Ormat 10Q 2010 Q2 Quarterly report

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, 2010
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, Nevada89511-1136

(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 ofRegulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No 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” inRule 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 inRule 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 45,430,886 par value of $0.001 per share.

ORMAT TECHNOLOGIES, INC

FORM 10-Q

FOR THE QUARTER ENDED JUNE 30, 2010


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	56
ITEM 4.	CONTROLS AND PROCEDURES	56

PART II — OTHER INFORMATION
ITEM 1.	LEGAL PROCEEDINGS	57
ITEM 1A.	RISK FACTORS	58
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	58
ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	58
ITEM 5.	OTHER INFORMATION	58
ITEM 6.	EXHIBITS	58
SIGNATURES		60
EX-31.1
EX-31.2
EX-32.1
EX-32.2
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

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,
	2010		2009
	(In thousands)

ASSETS
Current assets:
Cash and cash equivalents	$	54,195	$	46,307
Restricted cash, cash equivalents and marketable securities (all related to VIEs)		33,214		40,955
Receivables:
Trade		47,057		53,423
Related entity		518		441
Other		9,471		7,884
Due from Parent		1,347		422
Inventories		15,175		15,486
Costs and estimated earnings in excess of billings on uncompleted contracts		12,633		14,640
Deferred income taxes		3,573		3,617
Prepaid expenses and other		12,118		12,080

Total current assets		189,301		195,255
Long-term marketable securities		1,296		652
Restricted cash, cash equivalents and marketable securities (all related to VIEs)		1,751		2,512
Unconsolidated investments ($28,066 related to VIEs at June 30, 2010)		29,876		35,188
Deposits and other		18,754		18,653
Deferred charges		30,270		22,532
Property, plant and equipment, net ($1,271,225 related to VIEs at June 30, 2010)		1,319,358		998,693
Construction-in-process ($37,670 related to VIEs at June 30, 2010)		290,307		518,595
Deferred financing and lease costs, net		19,433		20,940
Intangible assets, net		40,413		41,981

Total assets	$	1,940,759	$	1,855,001

LIABILITIES AND EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	90,338	$	73,993
Billings in excess of costs and estimated earnings on uncompleted contracts		11,546		3,351
Current portion of long-term debt:
Limited and non-recourse (all related to VIEs at June 30, 2010)		15,493		19,191
Full recourse		12,916		12,823
Senior secured notes (non-recourse) (all related to VIEs at June 30, 2010)		20,583		20,227
Due to Parent, including current portion of notes payable to Parent		—		10,018

Total current liabilities		150,876		139,603
Long-term debt, net of current portion:
Limited and non-recourse (all related to VIEs at June 30, 2010)		121,694		129,152
Full recourse		70,695		77,177
Revolving credit lines with banks (full recourse)		234,395		134,000
Senior secured notes (non-recourse) (all related to VIEs at June 30, 2010)		224,005		231,872
Liability associated with sale of tax benefits		71,765		73,246
Deferred lease income		72,193		72,867
Deferred income taxes		47,375		44,530
Liability for unrecognized tax benefits		5,365		4,931
Liabilities for severance pay		18,572		18,332
Asset retirement obligation		14,630		14,238
Other long-term liabilities		2,115		3,358

Total liabilities		1,033,680		943,306

Commitments and contingencies
Equity:
The Company’s stockholders’ equity:
Common stock, par value $0.001 per share; 200,000,000 shares authorized; 45,430,886 and 45,353,120 shares issued and outstanding, respectively		46		46
Additional paid-in capital		712,324		709,354
Retained earnings		189,627		196,950
Accumulated other comprehensive income		469		622

		902,466		906,972
Noncontrolling interest		4,613		4,723

Total equity		907,079		911,695

Total liabilities and equity	$	1,940,759	$	1,855,001

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

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND
COMPREHENSIVE INCOME (LOSS)
(Unaudited)


	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
	(In thousands, except per share data)						(In thousands, except per share data)

Revenues:
Electricity	$	68,807		$	59,826		$	134,912		$	121,886
Product		27,459			39,673			44,008			76,924

Total revenues		96,266			99,499			178,920			198,810

Cost of revenues:
Electricity		63,498			44,718			118,021			88,404
Product		14,115			27,242			26,552			51,485

Total cost of revenues		77,613			71,960			144,573			139,889

Gross margin		18,653			27,539			34,347			58,921
Operating expenses:
Research and development expenses		3,614			2,487			6,881			3,288
Selling and marketing expenses		2,686			3,215			5,888			7,516
General and administrative expenses		6,996			5,582			14,016			13,117
Write-off of unsuccessful exploration activities		3,050			—			3,050			—

Operating income		2,307			16,255			4,512			35,000
Other income (expense):
Interest income		95			276			292			428
Interest expense, net		(9,426	)		(4,415	)		(19,140	)		(7,705	)
Foreign currency translation and transaction gains (losses)		(1,033	)		1,044			(599	)		(1,349	)
Income attributable to sale of tax benefits		2,070			4,366			4,209			8,534
Other non-operating income (expense), net		79			550			(280	)		400

Income (loss) from continuing operations, before income taxes and equity in income of investees		(5,908	)		18,076			(11,006	)		35,308
Income tax benefit (provision)		3,365			(3,868	)		5,922			(7,297	)
Equity in income of investees, net		479			355			1,025			905

Income (loss) from continuing operations		(2,064	)		14,563			(4,059	)		28,916
Discontinued operations:
Income from discontinued operations, net of related tax of $0, $604, $6 and $670, respectively		—			1,411			14			1,564
Gain on sale of a subsidiary in New Zealand, net of related tax of $570, $0, $2,000 and $0, respectively		570			—			4,336			—

Net income (loss)		(1,494	)		15,974			291			30,480
Net loss attributable to noncontrolling interest		57			77			110			156

Net income (loss) attributable to the Company’s stockholders	$	(1,437	)	$	16,051		$	401		$	30,636

Comprehensive income:
Net income (loss)	$	(1,494	)	$	15,974		$	291		$	30,480
Other comprehensive income (loss), net of related taxes:
Currency translation adjustment		—			423			43			371
Amortization of unrealized gains in respect of derivative instruments designated for cash flow hedge		(58	)		(65	)		(116	)		(130	)
Change in unrealized gains or losses on marketable securitiesavailable-for-sale		(18	)		260			(80	)		260

Comprehensive income (loss)		(1,570	)		16,592			138			30,981
Comprehensive loss attributable to noncontrolling interest		57			77			110			156

Comprehensive income (loss) attributable to the Company’s stockholders	$	(1,513	)	$	16,669		$	248		$	31,137

Earnings (loss) per share attributable to the Company’s stockholders — basic and diluted:
Income (loss) from continuing operations	$	(0.05	)	$	0.32		$	(0.09	)	$	0.64
Income from discontinued operations		0.02			0.03			0.10			0.03

Net income (loss)	$	(0.03	)	$	0.35		$	0.01		$	0.67

Weighted average number of shares used in computation of earnings (loss) per share attributable to the Company’s stockholders:
Basic		45,431			45,369			45,431			45,361

Diluted		45,431			45,451			45,431			45,425

Dividend per share declared	$	0.05		$	0.06		$	0.17		$	0.13

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

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY
(Unaudited)


	The Company’s Stockholders’ Equity
										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, 2008		45,353	$	45	$	701,273	$	138,241		$	645		$	840,204		$	7,031		$	847,235
Stock-based compensation		—		—		2,728		—			—			2,728			—			2,728
Cumulative effect of adopting theother-than-temporary impairment standard 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)		—		—		—		—			(130	)		(130	)		—			(130	)
Change in unrealized gains or losses on marketable securitiesavailable-for-sale (net of related tax of $144)											260			260						260

Balance at June 30, 2009		45,408	$	46	$	704,854	$	164,185		$	(59	)	$	869,026		$	6,875		$	875,901

Balance at December 31, 2009		45,431	$	46	$	709,354	$	196,950		$	622		$	906,972		$	4,723		$	911,695
Stock-based compensation		—		—		2,970		—			—			2,970			—			2,970
Cash dividend declared, $0.17 per share		—		—		—		(7,724	)		—			(7,724	)		—			(7,724	)
Net income (loss)		—		—		—		401			—			401			(110	)		291
Other comprehensive income (loss), net of related taxes:
Currency translation adjustment		—		—		—		—			43			43			—			43
Amortization of unrealized gains in respect of derivative instruments designated for cash flow hedge (net of related tax of $73)		—		—		—		—			(116	)		(116	)		—			(116	)
Change in unrealized gains or losses on marketable securitiesavailable-for-sale (net of related tax of $43)		—		—		—		—			(80	)		(80	)		—			(80	)

Balance at June 30, 2010		45,431	$	46	$	712,324	$	189,627		$	469		$	902,466		$	4,613		$	907,079

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

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)


	Six Months Ended
	June 30,
	2010			2009
	(In thousands)

Cash flows from operating activities:
Net income	$	291		$	30,480
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		40,329			31,193
Accretion of asset retirement obligation		556			520
Stock-based compensation		2,970			2,728
Amortization of deferred lease income		(1,343	)		(1,343	)
Income attributable to sale of tax benefits, net of interest expense		(1,481	)		(4,711	)
Equity in income of investees		(1,025	)		(905	)
Loss on disposal of property, plant and equipment		571			—
Write-off of unsuccessful exploration activities		3,050			—
Return on investment in unconsolidated investments		3,734			—
Loss on severance pay fund asset		515			106
Gain on sale of a subsidiary		(6,350	)		—
Deferred income tax provision (benefit)		(5,365	)		6,620
Liability for unrecognized tax benefits		434			652
Deferred lease revenues		669			725
Other		—			(70	)
Changes in operating assets and liabilities:
Receivables		4,160			(6,683	)
Costs and estimated earnings in excess of billings on uncompleted contracts		2,007			(7,640	)
Inventories		311			(885	)
Prepaid expenses and other		(38	)		7,771
Deposits and other		(209	)		(21	)
Accounts payable and accrued expenses		9,376			(962	)
Due from/to related entities, net		(77	)		(139	)
Billings in excess of costs and estimated earnings on uncompleted contracts		8,195			(1,086	)
Liabilities for severance pay		240			(186	)
Other long-term liabilities		(1,243	)		—
Due from/to Parent		(1,343	)		(832	)

Net cash provided by operating activities		58,934			55,332

Cash flows from investing activities:
Return of investment in unconsolidated investments		3,516			—
Marketable securities, net		—			200
Net change in restricted cash, cash equivalents and marketable securities		7,735			(10,633	)
Cash received from sale of a subsidiary		19,594			—
Capital expenditures		(139,171	)		(147,613	)
Investment in unconsolidated company		(281	)		—
Increase in severance pay fund asset, net of payments made to retired employees		(407	)		(418	)
Repayment from unconsolidated investment		—			62

Net cash used in investing activities		(109,014	)		(158,402	)

Cash flows from financing activities:
Proceeds from long-term loans		—			132,000
Proceeds from exercise of options by employees		—			854
Proceeds from revolving credit lines with banks		132,095			577,000
Repayment of revolving credit lines with banks		(31,700	)		(557,000	)
Repayments of long-term debt
Parent		(9,600	)		(16,600	)
Other		(25,056	)		(10,949	)
Deferred debt issuance costs		(47	)		(4,889	)
Cash dividends paid		(7,724	)		(5,897	)

Net cash provided by financing activities		57,968			114,519

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

Net change in cash and cash equivalents		7,888			11,635
Cash and cash equivalents at beginning of period		46,307			34,393

Cash and cash equivalents at end of period	$	54,195		$	46,028

Supplemental non-cash investing and financing activities:
Increase (decrease) in accounts payable related to purchases of property, plant and equipment	$	7,117		$	(23,713	)

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

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)


NOTE 1 —	GENERAL AND BASIS OF PRESENTATION

These unaudited condensed consolidated 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, 2010, the consolidated results of operations and comprehensive income for the three and six-month periods ended June 30, 2010 and 2009, and the consolidated cash flows for the six-month periods ended June 30, 2010 and 2009.

The financial data and other information disclosed in the notes to the condensed consolidated financial statements related to these periods are unaudited. The results for the three and six-month periods ended June 30, 2010 are not necessarily indicative of the results to be expected for the year ending December 31, 2010.

These condensed consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in the Company’s annual report onForm 10-K for the year ended December 31, 2009. The condensed consolidated balance sheet data as of December 31, 2009 was derived from the audited consolidated financial statements for the year ended December 31, 2009, 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 8).

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, 2010 and December 31, 2009, the Company had deposits totaling $42,767,000 and $24,561,000, respectively, in seven U.S. financial institutions that were federally insured up to $250,000 per account (after December 31, 2013, the deposits will be insured up to $100,000 per account). At June 30, 2010 and December 31, 2009, the Company’s deposits in foreign countries amounted to approximately $22,507,000 and $35,095,000, respectively.

At June 30, 2010 and December 31, 2009, accounts receivable related to operations in foreign countries amounted to approximately $18,453,000 and $30,761,000, respectively. At June 30, 2010 and December 31, 2009, accounts receivable from the Company’s major customers that have generated 10% or more of its revenues amounted to approximately 46% and 61% of the Company’s accounts receivable, respectively.

Southern California Edison Company (“SCE”) accounted for 25.5% and 21.3% of the Company’s total revenues for the three months ended June 30, 2010 and 2009, respectively, and 25.5% and 19.6% of the Company’s total revenues for the six months ended June 30, 2010 and 2009, respectively. SCE is also the power purchaser and revenue source for the Company’s Mammoth complex, which is accounted for under the equity method.

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

Sierra Pacific Power Company and Nevada Power Company (subsidiaries of NV Energy, Inc.) accounted for 13.7% and 12.2% of the Company’s total revenues for the three months ended June 30, 2010 and 2009, respectively, and 16.2% and 13.0% of the Company’s total revenues for the six months ended June 30, 2010 and 2009, respectively.

Hawaii Electric Light Company accounted for 8.0% and 4.9% of the Company’s total revenues for the three months ended June 30, 2010 and 2009, respectively, and 7.6% of the Company’s total revenues in each of the six months ended June 30, 2010 and 2009.

Kenya Power and Lighting Co. Ltd. accounted for 9.2% and 8.9% of the Company’s total revenues for the three months ended June 30, 2010 and 2009, respectively, and 9.9% and 8.6% of the Company’s total revenues for the six months ended June 30, 2010 and 2009, 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, 2010

Accounting for Transfers of Financial Assets

In June 2009, the Financial Accounting Standards Board (“FASB”) issued an amendment to the accounting and disclosure requirements for transfers of financial assets. This amendment requires greater transparency and additional disclosures for transfers of financial assets and the entity’s continuing involvement with them and changes the requirements for derecognizing financial assets. In addition, this amendment eliminates the concept of a qualifying special-purpose entity (“QSPE”). The adoption by the Company of this amendment on January 1, 2010 did not have any effect on the Company’s financial position, results of operations, or liquidity.

