Ended
	June 30,						June 30,
	2009			2008			2009			2008
	(In thousands, except per share data)						(In thousands, except per share data)

Statements of Operations Historical Data:
Revenues:
Electricity	$	60,562		$	61,774		$	123,200		$	121,293
Product		39,673			18,447			76,924			28,315

		100,235			80,221			200,124			149,608

Cost of revenues:
Electricity		44,958			41,506			88,842			80,182
Product		27,242			15,704			51,485			23,754

		72,200			57,210			140,327			103,936

Gross margin:
Electricity		15,604			20,268			34,358			41,111
Product		12,431			2,743			25,439			4,561

		28,035			23,011			59,797			45,672
Operating expenses:
Research and development expenses		2,487			785			3,288			1,481
Selling and marketing expenses		3,215			2,020			7,516			5,539
General and administrative expenses		5,582			5,925			13,117			11,952

Operating income		16,751			14,281			35,876			26,700
Other income (expense):
Interest income		276			1,052			428			2,098
Interest expense, net		(4,415	)		(4,851	)		(7,705	)		(9,637	)
Foreign currency translation and
transaction gains (losses)		2,569			(1,359	)		9			(1,542	)
Income attributable to sale of equity interests		4,366			4,848			8,534			8,164
Other non-operating income, net		550			309			400			21

Income before income taxes and equity in income of investees		20,097			14,280			37,542			25,804
Income tax provision		(4,478	)		(2,613	)		(7,967	)		(4,684	)
Equity in income of investees, net		355			408			905			947

Net income		15,974			12,075			30,480			22,067
Net loss attributable to the noncontrolling interest		77			86			156			158

Net income attributable to the Company’s stockholders	$	16,051		$	12,161		$	30,636		$	22,225

Earnings per share attributable to the Company’s stockholders — basic and diluted
Basic	$	0.35		$	0.28		$	0.68		$	0.52

Diluted	$	0.35		$	0.28		$	0.67		$	0.52

Weighted average number of shares used in computation of earnings per share attributable to the Company’s stockholders:
Basic		45,369			43,828			45,361			42,995

Diluted		45,451			43,978			45,425			43,127


	Three Months						Six Months
	Ended						Ended
	June 30,						June 30,
	2009			2008			2009			2008

Statements of Operations Percentage Data:
Revenues:
Electricity		60.4	%		77.0	%		61.6	%		81.1	%
Product		39.6			23.0			38.4			18.9

		100.0			100.0			100.0			100.0

Cost of revenues:
Electricity		74.2			67.2			72.1			66.1
Product		68.7			85.1			66.9			83.9

		72.0			71.3			70.1			69.5

Gross margin:
Electricity		25.8			32.8			27.9			33.9
Product		31.3			14.9			33.1			16.1

		28.0			28.7			29.9			30.5

Operating expenses:
Research and development expenses		2.5			1.0			1.6			1.0
Selling and marketing expenses		3.2			2.5			3.8			3.7
General and administrative expenses		5.6			7.4			6.6			8.0

Operating income		16.7			17.8			17.9			17.8
Other income (expense):
Interest income		0.3			1.3			0.2			1.4
Interest expense, net		(4.4	)		(6.0	)		(3.9	)		(6.4	)
Foreign currency translation and transaction gains (losses)		2.6			(1.7	)		0.0			(1.0	)
Income attributable to sale of equity interests		4.4			6.0			4.3			5.5
Other non-operating income, net		0.5			0.4			0.2			0.0

Income before income taxes and equity in income of investees		20.0			17.8			18.8			17.2
Income tax provision		(4.5	)		(3.3	)		(4.0	)		(3.1	)
Equity in income of investees, net		0.4			0.5			0.5			0.7

Net income		15.9			15.1			15.2			14.8
Net loss attributable to the noncontrolling interest		0.1			0.1			0.1			0.1

Net income attributable to the Company’s stockholders		16.0	%		15.2	%		15.3	%		14.9	%

Comparison of the Three Months Ended June 30, 2009 and the Three Months Ended June 30, 2008

Total Revenues

Total revenues for the three months ended June 30, 2009 were $100.2 million, as compared with $80.2 million for the three months ended June 30, 2008, which represented a 24.9% increase in total revenues. This increase is attributable to our Product Segment whose revenues increased by 115.1% over the same period in 2008 (for the reasons discussed below). Revenues in our Electricity Segment decreased by 2.0%, over the same period last year.

Electricity Segment

Revenues attributable to our Electricity Segment for the three months ended June 30, 2009 were $60.6 million, as compared with $61.8 million for the three months ended June 30, 2008, which represented a 2.0% decrease in such revenues. The decrease in our electricity revenues is a result of a decline in the average revenue rate of our electricity portfolio from $87 per MWh in the second quarter of 2008 to $75 per MWh in the second quarter of 2009. The decrease in the average rate is mainly attributable to a decrease in the energy rates in the Puna power plant, due to lower oil prices and to the expiration of the “adder”, an additional energy rate paid to us under the Heber 2 power purchase agreement. Our U.S. and international electricity generation increased from 711,794 MWh in the three months ended June 30, 2008 to 811,487 MWh in the three months ended June 30, 2009. The increase in our electricity generation is principally due to the 35 MW Phase II of the Olkaria III power plant in Kenya, which started generating electricity in January 2009 and to our 8 MW GDL power plant in New Zealand, which started generating electricity in the fourth quarter of 2008. In the United States, the electricity generation increased due to: (i) two new REG units at the OREG II power plants, which were placed in service in December 2008 and January 2009; and (ii) the replacement of turbines in the Steamboat 2/3 power plant. The increase was offset by a decrease in the generating capacity of the Puna power plant due to an enhancement and repair of the geothermal wellfield to increase its availability in advance of the addition of the new 8 MW expansion.

Product Segment

Revenues attributable to our Product Segment for the three months ended June 30, 2009 were $39.7 million, as compared with $18.4 million for the three months ended June 30, 2008, which represented a 115.1% increase in such revenues. Most of this increase in revenues was derived from EPC contracts with third parties for the construction of two large geothermal projects, the Blue Mountain project in Nevada and the Centennial Binary Plant in New Zealand.

Total Cost of Revenues

Total cost of revenues for the three months ended June 30, 2009 was $72.2 million, as compared with $57.2 million for the three months ended June 30, 2008, which represented a 26.2% increase in total cost of revenues. This increase occurred in both our Electricity and Product Segments, as discussed below. As a percentage of total revenues, our total cost of revenues for the three months ended June 30, 2009 was 72.0% compared with 71.3% for the same period in 2008.

