ORMAT TECHNOLOGIES, INC. (Form: 10-Q, Received: 08/09/2007 08:23:58)

Risk-free interest rates

Expected term (in years)

Dividend yield

Expected volatility

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SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


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

For the quarterly period ended June 30, 2007


	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, Suite 300, Reno, Nevada 89511-1136

(Address of principal executive offices)

Registrant’s telephone number, including area code: (775) 356-9029

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

Yes No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of ‘‘accelerated filer and large accelerated filer’’ in Rule 12b-2 of the Exchange Act.

Large accelerated filer Accelerated filer Non-accelerated filer

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes No

As of the date of this filing, the number of outstanding shares of common stock of Ormat Technologies, Inc. is 38,125,131, par value $0.001 per share.

ORMAT TECHNOLOGIES, INC

FORM 10-Q FOR THE QUARTER ENDED JUNE 30, 2007


PART I — UNAUDITED FINANCIAL INFORMATION		4
ITEM 1.	CONDENSED CONSOLIDATED FINANCIAL STATEMENTS	4
ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	19
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	45
ITEM 4.	CONTROLS AND PROCEDURES	45
PART II — OTHER INFORMATION		46
ITEM 1.	LEGAL PROCEEDINGS	46
ITEM 1A.	RISK FACTORS	46
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	47
ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	47
ITEM 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS	47
ITEM 5.	OTHER INFORMATION	47
ITEM 6.	EXHIBITS	47
SIGNATURES		49

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. The ‘‘OFC Senior Secured Notes’’ refers to the 8 ¼ % Senior Secured Notes due 2020 that were issued in February 2004 by our subsidiary, Ormat Funding Corp. The ‘‘OrCal Senior Secured Notes’’ refers to the 6.21% Senior Secured Notes due 2020 that were issued in December 2005 by our subsidiary, OrCal Geothermal Inc.

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PART I — UNAUDITED FINANCIAL INFORMATION

ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)


	June 30, 2007			December 31, 2006
	(in thousands)
Assets
Current assets:
Cash and cash equivalents		$	24,904		$	20,254
Marketable securities			48,098			96,486
Restricted cash, cash equivalents and marketable securities			74,166			56,425
Receivables:
Trade			52,552			36,463
Related entity			121			879
Other			3,404			5,277
Due from Parent			—			1,459
Inventories, net			9,671			7,403
Costs and estimated earnings in excess of billings on uncompleted contracts			8,018			11,216
Deferred income taxes			2,129			1,819
Prepaid expenses and other			5,768			4,911
Total current assets			228,831			242,592
Unconsolidated investments			35,093			37,207
Deposits and other			15,195			15,081
Deferred income taxes			5,658			6,172
Property, plant and equipment, net			742,009			624,089
Construction-in-process			106,369			169,075
Deferred financing and lease costs, net			14,792			15,800
Intangible assets, net			49,656			50,086
Total assets		$	1,197,603		$	1,160,102
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable and accrued expenses		$	77,532		$	70,445
Billings in excess of costs and estimated earnings on uncompleted contracts			7,960			5,803
Current portion of long-term debt:
Limited and non-recourse			8,787			8,482
Full recourse			1,000			1,000
Senior secured notes (non-recourse)			36,853			40,054
Due to Parent, including current portion of notes payable to Parent			82,809			82,379
Total current liabilities			214,941			208,163
Long-term debt, net of current portion:
Limited and non-recourse			17,686			22,157
Full recourse			—			1,000
Senior secured notes (non-recourse)			287,792			299,316
Notes payable to Parent, net of current portion			41,241			57,841
Deferred lease income			77,540			78,883
Deferred income taxes			15,941			21,674
Liability for unrecognized tax benefits			3,642			—
Liabilities for severance pay			13,480			13,378
Asset retirement obligation			15,734			16,832
Total liabilities			687,997			719,244
Minority interest			69,095			64
Contingencies (Note 9)
Stockholders’ equity:
Common stock, par value $0.001 per share; 200,000,000 shares authorized; 38,125,131 and 38,101,888 shares issued and outstanding, respectively			38			38
Additional paid-in capital			355,526			353,399
Retained earnings			82,851			85,053
Accumulated other comprehensive income			2,096			2,304
Total stockholders’ equity			440,511			440,794
Total liabilities and stockholders’ equity		$	1,197,603		$	1,160,102

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

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ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND
COMPREHENSIVE INCOME

(Unaudited)


	Three Months Ended June 30,								Six Months Ended June 30,
	2007				2006				2007				2006
	(in thousands, except per share data)								(in thousands, except per share data)
Revenues:
Electricity:
Energy and capacity		$	24,490			$	28,857			$	44,400			$	54,022
Lease portion of energy and capacity			30,198				19,238				53,275				37,135
Lease income			672				672				1,343				1,343
Total electricity			55,360				48,767				99,018				92,500
Products:
Related party			—				—				—				3,503
Other			28,692				15,319				46,781				28,404
Total products			28,692				15,319				46,781				31,907
Total revenues			84,052				64,086				145,799				124,407
Cost of revenues:
Electricity:
Energy and capacity			20,421				20,368				43,785				37,542
Lease portion of energy and capacity			13,597				9,258				28,644				17,640
Lease expense			1,310				1,310				2,621				2,621
Total electricity			35,328				30,936				75,050				57,803
Products			24,214				9,580				40,138				20,112
Total cost of revenues			59,542				40,516				115,188				77,915
Gross margin			24,510				23,570				30,611				46,492
Operating expenses:
Research and development expenses			1,061				890				1,765				1,663
Selling and marketing expenses			3,822				2,826				5,808				5,521
General and administrative expenses			5,162				4,404				10,909				9,088
Operating income			14,465				15,450				12,129				30,220
Other income (expense):
Interest income			1,621				2,347				3,036				3,462
Interest expense:
Parent			(1,514	)			(2,135	)			(3,147	)			(4,361	)
Other			(6,430	)			(7,645	)			(14,045	)			(14,875	)
Less – amount capitalized			874				2,039				2,340				4,042
Foreign currency translation and transaction gains (losses)			41				(69	)			(675	)			(77	)
Other non-operating income (expense)			(4	)			204				348				307
Income (loss) before income taxes and equity in income of investees			9,053				10,191				(14	)			18,718
Income tax benefit (provision)			(1,992	)			(2,156	)			3				(4,070	)
Minority interest			305				(571	)			305				(571	)
Equity in income of investees			1,181				931				2,412				2,210
Net income			8,547				8,395				2,706				16,287
Other comprehensive loss, net of related taxes:
Amortization of unrealized gains in respect of derivative instruments designated for cash flow hedge			(81	)			(91	)			(164	)			(181	)
Change in unrealized gains or losses on marketable securities available-for-sale			(78	)			(128	)			(44	)			(10	)
Comprehensive income		$	8,388			$	8,176			$	2,498			$	16,096

Earnings per share – basic and diluted		$	0.22			$	0.24			$	0.07			$	0.49
Weighted average number of shares used in computation of earnings per share:
Basic			38,123				35,105				38,116				33,343
Diluted			38,255				35,254				38,248				33,475