Consolidation Guidance for Variable Interest Entities

In June 2009, the FASB issued an amendment to the accounting and disclosure requirements for the consolidation of variable interest entities (“VIEs”). The elimination of the concept of a QSPE removes the exception from applying the consolidation guidance within this amendment. This amendment requires a company to perform a qualitative analysis when determining whether or not it must consolidate a VIE. The amendment also requires a company to continuously reassess whether it must consolidate a VIE. Additionally, the amendment requires enhanced disclosures about a company’s involvement with VIEs and any significant change in risk exposure due to that involvement, as well as how its involvement with VIEs impacts the company’s financial statements. Finally, a company is required to disclose significant judgments and assumptions used to determine whether or not to consolidate a VIE. The Company adopted this amendment on January 1, 2010. The impact of the adoption of this amendment on the Company’s condensed consolidated financial statements is disclosed in Note 5.

Updated Disclosure for Fair Value Measurements

In January 2010, the FASB updated the fair value measurements disclosures. This update will require an entity to disclose separately the amounts of significant transfers in and out of Levels 1 and 2 fair value measurements and to describe the reasons for the transfers. In addition, information about purchases, sales, issuances and settlements are required to be presented separately (i.e., present the activity on a gross basis rather than net) in the reconciliation for fair value measurements using significant unobservable inputs (Level 3

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

inputs). This update clarifies existing disclosure requirements for the level of disaggregation used for classes of assets and liabilities measured at fair value, and requires disclosures about the valuation techniques and inputs used to measure fair value for both recurring and nonrecurring fair value measurements using Level 2 and Level 3 inputs. This update became effective as of the first interim or annual reporting period beginning after December 15, 2009 (January 1, 2010 for the Company), except for the gross presentation of the Level 3 roll forward information, which is required for annual reporting periods beginning after December 15, 2010 (January 1, 2011 for the Company) and for interim reporting periods within those years. The adoption by the Company of the new guidance on January 1, 2010 did not have a material impact on the Company’s consolidated financial statements (see Note 6).

New accounting pronouncements effective in future periods

Accounting for Revenue Recognition

In October 2009, the FASB issued amendments to the accounting and disclosures for revenue recognition. These amendments, effective for fiscal years beginning on or after June 15, 2010 (January 1, 2011 for the Company) with early adoption permitted, modify the criteria for recognizing revenue in multiple element arrangements and require companies to develop a best estimate of the selling price to separate deliverables and allocate arrangement consideration using the relative selling price method. Additionally, the amendments eliminate the residual method for allocating arrangement considerations. The Company is currently evaluating the potential impact, if any, of the adoption of these amendments on its consolidated financial statements.

In April 2010, the FASB issued guidance for revenue recognition — milestone method, which provides guidance on the criteria that, should be met for determining whether the milestone method of revenue recognition is appropriate. A vendor can recognize consideration that is contingent upon achievement of a milestone in its entirety as revenue in the period in which the milestone is achieved only if the milestone meets all criteria to be considered substantive. A milestone should be considered substantive in its entirety. An individual milestone may not be bifurcated. The amendments in this update are effective on a prospective basis for milestones achieved in fiscal years, and interim periods within those years, beginning on or after June 15, 2010 (January 1, 2011 for the Company). The Company is currently evaluating the potential impact, if any, of the adoption of this guidance on its consolidated financial statements.

Accounting for Stock Compensation

In April 2010, the FASB issued an accounting standards update, which addresses the classification of an employee share-based payment award with an exercise price denominated in the currency of a market in which the underlying equity security trades. This update clarifies that an employee share-based payment award with an exercise price denominated in the currency of a market in which a substantial portion of the entity’s equity securities trades should not be considered to contain a condition that is not a market, performance, or service condition. Therefore, an entity should not classify such an award as a liability if it otherwise qualifies as equity. The amendments in this update are effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2010 (January 1, 2011 for the Company). The Company is currently evaluating the potential impact, if any, of the adoption of this update on its consolidated financial statements.

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)


NOTE 3 —	INVENTORIES

Inventories consist of the following:


	June 30,		December 31,
	2010		2009
	(Dollars in thousands)

Raw materials and purchased parts for assembly	$	10,421	$	7,322
Self-manufactured assembly parts and finished products		4,754		8,164

Total	$	15,175	$	15,486


NOTE 4 —	UNCONSOLIDATED INVESTMENTS

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


	June 30,		December 31,
	2010		2009
	(Dollars in thousands)

Mammoth	$	28,066	$	33,659
Sarulla		1,810		1,529

Total	$	29,876	$	35,188

The Mammoth Complex

The Company has a 50% interest in Mammoth Pacific, LP, which owns the Mammoth complex, located near the city of Mammoth, California. The purchase price was less than the underlying net equity of Mammoth Pacific, LP 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 Pacific, LP is accounted for under the equity method of accounting as the Company has the ability to exercise significant influence, but not control, over Mammoth Pacific, LP.

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


	June 30,		December 31,
	2010		2009
	(Dollars in thousands)

Condensed balance sheets:
Current assets	$	10,711	$	19,257
Non-current assets		61,636		64,728
Current liabilities		676		659
Non-current liabilities		3,321		3,196
Partners’ capital		68,350		80,130

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)


	Six Months Ended
	June 30,
	2010			2009
	(Dollars in thousands)

Condensed statements of operations:
Revenues	$	9,806		$	9,455
Gross margin		2,842			2,568
Net income		2,720			2,458
Company’s equity in income of Mammoth:
50% of Mammoth net income	$	1,360		$	1,229
Plus amortization of basis difference		296			296

		1,656			1,525
Less income taxes		(629	)		(580	)

Total	$	1,027		$	945

On August 2, 2010, the Company acquired the remaining 50% interest in Mammoth Pacific, LP, (see Note 16).

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 110 MW to 120 MW combined cycle geothermal plants in which the steam first produces power in a backpressure steam turbine and is subsequently condensed in a vaporizer of a binary plant, which produces additional power. The consortium is currently negotiating certain amendments to the energy sales contract, including an adjustment of commercial terms, and intends to proceed with the project after those amendments have become effective. On April 26, 2010, the parties agreed to increase the price of the power sold under the energy sales contract.

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 —	CONSOLIDATION GUIDANCE FOR VARIABLE INTEREST ENTITIES

Effective January 1, 2010, the Company adopted new accounting and disclosure guidance for variable interest entities (“VIEs”). Among other accounting and disclosure requirements, the new guidance requires the primary beneficiary of a VIE to be identified as the party that both (i) has the power to direct the activities of a VIE that most significantly impact its economic performance; and (ii) has an obligation to absorb losses or a right to receive benefits that could potentially be significant to the VIE. The adoption of this new accounting guidance did not result in the Company consolidating any additional VIEs or deconsolidating any VIEs.

The Company evaluated all transactions and relationships with VIEs to determine whether the Company is the primary beneficiary of the entities in accordance with the guidance. The Company’s overall methodology for evaluating transactions and relationships under the VIE requirements includes the following two steps: (i) determining whether the entity meets the criteria to qualify as a VIE; and (ii) determining whether the Company is the primary beneficiary of the VIE.

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

In performing the first step, the significant factors and judgments that the Company considers in making the determination as to whether an entity is a VIE include:


	•	The design of the entity, including the nature of its risks and the purpose for which the entity was created, to determine the variability that the entity was designed to create and distribute to its interest holders;

	•	The nature of the Company’s involvement with the entity;

	•	Whether control of the entity may be achieved through arrangements that do not involve voting equity;

	•	Whether there is sufficient equity investment at risk to finance the activities of the entity; and

	•	Whether parties other than the equity holders have the obligation to absorb expected losses or the right to receive residual returns.

If the Company identifies a VIE based on the above considerations, it then performs the second step and evaluates whether it is the primary beneficiary of the VIE by considering the following significant factors and judgments:


	•	Whether the Company has the power to direct the activities of the VIE that most significantly impact the entity’s economic performance; and

	•	Whether the Company has the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE.

The Company’s VIEs include certain of its wholly owned subsidiaries that own one or more power plants with long-term PPAs. In most cases, the PPAs require the utility to purchase substantially all of the plant’s electrical output over a significant portion of its estimated useful life. Most of the VIEs have associated project financing debt that is non-recourse to the general creditors of the Company, is collateralized by substantially all of the assets of the VIE and those of its wholly owned subsidiaries (also VIEs) and is fully and unconditionally guaranteed by such subsidiaries. The Company has concluded that such entities are VIEs primarily because the entities do not have sufficient equity at riskand/or subordinated financial support is provided through the long-term PPAs. The Company has evaluated each of its VIEs to determine the primary beneficiary by considering the party that has the power to direct the most significant activities of the entity. Such activities include, among others, construction of the power plant, operations and maintenance, dispatch of electricity, financing and strategy. The Company controls such activities at each of its VIEs and, therefore, is considered the primary beneficiary. The Company will perform an ongoing reassessment of the VIEs to determine the primary beneficiary and may be required to deconsolidate certain of its VIEs in the future. The Company has aggregated its consolidated VIEs into the following categories: (i) consolidated subsidiaries with project debt; and (ii) consolidated subsidiaries with PPAs.

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

The tables below detail the assets and liabilities (excluding intercompany balances which are eliminated in consolidation) for the Company’s VIEs, combined by VIE classifications, that were included in the condensed consolidated balance sheets as of June 30, 2010 and December 31, 2009:


	June 30, 2010
	Project Debt		PPAs

Assets:
Restricted cash, cash equivalents and marketable securities	$	34,965	$	—
Other current assets		53,892		9,592
Unconsolidated investments		28,066		—
Property, plant and equipment, net		834,330		436,895
Construction-in-process		36,520		1,150
Other long-term assets		55,402		—

Total assets	$	1,043,175	$	447,637

Liability:
Accounts payable and accrued expenses	$	10,634	$	3,556
Long-term debt		381,775		—
Other long-term liabilities		85,524		3,326

Total liabilities	$	477,933	$	6,882


	December 31, 2009
	Project Debt		PPAs

Assets:
Restricted cash, cash equivalents and marketable securities	$	43,467	$	—
Other current assets		58,037		1,459
Unconsolidated investments		33,659		—
Property, plant and equipment, net		866,024		89,822
Construction-in-process		12,151		239,799
Other long-term assets		58,282		—

Total assets	$	1,071,620	$	331,080

Liability:
Accounts payable and accrued expenses	$	11,328	$	1,749
Long-term debt		400,442		—
Other long-term liabilities		87,181		3,198

Total liabilities	$	498,951	$	4,947


NOTE 6 —	FAIR VALUE OF FINANCIAL INSTRUMENTS

The fair value measurement guidance clarifies that fair value is an exit price, representing the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. As such, fair value is a market-based measurement that should be determined based on assumptions that market participants would use in pricing an asset or liability. It establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of the fair value hierarchy under the fair value measurement guidance are described below:

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

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

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

The following table sets forth certain fair value information at June 30, 2010 and December 31, 2009 for financial assets and liabilities measured at fair value by level within the fair value hierarchy, as well as cost or amortized cost. As required by the fair value measurement guidance, assets and liabilities are classified in their entirety based on the lowest level of inputs that is significant to the fair value measurement.


	Cost or
	Amortized
	Cost at
	June 30,		Fair Value at June 30, 2010
	2010		Total			Level 1		Level 2			Level 3
	(Dollars in thousands)

Assets
Current assets:
Cash equivalents (including restricted cash accounts)	$	7,023	$	7,023		$	7,023	$	—		$	—
Non-current assets:
including restricted cash accounts) ($4.5 million par value), see below		4,110		3,047			—		—			3,047
Liabilities:
Current liabilities:
Derivatives*		—		(411	)		—		(411	)		—

	$	11,133	$	9,659		$	7,023	$	(411	)	$	3,047


	Cost or
	Amortized
	Cost at
	December 31,		Fair Value at December 31, 2009
	2009		Total			Level 1		Level 2			Level 3
			(Dollars in thousands)

Assets:
Current assets:
Cash equivalents (including restricted cash accounts)	$	20,227	$	20,227		$	20,227	$	—		$	—
Derivatives*		—		91			—		91			—
Non-current assets:
Illiquid auction rate securities including restricted cash accounts) ($4.5 million par value), see below		4,099		3,164			—		—			3,164
Liabilities:
Current liabilities:
Derivatives*		—		(32	)		—		(32	)		—

	$	24,326	$	23,450		$	20,227	$	59		$	3,164

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)


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

The Company’s financial assets measured at fair value (including restricted cash accounts) at June 30, 2010 and December 31, 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, 2010 and December 31, 2009, all of the Company’s auction rate securities are associated with failed auctions. Such securities have par values totaling $4.5 million at June 30, 2010 and December 31, 2009, 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, 2010 and 2009, respectively:


	Six Months Ended June 30,
	2010			2009
	(Dollars in thousands)

Balance at beginning of period	$	3,164		$	4,945
Sale of auction rate securities		—			(40	)
Total unrealized gains (losses):
Included in net income		—			(280	)
Included in other comprehensive income		(117	)		411

Balance at end of period	$	3,047		$	5,036

Effective April 1, 2009, the Company adopted the recognition and presentation of theother-than-temporary impairments standard, which requires an entity to separate another-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 theother-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 theother-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 theother-than-temporary

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

impairment is recognized in earnings and reflected as a reduction in the cost basis of the security. Upon adoption of this standard, the Company reclassified $1.2 million (net of taxes of $0.7 million) to other comprehensive income with an offset to retained earnings related to theother-than-temporary impairment charges previously recognized in earnings. This cumulative effect adjustment relates to auction rate securities for 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.

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 changes inother-than-temporary impairment losses in the three and six-month periods ended June 30, 2010 were 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, 2010 and December 31, 2009.

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 2010.

There were no transfers of assets or liabilities between Level 1 and Level 2 during the three andsix-month periods ended June 30, 2010.