Electricity Segment

Total cost of revenues attributable to our Electricity Segment for the three months ended June 30, 2009 was $45.0 million, as compared with $41.5 million for the three months ended June 30, 2008, which represented an 8.3% increase in total cost of revenues for such segment. The increase over the same period last year is due to: (i) increased costs as a result of new and enhanced projects placed into service (including depreciation); and (ii) an increase in costs mainly due to timing of certain maintenance costs in order to ensure higher availability during the summer., when electricity rates paid under the relevant power purchase agreement are higher. The increase in the cost of revenues is generation volume related, and thus, the cost per MWh was lower compared to the second quarter of 2008. As a percentage of total electricity revenues, the total cost of revenues attributable to our Electricity Segment for the three months ended June 30, 2009 was 74.2%, as compared with 67.2% for the three months ended June 30, 2008.

Product Segment

Total cost of revenues attributable to our Product Segment for the three months ended June 30, 2009 was $27.2 million, as compared with $15.7 million for the three months ended June 30, 2008, which represented a 73.5% increase in total cost of revenues related to such segment. This increase is attributable to the increase in our product revenues. As a percentage of total Products Segment revenues, our total cost of revenues attributable to this segment for the three months ended June 30, 2009 was 68.7% as compared with 85.1% for

the three months ended June 30, 2008. This decrease is attributable, in part, to a different product mix and to a decrease in costs as a result of the global decrease in commodities prices.

Research and Development Expenses

Research and development expenses for the three months ended June 30, 2009 were $2.5 million, as compared with $0.8 million for the three months ended June 30, 2008, which represented a 216.8% increase. This increase reflects an expansion of our research and development activities in the following areas: (i) Enhanced Geothermal Systems (EGS); (ii) a REG plant specifically designed to use the residual energy from the vaporization process at a liquefied natural gas regasification terminal; and (iii) development of a solar thermal system for the production of electricity.

Selling and Marketing Expenses

Selling and marketing expenses for the three months ended June 30, 2009 were $3.2 million, as compared with $2.0 million for the three months ended June 30, 2008, which represented a 59.2% increase. The increase was due primarily to an increase in Product Segment revenues. Selling and marketing expenses for the three months ended June 30, 2009 constituted 3.2% of total revenues for such period, as compared with 2.5% for the three months ended June 30, 2008.

General and Administrative Expenses

General and administrative expenses for the three months ended June 30, 2009 were $5.6 million, as compared with $5.9 million for the three months ended June 30, 2008, which represented a 5.8% decrease. General and administrative expenses for the three months ended June 30, 2009 constituted 5.6% of total revenues for such period, as compared with 7.4% for the three months ended June 30, 2008.

Operating Income

Operating income for the three months ended June 30, 2009 was $16.8 million, as compared with $14.3 million for the three months ended June 30, 2008. Such increase in operating income was principally attributable to an increase in total revenues as well as an increase in the gross margin of our Product Segment. Operating income attributable to our Electricity Segment for the three months ended June 30, 2009 was $10.0 million, as compared with $14.1 million for the three months ended June 30, 2008. Operating income attributable to our Product Segment for the three months ended June 30, 2009 was $6.8 million, as compared with $0.2 million for the three months ended June 30, 2008.

Interest Income

Interest income for the three months ended June 30, 2009 was $0.3 million, as compared with $1.1 million for the three months ended June 30, 2008, which represented a 73.8% decrease. The decrease is primarily due to a decrease in cash and cash equivalents, marketable securities and restricted cash as well as a decrease in interest rates payable on liquid investments.

Interest Expense, Net

Interest expense, net, for the three months ended June 30, 2009 was $4.4 million, as compared with $4.9 million for the three months ended June 30, 2008, which represented a 9.0% decrease. The $0.4 million decrease is primarily due to an increase of $2.3 million in interest capitalized to projects as a result of increased projects under construction, as well as principal repayments. The decrease was partially offset by an increase in interest expense from the long-term project finance loans of the Olkaria III and Amatitlan power plants, and borrowings under the Company’s revolving credit lines with banks.

During the second quarter of 2009, we capitalized $6.4 million in interest related to projects under construction. We expect this amount to decrease significantly due to a lower volume of projects under

construction and the upcoming commencement of commercial operation of our North Brawley power plant in the fourth quarter of 2009.

Foreign Currency Translation and Transaction Gains (Losses)

Foreign currency translation and transaction gains for the three months ended June 30, 2009 were $2.6 million, as compared with foreign currency translation and transaction losses of $1.4 million for the three months ended June 30, 2008. The $3.9 million increase is primarily due to: (i) foreign currency translation gains in the amount of $1.5 million with respect to a loan denominated in New Zealand dollars which was granted to our New Zealand subsidiary GDL, whose functional currency is the New Zealand dollar; and (ii) gains on forward and option foreign exchange transactions which do not qualify as hedge transactions for accounting purposes. The foreign currency translation gains in respect of the loan granted to our New Zealand subsidiary will increase the cost of the equipment which was financed by such loan.

Income Attributable to a Sale of Equity Interests

Income from the sale of limited liability company interests in OPC to institutional equity investors (as described in the “OPC Transaction”) for the three months ended June 30, 2009 was $4.4 million, as compared to $4.8 million for the three months ended June 30, 2008.

Income Taxes

Income tax provision for the three months ended June 30, 2009 was $4.5 million, as compared with $2.6 million for the three months ended June 30, 2008. The effective tax rate for the three months ended June 30, 2009 and 2008 was 22.3% and 18.3%, respectively. The increase in the effective tax rate primarily resulted from a lower impact of production tax credits on the effective tax rate for the quarter ended June 30, 2009 due to the increase in our income before income taxes.

Equity in Income of Investees

Our participation in the income generated from our investees in each of the three months ended June 30, 2009 and 2008 was $0.4 million. The amount is derived mainly from our 50% ownership of the Mammoth power plant.

Net Income

Net income for the three months ended June 30, 2009 was $16.0 million, as compared with $12.1 million for the three months ended June 30, 2008, which represents an increase of 32.3%. Such increase in net income was principally attributable to: (i) an increase of $2.5 million in our operating income; (ii) a $0.4 million decrease in interest expense; and (iii) a $3.9 million increase in foreign currency transaction and translation gains. This was partially offset by: (i) a $1.9 million increase in income tax provision; (ii) a $0.5 million decrease in income attributable to a sale of equity interests; and (iii) a $0.8 million decrease in interest income.