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

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ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(Unaudited)


	Common Stock					Additional Paid-in Capital			Retained Earnings				Accumulated Other Comprehensive Income
	Shares		Amount			Additional Paid-in Capital			Retained Earnings				Accumulated Other Comprehensive Income				Total
	(in thousands, except per share data)
Balance at December 31, 2006		38,102		$	38		$	353,399		$	85,053			$	2,304			$	440,794
Stock-based compensation		—			—			1,605			—				—				1,605
Cash dividend declared, $0.12 per share		—			—			—			(4,580	)			—				(4,580	)
Exercise of options by employees		23			—			369			—				—				369
Tax benefit on exercise of options by employees		—			—			153			—				—				153
Cumulative adjustment from adoption of FIN No. 48		—			—			—			(328	)			—				(328	)
Net income		—			—			—			2,706				—				2,706
Other comprehensive income, net of related taxes:
Amortization of unrealized gains in respect of derivative instruments designated for cash flow hedge (net of related tax of $104,000)		—			—			—			—				(164	)			(164	)
Change in unrealized gains or losses on marketable securities available-for-sale (net of related tax of $27,000)		—			—			—			—				(44	)			(44	)
Balance at June 30, 2007		38,125		$	38		$	355,526		$	82,851			$	2,096			$	440,511

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

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ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)


	Six Months Ended June 30,
	2007				2006
	(in thousands)

Cash flows from operating activities:
Net income		$	2,706			$	16,287
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization			24,538				20,763
Accretion of asset retirement obligation			629				462
Share-based compensation			1,605				641
Amortization of deferred lease income			(1,343	)			(1,343	)
Minority interest			(305	)			571
Equity in income of investees			(2,412	)			(2,210	)
Distributions from unconsolidated investments			4,081				2,039
Unrealized loss (gain) in respect of derivative instruments, net			67				(301	)
Loss (gain) on severance pay fund asset			29				(380	)
Deferred income tax benefit			(2,614	)			(556	)
Liability for unrecognized tax benefits			168				—
Changes in operating assets and liabilities, net of acquisitions:
Receivables			(14,216	)			(2,077	)
Costs and estimated earnings in excess of billings on uncompleted contracts			3,198				6,390
Inventories, net			(2,268	)			107
Prepaid expenses and other			(857	)			(2,059	)
Deposits and other			(399	)			50
Accounts payable and accrued expenses			(2,831	)			(5,682	)
Due from/to related entities, net			758				(1,372	)
Billings in excess of costs and estimated earnings on uncompleted contracts			2,157				(2,830	)
Other liabilities			—				(20	)
Liabilities for severance pay			102				1,259
Due from/to Parent			1,889				(812	)
Net cash provided by operating activities			14,682				28,927
Cash flows from investing activities:
Distributions from unconsolidated investments			800				2,000
Marketable securities, net			48,502				(40,251	)
Net change in restricted cash, cash equivalents and marketable securities			(17,933	)			4,010
Capital expenditures			(69,353	)			(80,015	)
Cash paid for acquisitions, net of cash received			—				(15,362	)
Intangible asset acquired			(1,150	)			—
Decrease (increase) in severance pay fund asset, net			189				(266	)
Repayment from unconsolidated investment			63				62
Net cash used in investing activities			(38,882	)			(129,822	)
Cash flows from financing activities:
Due to Parent, net			(16,600	)			(16,600	)
Proceeds from exercise of options by employees			369				—
Repayments of short-term and long-term debt			(19,891	)			(16,708	)
Deferred debt issuance costs			—				(720	)
Proceeds from the sale of limited liability company interest in OPC LLC, net of transaction costs			69,552				—
Proceeds from follow-on public offering, net of issuance costs			—				135,053
Cash dividends paid			(4,580	)			(2,370	)
Net cash provided by financing activities			28,850				98,655
Net increase (decrease) in cash and cash equivalents			4,650				(2,240	)
Cash and cash equivalents at beginning of period			20,254				26,976
Cash and cash equivalents at end of period		$	24,904			$	24,736
Supplemental non-cash investing and financing activities:
Increase (decrease) in accounts payable related to purchases of property, plant and equipment		$	9,702			$	(1,352	)
Accrued liabilities related to financing activities		$	216			$	—
Increase (decrease) in asset retirement cost and asset retirement obligation		$	(1,727	)		$	655

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

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ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

NOTE 1 — BASIS OF PRESENTATION

These unaudited condensed consolidated interim financial statements of Ormat Technologies, Inc. and its subsidiaries (the ‘‘Company’’) have been prepared in accordance with accounting principles generally accepted in the United States of America (‘‘U.S. GAAP’’) and pursuant to the rules and regulations of the Securities and Exchange Commission (‘‘SEC’’) for interim financial statements. Accordingly, they do not contain all information and notes required by U.S. GAAP for annual financial statements. In the opinion of management, the unaudited condensed consolidated interim financial statements reflect all adjustments, which include normal recurring adjustments, necessary for a fair statement of the Company’s consolidated financial position as of June 30, 2007, the consolidated results of operations for the three and six-month periods ended June 30, 2007 and 2006, and the consolidated cash flows for the six-month periods ended June 30, 2007 and 2006.

The financial data and other information disclosed in the notes to the condensed consolidated interim financial statements related to these periods are unaudited. The results for the three and six-month periods ended June 30, 2007 are not necessarily indicative of the results to be expected for the year ending December 31, 2007.

These condensed consolidated interim financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in the Company’s annual report on Form 10-K for the year ended December 31, 2006. The condensed consolidated balance sheet data as of December 31, 2006 was derived from the audited consolidated financial statements for the year ended December 31, 2006, 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’s presentation.

Change in estimated useful life of certain power plants

During the second quarter of 2007, the Company revised the estimated useful life of certain of its power plants from 20 or 25 years to 30 years to reflect the expected period these plants will be utilized. The change in estimated useful life has been accounted for on a prospective basis effective April 1, 2007. The impact of this change in estimate was an increase in net income and earnings per share of $257,000 and $0.01, respectively.

Concentration of credit risk

Financial instruments that potentially subject the Company to a concentration of credit risk consist principally of temporary cash investments 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, 2007 and December 31, 2006, the Company had deposits totaling $14,277,000 and $13,068,000, respectively, in six U.S. financial institutions that were federally insured up to $100,000 per account. At June 30, 2007 and December 31, 2006, the Company’s deposits in foreign countries amounted to approximately $17,686,000 and $15,321,000, respectively.

At June 30, 2007 and December 31, 2006, accounts receivable related to operations in foreign countries amounted to approximately $17,937,000 and $16,957,000, respectively. At June 30, 2007 and December 31, 2006, accounts receivable from the Company’s major customers that have generated 10% or more of its revenues amounted to approximately 55% and 49% of the Company’s accounts receivable, respectively.

Southern California Edison Company (‘‘SCE’’) accounted for 29.4% and 31.1% of the Company’s total revenues for the three months ended June 30, 2007 and 2006, respectively, and 27.4% and 29.1%

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ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

of the Company’s total revenues for the six months ended June 30, 2007 and 2006, respectively. SCE is also the power purchaser and revenue source for the Company’s Mammoth project, which is accounted for separately under the equity method.