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,
	2010		2009		2010		2009
	(Dollars in millions)				(Dollars in millions)

Orzunil Senior Loans	$	3.3	$	5.3	$	3.2	$	5.2
Olkaria III Loan		94.2		96.6		93.9		99.5
Amatitlan Loan		40.6		41.1		40.1		41.1
Senior Secured Notes:
Ormat Funding Corp.(“OFC”)		127.6		132.0		141.4		146.3
OrCal Geothermal Inc.(“OrCal”)		101.1		103.7		103.2		105.8
Loan from institutional investors		19.1		20.0		18.6		20.0
Parent Loan		—		9.7		—		9.6

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 7 —	STOCK-BASED COMPENSATION

On April 16, 2010, the Company granted to employees 592,900 stock appreciation rights (“SAR”) under the Company’s 2004 Incentive Plan. The exercise price of each SAR is $29.95, which represented the fair market value of the Company’s common stock on the date of grant. Such SARs will expire seven years from

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

the date of grant and will cliff vest and are exercisable from the grant date as follows: 25% after 24 months, 25% after 36 months, and the remaining 50% after 48 months. Upon exercise, SARs entitle the recipient to receive shares of common stock equal to the increase in value of the award between the grant date and the exercise date. The fair value of each SAR on the date of grant was $12.64.

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	2.58	%
Expected term (in years)	5.125
Dividend yield	0.72	%
Expected volatility	47.55	%
Forfeiture rate	13.0	%

On May 5, 2010, the Company granted to a non-employee director options to purchase 7,500 shares of common stock under the 2004 Incentive Plan. The exercise price of each option is $29.21, which represented the closing price of the Company’s common stock on May 6, 2010 (since the Company released its quarterly results for the first quarter of 2010 on May 5, 2010). Such options will expire seven years from the date of grant and will vest on the first anniversary of the date of grant. The fair value of each option on the date of grant was $11.19.

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


Risk-free interest rates	1.7	%
Expected term (in years)	4.0
Dividend yield	0.67	%
Expected volatility	49.71	%
Forfeiture rate	0	%


NOTE 8 —	DISCONTINUED OPERATIONS

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

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

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

The net assets of GDL on January 1, 2010 were as follows:


	(Dollars in
	thousands)

Cash and cash equivalents	$	871
Accounts receivables		434
Prepaid expenses and other		184
Property, plant and equipment		16,293
Accounts payables and accrued liabilities		(164	)
Other comprehensive income — translation adjustments		(156	)

Net assets	$	17,462

The operations and gain on sale of GDL have been included in discontinued operations on the condensed consolidated statements of operations and comprehensive income for all periods prior to the sale of GDL in January 2010. Electricity revenues related to GDL were $0 and $736,000 during the three months ended June 30, 2010 and 2009, respectively, and $64,000 and $1,314,000 during the six months ended June 30, 2010 and 2009, respectively. Basic and diluted earnings per share related to the $4.3 million after-tax gain on sale of GDL was $0.02 and $0.10 during the three and six-month periods ended June 30, 2010, respectively. Basic and diluted earnings per share related to income from discontinued operations was $0.03 during the three and six-month periods ended June 30, 2009 (none in 2010).


NOTE 9 —	ELECTRICITY REVENUES AND COST OF REVENUES

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2010		2009		2010		2009
	(Dollars in thousands)				(Dollars in thousands)

Revenues:
Energy and capacity	$	25,628	$	23,268	$	50,346	$	47,040
Lease portion of energy and capacity		42,507		35,886		83,223		73,503
Lease income		672		672		1,343		1,343

	$	68,807	$	59,826	$	134,912	$	121,886

Cost of revenues:
Energy and capacity	$	36,702	$	24,257	$	63,957	$	47,155
Lease portion of energy and capacity		25,486		19,151		51,443		38,628
Lease income		1,310		1,310		2,621		2,621

	$	63,498	$	44,718	$	118,021	$	88,404

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)


NOTE 10 —	INTEREST EXPENSE, NET

The components of interest expense, net are as follows:


	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
	(Dollars in thousands)						(Dollars in thousands)

Parent	$	130		$	310		$	310		$	753
Interest related to sale of tax benefits		1,353			2,151			2,728			4,081
Other		10,165			8,331			19,938			15,063
Less — amount capitalized		(2,222	)		(6,377	)		(3,836	)		(12,192	)

	$	9,426		$	4,415		$	19,140		$	7,705


NOTE 11 —	EARNINGS PER SHARE

Basic earnings per share attributable to the Company’s stockholders (“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.

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2010		2009		2010		2009
	(In thousands)				(In thousands)

Weighted average number of shares used in computation of basic earnings per share		45,431		45,369		45,431		45,361
Add:
Additional shares from the assumed exercise of employee stock options		—		82		—		64

Weighted average number of shares used in computation of diluted earnings per share		45,431		45,451		45,431		45,425

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

The number of stock options that could potentially dilute future earnings per share and were not included in the computation of diluted earnings per share because to do so would have been antidilutive was 2,791,204 and 1,747,252, respectively, for the three months ended June 30, 2010 and 2009, and 2,461,984 and 1,893,305, respectively, for the six months ended June 30, 2010 and 2009.


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

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES 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, 2010:
Net revenues from external customers	$	68,807		$	27,459	$	96,266
Intersegment revenues		—			21,102		21,102
Operating income (loss)		(5,109	)		7,416		2,307
Segment assets at period end*		1,867,982			72,777		1,940,759
Three Months Ended June 30, 2009:
Net revenues from external customers	$	59,826		$	39,673	$	99,499
Intersegment revenues		—			4,386		4,386
Operating income		9,508			6,747		16,255
Segment assets at period end*		1,697,172			75,585		1,772,757
Six months Ended June 30, 2010:
Net revenues from external customers	$	134,912		$	44,008	$	178,920
Intersegment revenues		—			28,296		28,296
Operating income (loss)		(2,014	)		6,526		4,512
Segment assets at period end*		1,867,982			72,777		1,940,759
Six months Ended June 30, 2009:
Net revenues from external customers	$	121,886		$	76,924	$	198,810
Intersegment revenues		—			17,221		17,221
Operating income		20,344			14,656		35,000
Segment assets at period end*		1,697,172			75,585		1,772,757


*		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						Three Months Ended
	June 30,						June 30,						March 31,
	2010			2009			2010			2009			2010			2009
	(Dollars in thousands)						(Dollars in thousands)						(Dollars in thousands)

Operating income	$	2,307		$	16,255		$	4,512		$	35,000		$	2,205		$	18,745
Interest income		95			276			292			428			197			152
Interest expense, net		(9,426	)		(4,415	)		(19,140	)		(7,705	)		(9,714	)		(3,290	)
Foreign currency translation and transaction gains (losses)		(1,033	)		1,044			(599	)		(1,349	)		434			(2,393	)
Income attributable to sale of tax benefits		2,070			4,366			4,209			8,534			2,139			4,168
Other non-operating income (expense), net		79			550			(280	)		400			(359	)		(150	)

Total consolidated income (loss) from continuing operations, before income taxes and equity in income of investees	$	(5,908	)	$	18,076		$	(11,006	)	$	35,308		$	(5,098	)	$	17,232

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)


NOTE 13 —	CONTINGENCIES

Securities Class Actions

Following the Company’s public announcement that it would restate certain of its financial results due to a change in the Company’s accounting treatment for certain exploration and development costs, three securities class action lawsuits were filed in the United States District Court for the District of Nevada on March 9, 2010, March 18, 2010 and April 7, 2010. These complaints assert claims against the Company and certain officers and directors for alleged violation of Sections 10(b) and 20(a) of the Securities Exchange Act of 1934 (the “Exchange Act”). One complaint also asserts claims for alleged violations of Sections 11, 12(a)(2) and 15 of the Securities Act of 1933 (the “Securities Act”). All three complaints allege claims on behalf of a putative class of purchasers of Company stock between May 6, 2008 or May 7, 2008 and February 23, 2010 or February 24, 2010.

These three lawsuits were consolidated by the Court in an order issued on June 3, 2010 and the Court appointed three of the Company’s stockholders to serve as lead plaintiffs. Lead plaintiffs filed a consolidated amended class action complaint (“CAC”) on July 9, 2010 that asserts claims under Sections 10(b) and 20(a) of the Exchange Act on behalf of a putative class of purchasers of Company stock between May 7, 2008 and February 24, 2010. The CAC alleges that certain of the Company’s public statements were false and misleading for failing to account properly for the Company’s exploration and development costs based on the Company’s announcement on February 24, 2010 that it was going to restate its financial results to change its method of accounting for exploration and development costs in certain respects. The CAC also alleges that certain of the Company’s statements concerning the North Brawley project were false and misleading. The CAC seeks compensatory damages, expenses, and such further relief as the Court may deem proper. Defendants intend to file a motion to dismiss the CAC on August 13, 2010.

The Company does not believe that these lawsuits have merit and intends to defend itself vigorously.

Stockholder Derivative Cases

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

The two stockholder derivative cases filed in the Second Judicial District Court of the State of Nevada in and for the County of Washoe were consolidated by the Court in an order dated May 27, 2010 and the plaintiffs are scheduled to file a consolidated derivative complaint on August 9, 2010. The two federal derivative cases filed in the United States District Court for the District of Nevada have not been consolidated yet but the parties filed a stipulation to consolidate them on July 9, 2010.

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

Other

From time to time, the Company is named as a party in various lawsuits, claims and other legal and regulatory proceedings that arise in the ordinary course of its business. These actions typically seek, among

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

other things, compensation for alleged personal injury, breach of contract, property damage, punitive damages, civil penalties or other losses, or injunctive or declaratory relief. With respect to such lawsuits, claims and proceedings, the Company accrues reserves in accordance with accounting principles generally accepted in the U.S. It is the opinion of the Company’s management that the outcome of these proceedings, individually and collectively, will not materially affect its business, financial condition, financial results or cash flow.


NOTE 14 —	CASH DIVIDENDS

On February 23, 2010, the Company’s Board of Directors declared, approved and authorized payment of a quarterly dividend of $5.5 million ($0.12 per share) to all holders of the Company’s issued and outstanding shares of common stock on March 16, 2010. Such dividend was paid on March 25, 2010.

On May 5, 2010, the Company’s Board of Directors declared, approved and authorized payment of a quarterly dividend of $2.3 million ($0.05 per share) to all holders of the Company’s issued and outstanding shares of common stock on May 18, 2010. Such dividend was paid on May 25, 2010.


NOTE 15 —	INCOME TAXES

The Company’s effective tax rate for the three months ended June 30, 2010 and 2009 was a tax benefit of 57.0% and tax expense of 21.4%, respectively. The effective tax rate differs from the federal statutory rate of 35% for the three months ended June 30, 2010 primarily due to: (i) the benefit of production tax credits for qualified power plants placed in service since 2005; (ii) lower tax rates in Israel; and (iii) a tax credit and tax exemption related to the Company’s subsidiaries in Guatemala. The effective tax rate differs from the federal statutory rate of 35% for the six months ended June 30, 2010 primarily due to: (i) the benefit of production tax credits for qualified power plants placed in service since 2005; (ii) lower tax rates in Israel; (iii) a tax credit and tax exemption related to the Company’s subsidiaries in Guatemala; and (iv) a valuation allowance related to capital loss carryovers that the Company will not, more likely than not, utilize.

The anticipated annual production tax credits associated with the Class B membership interest in OPC LLC, an entity the Company is consolidating, has a significant impact on the Company’s expected overall annual tax benefit in 2010. The Company is currently negotiating to sell such interest to a third party. Upon the sale of the Class B membership interest, the Company will no longer be eligible to receive production tax credits associated with the Class B membership interest. Due to uncertainties in the timing of selling its Class B membership interest and the significance of the production tax credits to the Company’s overall tax benefit in 2010, the Company is recognizing production tax credits as they are earned rather than including forecasted production tax credits in the annual effective tax rate estimate from continuing operations.

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


	Six Months		Year Ended
	Ended June 30,		December 31,
	2010		2009
	(Dollars in thousands)

Balance at beginning of period	$	4,931	$	3,425
Additions based on tax positions taken in prior years		434		964
Additions based on tax positions taken in the current year		—		1,282
Decrease for settlements with taxing authorities		—		(740	)

Balance at end of period	$	5,365	$	4,931

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)


NOTE 16 —	SUBSEQUENT EVENTS

Acquisition of 50% of Mammoth Pacific, LP

On August 2, 2010, the Company acquired the remaining 50% interest in Mammoth Pacific, LP that owns the Mammoth complex for a purchase price of $75.2 million. Following the acquisition, the Company became the sole owner of the Mammoth complex, as well as the rights to over 10,000 acres of undeveloped federal lands.

Following the acquisition, Mammoth Pacific, LP, previously accounted for under the equity method (See Note 4), will be consolidated in the Company’s consolidated financial statements. As a result of the acquisition, the Company will record in the third quarter of 2010, a gain equal to the difference between the book value of the investment in Mammoth Pacific, LP and the fair value of such investment at the acquisition date. The Company has not yet determined the fair value of its investment at the acquisition date. However, based on preliminary data, it estimates the pre-tax gain will equal up to approximately $40 million. The actual amount of the gain will not be known until the Company completes its determination of the fair value of the assets and liabilities of Mammoth Pacific, LP.

Issuance of Senior Unsecured Bonds

On August 3, 2010, the Company entered into a trust instrument governing the issuance of, and accepted subscriptions for, approximately $142 million in aggregate principal amount of senior unsecured bonds (the “Bonds”). The Company issued the Bonds outside the United States to investors who are not “U.S. persons” in an unregistered offering pursuant to, and subject to the requirements of, Regulation S under the Securities Act.

Subject to early redemption, principal of the Bonds is repayable in a single bullet payment upon the final maturity of the Bonds on August 1, 2017. The Bonds bear interest at a fixed rate of 7% per annum, payable semi-annually. The Company intends to use the proceeds of the Bonds for general corporate purposes, which may include the repayment of existing indebtedness and the acquisition, directly or indirectly, of additional energy assets, including by way of construction, enhancement and expansion of its existing projects.

Cash Dividend

On August 4, 2010, the Company’s Board of Directors declared, approved and authorized payment of a quarterly dividend of $2.3 million ($0.05 per share) to all holders of the Company’s issued and outstanding shares of common stock on August 17, 2010, payable on August 26, 2010.


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

This quarterly report onForm 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 onForm 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 onForm 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);

	•	financial market conditions and the results of financing efforts;

	•	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;

	•	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 (PPAs) for our power plants;

	•	contract counterparty risk;

	•	weather and other natural phenomena;

	•	the impact of recent and future federal and state regulatory proceedings and changes, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry 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 onForm 10-K for the year ended December 31, 2009;

	•	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 onForm 10-K for the year ended December 31, 2009 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, sell, own and operate clean, environmentally friendly geothermal and recovered energy-based power plants, in most cases using equipment that we design and manufacture.