Comparison of the Six Months Ended June 30, 2009 and the Six Months Ended June 30, 2008

Total Revenues

Total revenues for the six months ended June 30, 2009 were $200.1 million, as compared with $149.6 million for the six months ended June 30, 2008, which represented a 33.8% increase in total revenues. This increase is primarily attributable to our Product Segment whose revenues increased by 171.7% over the same period in 2008 (for the reasons discussed below). Revenues in our Electricity Segment increased by 1.6%, over the same period last year.

Electricity Segment

Revenues attributable to our Electricity Segment for the six months ended June 30, 2009 were $123.2 million, as compared with $121.3 million for the six months ended June 30, 2008, which represented a 1.6% increase in such revenues. The increase in the Electricity Segment revenues is attributable to an increase in our U.S. and international electricity generation from 1,444,060 MWh in the six months ended June 30, 2008 to 1,701,179 MWh in the six months ended June 30, 2009. The increase in our electricity generation is principally due to the 35 MW Phase II of the Olkaria III power plant in Kenya, which started generating electricity in January 2009 and to our 8 MW GDL power plant in New Zealand, which started generating electricity in the fourth quarter of 2008. In the United States, the electricity generation increased due to: (i) the new Galena 3 power plant, which was placed in service in the second half of the first quarter of 2008; (ii) two new REG units at the OREG II power plants, which were placed in service in December 2008 and January 2009; and (iii) the replacement of turbines in the Steamboat 2/3 power plant. The increase in our electricity revenues was offset by a decrease resulting from a decline in the average revenue rate of our electricity portfolio from $84 per MWh in the first half of 2008 to $72 per MWh in the first half of 2009. The decrease in the average rate is mainly attributable to a decrease in the energy rates in the Puna power plant, due to lower oil prices and to the expiration of the “adder”, an additional energy rate paid to us under the Heber 2 power purchase agreement. The decrease in the Electricity Segment revenues in the first half of 2009 is also attributable to a temporary decrease in the generating capacity of the Puna power plant due to an enhancement and repair of the geothermal wellfield to increase its availability in advance of the addition of the 8 MW expansion.

Product Segment

Revenues attributable to our Product Segment for the six months ended June 30, 2009 were $76.9 million, as compared with $28.3 million for the six months ended June 30, 2008, which represented a 171.7% increase in such revenues. Most of this increase in revenues was derived from EPC contracts with third parties for the construction of two large geothermal projects, the Blue Mountain project in Nevada and the Centennial Binary Plant in New Zealand.

Total Cost of Revenues

Total cost of revenues for the six months ended June 30, 2009 was $140.3 million, as compared with $103.9 million for the six months ended June 30, 2008, which represented a 35.0% increase in total cost of revenues. This increase is attributable to an increase in both our Electricity and Product Segments, as discussed below. As a percentage of total revenues, our total cost of revenues for the six months ended June 30, 2009 was 70.1% compared with 69.5% for the same period in 2008.

Electricity Segment

Total cost of revenues attributable to our Electricity Segment for the six months ended June 30, 2009 was $88.8 million, as compared with $80.2 million for the six months ended June 30, 2008, which represented a 10.8% increase in total cost of revenues for such segment. The increase from the same period last year is due to: (i) increased costs as a result of new and enhanced projects placed into service (including depreciation); and (ii) an increase in costs mainly due to timing of certain maintenance costs in order to ensure higher availability during the summer, when electricity rates paid under the relevant power purchase agreement are higher. The increase in the cost of revenues is generation volume related, and thus, the cost per MWh was lower compared to the first half of 2008. As a percentage of total electricity revenues, the total cost of revenues attributable to our Electricity Segment for the six months ended June 30, 2009 was 72.1%, as compared with 66.1% for the six months ended June 30, 2008.

Product Segment

Total cost of revenues attributable to our Product Segment for the six months ended June 30, 2009 was $51.5 million, as compared with $23.8 million for the six months ended June 30, 2008, which represented a

116.7% increase in total cost of revenues related to such segment. This increase is attributable to the increase in our product revenues. As a percentage of total Product Segment revenues, our total cost of revenues attributable to this segment for the six months ended June 30, 2009 was 66.9% as compared with 83.9% for the six months ended June 30, 2008. This decrease is attributable, in part, to a different product mix and to a decrease in costs as a result of the global decrease in commodities prices.

Research and Development Expenses

Research and development expenses for the six months ended June 30, 2009 were $3.3 million, as compared with $1.5 million for the six months ended June 30, 2008, which represented a 122.0% increase. Our research and development activities during the period included: (i) Enhanced Geothermal Systems (EGS); (ii) a REG plant specifically designed to use the residual energy from the vaporization process at a liquefied natural gas regasification terminal; and (iii) development of a solar thermal system for the production of electricity.

Selling and Marketing Expenses

Selling and marketing expenses for the six months ended June 30, 2009 were $7.5 million, as compared with $5.5 million for the six months ended June 30, 2008, which represented a 35.7% increase. The increase was due primarily to an increase in Product Segment revenues. Selling and marketing expenses for the six months ended June 30, 2009 constituted 3.8% of total revenues for such period, as compared with 3.7% for the six months ended June 30, 2008.

General and Administrative Expenses

General and administrative expenses for the six months ended June 30, 2009 were $13.1 million, as compared with $12.0 million for the six months ended June 30, 2008, which represented a 9.7% increase. Such increase is primarily attributable to a significant increase in bonus payments to company personnel, including our general and administrative staff, based on our performance. The bonus payment also affected other operating expenses. General and administrative expenses for the six months ended June 30, 2009 constituted 6.6% of total revenues for such period, as compared with 8.0% for the six months ended June 30, 2008.

Operating Income

Operating income for the six months ended June 30, 2009 was $35.9 million, as compared with $26.7 million for the six months ended June 30, 2008. Such increase in operating income was principally attributable to an increase in total revenues as well as an increase in the gross margin of our Product Segment. Operating income attributable to our Electricity Segment for the six months ended June 30, 2009 was $21.2 million, as compared with $26.7 million for the six months ended June 30, 2008. Operating income attributable to our Product Segment for the six months ended June 30, 2009 was $14.7 million, as compared with $0.1 million for the six months ended June 30, 2008.

Interest Income

Interest income for the six months ended June 30, 2009 was $0.4 million, as compared with $2.1 million for the six months ended June 30, 2008, which represented a 79.6% decrease. The decrease is primarily due to a decrease in cash and cash equivalents, marketable securities and restricted cash as well as a decrease in interest rates payable on liquid investments.