Sierra Pacific Power Company accounted for 9.0% and 12.5% of the Company’s total revenues for the three months ended June 30, 2007 and 2006, respectively, and 9.5% and 14.3% of the Company’s total revenues for the six months ended June 30, 2007 and 2006, respectively.

Hawaii Electric Light Company accounted for 12.0% and 16.2% of the Company’s total revenues for the three months ended June 30, 2007 and 2006, respectively, and 13.5% and 17.1% of the Company’s total revenues for the six months ended June 30, 2007 and 2006, 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 three and six-month periods ended June 30, 2007

SFAS No. 155 – Accounting for Certain Hybrid Financial Instruments

Effective January 1, 2007, the Company adopted Statement of Financial Accounting Standards (‘‘SFAS’’) No. 155, Accounting for Certain Hybrid Financial Instruments . SFAS No. 155 replaces certain provisions of SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities and SFAS No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities . SFAS No. 155 permits fair value measurement for any hybrid financial instrument that contains an embedded derivative that otherwise would require bifurcation. It clarifies which interest-only strips and principal-only strips are not subject to the requirements of SFAS No. 133. SFAS No. 155 also establishes a requirement to evaluate interests in securitized financial assets to identify interests that are freestanding derivatives or that are hybrid financial instruments that contain an embedded derivative requiring bifurcation. It also clarifies that concentrations of credit risk in the form of subordination are not embedded derivatives and amends SFAS No. 140 to eliminate the prohibition on a qualifying special-purpose entity from holding a derivative financial instrument that pertains to a beneficial interest other than another derivative financial instrument. SFAS No. 155 is effective for all financial instruments acquired or issued after January 1, 2007. The adoption by the Company of SFAS No. 155, effective January 1, 2007, did not have any impact on its results of operations or financial position.

FIN No. 48 – Accounting for Uncertainty in Income Taxes, an Interpretation of FASB Statement No. 109

Effective January 1, 2007, the Company adopted Financial Accounting Standards Board (‘‘FASB’’) Interpretation (‘‘FIN’’) No. 48, Accounting for Uncertainty in Income Taxes, an Interpretation of FASB Statement No. 109 . FIN No. 48 addresses the determination of whether tax benefits claimed or expected to be claimed on a tax return should be recorded in the financial statements. Under FIN No. 48, the Company may recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position should be measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement. FIN No. 48 also provides guidance on derecognition, classification and disclosure of tax positions, as well as the accounting for interest and penalties. As a result of the implementation of FIN No. 48, on

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ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

January 1, 2007, the Company recognized as a cumulative effect of change in accounting principle, a $328,000 increase in the liability for unrecognized tax benefits and a corresponding decrease in beginning retained earnings. See Note 11 for additional information about the Company’s unrecognized tax benefits.

EITF Issue No. 06-3 – How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (That is, Gross versus Net Presentation)

Effective January 1, 2007, the Company adopted EITF Issue No. 06-3, How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (That is, Gross versus Net Presentation ). The requirements of EITF Issue No. 06-3 apply to any tax assessed by a governmental authority that is imposed concurrently on a specific revenue-producing transaction between a seller and a customer. Examples of taxes subject to Issue No. 06-3 include sales, use, value added, and some excise taxes. EITF Issue No. 06-3 excludes taxes that are assessed on gross receipts or that are imposed during the process of obtaining inventory. Companies will be required to disclose their accounting policy regarding the presentation of taxes subject to EITF Issue No. 06-3, and the amounts of such taxes that are included in income on a gross basis, if those amounts are significant. The adoption by the Company of EITF Issue No. 06-3, effective January 1, 2007, did not have any impact on its financial statements.

New accounting pronouncements effective in future periods

SFAS No. 157 – Fair Value Measurements

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements . SFAS No. 157 clarifies the principle that fair value should be based on the assumptions market participants would use when pricing an asset or liability and establishes a fair value hierarchy that prioritizes the information used to develop those assumptions. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007 (January 1, 2008 for the Company) and interim periods within those fiscal years, with early adoption permitted. The Company is currently assessing the impact of SFAS No. 157, and has not yet determined the impact that its adoption will have on its results of operations or financial position.

SFAS No. 159 – The Fair Value Option for Financial Assets and Financial Liabilities

In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities . SFAS No.159 permits entities to choose to measure certain financial assets and liabilities and other eligible items at fair value, which are not otherwise currently required to be measured at fair value. Under SFAS No. 159, the decision to measure items at fair value is made at specified election dates on an irrevocable instrument-by-instrument basis. Entities electing the fair value option would be required to recognize changes in fair value in earnings and to expense upfront cost and fees associated with the item for which the fair value option is elected. Entities electing the fair value option are required to distinguish on the face of the statement of financial position, the fair value of assets and liabilities for which the fair value option has been elected and similar assets and liabilities measured using another measurement attribute. If elected, SFAS No. 159 is effective as of the beginning of the first fiscal year that begins after November 15, 2007 (January 1, 2008 for the Company) with earlier adoption permitted provided that the entity also early adopts all of the requirements of SFAS No. 159. The Company is currently evaluating whether to elect the option provided for in this standard.

NOTE 3 — EARNINGS PER SHARE

Basic earnings per share is computed by dividing net income available to common stockholders by the weighted average number of shares of common stock outstanding for the period. The Company

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ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

does not have any equity instruments that are dilutive, except for employee stock options which were granted in 2004, 2005, 2006 and 2007 and whose effect on earnings per share is immaterial for the three and six-month periods ended June 30, 2007 and 2006. The stock options granted to employees of the Company in Ormat Industries Ltd. (the ‘‘Parent’’) stock are not dilutive to the Company’s earnings per share in any period.

NOTE 4 — INVENTORIES

Inventories consist of the following:


	June 30, 2007			December 31, 2006
	(dollars in thousands)
Raw materials and purchased parts for assembly		$	6,160		$	3,397
Self-manufactured assembly parts and finished products			3,511			4,006
Total		$	9,671		$	7,403

NOTE 5 — UNCONSOLIDATED INVESTMENTS

Unconsolidated investments in power plant projects consist of the following:


	June 30, 2007			December 31, 2006
	(dollars in thousands)
Mammoth		$	30,950		$	31,913
OLCL			4,143			5,294
Total		$	35,093		$	37,207

From time to time, the unconsolidated power plants make distributions to their owners. Such distributions are deducted from the investments in such power plants.