Our geothermal power plants include both power plants that we have built and power plants that we have acquired, while all of our recovered energy-based plants have been constructed by us. We conduct our business activities in two business segments, which we refer to as our Electricity Segment and Product Segment. In our Electricity Segment, we develop, build, own and operate geothermal and recovered energy-based power plants in the United States and geothermal power plants in other countries around the world, and sell the electricity they generate. We have recently decided to expand our activities in the Electricity Segment to include the ownership and operation of power plants that produce electricity generated by solar-photovoltaic (PV) systems that we do not manufacture. In our Product Segment, we design, manufacture and sell equipment for geothermal and recovered energy-based electricity generation, remote power units and other power generating units and provide services relating to the engineering, procurement, construction, operation and maintenance of geothermal and recovered energy power plants. Both our Electricity Segment and Product Segment operations are conducted in the United States and throughout the world. Our current generating portfolio includes geothermal power plants in the United States, Guatemala, Kenya, and Nicaragua, as well as recovered

energy generation (REG) power plants in the United States. During the six months ended June 30, 2010 and 2009, our consolidated power plants generated 1,797,616 MWh and 1,671,330 MWh, respectively.

For the six months ended June 30, 2010, our Electricity Segment revenues represented approximately 75.4% of our total revenues, while our Product Segment revenues represented approximately 24.6% of our total revenues during such period. For the six months ended June 30, 2009, our Electricity Segment revenues represented approximately 61.3% of our total revenues, while our Product Segment revenues represented approximately 38.7% of our total revenues, during such period.

For the six months ended June 30, 2010, our total revenues decreased by 10.0% (from $198.8 million to $178.9 million) over the same period last year. Revenues from the Electricity Segment increased by 10.7%, while revenues from the Product Segment decreased by 42.8%. As discussed below and in our previous quarterly report for the three months ended March 31, 2010, this decrease is attributable to the decline in our Product Segment order backlog.

For the six months ended June 30, 2010, total Electricity Segment revenues from the sale of electricity by our consolidated power plants were $134.9 million, compared to $121.9 million for the six months ended June 30, 2009. In addition, revenues from our 50% ownership of the Mammoth complex in the six months ended June 30, 2010 and 2009 were $4.9 million and $4.7 million, respectively. 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 complex 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, 2010 and 2009.

For the six months ended June 30, 2010, revenues attributable to our Product Segment were $44.0 million, compared to $76.9 million for the six months ended June 30, 2009, a decrease of 42.8%. The decrease is due to a decline in our Product Segment order backlog.

Revenues from our Electricity Segment are relatively predictable, as they are derived from sales of electricity generated by our power plants pursuant to long-term PPAs. The price for electricity under all but one of our PPAs is effectively a fixed price at least through May 2012. The exception is the PPA of the Puna power plant. It has a monthly variable energy rate based on the local utility’s avoided cost, which is the incremental cost that the power purchaser avoids by not having to generate such electrical energy itself or purchase it from others. In the six months ended June 30, 2010, the variable energy rate in the Puna power plant 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, 2010, 87.2% of our electricity revenues were derived from contracts with fixed energy rates, and therefore most of our electricity revenues were not affected by the fluctuations in energy commodity prices. However, electricity revenues are subject to seasonal variations and can be affected by higher-than average ambient temperatures, as described below under the heading “Seasonality.” Revenues attributable to our Product Segment are based on the sale of equipment and the provision of various services to our customers. These revenues may vary significantly from period to period because of the timing of our receipt of purchase orders and the progress of our execution of each project.

Our management assesses the performance of our two segments of operation differently. In the case of our Electricity Segment, when making decisions about potential acquisitions or the development of new projects, we typically focus on the internal rate of return of the relevant investment, relevant technical and geological matters and other relevant business considerations. We evaluate our operating 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 compared to the costs originally budgeted for such orders.

Recent Developments


	•	On August 3, 2010, we entered into a trust instrument governing the issuance of, and accepted subscriptions for an aggregate principal amount of approximately $142 million of senior unsecured bonds (the Bonds). We issued the bonds outside the United States to investors who are not “U.S. persons” in an unregistered offering pursuant to, and subject to the requirements of, Regulation S under the Securities Act of 1933, as amended. Subject to early redemption, principal of the bonds is repayable in a single bullet payment upon the final maturity of the Bonds on August 1, 2017. The Bonds bear interest at a fixed rate of 7% per annum, payable semi-annually. We intend to use the proceeds of the bonds for general corporate purposes, which may include the repayment of existing indebtedness and acquisitions.

	•	On August 2, 2010, we acquired the remaining 50% interest in Mammoth Pacific, LP, an entity that owns the Mammoth complex, for a purchase price of $72.5 million. Following the acquisition, we will become the sole owner of the Mammoth complex, and have the rights to over 10,000 acres of undeveloped federal lands which will enable us to expand the facility and substantially increase the generation capacity.

Following the acquisition, Mammoth Pacific, LP, previously accounted for under the equity method, will be consolidated in our consolidated financial statements. As a result of the acquisition, we will record in the third quarter of 2010, a gain resulting from the difference between the book value of the investment in Mammoth Pacific, LP and the fair value of such investment at the acquisition date. We have not yet calculated the gain, but we estimate that the pre-tax gain will equal up to approximately $40 million.


	•	In July 2010, our subsidiary, Ormat Nevada Inc. (Ormat Nevada), mandated John Hancock Life Insurance Company (U.S.A.) (John Hancock) to arrange senior secured construction and term loan facilities under a United States Department of Energy (DOE) loan guarantee program of up to $350 million for three geothermal projects currently under construction in Nevada. The three projects are the McGinness Hills, Jersey Valley and Tuscarora geothermal projects. Construction of all three projects has already commenced with commercial operation of the first phase of each project expected between 2011 and 2013. Part I of the application under the DOE loan guarantee program was submitted on July 27, 2010.

	•	In June 2010, we submitted an application for a cash grant from the U.S. Department of Treasury under the recently enacted American Recovery and Reinvestment Act of 2009 (ARRA) relating to our North Brawley power plant. The cash grant is equal to 30% of the eligible costs for such plant. We expect to receive the funds during the third quarter of 2010.

	•	On June 2, 2010, Alaska Governor, Sean Parnell, signed Alaska Senate Bill 243. This bill significantly reduces the annual royalty rate paid from geothermal production on state lands from a minimum of 10% of gross revenues to the same level paid on Federal land. Following the passage of Alaska Senate Bill 243, we announced that we will accelerate geothermal exploration work this summer on our Mount Spurr lease that we had won through a competitive bid in October 2008.

The Alaska Energy Authority (AEA) has recently approved a $2 million grant from the Renewable Energy Grant Fund to support our exploration and drilling work at Mount Spurr to be conducted during the summer and fall of 2010 and 2011. The goal for the Renewable Energy Grant is to promote renewable energy projects throughout the state, with a focus on rural Alaska where current diesel-based power prices are very high. The state has appropriated a total of $250 million for this program in an attempt to distribute the funds over five years, of which $25 million are allocated for the 2010 fiscal year

(July 2010 to July 2011). We expect to sign the grant contact during the third quarter of 2010. The grant will reimburse us for eligible costs as from July 1, 2010.


	•	On April 26, 2010, the Medco-Ormat-Itochu-Kyushu Consortium, which consists of Medco Energi Internasional Tbk, Ormat International Inc., our wholly owned subsidiary, Itochu Corporation and Kyushu Electric Power Co. Inc., signed the “Sarulla Project Joint Confirmation” with the state-owned Indonesian power company PT Perusahaan Listrik Negara (PLN) confirming an agreement on terms for amending the Energy Sales Contract (ESC), with the concession holder PT Pertamina Geothermal Energy (PGE), a wholly owned subsidiary of the Indonesian state-owned oil and gas company PT Pertamina (Persero), signing as witness. The ESC had been executed in December 2007 for the 330 MW net power Sarulla Geothermal Project. The Sarulla Project Joint Confirmation was signed during the opening ceremony of the World Geothermal Congress in Bali.

The parties have agreed to change the price of the power sold under the ESC to a levelized payment of 6.79 cents per kWh, whereby the tariff payable in the early years after commercial operation date shall be higher and shall be reduced in the later years. The parties have also agreed on a90-day schedule for resolving certain other contractual amendments for facilitation of project financing and for signing the resulting amended ESC. The modified tariff itself is subject to verification by the State Audit Agency for Development and approval from the Minister of Energy and Mineral Resources.


	•	Since the beginning of 2010, we entered into new lease agreements covering approximately 52,219 acres of federal or private land in Nevada, Utah, Hawaii, and California.

	•	In February 2010, we signed a letter of intent with Kenya Power and Lighting Co. Ltd. (KPLC), the off-taker, of the Olkaria III complex located in Naivasha, Kenya, to amend the existing PPA by expanding the Olkaria III complex by up to 52 MW within the framework of the existing PPA. The expansion is to be developed in two phases. Phase I will be comprised of 36 MW, to be completed within 3.5 years from finalizing the amendment to the existing PPA. An optional phase II may be comprised of up to 16 MW, to be completed within 4.5 years from finalizing the amendment to the existing PPA. The amendment to the existing PPA is subject to applicable governmental approvals and the consent of the lenders that provided the financing to the existing power plant.

	•	In February 2010, we signed an agreement to acquire 100% of the membership interests in HSS II, LLC, which owns the Tuscarora Project in the northern Independence Valley of northeast Nevada. The project is in an advanced stage of development and has one successful well. We plan to construct and operate a geothermal plant on the site, the first phase of 16 MW of which is expected to become operational in 2012, and sell electricity under a new PPA, which we signed with Nevada Power Company (a subsidiary of NV Energy, Inc).

	•	In January 2010,the North Brawley geothermal power plant in California was placed in service and is currently operating at a stable capacity of 20 MW. Southern California Edison Company (Southern California Edison), the PPA off-taker, agreed to extend the firm operation date until March 31, 2011. This extension will give us time to bring the power plant’s generation to its full design capacity of 50MW.

	•	In January 2010, we were awarded a geothermal exploration concession in Chile. The concession is on approximately 26,000 acres located to the north of the San Pablo/San Pedro twin volcanic complex in northern Chile and is close to access roads and to copper mines that could be potential users of the electricity. We plan to engage in preliminary testing and studies to assess the feasibility of the site for commercial development in accordance with the milestones set forth in the concession.

	•	In January 2010, we sold our interest in GDL for NZ$3.5 million (approximately US$2.8 million), and we were repaid a loan we had made to GDL with an outstanding balance of NZ$24.3 million (approximately US$17.6 million).

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 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 PPAs. We also intend to continue to pursue growth in our recovered energy business. We expect our Product Segment revenues in 2010 to be significantly lower than the 2009 revenues in such segment.

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 that began in late 2007 has resulted in reduced demand for energy in a number of the markets we serve. 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. In addition, the cost of obtaining financing for our project needs may increase or such financing may be more difficult to obtain.

	•	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 may look at acquisition opportunities that may arise.

	•	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, 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 from projected 2020 levels or about 15% from 2008 levels. The California Air Resources Board is expected to put in place measures for implementing the Global Warming Solutions Act of 2006 by 2012. In September of 2006, California also passed Senate Bill 1368, which prohibits the state’s utilities from entering into long-term financial commitments for base-load generation with power plants that fail to meet a CO₂ emission performance standard established by the California Energy Commission and the California Public Utilities Commission. California’s long-term climate change goals are reflected in Executive OrderS-3-05, which requires a reduction in greenhouse gases to: (i) 2000 levels by 2010; (ii) 1990 levels by 2020; and (iii) 80% of 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, Maryland, 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, thefirst-in-the-nation auction of CO₂ allowances was held under the RGGI, a regionalcap-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% at a rate of 2.5% 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 OrderS-14-08, adopted a goal for all retailers of electricity to serve 33% of their load with renewable energy by 2020, and in September of 2009, Executive OrderS-21-09 directed the California Air Resources Board to adopt regulations consistent with the 33% renewable energy target by July 31, 2010. 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. The current demand for renewable energy is large enough that this increased competition has not materially impacted our ability to obtain new PPAs. However, the increase in competition and in the amount of renewable energy under contract may contribute to a reduction in electricity prices. Despite increased competition from the wind and solar power generation industry, we believe that baseload electricity, such as geothermal-based energy, will continue to be a leading source of renewable energy in areas with commercially viable geothermal resources.

	•	We expect increased competition from binary power plant equipment suppliers. While we believe that we have a distinct competitive advantage based on our accumulated experience and current worldwide share of installed binary generation capacity, which is in excess of 90%, an increase in competition may lead to a reduction in prices that we are able to charge for our binary equipment, which in turn may impact our profitability.


	•	We also expect increased competition from new developers which may impact the prices and availability of new leases for geothermal resource.

	•	While the current demand for renewable energy is large enough that increased competition has not impacted our ability to obtain new PPAs 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 a geothermal resource depends on various factors such as the resource temperature, the permeability of the resource (i.e., the ability to get geothermal fluids to the surface) and operational factors relating to the extraction and injection of the geothermal fluids. Such factors, together with the possibility that we may fail to find commercially viable geothermal resources in the future, represent significant uncertainties 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 PPAs 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 PPAs. 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 power plant, which sells its electricity to Sierra Pacific Power Company on ayear-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 acase-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 PPAs, 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 PPAs. However, such revenues are subject to seasonal variations, as more fully described below in the section entitled “Seasonality”. Electricity Segment revenues may also be affected byhigher-than-average ambient temperatures, which could cause a decrease in

the generating capacity of our power plants, and by unplanned major maintenance activities related to our power plants.

Our PPAs generally provide for the payment of energy payments, or energy and capacity payments. Generally, capacity payments are payments calculated based on the amount of time that our power plants are available to generate electricity. Some of our PPAs provide for bonus payments in the event that we are able to exceed certain target levels and the potential forfeiture of payments if we fail to meet minimum target levels. Energy payments, on the other hand, are payments calculated based on the amount of electrical energy delivered to the relevant power purchaser at a designated delivery point. The rates applicable to such payments are either fixed (subject, in certain cases, to certain adjustments) or are based on the relevant power purchaser’s short run avoided costs (the incremental costs that the power purchaser avoids by not having to generate such electrical energy itself or purchase it from others). Our more recent PPAs generally provide for energy payments along with an obligation to compensate the off-taker for its incremental costs as a result of shortfalls in our supply.

The prices paid for electricity pursuant to the PPA of the Puna power plant are tied to the price of oil. Accordingly, our revenues for that power plant, which accounted for approximately 7.6% of our total revenues for the six-month period ended June 30, 2010, may be volatile.