Interest Expense, Net

Interest expense, net, for the six months ended June 30, 2009 was $7.7 million, as compared with $9.6 million for the six months ended June 30, 2008, which represented a 20.0% decrease. The $1.9 million decrease is primarily due to an increase of $4.3 million in interest capitalized to projects as a result of increased projects under construction, as well as principal repayments. The decrease was partially offset by an

increase in interest expenses related to the sale of limited liability company interests in OPC and interest expenses related to our long-term project finance loans of the Olkaria III and Amatitlan power plants and borrowings under our revolving credit lines with banks.

Foreign Currency Translation and Transaction Gains (Losses)

Foreign currency translation and transaction gains for the six months ended June 30, 2009 were $0.1 million, as compared with foreign currency translation and transaction losses of $1.5 million for the six months ended June 30, 2008. The $1.6 million increase is primarily due to foreign currency translation gains in the amount of $1.3 million with respect to a loan denominated in New Zealand dollars, which was granted to our New Zealand subsidiary GDL, whose functional currency is the New Zealand dollar.

Income Attributable to a Sale of Equity Interests

Income from the sale of limited liability company interests in OPC to institutional equity investors (as described in “OPC Transaction”) for the six months ended June 30, 2009 was $8.5 million, as compared to $8.2 million for the six months ended June 30, 2008.

Income Taxes

Income tax provision for the six months ended June 30, 2009 was $8.0 million, as compared with $4.7 million for the six months ended June 30, 2008. The effective tax rate for the six months ended June 30, 2009 and 2008 was 21.2% and 18.2%, respectively. The increase in the effective tax rate primarily resulted from a lower impact of production tax credits on the effective tax rate for the period ended June 30, 2009 due to the increase in our income before income taxes.

Equity in Income of Investees

Our participation in the income generated from our investees for each of the six months ended June 30, 2009 and 2008 was $0.9 million. The amount is derived mainly from our 50% ownership of the Mammoth power plant.

Net Income

Net income for the six months ended June 30, 2009 was $30.5 million, as compared with $22.1 million for the six months ended June 30, 2008, which represents an increase of 38.1%. Such increase in net income was principally attributable to: (i) an increase of $9.2 million in our operating income; (ii) a $1.9 million decrease in interest expense; (iii) an increase of $1.6 million in foreign currency transaction and translation gains; and (iv) a $0.4 million increase in income attributable to a sale of equity interests. This was partially offset by: (i) a $3.3 million increase in income tax provision; and (ii) a $1.7 million decrease in interest income.

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, issuance by Ormat Funding and OrCal Geothermal of their Senior Secured Notes and project financing (including the Puna lease, the OPC Transaction and the Olkaria III and Amatitlan loans described below). We have utilized this cash to fund our acquisitions, develop and construct power generation plants, and meet our other cash and liquidity needs.

As of June 30, 2009, we have access to the following sources of funds: (i) $46.0 million in cash and cash equivalents; (ii) proceeds of $15.0 million which were drawn on July 10, 2009 under the Olkaria III refinancing described below; and (iii) $201.1 million of unused corporate borrowing capacity under existing committed lines of credit with different commercial banks. In addition, as described below, in July 2009,

following the period of this report, we entered into two long-term loan agreements of $20.0 million each with financial institutions.

Our estimated capital needs for the rest of 2009 include approximately $150.0 million for capital expenditures on new projects in development or construction, exploration activity, operating projects, and machinery and equipment, as well as $21.6 million for debt repayment (including to our parent).

We expect to finance these requirements with: (i) the sources of liquidity described above; (ii) cash flows from our operations; (iii) $40.0 million of proceeds from loan agreements with financial institutions that we entered into in July 2009; (iv) additional borrowing capacity under future lines of credit with commercial banks that are under negotiations; (v) future project financing and refinancing; and (vi) cash grant available to us under the ARRA in respect of the North Brawley power plant. Our management believes that these sources will address our anticipated liquidity, capital expenditures and other investment requirements. Our shelf registration statement on Form S-3, which was declared effective on October 2, 2008, provides us with the ability to raise additional capital of up to $1.5 billion through the issuance of securities, subject to market conditions.

Loan Agreements with our Parent

In 2003, we entered into a loan agreement with Ormat Industries Ltd. (our parent company), which was further amended on September 20, 2004. Pursuant to this loan agreement, Ormat Industries agreed to make a loan to us in one or more advances not exceeding a total aggregate amount of $150.0 million. The proceeds of the loan were used to fund our general corporate activities and investments. We are required to repay the loan and accrued interest in full and in accordance with an agreed-upon repayment schedule and in any event on or prior to June 5, 2010. Interest on the loan is calculated on the balance from the date of the receipt of each advance until the date of payment thereof at a fixed rate of 7.5% per annum. All computations of interest are made by Ormat Industries on the basis of a year consisting of 360 days. As of June 30, 2009, the outstanding balance of the loan was approximately $9.6 million, compared to $26.2 million, as of December 31, 2008.

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 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

Ormat Funding Senior Secured Notes — Non Recourse

On February 13, 2004, Ormat Funding Corp. (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, for the purpose of refinancing the acquisition cost of the Brady, Ormesa and Steamboat 1/1A power plants, and the financing of the acquisition cost of the Steamboat 2/3 power plants. The OFC Senior Secured Notes have a final maturity date of December 30, 2020. Principal and interest on the OFC Senior Secured Notes are payable in semi-annual payments which commenced on June 30, 2004. The OFC Senior Secured Notes are collateralized by substantially all of the assets of OFC and those of its wholly owned subsidiaries and are fully and unconditionally guaranteed by all of the wholly owned subsidiaries of OFC. There are various restrictive covenants under the OFC Senior Secured Notes, which include limitations on additional indebtedness and payment of dividends. As of June 30, 2009, OFC was in compliance with the covenants under the OFC Senior Secured Notes. As of June 30, 2009, there were $150.9 million of OFC Senior Secured Notes outstanding.