The Mammoth Project

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

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ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

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


	June 30, 2007			December 31, 2006
	(dollars in thousands)
Condensed balance sheets:
Current assets		$	3,655		$	3,425
Non-current assets			77,274			79,942
Current liabilities			527			667
Non-current liabilities			3,225			3,130
Partners’ Capital			77,177			79,570


	Six Months Ended June 30,
	2007				2006
	(dollars in thousands)
Condensed statements of operations:
Revenues		$	7,793			$	6,920
Gross margin			1,757				(14	)
Net income (loss)			1,606				(125	)
Company’s equity in income (loss) of Mammoth:
50% of Mammoth net income		$	803			$	(63	)
Plus amortization of basis difference			297				297
			1,100				234
Less income taxes			(418	)			(89	)
Total		$	682			$	145

The Leyte Project

The Company holds an 80% interest in Ormat Leyte Co. Ltd. (‘‘OLCL’’). OLCL is a limited partnership established for the purpose of developing, financing, operating, and maintaining a geothermal power plant in Leyte Provina, the Philippines. Upon the adoption of FIN No. 46R, Consolidation of Variable Interest Entities (revised December 2003) – an interpretation of ARB No. 51 , on March 31, 2004, the Company concluded that OLCL should not be consolidated. As a result of such conclusion, the Company’s 80% ownership interest in OLCL is accounted for under the equity method of accounting.

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


	June 30, 2007			December 31, 2006
	(dollars in thousands)
Condensed balance sheets:
Current assets		$	6,189		$	7,548
Non-current assets			1,430			4,632
Current liabilities			2,325			4,782
Stockholders’ equity			5,294			7,398

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ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


	Six Months Ended June 30,
	2007			2006
	(dollars in thousands)
Condensed statements of operations:
Revenues		$	6,957		$	6,854
Gross margin			3,398			3,431
Net income			1,495			1,842
Company’s equity in income of OLCL:
80% of OLCL net income		$	1,196		$	1,474
Plus amortization of deferred revenue on intercompany profit ($0.3 million unamortized balance at June 30, 2007)			534			866
Total		$	1,730		$	2,340

In 1996, OLCL entered into a Build, Operate, and Transfer (‘‘BOT’’) agreement with PNOC-Energy Development Corporation (‘‘PNOC’’) in connection with the four geothermal power generation plants, with a total capacity of 49MW, located in Leyte, Philippines. During 1997, the power plants started commercial operations and began selling power to PNOC under a ten year power purchase agreement (tolling arrangement). OLCL owns the plants for a ten-year period ending September 2007, at which time they will be transferred to PNOC for no further consideration. The Company does not anticipate any material financial loss as a result of such transfer, although going forward this will reduce the Company’s foreign generation capacity by 49 MW with a commensurate impact on equity in income of investees and net income.

NOTE 6 — OPC TAX MONETIZATION TRANSACTION

On June 7, 2007, a wholly owned subsidiary of the Company, Ormat Nevada Inc. (‘‘Ormat Nevada’’), concluded a transaction to monetize production tax credits and other favorable tax attributes, such as accelerated depreciation, generated from certain of its geothermal power projects. Pursuant to the transaction, affiliates of Morgan Stanley & Co. Incorporated and Lehman Brothers Inc. became institutional equity investors in a newly formed subsidiary of Ormat Nevada. The projects involved in the transaction include Desert Peak 2, Steamboat Hills, and Galena 2, all located in Nevada.

Under the transaction structure, Ormat Nevada transferred the aforementioned geothermal power projects to the newly formed subsidiary, OPC LLC (‘‘OPC’’), and sold limited liability company interests in OPC to the institutional equity investors for $71.8 million. Ormat Nevada will continue to operate and maintain the projects and will receive initially all of the distributable cash flow generated by the projects until it recovers the capital that it has invested in the projects, while the institutional equity investors will receive substantially all of the production tax credits and the taxable income or loss (together, the ‘‘Economic Benefits’’), and the distributable cash flow after Ormat Nevada has recovered its capital. The institutional equity investor’s return is limited by the term of the transaction. Once the investors reach a target after-tax yield on their investment in OPC (the ‘‘Flip Date’’), Ormat Nevada will receive 95% of both distributable cash and taxable income and the investors will receive 5% of both distributable cash and taxable income on a going forward basis. Following the Flip Date, Ormat Nevada also has the option to buy out the investors’ remaining interest in OPC at the then-current fair market value or, if greater, the investors’ capital account balances in OPC. Should Ormat Nevada exercise this purchase option, it would thereupon revert to being sole owner of the projects. The transaction provides for a second closing whereby Ormat Nevada would contribute another geothermal plant currently under construction and receive an additional amount of $46.6 million.

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ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Under the transaction, Ormat Nevada retains the controlling voting interest in the subsidiary and therefore continues to consolidate OPC. This transaction has been accounted for as a financing with the payments received for the equity interest recorded in minority interest on the Consolidated Balance Sheets. As the Economic Benefits flow to the institutional equity investors, they are recognized by the Company in minority interest on the Consolidated Statements of Operations and Comprehensive Income. Interest expense, representing the institutional equity investors’ targeted yield on the balance of the amount paid by the investors, is charged to minority interest.

Transaction costs amounting to $2.5 million as of June 30, 2007 have been reflected as a component of minority interest on the Consolidated Balance Sheets and will be amortized to minority interest in the Consolidated Statements of Operations and Comprehensive Income through the Flip Date.

NOTE 7 — STOCK-BASED COMPENSATION

On February 27, 2007, the Company granted to a non-employee director non-qualified stock options, under the Company’s 2004 Incentive Compensation Plan (‘‘2004 Incentive Plan’’), to purchase 7,500 shares of common stock at an exercise price of $38.85 per share, which amount represented the fair market value of the Company’s common stock on the day following the date of grant, since on the date of grant the Company released its results of operation for the fourth quarter of 2006. 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 $12.61 per share.

On March 29, 2007, the Company granted to employees incentive stock options, under the Company’s 2004 Incentive Plan, to purchase 397,150 shares of common stock at an exercise price of $42.08 per share, which amount represented the fair market value of the Company’s common stock on the date of grant. Such options will expire seven years from the date of grant and will cliff vest and are exercisable from the grant date as follows: 25% after 24 months, 25% after 36 months, and the remaining 50% after 48 months. The fair value of each option on the date of grant was $15.77 per share.

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:

On May 8, 2007 the Company’s shareholders approved an amendment to the Company’s 2004 Incentive Plan to increase the number of shares of common stock authorized for issuance pursuant to the plan by 2,500,000. Following this increase, the number of shares available for future grant is 2,825,803.

NOTE 8 — BUSINESS SEGMENTS

The Company has two reporting segments: electricity and products segments. Such 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 pursuant to power purchase agreements. The products 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.