Revenues attributable to our Product Segment are generally less predictable than revenues from our Electricity Segment. This is because larger customer orders for our products are typically 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				Six Months				Three Months						Six Months
	Ended				Ended				Ended						Ended
	June 30,				June 30,				June 30,						June 30,
	2010		2009		2010		2009		2010			2009			2010			2009

Revenues
Electricity Segment	$	68,807	$	59,826	$	134,912	$	121,886		71.5	%		60.1	%		75.4	%		61.3	%
Product Segment		27,459		39,673		44,008		76,924		28.5			39.9			24.6			38.7

Total	$	96,266	$	99,499	$	178,920	$	198,810		100.0	%		100.0	%		100.0	%		100.0	%

Geographical Breakdown of Revenues

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


	Revenues in Thousands								% of Revenues for Period Indicated
	Three Months				Six Months				Three Months
	Ended				Ended				Ended						Six Months Ended
	June 30,				June 30,				June 30,						June 30,
	2010		2009		2010		2009		2010			2009			2010			2009

Electricity Segment:
United States	$	50,910	$	41,926	$	98,499	$	87,283		74.0	%		70.1	%		73.0	%		71.6	%
Foreign		17,897		17,900		36,413		34,603		26.0			29.9			27.0			28.4

Total	$	68,807	$	59,826	$	134,912	$	121,886		100.0	%		100.0	%		100.0	%		100.0	%

Product Segment:							��
United States	$	2,644	$	24,050	$	5,023	$	47,212		9.6	%		60.6	%		11.4	%		61.4	%
Foreign		24,815		15,623		38,985		29,712		90.4			39.4			88.6			38.6

Total	$	27,459	$	39,673	$	44,008	$	76,924		100.0	%		100.0	%		100.0	%		100.0	%

Seasonality

The prices paid for the electricity generated by some of our domestic power plants pursuant to our PPAs are subject to seasonal variations. The prices paid for electricity under the PPAs with Southern California Edison Company (Southern California Edison) for the Heber 1 and 2 plants, the Mammoth complex and the Ormesa complex and the prices that will be paid for the electricity under the PPA 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 PPAs 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 electricity revenues are generally higher in the summer than in the winter.

Breakdown of Cost of Revenues

Electricity Segment

The principal expenses 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 ofmake-up water for use in our cooling towers. Some of these expenses, such as parts, third-party services and major maintenance, are not incurred on a regular basis. This results in fluctuations in our expenses and our results of operations for individual projects from quarter to quarter. Payments made to government agencies and private entities 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, 2010, royalties constituted approximately 3.4% of the Electricity Segment revenues, compared to approximately 4.0% for the same period in 2009.

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, 2010 increased to $54.2 million from $46.3 million as of December 31, 2009. This increase is principally due to: (i) a net increase of $100.4 million in amounts drawn under revolving credit lines with commercial banks; (ii) $58.9 million derived from operating activities during the six months ended June 30, 2010; and (iii) $19.6 million cash received from the sale of GDL. The increase in our cash resources was partially offset due to: (i) our use of $139.2 million of cash resources to fund capital expenditures; and (ii) $34.7 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 as of June 30, 2010 was $362.5 million, as described below in the section entitled “Liquidity and Capital Resources”, of which we utilized $293.8 million (including $59.4 million of letters of credit) as of June 30, 2010.

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 onForm 10-K for the year ended December 31, 2009.

New Accounting Pronouncements

On January 1, 2010, we adopted the amended consolidation guidance for variable interest entities. As to the impact of the adoption of this amendment on the consolidated financial statements and the additional disclosure in such consolidated financial statements, see Note 5 to our condensed consolidated financial statements set forth in Item 1 of this quarterly report.

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) a significant downward fluctuation in revenues from our Product Segment.


	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
	(In thousands, except per share data)						(In thousands, except
							per share data)

Statements of Operations Historical Data:
Revenues:
Electricity	$	68,807		$	59,826		$	134,912		$	121,886
Product		27,459			39,673			44,008			76,924

		96,266			99,499			178,920			198,810

Cost of revenues:
Electricity		63,498			44,718			118,021			88,404
Product		14,115			27,242			26,552			51,485

		77,613			71,960			144,573			139,889

Gross margin:
Electricity		5,309			15,108			16,891			33,482
Product		13,344			12,431			17,456			25,439

		18,653			27,539			34,347			58,921
Operating expenses:
Research and development expenses		3,614			2,487			6,881			3,288
Selling and marketing expenses		2,686			3,215			5,888			7,516
General and administrative expenses		6,996			5,582			14,016			13,117
Write-off of unsuccessful exploration activities		3,050			—			3,050			—

Operating income		2,307			16,255			4,512			35,000
Other income (expense):
Interest income		95			276			292			428
Interest expense, net		(9,426	)		(4,415	)		(19,140	)		(7,705	)
Foreign currency translation and transaction gains (losses)		(1,033	)		1,044			(599	)		(1,349	)
Income attributable to sale of tax benefits		2,070			4,366			4,209			8,534
Other non-operating income (expense), net		79			550			(280	)		400

Income (loss) from continuing operations, before income taxes and equity in income of investees		(5,908	)		18,076			(11,006	)		35,308
Income tax benefit (provision)		3,365			(3,868	)		5,922			(7,297	)
Equity in income of investees, net		479			355			1,025			905

Income (loss) from continuing operations		(2,064	)		14,563			(4,059	)		28,916
Discontinued operations:
Income from discontinued operations, net of related tax		—			1,411			14			1,564
Gain on sale of of a subsidiary in New Zealand, net of related tax		570			—			4,336			—

Net income (loss)		(1,494	)		15,974			291			30,480
Net loss attributable to noncontrolling interest		57			77			110			156

Net income (loss) attributable to the Company’s stockholders	$	(1,437	)	$	16,051		$	401		$	30,636

Earnings (loss) per share — basic and diluted:
Income (loss) from continuing operations	$	(0.05	)	$	0.32		$	(0.09	)	$	0.64
Income from discontinued operations		0.02			0.03			0.10			0.03

Net income (loss)	$	(0.03	)	$	0.35		$	0.01		$	0.67

Weighted average number of shares used in computation of earnings (loss) per share:
Basic		45,431			45,369			45,431			45,361

Diluted		45,431			45,451			45,431			45,425


	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009

Statements of Operations Percentage Data:
Revenues:
Electricity		71.5	%		60.1	%		75.4	%		61.3	%
Product		28.5			39.9			24.6			38.7

		100.0			100.0			100.0			100.0

Cost of revenues:
Electricity		92.3			74.7			87.5			72.5
Product		51.4			68.7			60.3			66.9

		80.6			72.3			80.8			70.4

Gross margin:
Electricity		7.7			25.3			12.5			27.5
Product		48.6			31.3			39.7			33.1

		19.4			27.7			19.2			29.6
Operating expenses:
Research and development expenses		3.8			2.5			3.8			1.7
Selling and marketing expenses		2.8			3.2			3.3			3.8
General and administrative expenses		7.3			5.6			7.8			6.6
Write-off of unsuccessful exploration activities		3.2			0.0			1.7			0.0

Operating income		2.4			16.3			2.5			17.6
Other income (expense):
Interest income		0.1			0.3			0.2			0.2
Interest expense, net		(9.8	)		(4.4	)		(10.7	)		(3.9	)
Foreign currency translation and transaction gains (losses)		(1.1	)		1.0			(0.3	)		(0.7	)
Income attributable to sale of tax benefits		2.2			4.4			2.4			4.3
Other non-operating income (expense), net		0.1			0.6			(0.2	)		0.2

Income (loss) from continuing operations, before income taxes and equity in income of investees		(6.1	)		18.2			(6.2	)		17.8
Income tax benefit (provision)		3.5			(3.9	)		3.3			(3.7	)
Equity in income of investees, net		0.5			0.4			0.6			0.5

Income (loss) from continuing operations		(2.1	)		14.6			(2.3	)		14.5
Discontinued operations:
Income from discontinued operations, net of related tax		0.0			1.4			0.0			0.8
Gain on sale of of a subsidiary in New Zealand, net of related tax		0.6			0.0			2.4			0.0

Net income (loss)		(1.6	)		16.1			0.2			15.3
Net loss attributable to noncontrolling interest		0.1			0.1			0.1			0.1

Net income (loss) attributable to the Company’s stockholders		(1.5	)%		16.1	%		0.2	%		15.4	%

Comparison of the Three Months Ended June 30, 2010 and the Three Months Ended June 30, 2009

Total Revenues

Total revenues for the three months ended June 30, 2010 were $96.3 million, compared with $99.5 million for the three months ended June 30, 2009, which represented a 3.2% decrease in total revenues. While revenues from our Electricity Segment increased by 15.0% from the same period last year, revenues from our Product Segment decreased by 30.8% from the same period in 2009, thereby causing the decrease in total revenues.

Electricity Segment

Revenues attributable to our Electricity Segment for the three months ended June 30, 2010 were $68.8 million, compared to $59.8 million for the three months ended June 30, 2009, which represented a 15.0% increase in such revenues. This increase is a result of increased electricity generation at most of our power plants from 795,662 MWh in the three months ended June 30, 2009 to 879,734 MWh in the three months ended June 30, 2010. The single most significant contributor to the increase in our electricity generation was the placement in service of our North Brawley power plant in January 2010, with revenues of $3.5 million in the three months ended June 30, 2010. This increase in generation was also due to an increase in the generating capacity of the Puna power plant due to repair work that was completed in the second quarter of 2010. The increase in our electricity segment revenues is also attributable to a slight increase in the average revenue rate of our electricity portfolio from $75 per MWh in the second quarter of 2009 to $78 per MWh in the second quarter of 2010.

Product Segment

Revenues attributable to our Product Segment for the three months ended June 30, 2010 were $27.5 million, compared to $39.7 million for the three months ended June 30, 2009, which represented a 30.8% decrease in such revenues. This decrease in our product revenue is a result of a decline in our Product Segment order backlog. As previously disclosed, we expect this downward fluctuation to affect revenues from our Product Segment throughout this year.

Total Cost of Revenues

Total cost of revenues for the three months ended June 30, 2010 was $77.6 million, compared to $72.0 million for the three months ended June 30, 2009, which represented a 7.9% increase in total cost of revenues. This increase is attributable to an increase in our Electricity Segment cost of revenues, as discussed below. The increase was partially offset by a decrease in our Product Segment cost of revenues. As a percentage of total revenues, our total cost of revenues for the three months ended June 30, 2010 was 80.6% compared with 72.3% for the same period in 2009. This increase is mainly attributable to high costs in our North Brawley plant, as described below.

Electricity Segment

Total cost of revenues attributable to our Electricity Segment for the three months ended June 30, 2010 was $63.5 million, which includes $11.9 million (including depreciation) related to the North Brawley power plant, compared to $44.7 million for the three months ended June 30, 2009, which represented a 42.0% increase in total cost of revenues for such segment. The increase over the same period last year is mainly attributable to our North Brawley power plant, which was placed in service in January 2010. We have incurred high costs (including depreciation) associated with operating and maintaining a 50 MW power plant, even though the North Brawley power plant performed at less than 50% of its generating capacity. The higher costs in the North Brawley power plant increased the cost per MWh in the current quarter compared to the second quarter of 2009. Since March 2010, we have installed permanent solid removals on the injection flows in our North Brawley power plant. Such permanent solid removals have the ability to provide better removal efficiency at a fraction of the operating costs that we have seen with the disposable cartridges, and we are in the process of implementing this solution on the production wells. Nevertheless, we expect to have high maintenance costs related to the cleaning of the wells and replacements of pumps in the next few quarters. As

a percentage of total electricity revenues, the total cost of revenues attributable to our Electricity Segment for the three months ended June 30, 2010 was 92.3%, compared to 74.7% for the three months ended June 30, 2009. We expect this trend to continue during the remainder of 2010.

Product Segment

Total cost of revenues attributable to our Product Segment for the three months ended June 30, 2010 was $14.1 million, compared to $27.2 million for the three months ended June 30, 2009, which represented a 48.2% decrease in total cost of revenues related to such segment. This decrease is attributable to the decrease in revenues as described above. As a percentage of total Product Segment revenues, our total cost of revenues attributable to this segment for the three months ended June 30, 2010 was 51.4%, compared to 68.7% for the three months ended June 30, 2009. This percentage decrease is attributable to the removal of a contingency relating to a project that was substantially completed in the second quarter of 2010.

Research and Development Expenses

Research and development expenses for the three months ended June 30, 2010 were $3.6 million, compared to $2.5 million for the three months ended June 30, 2009, which represented a 45.3% increase. Our research and development activities during the three months ended June 30, 2010 included: (i) an experimental REG plant specifically designed to use the residual energy from the vaporization process at liquefied natural gas regasification terminals; (ii) development of a solar thermal system for the production of electricity; and (iii) research of various solutions related to power plant cooling systems. The large percentage increase is primarily attributable to the costs related to the experimental REG plant in the amount of $2.4 million in the three months ended June 30, 2010, compared to $1.5 million in the three months ended June 30, 2009, that include developing and building a unit at a customer’s premises in Spain. If the development of the unit is not successful we will have to remove the unit from the customer’s site. If the unit operates successfully and passes acceptance tests, we will be paid by the customer an amount of approximately $13.6 million which will be recognized as revenue upon acceptance by the customer.

Selling and Marketing Expenses

Selling and marketing expenses for the three months ended June 30, 2010 were $2.7 million, compared to $3.2 million for the three months ended June 30, 2009, which represented a 16.5% decrease. The decrease was due primarily to the decrease in Product Segment revenues. Selling and marketing expenses for the three months ended June 30, 2010 constituted 2.8% of total revenues for such period compared to 3.2% for the three months ended June 30, 2009.

General and Administrative Expenses

General and administrative expenses for the three months ended June 30, 2010 were $7.0 million, compared to $5.6 million for the three months ended June 30, 2009, which represented a 25.3% increase. This increase was due primarily to increased payroll expenses and legal fees related to a potential acquisition that did not materialize. General and administrative expenses for the three months ended June 30, 2010 constituted 7.3% of total revenues for such period, compared to 5.6% for the three months ended June 30, 2009.

Write-off of Unsuccessful Exploration Activities

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

Operating Income

Operating income for the three months ended June 30, 2010 was $2.3 million, compared to $16.3 million for the three months ended June 30, 2009. Such decrease in operating income was principally attributable to a decrease in the total gross margin due to the decrease in Product Segment revenues and the increase in Electricity Segment cost of revenues, as well as the write-off of unsuccessful exploration activities. Operating loss attributable to our Electricity Segment for the three months ended June 30, 2010 was $5.1 million, compared to operating income of $9.5 million for the three months ended June 30, 2009, mainly due to the increase in electricity cost of revenues, as explained above. Operating income attributable to our Product Segment for the three months ended June 30, 2010 was $7.4 million, compared to $6.7 million for the three months ended June 30, 2009.