OrCal Geothermal Senior Secured Notes — Non-Recourse

On December 8, 2005, OrCal Geothermal Inc. (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 of 1933, as amended, for the purpose of refinancing the acquisition cost of the Heber power plants. The OrCal Senior Secured Notes have been rated BBB- by Fitch. The OrCal Senior Secured Notes have a final maturity date of December 30, 2020. Principal and interest on the OrCal Senior Secured Notes are payable in semi-annual payments that commenced on June 30, 2006. The OrCal Senior Secured Notes are collateralized by substantially all of the assets of OrCal and those of its wholly owned subsidiaries and are fully and unconditionally guaranteed by all of the wholly owned subsidiaries of OrCal. There are various restrictive covenants under the OrCal Senior Secured Notes, which include limitations on additional indebtedness and payment of dividends. As of June 30, 2009, OrCal was in compliance with the covenants under the OrCal Senior Secured Notes. As of June 30, 2009, there were $113.6 million of OrCal Senior Secured Notes outstanding.

Olkaria III Loan — Non-Recourse

In March 2009, our wholly owned subsidiary, OrPower 4, Inc. (OrPower 4), closed a project financing loan of $105.0 million to refinance its investment in the 48 MW Olkaria III geothermal power plant located in Kenya. We initially financed construction of Phase I and Phase II of the project, as well as the drilling of wells, with our own funds. The loan is provided by a group of European Development Finance Institutions (DFIs) arranged by DEG — Deutsche Investitions-und Entwicklungsgesellschaft mbH (DEG). The first disbursement of $90.0 million was made on March 23, 2009 and the second disbursement of $15.0 million was made on July 10, 2009. The loan will mature on December 15, 2018, and will be payable in 19 equal semi-annual installments, commencing December 15, 2009. Interest on the loan is variable based on 6-month LIBOR plus 4.0%, but we had the option to fix the interest rate upon each disbursement. We fixed the interest rate on $77.0 million of the loan at 6.90% per annum. There are various restrictive covenants under the loan, which include limitations on OrPower 4’s ability to make distributions to its shareholders. As of June 30, 2009, OrPower 4 was in compliance with the covenants under the loan.

Amatitlan Loan — Non-Recourse

In May 2009, the Company’s wholly owned subsidiary, Ortitlan Limitada (Ortitlan), entered into a note purchase agreement, in an aggregate principal amount of $42.0 million to refinance its investment in the 20 MW Amatitlan geothermal power plant located in Amatitlan, Guatemala. We initially financed the construction of the project, as well as the drilling of wells with corporate funds. The loan was provided by TCW Global Project Funds II, Ltd. (TCW). The loan will mature on June 15, 2016, and will be payable in 28 quarterly installments, commencing September 15, 2009. The annual interest rate on the loan is 9.83%, but the effective cost for us is approximately 8%, due to the elimination, following the refinancing, of the political risk insurance premiums that we had been paying on our equity investment in the project. There are various restrictive covenants under the loan, which include limitations on Ortitlan’s ability to make distributions to its shareholders. Management believes that as of June 30, 2009, Ortitlan was in compliance with the covenants under the loan.

Senior Loans from International Finance Corporation (IFC) and Commonwealth Development Corporation (CDC) — (The Zunil Power Plant) — Non-Recourse

Orzunil I de Electricidad, Limitada (Orzunil), a wholly owned subsidiary in Guatemala, has senior loan agreements with IFC and CDC. The loan from IFC, of which $4.0 million was outstanding as of June 30, 2009, has a fixed annual interest rate of 11.775%, and matures on November 15, 2011. The loan from CDC, of which $3.2 million was outstanding as of June 30, 2009, has a fixed annual interest rate of 10.300%, and matures on August 15, 2010. There are various restrictive covenants under the Senior Loans, which include limitations on Orzunil’s ability to make distributions to its shareholders. As of June 30, 2009, Orzunil was in compliance with the covenants under these senior loans.

Credit Facility Agreement (The Momotombo Power Plant) — Limited Recourse

Ormat Momotombo Power Company (Momotombo), a wholly owned subsidiary in Nicaragua, has a loan agreement with Bank Hapoalim, of which $4.0 million was outstanding as of June 30, 2009, bearing an interest rate of 3-month LIBOR plus 2.375% per annum on tranche one of the loan and 3-month LIBOR plus 3.0% per annum on tranche two of the loan. Tranche one of the loan matures on September 5, 2010, and is payable in 32 quarterly installments of $298,000 each and tranche two of the loan matures on December 5, 2010, and is payable in 28 quarterly installments of $424,000 each. There are various restrictive covenants under this loan, which include limitations on Momotombo’s ability to make distributions to its shareholders. As of June 30, 2009, Momotombo was in compliance with the covenants under the loan.

New Financing of Our Projects

Financing of the North Brawley Power Plant

As a result of the recent enactment of the ARRA, we intend to refinance the equity invested in the North Brawley power plant partially with a cash grant available to us under the ARRA and with long-term debt. We have started to review possible debt options in the capital market.

Full-Recourse Third Party Debt

In December 2008, our subsidiary, Ormat Nevada Inc. (Ormat Nevada), entered into an amendment of its credit agreement with Union Bank, N.A., formerly known as Union Bank of California, N.A. (Union Bank), extending the final maturity of the facility and increasing its total amount to $37.5 million. Under the credit agreement, Ormat Nevada can request extensions of credit in the form of loans and/or the issuance of one or more letters of credit. Union Bank is currently the sole lender and issuing bank under the credit agreement, but is also designated as an administrative agent on behalf of banks that may, from time to time in the future, join the credit agreement as parties thereto. In connection with this transaction, we have entered into a guarantee in favor of the administrative agent for the benefit of the banks, pursuant to which we agreed to guarantee Ormat Nevada’s obligations under the credit agreement. Ormat Nevada’s obligations under the credit agreement are otherwise unsecured by any of its (or any of its subsidiaries’) assets.

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

As of June 30, 2009, ten letters of credit in the amount of $26.4 million remain issued and outstanding under this credit agreement with Union Bank.

We also have credit agreements with five commercial banks for an aggregate amount of $310.0 million. Under these credit agreements, we or our Israeli subsidiary, Ormat Systems, can request extensions of credit in the form of loans and/or the issuance of one or more letters of credit. Each of the credit agreements has a term of three years.

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, 2009, loans in the amount of $120.0 million were outstanding under such credit agreements.

Following the period covered by this report, in July 2009, we entered into a 6-year loan agreement of $20.0 million with a group of financial institutions. The loan matures on July 16, 2015, is payable in 12 semi-annual installments commencing January 16, 2010 and bears annual interest of 6.5%.

Also following the period covered by this report, in July 2009, we entered into an 8-year loan agreement of $20.0 million with a group of financial institutions. The loan matures on August 1, 2017, is payable in 12 semi-annual installments commencing February 1, 2012 and bears interest at 6-month LIBOR plus 5.0%.