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ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

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


	Electricity			Products				Consolidated
	(dollars in thousands)
Three Months Ended June 30, 2007:
Net revenues from external customers		$	55,360		$	28,692			$	84,052
Intersegment revenues			—			14,492				14,492
Operating income			14,147			318				14,465
Segment assets at period end*			1,131,517			66,086				1,197,603
* Including unconsolidated investments			35,093			—				35,093
Three Months Ended June 30, 2006:
Net revenues from external customers		$	48,767		$	15,319			$	64,086
Intersegment revenues			—			19,727				19,727
Operating income			12,397			3,053				15,450
Segment assets at period end*			1,001,279			52,025				1,053,304
* Including unconsolidated investments			38,189			—				38,189
Six Months Ended June 30, 2007:
Net revenues from external customers		$	99,018		$	46,781			$	145,799
Intersegment revenues			—			18,477				18,477
Operating income (loss)			12,615			(486	)			12,129
Segment assets at period end*			1,131,517			66,086				1,197,603
* Including unconsolidated investments			35,093			—				35,093
Six Months Ended June 30, 2006:
Net revenues from external customers		$	92,500		$	31,907			$	124,407
Intersegment revenues			—			35,752				35,752
Operating income			23,709			6,511				30,220
Segment assets at period end*			1,001,279			52,025				1,053,304
* Including unconsolidated investments			38,189			—				38,189

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


	Three Months Ended June 30,								Six Months Ended June 30,
	2007				2006				2007				2006
	(dollars in thousands)								(dollars in thousands)
Operating income		$	14,465			$	15,450			$	12,129			$	30,220
Interest expenses, net			(5,449	)			(5,394	)			(11,816	)			(11,732	)
Non-operating income (loss) and other, net			37				135				(327	)			230
Total consolidated income (loss) before income taxes and equity in income of investees		$	9,053			$	10,191			$	(14	)		$	18,718

NOTE 9 — CONTINGENCIES

One of the Company’s U.S. Subsidiaries (the ‘‘subsidiary’’) is a party to a third-party complaint originally filed on November 15, 2005 by Lacy M. Henry and Judy B. Henry (the ‘‘Henrys’’) in a bankruptcy proceeding in the United States Bankruptcy Court for the Eastern District of North Carolina. The Henrys are debtors in a Chapter 11 bankruptcy filed in the Bankruptcy Court. The

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ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Henrys were the sole shareholders of MPS Generation, Inc. (‘‘MPSG’’). The subsidiary entered into a supply contract with MPSG dated as of December 29, 2003, under which the subsidiary was retained as a subcontractor to produce four waste heat energy converters for a project for which MPSG had entered into a contract with Basin Electric Power Cooperative (‘‘Basin’’). Basin filed a lawsuit on February 24, 2005 against, among others, MPSG and the Henrys in the United States District Court for the District of North Dakota, alleging various causes of action including breach of contract, actual and constructive fraud, and conversion, and demanding the piercing of MPSG’s corporate veil to establish the personal liability of the Henrys for MPSG’s debts. On September 15, 2005, Basin filed a complaint commencing the bankruptcy adversary proceeding, seeking a determination that the claims which Basin alleged against the Henrys in the North Dakota lawsuit were not dischargeable. On November 15, 2005, the Henrys answered Basin’s complaint in the bankruptcy proceeding and also filed a third-party complaint against the subsidiary, alleging that to the extent the Henrys are found personally liable to Basin for MPSG’s debts, the Henrys have claims against the subsidiary for breach of contract/breach of warranty, tortious interference with contract, unfair or deceptive trade practices and fraud. The Henrys alleged damages in excess of $100 million. On December 15, 2005, the subsidiary filed an answer denying the Henrys’ claims and asserting counterclaims against the Henrys. The subsidiary filed a motion to dismiss the Henrys’ claims on January 31, 2006. On March 21, 2006, Basin filed an Amended Complaint in the bankruptcy proceeding, consolidating the causes of action it brought in the North Dakota lawsuit. In their answer to Basin’s Amended Complaint, the Henrys raised the same third party claims against the subsidiary. On May 11, 2006, the Bankruptcy Court entered an order denying the subsidiary’s motion to dismiss the Henrys’ claims against it, but staying the Henrys’ litigation against the subsidiary pending the resolution of Basin’s alter ego claims against the Henrys. In its answer to Basin’s Amended Complaint, MPSG asserted third party claims against the subsidiary similar to those claims raised by the Henrys. A trial on all issues raised in the bankruptcy proceeding is scheduled to begin in September 2007 in the Bankruptcy Court following unsuccessful mediation attempts. The Company believes that the subsidiary has no liability to the Henrys or to MPSG and intends to defend vigorously against the Henrys’ and MPSG’s claims in the bankruptcy proceeding. Therefore, no provision is included in the financial statements in respect of the claim.

In connection with the power purchase agreements for the Ormesa project, SCE had expressed its intent not to pay the contract rate for power supplied by the GEM 2 and GEM 3 plants to the Ormesa project. SCE contended that California ISO real-time prices should apply, while management believed that SP-15 prices quoted by NYMEX should apply. Ormesa LLC, the Company’s wholly-owned subsidiary, and SCE signed an Interim Agreement in 2005 whereby SCE agreed to procure GEM 2 and GEM 3 power at the then-current energy rate under the July 18, 1984 Ormesa power purchase agreement of 5.37 cents per kWh until May 1, 2007. On April 23, 2007, the parties finalized an agreement with terms that are similar to the arrangement agreed to in the Interim Agreement, whereby 6.5 MW of power from GEM 2 and GEM 3 will be sold to SCE at the current energy rate of the July 18, 1984 Ormesa power purchase agreement. For the period commencing May 1, 2007, the energy rate is 6.15 cents per kWh. The parties simultaneously entered into other agreements and agreed to release each other from any and all claims relating to the Ormesa project. Pursuant to these agreements, Ormesa LLC paid SCE an immaterial amount to consolidate the June 13, 1984 and July 18, 1984 power purchase agreements. Combining these agreements will reduce scheduling fees over the term of the agreement and provide other operational benefits.

Steamboat Geothermal LLC (‘‘SG’’), a wholly owned subsidiary, was party to litigation related to a dispute over amounts owed to the plaintiffs under certain operating agreements. On December 31, 2005 and January 9, 2006, SG entered into a sales, settlement and release agreement and an assignment agreement, respectively, with an assignee of the right of one of the plaintiffs to 37% of net operating revenues, whereby SG was assigned 37% of the net operating revenues of Steamboat 1 in

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ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

partial settlement of the dispute with the plaintiff. On April 11, 2007, SG entered into a settlement agreement with the plaintiff, Geothermal Development Associates (‘‘GDA’’), to settle the remaining claims. As a result of the settlement, the Company paid the total settlement amount to GDA in April 2007 and recorded additional expenses of $0.8 million in the six-month period ended June 30, 2007. The settlement agreement provides for the mutual release of any and all claims, demands and causes of action by and between the parties and stipulates that the settlement should not be construed as an admission of liability or fault by any party.

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

NOTE 10 — CASH DIVIDEND

On February 27, 2007, the Company’s Board of Directors declared, approved and authorized payment of a quarterly dividend of $2.7 million ($0.07 per share) to all holders of the Company’s issued and outstanding shares of common stock on March 21, 2007. Such dividend was paid on March 29, 2007.

On May 8, 2007, the Company’s Board of Directors declared, approved and authorized payment of a quarterly dividend of $1.9 million ($0.05 per share) to all holders of the Company’s issued and outstanding shares of common stock on May 22, 2007. Such dividend was paid on May 29, 2007.

NOTE 11 — INCOME TAXES

The Company’s effective tax rate for the three and six months ended June 30, 2007 was 22.0% and 21.4%, respectively, which differs from the federal statutory rate of 35% primarily due to: (i) the benefit of production tax credits for new power plants placed in service since 2005; and (ii) a tax credit related to the Company’s subsidiaries in Guatemala.