Interest Income

Interest income for the three months ended June 30, 2010 was $0.1 million, as compared with $0.3 million for the three months ended June 30, 2009. Interest income includes interest payable on investments included in cash and cash equivalents, marketable securities and restricted cash.

Interest Expense, Net

Interest expense, net, for the three months ended June 30, 2010 was $9.4 million, compared to $4.4 million for the three months ended June 30, 2009, which represented a 113.5% increase. The $5.0 million increase is primarily due to: (i) a decrease of $4.2 million in interest capitalized to projects as a result of decreased costs for projects under construction primarily due to the commencement of commercial operations of our North Brawley power plant in January 2010; (ii) borrowings under our revolving credit lines with banks; and (iii) loan agreements with two groups of institutional investors and a commercial bank. The increase was partially offset by a decrease in interest related to the sale of tax benefits in connection with the acquisition of a thirty percent interest in the Class B membership units of OPC in the fourth quarter of 2009 by our subsidiary, Ormat Nevada, as well as principal repayments.

Foreign Currency Translation and Transaction Gains (Losses)

Foreign currency translation and transaction losses for the three months ended June 30, 2010 were $1.0 million, compared to foreign currency translation and transaction gains of $1.0 million for the three months ended June 30, 2009. The $2.0 million decrease is primarily due to losses on forward foreign exchange transactions which do not qualify as hedge transactions for accounting purposes for the three months ended June 30, 2010, compared to gains in the three months ended June 30, 2010.

Income Attributable to Sale of Tax Benefits

Income from the sale of tax benefits to institutional equity investors (as described in the “OPC Transaction”) for the three months ended June 30, 2010 was $2.1 million, compared to $4.4 million for the three months ended June 30, 2009. This income represents the value of production tax credits (PTCs) and taxable income or loss generated by OPC and allocated to the investors. The decrease is due to lower depreciation for tax purposes as a result of declining depreciation rates utilizing the Modified Accelerated Cost Recovery System (MACRS) and to our purchase of Class B membership units of OPC from Lehman-OPC.

Income Taxes

Income tax benefit for the three months ended June 30, 2010 was $3.4 million, compared to income tax provision of $3.9 million for the three months ended June 30, 2009. The effective tax rate for the three months ended June 30, 2010 was a tax benefit of 57.0% compared to a tax expense of 21.4% for the three months ended June 30, 2009. The fluctuation in the effective tax rate primarily resulted from a higher impact of production tax credits on the effective tax rate for the quarter ended June 30, 2010 due to the Company’s pretax loss from continuing operations. We expect to recognize an income tax benefit during 2010 due to the significance of the forecasted production tax credits in relation to our forecasted pretax income from continuing operations.

Equity in Income of Investees

Our participation in the income generated from our investees for the three months ended June 30, 2010 was $0.5 million compared to $0.4 million for the three months ended June 30, 2009. The amount is derived mainly from our 50% ownership of the Mammoth complex.

Income (Loss) from Continuing Operations

Loss from continuing operations for the three months ended June 30, 2010 was $2.1 million, compared to income from continuing operations of $14.6 million for the three months ended June 30, 2009. Such decrease in income from continuing operations was principally attributable to: (i) a decrease of $13.9 million in operating income; (ii) a $5.0 million increase in interest expense; (iii) a $2.3 million decrease in income attributable to the sale of tax benefits; and (iv) a $2.1 million increase in foreign currency transaction and translation gains. This was partially offset by a $7.2 million decrease in income taxes.

Discontinued Operations

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

Net Income (Loss)

Net loss for the three months ended June 30, 2010 was $1.5 million, compared to net income of $16.0 million for the three months ended June 30, 2009. Such decrease in net income was principally attributable to the decrease in income from continuing operations in the amount of $16.6 million, as discussed above.

Comparison of the Six Months Ended June 30, 2010 and the Six Months Ended June 30, 2009

Total Revenues

Total revenues for the six months ended June 30, 2010 were $178.9 million, compared with $198.8 million for the six months ended June 30, 2009, which represented a 10.0% decrease in total revenues. While revenues from our Electricity Segment increased by 10.7% from the same period last year, revenues from our Product Segment decreased by 42.8% from the same period in 2009, thereby causing the decrease in total revenues.

Electricity Segment

Revenues attributable to our Electricity Segment for the six months ended June 30, 2010 were $134.9 million, compared to $121.9 million for the six months ended June 30, 2009, which represented a 10.7% increase in such revenues. This increase is a result of increased electricity generation at most of our power plants from 1,671,330 MWh in the six months ended June 30, 2009 to 1,797,616 MWh in the six months ended June 30, 2010. The single most significant contributor to the increase in our electricity generation was the placement in service of our North Brawley power plant in January 2010 with revenues of $6.2 million in the six months ended June 30, 2010. The increase in our Electricity Segment revenues is also attributable to a slight increase in the average revenue rate of our electricity portfolio from $73 per MWh in the first half of 2009 to $75 per MWh in the first half of 2010.

Product Segment

Revenues attributable to our Product Segment for the six months ended June 30, 2010 were $44.0 million, compared to $76.9 million for the six months ended June 30, 2009, which represented a 42.8% decrease in such revenues. This decrease in our product revenue is a result of a decline in our Product Segment order backlog.

Total Cost of Revenues

Total cost of revenues for the six months ended June 30, 2010 was $144.6 million, compared to $139.9 million for the six months ended June 30, 2009, which represented a 3.3% increase in total cost of revenues. This increase is attributable to an increase in our Electricity Segment cost of revenues. The increase was partially offset by a decrease in our Product Segment cost of revenues, as discussed below. As a percentage of total revenues, our total cost of revenues for the six months ended June 30, 2010 was 80.8% compared with 70.4% for the same period in 2009. This increase is mainly attributable to high costs in our North Brawley plant, as described below.

Electricity Segment

Total cost of revenues attributable to our Electricity Segment for the six months ended June 30, 2010 was $118.0 million, which includes $21.4 million (including depreciation) related to our North Brawley power plant, compared to $88.4 million for the six months ended June 30, 2009, which represented a 33.5% increase in total cost of revenues for such segment. The increase over the same period last year is mainly attributable to our North Brawley power plant which was placed in service in January 2010. We have incurred high costs (including depreciation) associated with operating and maintaining a 50 MW power plant, even though the North Brawley power plant performed at less than 50% of its generating capacity. The higher costs in the North Brawley power plant increased the cost per MWh for the six months ended June 30, 2010, compared to the six months ended June 30, 2009. As a percentage of total electricity revenues, the total cost of revenues attributable to our Electricity Segment for the six months ended June 30, 2010 was 87.5%, compared to 72.5% for the six months ended June 30, 2009.

Product Segment

Total cost of revenues attributable to our Product Segment for the six months ended June 30, 2010 was $26.6 million, compared to $51.5 million for the six months ended June 30, 2009, which represented a 48.4% decrease in total cost of revenues related to such segment. This decrease is attributable to the decrease in revenues associated with the decline in our Product Segment backlog. As a percentage of total Product Segment revenues, our total cost of revenues attributable to this segment for the six months ended June 30, 2010 was 60.3%, compared to 66.9% for the six months ended June 30, 2009. This percentage decrease is attributable to the removal of a contingency relating to a project that was substantially completed in the second quarter of 2010.

Research and Development Expenses

Research and development expenses for the six months ended June 30, 2010 were $6.9 million, compared to $3.3 million for the six months ended June 30, 2009, which represented a 109.3% increase. Our research and development activities during the six months ended June 30, 2010 included: (i) an experimental REG plant specifically designed to use the residual energy from the vaporization process at liquefied natural gas regasification terminals; (ii) continued development of enhanced geothermal systems (EGS); (iii) development of a solar thermal system for the production of electricity; and (iv) research of various solutions related to power plant cooling systems. The large percentage increase is primarily attributable to the costs related to the experimental REG plant in the amount of $5.0 million (in addition to $7.5 million recorded in the year ended December 31, 2009), that include developing and building a unit at a customer’s premises in Spain.

Selling and Marketing Expenses

Selling and marketing expenses for the six months ended June 30, 2010 were $5.9 million, compared to $7.5 million for the six months ended June 30, 2009, which represented a 21.7% decrease. The decrease was due primarily to the decrease in Product Segment revenues. Selling and marketing expenses for the six months ended June 30, 2010 constituted 3.3% of total revenues for such period compared to 3.8% for the six months ended June 30, 2009.

General and Administrative Expenses

General and administrative expenses for the six months ended June 30, 2010 were $14.0 million, compared to $13.1 million for the six months ended June 30, 2009, which represented a 6.8% increase. General and administrative expenses for the six months ended June 30, 2010 constituted 7.8% of total revenues for such period, compared to 6.6% for the six months ended June 30, 2009.

Write-off of Unsuccessful Exploration Activities

Write-off of unsuccessful exploration activities for the six months ended June 30, 2010 was $3.1 million, which represents the write-off of exploration costs related to the Gabbs Valley project, which we determined in the second quarter of 2010 would not support commercial operations.

Operating Income

Operating income for the six months ended June 30, 2010 was $4.5 million, compared to $35.0 million for the six months ended June 30, 2009. Such decrease in operating income was principally attributable to a decrease in the total gross margin due to the decrease in Product Segment revenues and the increase in Electricity Segment cost of revenues, as well as the write-off of unsuccessful exploration activities. Operating loss attributable to our Electricity Segment for the six months ended June 30, 2010 was $2.0 million, compared to operating income of $20.4 million for the six months ended June 30, 2009, mainly due to the increase in electricity cost of revenues, as explained above. Operating income attributable to our Product Segment for the six months ended June 30, 2010 was $6.5 million, compared to operating income of $14.6 million for the six months ended June 30, 2009, mainly due to the decrease in product revenues, as explained above.

Interest Income

Interest income for the six months ended June 30, 2010 was $0.3 million, as compared with $0.4 million for the six months ended June 30, 2009. Interest income includes interest payable on investments included in cash and cash equivalents, marketable securities and restricted cash.

Interest Expense, Net

Interest expense, net, for the six months ended June 30, 2010 was $19.1 million, compared to $7.7 million for the six months ended June 30, 2009, which represented a 148.4% increase. The $11.4 million increase is primarily due to: (i) a decrease of $8.4 million in interest capitalized to projects as a result of decreased costs for projects under construction primarily due to the commencement of commercial operations of our North Brawley power plant in January 2010; (ii) an increase in interest expenses related to our long-term project finance loans of the Olkaria III and Amatitlan power plants; (iii) borrowings under our revolving credit lines with banks; and (iv) loan agreements with two groups of institutional investors and a commercial bank. The increase was partially offset by a decrease in interest related to the sale of tax benefits in connection with the acquisition of a thirty percent interest in the Class B membership units of OPC in the fourth quarter of 2009 by our subsidiary, Ormat Nevada, as well as principal repayments.

Foreign Currency Translation and Transaction Losses

Foreign currency translation and transaction losses for the six months ended June 30, 2010 were $0.6 million, compared to $1.3 million for the six months ended June 30, 2009. The $0.7 million decrease is primarily due to lower losses on forward foreign exchange transactions which do not qualify as hedge transactions for accounting purposes for the six months ended June 30, 2010, compared to the six months ended June 30, 2009.

Income Attributable to Sale of Tax Benefits

Income from the sale of tax benefits to institutional equity investors (as described in the “OPC Transaction”) for the six months ended June 30, 2010 was $4.2 million, compared to $8.5 million for the six months ended June 30, 2009. This income represents the value of PTCs and taxable income or loss generated by OPC and allocated to the investors. The decrease is due to lower depreciation for tax purposes as a result of declining depreciation rates utilizing MACRS and to our purchase of Class B membership units of OPC from Lehman-OPC.

Income Taxes

Income tax benefit for the six months ended June 30, 2010 was $5.9 million, compared to income tax provision of $7.3 million for the six months ended June 30, 2009. The effective tax rate for the six months ended June 30, 2010 was a tax benefit of 53.8% compared to a tax expense of 20.7% for the six months ended June 30, 2009. The fluctuation in the effective tax rate primarily resulted from a higher impact of production tax credits on the effective tax rate from the six months ended June 30, 2010 due to the Company’s pretax loss from continuing operations, partially offset by a valuation allowance recorded in 2010 relating to capital loss carryovers. We expect to recognize an income tax benefit during 2010 due to the significance of the forecasted production tax credits in relation to our forecasted pretax income from continuing operations.

Equity in Income of Investees

Our participation in the income generated from our investees for the six months ended June 30, 2010 was $1.0 million, compared to $0.9 million for the six months ended June 30, 2009. The amount is derived mainly from our 50% ownership of the Mammoth complex.

Income (Loss) from Continuing Operations

Loss from continuing operations for the six months ended June 30, 2010 was $4.1 million, compared to income from continuing operations of $28.9 million for the six months ended June 30, 2009. Such decrease in income from continuing operations was principally attributable to: (i) a decrease of $30.5 million in operating income; (ii) an $11.4 million increase in interest expense; and (iii) a $4.3 million decrease in income attributable to the sale of tax benefits. This was partially offset by: (i) a $0.7 million decrease in foreign currency transaction and translation losses; and (ii) a $13.2 million decrease in income taxes.

Discontinued Operations

Net Income

Net income for the six months ended June 30, 2010 was $0.3 million, compared to $30.5 million for the six months ended June 30, 2009. Such decrease in net income was principally attributable to the decrease in income from continuing operations in the amount of $33.0 million, as discussed above, partially offset by the gain on the sale of shares in GDL in the amount of $4.3 million, net of related income taxes.

Liquidity and Capital Resources

Our principal sources of liquidity have been derived from cash flows from operations, the issuance of our common stock in public and private offerings, proceeds from third party debt in the form of borrowings under credit facilities and private offerings, issuance by Ormat Funding Corp. (OFC) and OrCal Geothermal Inc. (OrCal) of their respective Senior Secured Notes and project financing (including the Puna lease and the OPC

Transaction 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, 2010, we have access to the following sources of funds: (i) $54.2 million in cash and cash equivalents; and (ii) $68.7 million of unused corporate borrowing capacity under existing committed lines of credit with different commercial banks.

Our estimated capital needs for the rest of 2010 include approximately $172.0 million for capital expenditures on new projects in development or construction, exploration activity, operating projects, and machinery and equipment, as well as $27.2 million for debt repayment.