Our obligations under the credit and loan agreements are unsecured, but we are subject to a negative pledge in favor of the banks 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. In some cases, we have agreed to maintain certain financial ratios such as a debt service coverage ratio and a debt to equity ratio. 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.

Some of the credit and loan agreements contain cross-default provisions with respect to other material indebtedness owed by us to any third party.

We are currently in compliance with our covenants with respect to these credit and loan agreements, 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, our subsidiary, Ormat Systems, is required from time to time to post performance letters of credit in favor of our customers with respect to orders of products.

Bank Hapoalim and Bank Leumi have issued such performance letters of credit in favor of our customers from time to time. As of June 30, 2009, Bank Hapoalim and Bank Leumi have agreed to make available to us letters of credit totaling $32.9 million and $25.8 million, respectively. As of such date, Bank Hapoalim and Bank Leumi have issued letters of credit in the amount of $19.3 million and $25.8 million, respectively. These letters of credit were not issued under the credit agreements discussed under “Full-Recourse Third Party Debt” above and therefore do not use up the of $310.0 million of credit available under those agreements.

In addition, we and certain of our subsidiaries may request letters of credit under the credit agreements with Union Bank and five other commercial banks as described above under “Full-Recourse Third Party Debt”. As of June 30, 2009, ten letters of credit in the amount of $26.4 million remained issued and outstanding under the Union Bank credit agreement

Puna Project Lease Transactions

On May 19, 2005, our subsidiary in Hawaii, Puna Geothermal Ventures (PGV), entered into a transaction involving the Puna geothermal power plant located on the Big Island of Hawaii. The transaction was concluded with financing parties by means of a leveraged lease transaction. A secondary stage of the lease transaction relating to two new geothermal wells that PGV drilled in the second half of 2005 (for production and injection) was completed on December 30, 2005. Pursuant to a 31-year head lease, PGV leased its geothermal power plant to the abovementioned financing parties in return for deferred lease payments by such financing parties to PGV in the aggregate amount of $83.0 million.

OPC Transaction

On June 7, 2007, our wholly owned subsidiary, Ormat Nevada, entered into agreements with affiliates of Morgan Stanley & Co. Incorporated and Lehman Brothers Inc., under which those investors purchased, for $71.8 million, interests in a newly formed subsidiary of Ormat Nevada, OPC, which owns our Desert Peak 2, Steamboat Hills and Galena 2 power plants located in Nevada.

On April 17, 2008, a second closing of the transaction was concluded. Under this second closing, Ormat Nevada transferred the Galena 3 geothermal power plant to OPC, and received from the institutional equity investors $63.0 million, net of transaction costs.

Ormat Nevada will continue to operate and maintain the projects and will receive initially all of the distributable cash flow generated by the projects until it recovers the capital that it has invested in the projects, while the investors will receive substantially all of the production tax credits and the taxable income or loss, and the distributable cash flow after Ormat Nevada has recovered its capital. The investor’s 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 and the investors will receive 5% 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 projects.

Liquidity Impact of Uncertain Tax positions

As discussed in Note 14 to our Condensed Consolidated Financial Statements set forth in Item 1 of this quarterly report, we have a liability associated with unrecognized tax benefits and related interest and penalties in the amount of approximately $4.1 million as of June 30, 2009. 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 do not believe that the ultimate settlement of our obligations will materially effect our liquidity.

Dividend

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


	Dividend Amount
Date Declared	per Share		Record Date	Payment Date

November 6, 2007	$	0.05	November 28, 2007	December 12, 2007
February 26, 2008	$	0.05	March 14, 2008	March 27, 2008
May 6, 2008	$	0.05	May 20, 2008	May 27, 2008
August 5, 2008	$	0.05	August 19, 2008	August 29, 2008
November 5, 2008	$	0.05	November 19, 2008	December 2, 2008
February 24, 2009	$	0.07	March 16, 2009	March 26, 2009
May 8, 2009	$	0.06	May 20, 2009	May 27, 2009
August 5, 2009	$	0.06	August 18, 2009	August 27, 2009

Historical Cash Flows

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


	Six Months Ended
	June 30,
	2009			2008

Net cash provided by operating activities	$	55,332		$	49,624
Net cash used in investing activities		(158,402	)		(167,377	)
Net cash provided by financing activities		114,519			208,293
Translation adjustments on cash and cash equivalents		186			—
Net change in cash and cash equivalents		11,635			90,540

For the Six Months ended June 30, 2009

Net cash provided by operating activities for the six months ended June 30, 2009 was $55.3 million, as compared with $49.6 million for the six months ended June 30, 2008. Such net increase of $5.7 million resulted primarily from the increase in net income to $30.5 million in the six months ended June 30, 2009, as compared with $22.1 million in the six months ended June 30, 2008, mainly as a result of the increase in the operating income, as described above.

Net cash used in investing activities for the six months ended June 30, 2009 was $158.4 million, as compared with $167.4 million for the six months ended June 30, 2008. The principal factors that affected our net cash used in investing activities during the six months ended June 30, 2009 were capital expenditures of $147.6 million, primarily for our facilities under construction and a $10.6 million increase in restricted cash, cash equivalents and marketable securities. The principal factors that affected our net cash used in investing activities during the six months ended June 30, 2008 were capital expenditures of $177.9 million, primarily for our power facilities under construction and a $3.1 million increase in restricted cash, cash equivalents and marketable securities, offset by a $12.6 million decrease in marketable securities.

Net cash provided by financing activities for the six months ended June 30, 2009 was $114.5 million, as compared with $208.3 million for the six months ended June 30, 2008. The principal factors that affected the net cash provided by financing activities during the six months ended June 30, 2009 were: (i) the proceeds of $90.0 million from the Olkaria III Loans; (ii) proceeds of $42.0 million from the Amatitlan Loan; and (iii) $20.0 million drawn under revolving lines of credit from banks, offset by: (i) the repayment of debt to our parent in the amount of $16.6 million; (ii) the repayment of long-term debt in the amount of $10.9 million; and (iii) the payment of a dividend to our shareholders in the amount of $5.9 million. The principal factors that affected our net cash provided by financing activities during the six months ended June 30, 2008 were: (i) the net proceeds of $149.7 million from the sale of 3,100,000 shares in block trade; (ii) the $33.3 million net proceeds from our sale of 693,750 shares to our parent; and (iii) the $63.1 million in net proceeds received from the institutional equity investors in OPC for the transfer of the Galena 3 geothermal project to OPC, relating to the second closing of the OPC Transaction, offset by: (i) the repayment of long-term debt in the amount of $17.0 million, (ii) the repayment of debt to our parent in the amount of $16.6 million; and (iii) the payment of a dividend to our shareholders in the amount of $4.4 million.