As disclosed in Note 2, the Company adopted the provisions of FIN No. 48 on January 1, 2007. As a result of the adoption of FIN No. 48, the Company recognized as a cumulative effect of change in accounting principle, a $328,000 increase in the liability for unrecognized tax benefits and a corresponding decrease in beginning retained earnings. This amount consists of interest and penalties related to uncertain tax positions. In addition, on January 1, 2007, the Company reclassified its liability for uncertain tax positions in the amount of $3,146,000 from long-term deferred income tax liabilities to liability for unrecognized tax benefits. During the three and six months ended June 30, 2007, the Company increased its liability for unrecognized tax benefits by $84,000 and $168,000, respectively. The liability for unrecognized tax benefits of $3,642,000 at June 30, 2007 would impact the Company’s effective tax rate, if recognized. Interest and penalties assessed by taxing authorities on an underpayment of income taxes are included as a component of income tax provision (benefit) in the consolidated statements of operations.

The Company and its U.S. subsidiaries file consolidated income tax returns for federal and state purposes. As of June 30, 2007, the Company has not been subject to U.S. federal or state income tax examinations. The Company remains open to examination by the Internal Revenue Service for the years 2000-2006 and by local state jurisdictions for the years 2002-2006.

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ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

The Company’s foreign subsidiaries remain open to examination by the local income tax authorities in the following countries for the years indicated:


Israel			2003 – 2006
Nicaragua			2003 – 2006
Kenya			2000 – 2006
Guatemala			2002 – 2006
Philippines			2004 – 2006

Management believes that the liability for unrecognized tax benefits is adequate for all open tax years based on its assessment of many factors, including among others, past experience and interpretations of local income tax regulations. This assessment relies on estimates and assumptions and may involve a series of complex judgments about future events. As a result, it is possible that federal, state and foreign tax examinations will result in assessments in future periods. To the extent any such assessments occur, the Company will adjust its liability for unrecognized tax benefits.

NOTE 12 — SUBSEQUENT EVENT

Cash Dividend

On August 8, 2007, the Company’s Board of Directors declared, approved and authorized payment of a quarterly dividend of $1.9 million ($0.05 per share) to all holders of the Company’s issued and outstanding shares of common stock on August 22, 2007, payable on August 29, 2007.

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

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

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


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


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


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


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


	•	construction or other project delays or cancellations;


	•	financial market conditions and the results of financing efforts;


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


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


	•	contract counterparty risk;


	•	weather and other natural phenomena;


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


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

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	•	current and future litigation;


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


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


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


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


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


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


	•	the risk factors set forth in our annual report on Form 10-K for the year ended December 31, 2006 and any updates contained herein which may have a significant impact on our business, operating results or financial condition;


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


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

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

The following discussion and analysis of our financial condition and results of operations should be read together with our condensed consolidated financial statements and related notes included elsewhere in this report and the ‘‘Risk Factors’’ section of our annual report on Form 10-K for the year ended December 31, 2006 and any updates contained herein as well as those set forth in our reports and other filings made with the SEC.

General

Overview

We are a leading vertically integrated company engaged in the geothermal and recovered energy power business. We design, develop, build, own and operate clean, environmentally friendly geothermal and recovered energy-based power plants using equipment that we design and manufacture. In addition, we sell the equipment we design and manufacture for geothermal electricity generation, recovered energy-based electricity generation, and other equipment for electricity generation to third parties. Our operations consist of two business segments. The first consists of the sale of electricity from our power plants, which we refer to as the Electricity Segment. The second consists of the design, manufacturing and sale of equipment for electricity generation, the installation thereof and the provision of services relating to the engineering, procurement, construction, operation and maintenance of geothermal and recovered energy power plants, which we refer to as the Products Segment.

Our Electricity Segment currently consists of our investment in power plants producing electricity from geothermal resources and, as of recently, from recovered energy resources. Our geothermal

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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. Our Products Segment consists of the design, manufacture and sale of equipment that generates electricity, principally from geothermal and recovered energy resources, but also using other fuel sources as well. Our Products Segment also includes, to the extent requested by our customers, the installation of our equipment and other related power plant installations and the provision of services relating to the engineering, procurement, construction, operation and maintenance of geothermal and recovered energy power plants. For the six months ended June 30, 2007, our Electricity Segment represented approximately 67.9% of our total revenues, while our Products Segment represented approximately 32.1% of our total revenues during such period.

During the six months ended June 30, 2007, total Electricity Segment revenues from the sale of electricity by our consolidated power plants were $99.0 million. In addition, revenues from our 50% ownership of the Mammoth Project and from our 80% ownership of the Leyte Project for the six months ended June 30, 2007 were $9.5 million. This additional data is a Non-Generally Accepted Accounting Principles (Non-GAAP) financial measure, as defined by the SEC. There is no comparable GAAP measure. Management believes 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 investments in the Mammoth and Leyte projects are 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, 2007.

Our Electricity Segment operations are conducted in the United States and throughout the world. Since January 1, 2001, we have completed various acquisitions of geothermal power plants with an aggregate acquisition cost, net of cash received, of $526.7 million. We currently own or control, as well as operate geothermal projects in the United States, Guatemala, Kenya, Nicaragua and the Philippines, as well as recovered energy generation (REG) plants in the United States.

Our Products Segment operations are also conducted in the United States and throughout the world. During the six months ended June 30, 2007, revenues attributable to our Products Segment were $46.8 million.

We have identified recovered energy-based power generation as a significant market opportunity for us in the United States and throughout the world. We expect that recovered energy generation projects will increase our revenues in both the Electricity Segment and the Products Segment.

During the six months ended June 30, 2007, we recognized revenues in our Products Segment of approximately $17.8 million from REG compared to $9.2 million in the same period last year. During the six months ended June 30, 2007 we received purchase orders for the supply and construction of REG plants in a total amount of $20.7 million.

Our Electricity Segment is characterized by relatively predictable revenues generated by our power plants pursuant to long-term power purchase agreements, with terms which are generally up to 25 years. However, in the first quarter of 2007, we experienced several operational issues, which resulted in both reduced revenues and increased costs. The price for electricity under all but one of our power purchase agreements is effectively a fixed price. The exception is the power purchase agreement of the Puna project. It has a variable energy rate based on the local utility’s short run 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, 2007, 82.2% of the electricity revenues generated was derived from contracts with fixed energy rates, and therefore such revenues were not affected by the fluctuations in energy commodity prices.

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

Our management assesses the performance of our two segments of operation differently. In the case of our Electricity Segment, when making decisions about potential acquisitions or the

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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. By contrast, we evaluate the performance of our Products Segment based on the timely delivery of our products, performance quality of our products and costs actually incurred to complete customer orders as compared to the costs originally budgeted for such orders.

During the three and six months ended June 30, 2007 our total revenues increased by 31.2% (from $64.1 million to $84.1 million) and 17.2% (from $124.4 million to $145.8 million), respectively, over the same periods last year. Revenues from the Electricity Segment increased by 13.5% and 7.0%, respectively, and revenues from the Product Segment increased by 87.3% and 46.6%, respectively, from the same periods last year.

During the three and six months ended June 30, 2007, our U.S. power plants generated 521,380 MWh and 958,505 MWh, respectively. During the three and six months ended June 30, 2006 our U.S. power plants generated 430,012 MWh and 886,171 MWh, respectively.