We expect to finance these requirements with: (i) the sources of liquidity described above; (ii) cash flows from our operations; (iii) additional borrowing capacity under future lines of credit with commercial banks that are under negotiations; (iv) future project financing and refinancing; (v) proceeds of approximately $142.0 million from the issuance of senior unsecured bonds on August 3, 2010, as described below; and (vi) a cash grant available to us under the ARRA in respect of the North Brawley power plant. We submitted the application for the grant in June 2010 and expect to receive the funds shortly. Management believes that these sources will address our anticipated liquidity, capital expenditures and other investment requirements. Our shelf registration statement onForm 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.

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

OFC Senior Secured Notes — Non Recourse

On February 13, 2004, OFC, one of our subsidiaries, issued $190.0 million, 81/4% Senior Secured Notes (OFC Senior Secured Notes) in an offering subject to Rule 144A and Regulation S of the Securities Act of 1933, as amended (the Securities Act), for the purpose of refinancing the acquisition cost of the Brady, Ormesa and Steamboat 1/1A power plants, and the financing of the acquisition cost of the Steamboat2/3 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, 2010, OFC was in compliance with the covenants under the OFC Senior Secured Notes. As of June 30, 2010, there were $141.4 million of OFC Senior Secured Notes outstanding.

OrCal Secured Notes — Non-Recourse

On December 8, 2005, OrCal, one of our subsidiaries, issued $165.0 million, 6.21% Senior Secured Notes (OrCal Senior Secured Notes) in an offering subject to Rule 144A and Regulation S of the Securities Act, for the purpose of refinancing the acquisition cost of the Heber power plants. The OrCal Senior Secured Notes have been rated BBB- by Fitch. 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,

2010, OrCal was in compliance with the covenants under the OrCal Senior Secured Notes. As of June 30, 2010, there were $103.2 million of OrCal Senior Secured Notes outstanding.

Olkaria III Loan — Non-Recourse

OrPower 4, Inc. (OrPower 4), has a project financing loan of $105.0 million which refinanced its investment in the 48 MW Olkaria III geothermal power plant located in Kenya. The loan was provided by a group of European Development Finance Institutions (DFIs) arranged by DEG — Deutsche Investitions-und Entwicklungsgesellschaft mbH (DEG). 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 on6-month LIBOR plus 4.0%. We fixed the interest rate on $77.0 million of the loan at 6.90% per annum. There are various restrictive covenants under the loan, which include limitations on OrPower 4’s ability to make distributions to its shareholders. As of June 30, 2010, OrPower 4 was in compliance with the covenants under the loan. As of June 30, 2010, $93.9 million of the Olkaria III loan was outstanding.

Amatitlan Loan — Non-Recourse

Ortitlan Limitada (Ortitlan), entered into a note purchase agreement in an aggregate principal amount of $42.0 million which refinanced its investment in the 20 MW Amatitlan geothermal power plant located in Amatitlan, Guatemala. The loan was provided by TCW Global Project Fund II, Ltd. (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, 2010, Ortitlan was in compliance with the covenants under the loan. As of June 30, 2010, $40.1 million of the Amatitlan loan was outstanding.

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 $2.5 million was outstanding as of June 30, 2010, has a fixed annual interest rate of 11.775%, and matures on November 15, 2011. The loan from CDC, of which $0.7 million was outstanding as of June 30, 2010, 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, 2010, Orzunil was in compliance with the covenants under these senior loans.

New Financing of Our Projects

Financing of the North Brawley Power Plant

As a result of the recent 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 of approximately $100.0 million that we are currently negotiating with a financial institution.

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

Our subsidiary, Ormat Nevada, has mandated John Hancock to arrange senior secured construction and term loan facilities under a United States DOE loan guarantee program of up to $350 million for three geothermal projects currently under construction in Nevada. The three projects are the McGinness Hills, Jersey Valley and Tuscarora geothermal projects. Construction of all three projects has already commenced with commercial operation of the first phase of each project expected between 2011 and 2013.

The availability of the credit facilities is subject to various conditions, including execution of mutually satisfactory documentation and approval of the DOE.

Ormat Nevada and John Hancock submitted Part I of the loan guarantee application to the DOE on July 27, 2010. The process will continue with the DOE and John Hancock’s due diligence, followed by a conditional commitment for the financing, completion of documentation and closing of the financing. Based on the experience gained so far in the program, the Company expects that this process may take 6 to 12 months to be completed.

Full-Recourse Third Party Debt

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

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

As of June 30, 2010, letters of credit in the amount of $30.0 million remain issued and outstanding under this credit agreement with Union Bank.

We also have credit agreements with six commercial banks for an aggregate amount of $325.0 million. Under these credit agreements, we or our Israeli subsidiary, Ormat Systems Ltd., can request extensions of credit in the form of loansand/or the issuance of one or more letters of credit. The credit agreements mature between December 2010 and November 2011.

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, 2010, loans in the amount of $234.4 million were outstanding, and letters of credit in the total amount of $29.5 million remain issued and outstanding under such credit agreements.

We have a $20.0 million term loan with a group of financial institutions, which matures on July 16, 2015, is payable in 12 semi-annual installments commencing January 16, 2010, and bears annual interest of 6.5%. As of June 30, 2010, $18.6 million was outstanding under this loan.

We have a $20.0 million term loan with a group of financial institutions, which matures on August 1, 2017, is payable in 12 semi-annual installments commencing February 1, 2012, and bears interest at6-month LIBOR plus 5.0%. As of June 30, 2010, $20.0 million was outstanding under this loan.

We have a $50.0 million term loan with a commercial bank, which matures on November 10, 2014, and is payable in 10 semi-annual installments commencing May 10, 2010, and bears interest at6-month LIBOR plus 3.25%. As of June 30, 2010, $45.0 million was outstanding under this loan.

On August 3, 2010, we entered into a trust instrument governing the issuance of, and accepted subscriptions for approximately $142 million in aggregate principal amount of senior unsecured bonds (the Bonds). We issued the Bonds outside the United States to investors who are not “U.S. persons” in an unregistered offering pursuant to, and subject to the requirements of, Regulation S under the Securities Act.

Subject to early redemption, principal of the Bonds is repayable in a single bullet payment upon the final maturity of the Bonds on August 1, 2017. The Bonds bear interest at a fixed rate of 7% per annum, payable semi-annually. We intend to use the proceeds of the Bonds for general corporate purposes, which may include the repayment of existing indebtedness and the acquisition, directly or indirectly, of additional energy assets, including by way of construction, enhancement and expansion of its existing projects.

Our obligations under the credit agreements, the loan agreements and the trust agreement governing the Bonds, described above, are unsecured, but we are subject to a negative pledge in favor of the banks and the other lenders and certain other restrictive covenants. These include, among other things, a prohibition on: (i) creating any floating charge or any permanent pledge, charge or lien over our assets without obtaining the prior written approval of the lender; (ii) guaranteeing the liabilities of any third party without obtaining the prior written approval of the lender; and (iii) selling, assigning, transferring, conveying or disposing of all or substantially all of our assets. In some cases, we have agreed to maintain certain financial ratios such as a debt service coverage ratio, a debt to equity ratio, and a debt to EBITDA ratio. There are also certain restrictions on distribution of dividends. 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 agreements, the loan agreements and the trust agreement governing the Bonds 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.

Two commercial banks have issued such performance letters of credit in favor of our customers from time to time. As of June 30, 2010, such banks have agreed to make available to us letters of credit totaling $31.7 million. As of such date, such banks have issued letters of credit in the amount of $30.3 million. These letters of credit were not issued under the credit agreements discussed under “Full-Recourse Third Party Debt” above.

In addition, we and certain of our subsidiaries may request letters of credit under the credit agreements with Union Bank and six other commercial banks as described above under “Full-Recourse Third Party Debt”. As of June 30, 2010, nine letters of credit in the amount of $59.4 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 Venture (PGV), entered into a transaction involving the Puna geothermal power plant located on the Big Island of Hawaii. The transaction was concluded with financing parties by means of a leveraged lease transaction. A secondary stage of the lease transaction relating to two new geothermal wells that PGV drilled in the second half of 2005 (for production and injection) was completed on December 30, 2005. Pursuant to a31-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

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

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

Ormat Nevada continues to operate and maintain the power plants 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 PTCs and the taxable income or loss, 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.

The Class B membership units are provided with a 5% residual economic interest in OPC. The 5% residual interest commences on achievement by the investors of a contractually stipulated return that triggers the Flip Date. The actual Flip Date is not known with certainty and is determined by the operating results of OPC. This residual 5% interest represents a noncontrolling interest and is not subject to mandatory redemption or guaranteed payments. As a result of the acquisition by Ormat Nevada, on October 30, 2009, of all of the Class B membership units of OPC held by Lehman-OPC LLC (see below), the residual interest decreased to 3.5%.

Our voting rights in OPC are based on a capital structure that is comprised of Class A and Class B membership units. We own, through our subsidiary, Ormat Nevada, all of the Class A membership units, which represent 75% of the voting rights in OPC and 30% of the Class B membership units, which represent 7.5% of the voting rights of OPC, and in total we have 82.5% of the voting rights in OPC. The investors own 70% of the Class B membership units, which represent 17.5% of the voting rights of OPC. Other than in respect of customary protective rights, all operational decisions in OPC are decided by the vote of a majority of the membership units. Following the Flip Date, Ormat Nevada’s voting rights will increase to 96.5% and the investor’s voting rights will decrease to 3.5%. Ormat Nevada retains the controlling voting interest in OPC both before and after the Flip Date and therefore has continued to consolidate OPC.

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

Liquidity Impact of Uncertain Tax positions

As discussed in Note 15 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 $5.4 million as of June 30, 2010. This liability is included in long-term liabilities in our consolidated balance sheet, because we generally do not anticipate that settlement of the liability will require payment of cash within the next twelve months. We are not able to reasonably estimate

when we will make any cash payments required to settle this liability, but believe that the ultimate settlement of our obligations will not materially affect our liquidity.

Dividend

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


	Dividend Amount
Date Declared	per Share		Record Date	Payment Date

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
November 4, 2009	$	0.06	November 18, 2009	December 1, 2009
February 23, 2010	$	0.12	March 16, 2010	March 25, 2010
May 5, 2010	$	0.05	May 18, 2010	May 25, 2010
August 4, 2010	$	0.05	August 17, 2010	August 26, 2010

Historical Cash Flows

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


	Six Months Ended
	June 30,
	2010			2009
	(Dollars in thousands)

Net cash provided by operating activities	$	58,934		$	55,332
Net cash used in investing activities		(109,014	)		(158,402	)
Net cash provided by financing activities		57,968			114,519
Translation adjustments on cash and cash equivalents		—			186
Net change in cash and cash equivalents		7,888			11,635

For the Six Months Ended June 30, 2010

Net cash provided by operating activities for the six months ended June 30, 2010 was $58.9 million, compared to $55.3 million for the six months ended June 30, 2009. The net increase of $3.6 million resulted primarily from: (i) an increase of $9.1 million in depreciation and amortization mainly due to the placement in service of our North Brawley power plant in January 2010, as described above; (ii) a decrease in receivables of $4.2 million in the six months ended June 30, 2010, compared to an increase of $6.7 million in the six months ended June 30, 2009; (iii) a net decrease in costs and estimated earnings in excess of billings on uncompleted contracts of $10.2 million in the six months ended June 30, 2010, compared to a net increase of $7.8 million in the six months ended June 30, 2009; and (iv) an increase in accounts payable and accrued expenses of $9.4 million in the six months ended June 30, 2010, compared to a decrease of $1.0 million in the six months ended June 30, 2009. Such increase was partially offset by: (i) a decrease in net income of $0.3 million in the six months ended June 30, 2010, from $30.5 million in the six months ended June 30, 2009, mainly as a result of the decrease in operating income, as described above; and (ii) a gain on sale of GDL of $6.4 million in the six months ended June 30, 2010.

Net cash used in investing activities for the six months ended June 30, 2010 was $109.0 million, compared to $158.4 million for the six months ended June 30, 2009. The principal factors that affected our net cash used in investing activities during the three months ended June 30, 2010 were capital expenditures of $139.2 million, primarily for our facilities under construction, which was offset by $19.6 million cash received from the sale of GDL and a $7.7 million decrease 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, 2009 were capital expenditures of $147.6 million, primarily for our power facilities under construction, and a $10.6 million increase in restricted cash, cash equivalents and marketable securities.

Net cash provided by financing activities for the six months ended June 30, 2010 was $58.0 million, compared to $114.5 million for the six months ended June 30, 2009. The principal factor that affected the net cash provided by financing activities during the six months ended June 30, 2010 was the $100.4 million drawn under revolving lines of credit from banks, which was offset by: (i) the repayment of long-term debt in the amount of $34.7 million; and (ii) the payment of a dividend to our shareholders in the amount of $7.7 million. The principal factors that affected our 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) the proceeds of $42.0 million from the Amatitlan Loan; and (iii) the $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 payment of a dividend to our shareholders in the amount of $5.9 million; and (iii) the repayment of long-term debt in the amount of $10.9 million.

Adjusted EBITDA

Adjusted EBITDA for the three months ended June 30, 2010 was $24.0 million compared to $39.8 million for the three months ended June 30, 2009. Adjusted EBITDA for the six months ended June 30, 2010 was $56.1 million compared to $77.2 million for the six months ended June 30, 2009. Adjusted EBITDA includes consolidated EBITDA and our share in the interest, taxes, depreciation and amortization related to our unconsolidated 50% interest in the Mammoth complex.

We calculate EBITDA as net income before interest, taxes, depreciation and amortization. We calculate adjusted EBITDA to include depreciation and amortization, interest and taxes attributable to our equity investments in the Mammoth complex. EBITDA and adjusted EBITDA are not measurements of financial performance or liquidity under GAAP and should not be considered as an alternative to cash flow from operating activities or as a measure of liquidity or an alternative to net earnings as indicators of our operating performance or any other measures of performance derived in accordance with GAAP. EBITDA and adjusted EBITDA are presented because we believe they are frequently used by securities analysts, investors and other interested parties in the evaluation of a Company’s ability to serviceand/or incur debt. However, other companies in our industry may calculate EBITDA and adjusted EBITDA differently than we do.