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. We expect that the following enhancements of our existing power plants and the construction of new power plants will be funded initially from internally generated cash or other available corporate resources, which we expect to subsequently refinance with limited or non-recourse debt at the project level.

Puna Project. An enhancement program for the Puna project is intended to increase the output of the project by an estimated 8 MW through the construction of OEC units. We expect that such enhancement program will be completed by the end of 2009 or 2010. We are in discussions with Hawaii Electric Light Company for the sale of additional electrical power from the Puna project.

OREG 2 Project. We have brought on line two of the four units of the OREG 2 REG project along the Northern Border natural gas pipeline, which have a net capacity of 5.5 MW each. The remaining two units are expected to be completed by the end of 2009.

East Brawley Project. We plan to construct and have begun manufacturing equipment and exploration drilling for an additional 30 MW power plant in the Brawley Known Geothermal Resource Area in Imperial County, California, adjacent to the North Brawley project. Completion of the project was initially projected for the end of 2009. We are still awaiting the required construction permits and therefore the project’s completion will be delayed until 2010.

GRE Project. We are developing a 5.3 MW recovered energy generation project for Great River Energy, which will be located along the Northern Border pipeline in Martin County, Minnesota. We signed a 20-year

power purchase agreement with Great River Energy. We expect this facility to be commissioned by the end of 2009.

Jersey Valley Project. We are currently developing the Jersey Valley project on Bureau of Land Management leases located in Nevada. The project is expected to deliver between 18 MW to 30 MW of power generation under a 20-year power purchase agreement with NV Energy, Inc. We expect this project to be completed by the end of 2010.

We have budgeted approximately $353 million for the projects described above and have invested approximately $121 million of such budget as of June 30, 2009, and expect to invest approximately $103 million in the rest of 2009.

In addition to the above projects, our operating power plants have capital expenditure requirements for 2009 of approximately $2 million. We plan to start other construction and enhancement of additional projects for a total amount of $2 million and we have various leases for geothermal resources, in which we have started exploration activity, for a total investment amount of approximately $15 million for the rest of 2009.

In addition, in order to finalize the construction of the North Brawley power plant we plan to invest approximately $28 million in such power plant in the rest of 2009.

Exposure to Market Risks

The recent worldwide financial and credit crisis has reduced the availability of liquidity and credit to fund the continuation and expansion of industrial business operations worldwide. While, based on current conditions, we believe that we have sufficient financial resources to fund our activities and execute our business plan in 2009, if worldwide economic conditions worsen, the cost of obtaining financing for our project needs may increase significantly or such financing may not be available at all. In addition, 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 limited currently because our long-term power purchase agreements 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 power purchase agreements for the Heber 1 and 2 power plants, the Ormesa complex and the Mammoth power plants will be determined by reference to the relevant power purchaser’s short run avoided costs. The decline in oil prices that impact Hawaii Electric Light Company’s avoided costs reduced the energy rates for the Puna plant and may reduce it further if oil prices continue to decline. However, the energy rates in the Puna power plant are higher than the floor under the Puna power purchase agreement. As of June 30, 2009, 74.5% of our consolidated long-term debt (including amounts owed to our parent) was in the form of fixed rate securities, and therefore, not subject to interest rate volatility risk. As of such date, 25.5% 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, 2009, $137.0 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, commercial paper (with a minimum investment grade rating of AA by Standard & Poor’s Ratings Services).

Our cash equivalents and our portfolio of marketable securities are subject to market risk due to changes in interest rates. Fixed rate securities may have their market value adversely impacted due to a rise in interest rates, while floating rate securities may produce less income than expected if interest rates fall. Due in part to these factors, our future investment income may fall short of expectation 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. Auction rate securities are securities that are structured with short-term interest rate reset dates of generally less than ninety days but with contractual maturities that can be

well in excess of ten years. At the end of each reset period, which depending on the security can occur on a daily, weekly, or monthly basis, investors can sell or continue to hold the securities at par. These securities are subject to fluctuations in fair value depending on the supply and demand at each auction.

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 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 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 power purchase agreements 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. Through most of 2008, we did not use any material foreign currency exchange contracts or other derivative instruments to reduce our exposure to this risk. 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, Hawaii Electric Light Company, and Sierra Pacific Power Company and Nevada Power Company (subsidiaries of NV Energy, Inc.). If any of these electric utilities fails to make payments under its power purchase agreements with us, such failure would have a material adverse impact on our financial condition.

Southern California Edison accounted for 21.1% and 30.7% of our total revenues for the three months ended June 30, 2009 and 2008, respectively, and 19.5% and 30.5% of our total revenues for the six months ended June 30, 2009 and 2008, respectively. Southern California Edison is also the power purchaser and revenue source for our Mammoth power plants, which we account for separately under the equity method of accounting.

Hawaii Electric Light Company accounted for 4.9% and 16.5% of our total revenues for the three months ended June 30, 2009 and 2008, respectively, and 7.4% and 18.6% of our total revenues for the six months ended June 30, 2009 and 2008, respectively.

Sierra Pacific Power Company and Nevada Power Company accounted for 12.0% and 12.4% of our total revenues for the three months ended June 30, 2009 and 2008, respectively, and 12.8% and 13.5% of our total revenues for the six months ended June 30, 2009 and 2008, respectively.

Government Grants and Tax Benefits

On February 17, 2009, President Obama signed into law the ARRA, which extended the existing tax subsidy for companies that use geothermal steam or fluid to generate electricity. The existing tax subsidy is a “production tax credit,” which in 2009 is 2.1 cents per kWh and is adjusted annually for inflation. The production tax credit may be claimed for ten years on the electricity output of new geothermal power plants put into service by December 31, 2013. The ARRA also allows companies that generate electricity from certain renewable sources, including geothermal steam or fluid, to forego the production tax credit and elect instead a one-time investment tax credit equal to 30% of the cost of the renewable energy production facility. The investment tax credit is claimed when the qualifying facility is placed in service for federal income tax purposes. The owner of the project must choose between the production tax credit and the 30% investment tax credit 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 production tax credit or the investment tax credit, 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 maybe deducted in the first few years than during the remainder of the depreciation period. For certain projects that we place into service in 2009, we may be able to claim a depreciation bonus that, in addition to accelerated depreciation, would permit us to deduct 50% of the plant cost in 2009. If we claim the investment tax credit, our “tax base” in the plant that we can recover through depreciation and the depreciation bonus must be reduced by half of the tax credit; if we claim a production tax credit; there is no reduction in the tax basis for depreciation. Companies that begin construction on qualifying energy facilities during 2009 or 2010 (and complete such facilities no later than 2013), or place qualifying facilities in service during 2009 or 2010, may choose to apply for a cash grant from the U.S. Department of Treasury in an amount equal to the investment tax credit. Under the ARRA, the U.S. Department of 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. We believe that a number of our new geothermal plants may qualify for the cash grant from the Department of Treasury. Although some questions remain open regarding the scope of the new subsidies under the ARRA, we expect them to lead to increased sources of capital for our business.