Recent Developments


	•	During the first half of 2007, we have achieved several milestones related to our projects and operations:


	•	We signed geothermal lease agreements for the leases of surface, mineral and geothermal rights for approximately 7,200 acres in Nevada and California.


	•	We acquired two drilling rigs, one of which was used for the construction of the Heber South project in California and is currently being used for the drilling the Brawley production wells and the other will be used for the exploration program in Nevada.


	•	We finalized our minority interest share in the Indonesian special purpose company that will own and operate the 340 MW Sarulla project in Indonesia. Such share will be 12.75%.


	•	We declared commercial operation of the 11 MW Desert Peak 2 project.


	•	We completed the construction of additional Ormat Energy Converter (OEC) units, which increased the capacity of the Ormesa complex by 10MW, bringing its generating capacity to 57 MW.


	•	We declared commercial operation of the 10 MW Galena 2 project.


	•	We completed the construction of an additional OEC unit in the Steamboat Hills project and increased the generating capacity of the project by 4 MW.


	•	In August 2007, we entered into a $5.7 million agreement with Italcementi Group of Bergamo, Italy, for the supply of one OEC for a new REG plant. The plant is to be installed in the Martinsburg, West Virginia cement plant, belonging to Essroc, an Italcementi subsidiary in the US.. The equipment is to be supplied within 14 months from the contract date. Construction of the REG power plant is being undertaken by the Italcementi Group itself. When completed, the OEC power plant will convert unused exhaust air from the cement plant’s clinker cooler into electric power.


	•	In July 2007, we signed a 20-year power purchase agreement with Highline Electric Association, a consumer-owned cooperative serving load in Colorado and Nebraska, for the sale of electricity generated from a 4 MW Ormat REG facility to be constructed along a natural gas compression station near Denver, Colorado. The facility will convert the recovered waste heat from the exhaust of existing gas turbines into clean energy, and is expected to be commissioned in mid-2009. We will own and operate this facility through the term of the power purchase agreement. Expected revenues are approximately $1.1 million in the first full year of operation, escalating at a rate of approximately 2.7% a year in the first 10 years of the contract and at a rate of approximately 2.0% a year thereafter.

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	•	In June 2007, we signed a 20-year power purchase agreement with Southern California Edison Company (Southern California Edison) for the sale of 50MW of energy to be produced from the North Brawley project, which we are currently constructing in Imperial County, California. The power purchase agreement includes an option to increase capacity to 100 MW at our discretion and is subject to the approval of the California Public Utilities Commission. The Brawley I project is projected to come on line by the end of 2008.


	•	In May 2007, we signed a 20-year power purchase agreement with Nevada Power Company, a subsidiary of Sierra Pacific Resources, for the sale of 18-30 MW of energy to be produced from the Grass Valley geothermal power plant that we plan to build in Lander County in northern Nevada. The power purchase agreement is subject to the approval of the Nevada Public Utilities Commission. The Grass Valley project is projected to come on line in late 2010.


	•	In May 2007, we executed, pursuant to an existing Power Purchase Option Agreement with Basin Electric Power Cooperative (Basin Electric) that we signed in January 2007, four out of the five definitive 25-year power purchase agreements. Under these agreements we will sell electricity that will be produced by four new Ormat REG facilities that will have a net capacity of 5.5 MW each. These facilities will convert the recovered waste heat from the exhaust of existing gas turbines at compressor sites located on the Northern Border natural gas pipeline into clean energy. Two plants are expected to be commissioned in 2008 or early 2009, and the other two, in late 2009. We have secured the rights to the waste heat for all five new facilities.


	•	In April 2007, we received a 21 million New Zealand dollars (approximately $15.4 million) order from Geothermal Development Ltd (GDL), a company in which we own 49%, to supply and construct a geothermal power plant in Kawerau, New Zealand. Ormat will also provide the required construction loan. GDL expects to sell electricity produced by the project to Bay of Plenty Electricity of New Zealand under an existing 7-year power purchase agreement extendable an additional 5 years by mutual agreement. We have an option to acquire the remaining 51% of GDL before the completion of construction. Construction is expected to be completed in the first half of 2009.


	•	In March 2007, we entered into an $11.5 million contract with ENAGAS, S.A. of Madrid, Spain for the supply of one OEC unit for a REG plant. The REG plant is being specially designed to use the residual energy from the vaporization process of a Liquefied Natural Gas regasification terminal located in Huelva, Spain. The equipment is scheduled to be supplied and installed within 26 months from the receipt of a notice to proceed, which is expected in the next few months.


	•	In February 2007, the Nevada Public Utilities Commission approved two new 20-year power purchase agreements that two of our subsidiaries entered into on August 3, 2006 with Nevada Power Company, a subsidiary of Sierra Pacific Resources, for the sale of energy to be produced from the Carson Lake (near Fallon) and Buffalo Valley power plants, two new geothermal power plants that we plan to build in Lander and Churchill Counties in northern Nevada. The Carson Lake and Buffalo Valley projects are both projected to come on line in late 2009. These new plants are expected to increase the total output we supply to Sierra Pacific Resources by between 36 and 60 MW.


	•	In January 2007, we entered into two contracts with a combined value of $9.0 million with Enpower Green Energy Generation, Inc. for the supply of two OEC units for two REG plants to be located on the Duke Energy T South Pipeline System in British Columbia, Canada. The equipment is to be supplied by the end of April 2008.


	•	In January 2007, our subsidiary developing the Olkaria III project entered into an Amended and Restated Power Purchase Agreement and a Project Security Agreement, with Kenya Power and Lighting Co., the Kenyan parastatal electricity transmission and distribution company, with respect to Phase II of the Olkaria III project. These agreements were executed

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		after receipt of appropriate regulatory approvals from the Kenyan authorities. The construction of Phase II of the project is expected, upon completion, to add approximately 35 MW to the existing facility, bringing the project’s total capacity to approximately 48 MW. Following completion of Phase II, total anticipated annual revenues from the project will be approximately $32 million .


	•	In January 2007, we entered into supply and engineering, procurement and construction contracts with Ngawha Generation Ltd., a subsidiary of Top Energy Limited, for a new geothermal power plant in Ngawha, New Zealand. The contracts are for a total of approximately $20 million. The construction of the power plant is expected to be completed within 20 months from the contract date.

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 production costs for electricity generated from geothermal resources have become more competitive relative to fossil fuel generation. This is partly due to increasing natural gas and oil prices and newly enacted legislative and regulatory incentives, such as state renewable portfolio standards. 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 the most significant trends affecting our industry today and in the immediate future. Our operations and the trends that from time to time impact our operations are subject to market cycles.

Although other trends, factors and uncertainties may impact our operations and financial condition, including many that we do not or cannot foresee, we believe that our results of operations and financial condition for the foreseeable future will be affected by the following trends, factors and uncertainties:


	•	In 2005, 2006 and in the first half of 2007, our primary activity has been the implementation of our organic growth through the construction of new projects and enhancements of several of our existing projects. As a result, growth in revenues and overall generating capacity has been more moderate than in 2003 and 2004, in which we made significant acquisitions. Nevertheless, we expect that this investment in organic growth will increase our total generating capacity, consolidated revenues and operating income attributable to our Electricity Segment in 2007, as compared with 2006.