The following table reconciles net cash provided by operating activities to EBITDA and adjusted EBITDA, for the three and six-month periods ended June 30, 2010 and 2009:


							Six Months Ended
	Three Months Ended June 30,						June 30,
	2010			2009			2010			2009
	(In thousands)						(In thousands)

Net cash provided by operating activities	$	10,694		$	12,798		$	58,934		$	55,332
Adjusted for:
Interest expense, net (excluding amortization of deferred financing costs)		8,754			3,736			17,775			6,127
Interest income		(95	)		(276	)		(292	)		(428	)
Income tax provision (benefit)		2			4,478			21			7,967
Adjustments to reconcile net income to net cash provided by operating activities (excluding depreciation and amortization)		3,755			18,237			(22,251	)		6,341

EBITDA		23,110			38,973			54,187			75,339
Interest, taxes, depreciation and amortization attributable to the Company’s equity in Mammoth-Pacific L.P.		939			834			1,912			1,823

Adjusted EBITDA	$	24,049		$	39,807		$	56,099		$	77,162

Net cash used in investing activities	$	(44,033	)	$	(67,177	)	$	(109,014	)	$	(158,402	)

Net cash provided by financing activities	$	44,423		$	57,533		$	57,968		$	114,519

This comparative non-GAAP information is provided to assist investors in evaluating the impact of the change in the way we calculate these amounts in performing their financial analysis of our operations for the periods presented. This information should not be considered in isolation or as a substitute for, or superior to, measures of financial performance prepared in accordance with GAAP or other non-GAAP financial measures.

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 underway to increase the output of the project by an estimated 8 MW and improve the performance of the wellfield. The enhancement includes recompletion of the major production and injection wells and the construction of two additional OEC units. Permits to start construction have been obtained and site construction has begun. Equipment manufacturing has been completed. We signed a memorandum of understanding and concluded the final terms of the PPA with Hawaii Electric Light Company for the sale of additional electrical power from the Puna project. We are currently waiting for the approval of the Puna power plant lender and expect to place the enhancement in service by the end of 2010.

East Brawley Project We previously began construction and manufacturing of equipment for an additional 30 MW plant in the Brawley Known Geothermal Area in Imperial County, California, adjacent to the North Brawley project. We drilled several commercial size wells that we planned to utilize for this project, and were otherwise awaiting the required construction permits. However, at this point in time, and until the North Brawley power plant is stabilized, we have transferred the use of the East Brawley wells, on a temporary basis, to the North Brawley power plant as part of our ongoing efforts to bring the North Brawley power plant from its current operational level of approximately 20 MW to its full design capacity of 50 MW.

Appropriate permits for such transfer were approved and the formal signed certificate is expected shortly. We expect to discontinue the North Brawley power plant’s usage of these wells once it is stabilized at an acceptable operational level. As a result, we have put the continued construction of the East Brawley project on temporary hold. We currently expect to reschedule such construction once the North Brawley power plant has stabilized at an acceptable operational level, although our construction plans could change based on our evaluation of the site, market conditions and other relevant factors at that time.

GRE Project We completed the construction of a 5.5 MW recovered energy generation project for Great River Energy, which will be located along the Northern Border pipeline in Martin County, Minnesota. We signed a20-year PPA with Great River Energy. Plant interconnection to the utility grid line has been completed. Commercial operation will commence shortly.

Jersey Valley Project We are currently constructing the Jersey Valley project on Bureau of Land Management leases located in Pershing County, Nevada. We plan to build the project with three units. Field development and production of the power generating unit for the 15MW first phase has been completed, the construction permits have been obtained and civil work has started at the site. Completion of construction of the first phase is expected at the end of 2010 or the beginning of 2011.

McGinness Hills Project We are currently developing the first phase of the 30 MW McGinness Hills project on Bureau of Land Management leases located in Lander County, Nevada. Basic well field site preparation has been completed and permits to drill have been obtained. Four production wells and a successful injection well have been drilled and drilling for additional wells is continuing. We have submitted documents to obtain the required construction permits and an Environmental Assessment has begun. We signed a20-year PPA with Nevada Power Company, which was approved by the Public Utilities Commission of Nevada (PUCN) on July 28, 2010 . Commercial operation of the project’s first phase is expected in 2012.

Tuscarora Project We are currently developing the first phase (16 MW) of the Tuscarora project on private land located in Elko County, Nevada. The land, when acquired, contained a drilled production well. We have drilled a successful injection well and a successful production well and are continuing with field development work. We signed a20-year PPA with Nevada Power Company, which was approved by the PUCN on July 28, 2010. Commercial operation of the project’s first phase is expected in 2012.

Carson Lake We are currently developing the 20 MW Carson Lake project on Bureau of Land Management leases located in Churchill County, Nevada. Our initial joint venture with Nevada Power Company for this project contemplated a larger project. We are in preliminary discussions to address the implications of a smaller project. The project is expected to start commercial operation in 2013.

We have estimated approximately $676 million for construction of new projects that are still under construction and have invested approximately $250 million of such estimate as of June 30, 2010. We expect to invest approximately $106 million for these power plants in the rest of 2010 (including the North Brawley power plant).

In addition, we expect to invest approximately $32 million through the remainder of 2010 in new projects under development. Our operating power plants have capital expenditure requirements for the rest of 2010 of approximately $24 million. We have various leases for geothermal resources, in which we have started exploration activity, for a total investment amount of approximately $7 million for the rest of 2010 and we also plan to invest approximately $3 million in our production facilities.

By the end of 2010, we plan to start construction in Wister and Mammoth Phase II. We expect these projects will qualify for the ITC cash grant available under the ARRA.

Exposure to Market Risks

While, based on current conditions, we believe that we have sufficient financial resources to fund our activities and execute our business plans, the cost of obtaining financing for our project needs may increase

significantly or such financing may be difficult to obtain. A prolonged economic slowdown could reduce worldwide demand for energy, including our geothermal energy, REG and other products.

One market risk to which power plants are typically exposed is the volatility of electricity prices. However, our exposure to such market risk is currently limited because our long-term PPAs (except for Puna) have fixed or escalating rate provisions that limit our exposure to changes in electricity prices. However, beginning in May 2012, the energy payments under the PPAs of the Heber 1 and 2 power plants, the Ormesa complex and the Mammoth complex will be determined by reference to the relevant power purchaser’s short run avoided costs. The Puna power plant is currently benefiting from energy prices which are higher than the floor under the Puna PPA as a result of the high fuel costs that impact HELCO’s avoided costs.

As of June 30, 2010, 53.7% 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, 46.3% 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, 2010, $324.3 million of our debt remained subject to some floating rate risk.

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

Our cash equivalents and our portfolio of marketable securities are subject to market risk due to changes in interest rates. Fixed rate securities may have their market value adversely impacted due to a rise in interest rates, while floating rate securities may produce less income than expected if interest rates fall. Due in part to these factors, our future investment income may fall short of expectation 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 beother-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 we or any of our foreign subsidiaries borrows funds or incurs operating or other expenses in one type of currency but receives revenues in another. In such cases, an adverse change in exchange rates can reduce our or such subsidiary’s ability to meet its debt service obligations, reduce the amount of cash and income we receive from such foreign subsidiary, or increase such subsidiary’s overall expenses. Risks attributable to fluctuations in foreign currency exchange rates can also arise when the currency denomination of a particular contract is not the U.S. dollar. Substantially all of our PPAs in the international markets are either U.S. dollar-denominated or linked to the U.S. dollar. Our construction contracts from time to time contemplate costs which are incurred in local currencies. The way we often mitigate such risk is to receive part of the proceeds from the sale contract in the currency in which the expenses are incurred. Through most of 2009, 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 Nevada Power Company

(subsidiaries of NV Energy, Inc.) and Kenya Power and Lighting Co. Ltd. If any of these electric utilities fails to make payments under its PPAs with us, such failure would have a material adverse impact on our financial condition.

Southern California Edison accounted for 25.5% and 21.3% of our total revenues for the three months ended June 30, 2010 and 2009, respectively, and 25.5% and 19.6% of our total revenues for the six months ended June 30, 2010 and 2009, 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.

Sierra Pacific Power Company and Nevada Power Company accounted for 13.7% and 12.2% of our total revenues for the three months ended June 30, 2010 and 2009, respectively, and 16.2% and 13.0% of our total revenues for the six months ended June 30, 2010 and 2009, respectively.

Hawaii Electric Light Company accounted for 8.0% and 4.9% of our total revenues for the three months ended June 30, 2010 and 2009, respectively, and 7.6% of our total revenues in each of the six months ended June 30, 2010 and 2009.

Kenya Power and Lighting Co. Ltd. accounted for 9.2% and 8.9% of the Company’s total revenues for the three months ended June 30, 2010 and 2009, respectively, and 9.9% and 8.6% of our total revenues for the six months ended June 30, 2010 and 2009, respectively.

Government Grants and Tax Benefits

The U.S. government encourages production of electricity from geothermal resources through certain tax subsidies under the recently enacted ARRA. We are permitted to claim 30% of the eligible costs of each new geothermal power plant in the United States as an ITC against our federal income taxes. Alternatively, we are permitted to claim a PTC, which in 2010 is 2.2 cents per kWh and which is adjusted annually for inflation. The PTC may be claimed for ten years on the electricity output of new geothermal power plants put into service by December 31, 2013. The owner of the project must choose between the PTC and the 30% ITC described above. In either case, under current tax rules, any unused tax credit has a1-year carry back and a20-year carry forward. Whether we claim the PTC or the ITC, we are also permitted to depreciate most of the plant for tax purposes over five years on an accelerated basis, meaning that more of the cost may be deducted in the first few years than during the remainder of the depreciation period. If we claim the ITC, our “tax basis” in the plant that we can recover through depreciation must be reduced by half of the tax credit. If we claim a PTC, there is no reduction in the tax basis for depreciation. Companies that begin construction on, or place in service qualifying renewable energy facilities, 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 ITC. 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.

Production of electricity from geothermal resources is also supported under the new “Temporary Program For Rapid Deployment of Renewable Energy and Electric Power Transmission Projects” established with the DOE as part of the DOE’s existing Innovative Technology Loan Guarantee Program. The new 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, which will not exceed 25% for an additional five years. Ormat Systems is also exempt from Israeli income taxes with respect to income derived from the second benefited investment for a period of two years that started in 2007, and thereafter such income is subject to reduced Israeli income tax rates which will not exceed 25% for an additional five years. 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 onForm 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 toRule 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 March 31, 2010, our Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures (as defined inRules 13a-15(e) and15d-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 2010 that have materially affected or are reasonably likely to materially affect our internal controls over financial reporting.

PART II — OTHER INFORMATION


ITEM 1.	*LEGAL PROCEEDINGS*

Securities Class Actions

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

These three lawsuits were consolidated by the Court in an order issued on June 3, 2010 and the Court appointed three of the Company’s stockholders to serve as lead plaintiffs. Lead plaintiffs filed a consolidated amended class action complaint (CAC) on July 9, 2010 that asserts claims under Sections 10(b) and 20(a) of the Securities Exchange Act of 1934 on behalf of a putative class of purchasers of Company stock between May 7, 2008 and February 24, 2010. The CAC alleges that certain of the Company’s public statements were false and misleading for failing to account properly for the Company’s exploration and development costs based on the Company’s announcement on February 24, 2010 that it was going to restate its financial results to change its method of accounting for exploration and development costs in certain respects. The CAC also alleges that certain of the Company’s statements concerning the North Brawley project were false and misleading. The CAC seeks compensatory damages, expenses, and such further relief as the Court may deem proper. Defendants intend to file a motion to dismiss the CAC on August 13, 2010.

The Company does not believe that these lawsuits have merit and intends to defend itself vigorously.

Stockholder Derivative Cases

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

Other

In addition, from time to time, we are named as a party to various lawsuits, claims and other legal and regulatory proceedings that arise in the ordinary course of our business. These actions typically seek, among other things, compensation for alleged personal injury, breach of contract, property damage, punitive damages, civil penalties or other losses, or injunctive or declaratory relief. With respect to such lawsuits, claims and proceedings, 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 onForm 10-K for the year ended December 31, 2009 filed with the SEC on March 8, 2010.


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 2010.

In the second quarter of 2010, our parent, Ormat Industries Ltd., made the following open-market purchases of our common stock:


	Affiliated Purchaser Purchases of Equity Securities(1)
							(d) Maximum Number (or
					(c) Total Number of		Approximate Dollar
					Shares (or Units)		Value) of Shares (or
					Purchased as Part		Units) that May Yet Be
	(a) Total Number of		(b) Average Price		of Publicly		Purchased Under the
	Shares Purchased		Paid per Share		Announced Plans or		Plans or
Period	(2)		(or Unit)		Programs		Programs(3)

Month #1 April 1 — April 30, 2010		—	$	—		—	$	—
Month #2 May 1 — May 30, 2010		907,680	$	28.4523		907,680	$	24,174,416
Month #3 June 1 — June 30, 2010		848,900	$	28.4155		848,900	$	—

Total		1,756,580	$	28.4344		1,756,580	$	—


(1)		The information in this table is based on information provided to the Company by Ormat Industries Ltd. It is reported because our Parent may be an Affiliated Purchaser within the meaning ofRule 10-b(18)(3)(ii) under the Exchange Act by virtue of our Parent and our Company having certain common officers and directors who control purchases of securities by us and our Parent.

(2)		All of the purchases were made in open-market transactions.

(3)		The plan was announced on May 10, 2010. The plan was for the purchase of common stock valued at up to $50 million. As of June 30, 2010, Ormat Industries Ltd. purchased the maximum dollar value of shares authorized under the plan.


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 5.	*OTHER INFORMATION*

None.


ITEM 6.	*EXHIBITS*


Exhibit No.			Document

	3	.1	Second Amended and Restated Certificate of Incorporation, incorporated by reference to Exhibit 3.1 to Ormat Technologies, Inc. Registration Statement onForm S-1 (FileNo. 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 onForm 8-K to the Securities and Exchange Commission on February 26, 2009.


Exhibit No.			Document

	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 onForm 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 onForm S-1 (FileNo. 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 onForm S-3 (FileNo. 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 onForm S-3 (FileNo. 333-131064) to the Securities and Exchange Commission on January 26, 2006
	31	.1	Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, filed herewith.
	31	.2	Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, filed herewith.
	32	.1	Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, filed herewith.
	32	.2	Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, filed herewith.

SIGNATURES

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

ORMAT TECHNOLOGIES, INC.


	By:	/s/ Joseph Tenne

Name: Joseph Tenne


	Title:	Chief Financial Officer

Date: August 6, 2010

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 onForm S-1 (FileNo. 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 onForm 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 onForm 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 onForm S-1 (FileNo. 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 onForm S-3 (FileNo. 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 onForm S-3 (FileNo. 333-131064) to the Securities and Exchange Commission on January 26, 2006.
	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.

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