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

To be eligible for a guarantee under the new program, a supported project must break ground, and the guarantee must be issued, by September 30, 2011. A project supported by the federal guarantee under the new program must pay prevailing federal wages.

Based on the appropriation of $6 billion dollars to pay the credit subsidy costs of guarantees issued under the new program, it is likely that between $60 billion to $120 billion of financing (assuming average subsidy requirements between 10% and 5%, respectively) will be available to eligible projects, including geothermal power plants.

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 is subject to reduced Israeli income tax rates of 25% for an additional five years. Ormat Systems is also exempt from Israeli income taxes with respect to income derived from the second benefited investment for a period of two years that started in 2007, and thereafter such income is subject to reduced Israeli income tax rates of 25% for an additional five years. These benefits are subject to certain conditions, including among other things, that all transactions between Ormat Systems and our affiliates are at arms length, and that the management and control of Ormat Systems will be from Israel during the whole period of the tax benefits. A change in control should be reported to the Israeli Tax Authorities in order to maintain the tax benefits. In addition, as an industrial company, Ormat Systems is entitled to accelerated depreciation on equipment used for its industrial activities. Under the provisions of certain tax regulations published in Israel in 2005, industrial companies whose operations are mostly “Eligible Operations” are entitled to claim accelerated depreciation at the rate of 100% on machinery and equipment acquired from July 1, 2005 to December 31, 2006. Accelerated depreciation is to be claimed over two years. In the year in which the equipment was acquired, the regular depreciation rate is to be claimed, with the remainder to be claimed in the second year. Under the provisions of certain tax regulations published in Israel in July 2008, industrial companies whose operations are mostly “Eligible Operations” are entitled to claim accelerated depreciation at the rate of 50% on machinery and equipment acquired from June 1, 2008 to May 31, 2009 and placed in service at the later of six months after acquisition or before May 31, 2009.


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, 2009, 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 2009 that have materially affected or are reasonably likely to materially affect our internal controls over financial reporting.

PART II — OTHER INFORMATION


ITEM 1.	*LEGAL PROCEEDINGS*

There were no material developments in any legal proceedings to which the Company is a party during the three months period ended June 30, 2009.

From time to time, we (and our subsidiaries) are a party to various lawsuits, claims and other legal and regulatory proceedings that arise in the ordinary course of our (and their) 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, we accrue reserves in accordance with accounting principles generally accepted in the U.S. We do not believe that any of these proceedings, individually or in the aggregate, would materially and adversely affect our business, financial condition, future results and cash flows.


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, 2008 filed with the SEC on March 2, 2009.


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 2009.


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.	*SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS*

On May 8, 2009, we held our Annual Meeting of Stockholders. The three directors whose terms expired at the meeting, Yehudit Bronicki, Jacob J. Worenklein and Robert F. Clarke, were each re-elected by vote of the stockholders at such meeting. In addition, the stockholders voted to ratify the appointment of PricewaterhouseCoopers LLP as our independent auditor for fiscal year 2009.

The results of the votes were as follows:

Votes Against/

Broker

Proposal

Votes For

Withheld

Abstentions

Non-Vote

Election of Director Yehudit Bronicki

34,106,003

5,975,323

None

Election of Director Jacob J. Worenklein

39,799,214

282,112

None

Election of Director Robert F. Clarke

39,799,214

309,301

None

Ratification of appointment of PricewaterhouseCoopers LLP

35,256,819

181,941

None


ITEM 5.	*OTHER INFORMATION*

None.


ITEM 6.	*EXHIBITS [to update]*


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	.3	Form of Rights Agreement by and between Ormat Technologies, Inc. and American Stock Transfer & Trust Company, incorporated by reference to Exhibit 4.3 to Ormat Technologies, Inc. Registration Statement Amendment No. 2 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on October 22, 2004.
	4	.4	Indenture for Senior Debt Securities, dated as of January 16, 2006, between Ormat Technologies, Inc. and Union Bank of California, incorporated by reference to Exhibit 4.2 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-3 (File No. 333-131064) to the Securities and Exchange Commission on January 26, 2006.
	4	.5	Indenture for Subordinated Debt Securities, dated as of January 16, 2006, between Ormat Technologies, Inc. and Union Bank of California, incorporated by reference to Exhibit 4.3 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-3 (File No. 333-131064) to the Securities and Exchange Commission on January 26, 2006.


Exhibit No.			Document

	10	.23	Note Purchase Agreement, dated as of may 18, 2009 among Ortitlan Limitada and TCW Global Project Fund II, Ltd., incorporated by reference to Exhibit 10.23 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on May 21, 2009.
	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 5, 2009

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	.3	Form of Rights Agreement by and between Ormat Technologies, Inc. and American Stock Transfer & Trust Company, incorporated by reference to Exhibit 4.3 to Ormat Technologies, Inc. Registration Statement Amendment No. 2 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on October 22, 2004.
	4	.4	Indenture for Senior Debt Securities, dated as of January 16, 2006, between Ormat Technologies, Inc. and Union Bank of California, incorporated by reference to Exhibit 4.2 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-3 (File No. 333-131064) to the Securities and Exchange Commission on January 26, 2006.
	4	.5	Indenture for Subordinated Debt Securities, dated as of January 16, 2006, between Ormat Technologies, Inc. and Union Bank of California, incorporated by reference to Exhibit 4.3 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-3 (File No. 333-131064) to the Securities and Exchange Commission on January 26, 2006.
	10	.23	Note Purchase Agreement, dated as of may 18, 2009 among Ortitlan Limitada and TCW global Project Fund II, Ltd., incorporated by reference to Exhibit 10.23 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on May 21, 2009.
	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.