	•	We continue to experience increases in the cost of raw materials required for our equipment manufacturing activities and equipment used in our power plants. We have experienced an increase in drilling costs and a shortage in drilling equipment. We believe this is the result of the high oil prices resulting in increased drilling activity in the marketplace. We also have experienced, and expect to continue to experience, an increase in construction costs. This is particularly true in the United States, where a significant increase in construction activities has caused higher prices. An increase in our raw materials, drilling, construction and other costs may have an adverse effect on our financial condition and results of operations.


	•	We expect that the increased awareness of climate change may result in significant changes in the energy, business and regulatory environments, which may create business opportunities for us going forward.


	•	In the United States, we expect to continue to benefit from the increasing demand for renewable energy as a result of favorable legislation adopted by 25 states and the District of Columbia, including California, Nevada and Hawaii (where we have been most active in geothermal development and where all of our U.S. geothermal projects are located). These laws require that an increasing percentage of the electricity supplied by electric utility

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		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 create additional opportunities for us to expand existing projects and build new power plants.


	•	On September 27, 2006, the California Global Warming Solutions Act of 2006 (the Act) was signed into law. The Act regulates most sources of greenhouse gas emissions and is expected to result in a reduction of carbon emissions to 1990 levels by 2020, representing a twenty-five percent reduction in greenhouse gas emissions. To accomplish this, the Act provides a framework for greenhouse gas emissions reductions through the use of emissions control technologies and other cost-effective reduction strategies, one of which may involve the use of market-based trading of emissions rights. The California Air Resources Board must adopt standards for implementing the Act by 2011. Although programs under the Act will take some time to develop, its requirements, particularly the creation of a market-based trading mechanism to achieve compliance with emissions caps, should be highly advantageous to in-state energy generating sources that have low carbon emissions such as geothermal energy.


	•	On September 27, 2006, California also enacted legislation requiring that its renewable portfolio standard of 20% generation from renewable energy resources per year be met by December 2010, ahead of the previous legislative mandated target of December 2017. The California legislature is currently considering an increase to 33% by December 31, 2020.


	•	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 remote power units and other 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 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 payments under long-term power purchase agreements. Simultaneously, we intend to continue to pursue growth in our recovered energy business, and we expect that the portion of revenues from our recovered energy business, as a percentage of the total revenues from our Products Segment, will increase.


	•	Over the last two years, competition from the wind and solar power generation industry has increased. While the current demand for renewable energy is large enough that this increased competition has not impacted our ability to obtain new power purchase agreements, it may contribute to a reduction in electricity prices.


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


	•	As our power plants age, they may require increased maintenance with a resulting decrease in their availability.


	•	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 to mitigate these risks, insurance does not provide complete coverage with respect to all such risks.

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	•	The United States extended a tax subsidy and increased the amount of the tax subsidy for companies that use geothermal steam or fluid to generate electricity as part of the Energy Policy Act of 2005 that became law on August 8, 2005. The tax subsidy is a ‘‘production tax credit’’, which in 2006 was 1.9 cents per kWh and is adjusted annually for inflation. The production tax credit may be claimed for ten years on the electricity output of new geothermal power plants put into service by December 31, 2008.


	•	The Energy Policy Act of 2005 authorizes the Federal Energy Regulatory Commission (FERC) to revise the Public Utility Regulatory Policy Act (PURPA) so as to terminate the obligation of electric utilities to purchase the output of a Qualifying Facility if FERC finds that there is an accessible competitive market for energy and capacity from the Qualifying Facility. The legislation does not affect existing power purchase agreements. We do not expect this change in law to affect our U.S. projects significantly, as all except one of our current contracts (our Steamboat 1 project, which sells it electricity to Sierra Pacific Power Company on a year-by-year basis) are long-term. FERC has recently issued a final rule that could eliminate the utility’s purchase obligation in four regions of the country. None of those regions includes a state in which our current projects operate. However, FERC has the authority under the Energy Policy Act of 2005 to act, on a case-by-case basis, to eliminate the mandatory purchase obligation in other regions. In the final rule, FERC expressly noted that the California Independent System Operator (CAISO) has satisfied one but not all of the criteria for relief from the mandatory purchase obligation. If the utilities in the regions in which our domestic projects operate were to be relieved of the mandatory purchase obligation, they would not be required to purchase energy from us upon termination of the existing power purchase agreement, which could have an adverse effect on our revenues.


	•	On May 2, 2007, the Bureau of Land Management and the Minerals Management Service (each part of the Department of the Interior) issued separate final rules to implement relevant provisions of the Energy Policy Act of 2005. These rules revise existing federal regulations dealing with the general geothermal leasing process for federal land, lease durations, work commitments, annual rental and credit of rental toward royalties, and royalty calculations. The new rules include: a requirement that geothermal resources be offered through a competitive lease process; the introduction of a new royalty methodology, calculated on the basis of gross proceeds from the sale of electricity, rather than the ‘‘netback’’ calculation previously in use; the introduction of increased rental payments (that are creditable toward royalties owed); and a new scheme of lease terms and extensions. The rules also establish ‘‘production incentives’’ for new facilities and qualified expansion facilities that are put into commercial operation by August 8, 2011, in the form of a four year 50% reduction in royalties from what would otherwise be due. The 50% reduction applies to all of the electricity generated from a new facility, and to the incremental electricity generated by a qualified expansion facility. The provisions of the rules dealing with fees, rental payments, and royalties apply to geothermal leases issued after August 8, 2005. However, lessees under leases issued prior to August 8, 2005 may elect to convert their leases to the new regulatory framework. We evaluated the impact of these final rules and we do not expect a material impact on our financial condition and results of operations.

Revenues

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

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

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

The lease income related to the Puna lease transactions, which are accounted for as operating leases, is included as a separate line item in our Electricity Segment revenues (See ‘‘Liquidity and Capital Resources’’). For management purposes, we analyze such revenue on a combined basis with other revenues in our Electricity Segment.

As required by Emerging Issues Task Force (EITF) Issue No. 01-8, Determining Whether an Arrangement Contains a Lease , we have assessed all of our power purchase agreements agreed to, modified or acquired in business combinations on or after July 1, 2003, and concluded that all such agreements contain a lease element requiring lease accounting. Accordingly, revenue related to the lease element of the agreements is presented as ‘‘lease portion of energy and capacity’’ revenue, with the remaining revenue related to the production and delivery of the energy presented as ‘‘energy and capacity’’ revenue in our consolidated financial statements. As the lease revenue and the energy and capacity revenues are derived from the same arrangement and both fall within our Electricity Segment, we analyze such revenues, and related costs, on a combined basis for management purposes.

Revenues attributable to our Products 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 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 Products Segment fluctuate (and at times, extensively) from period to period.

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


	Revenues in Thousands												% of Revenues for Period Indicated
	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended June 30,						Six Months Ended June 30,
	2007			2006			2007			2006			2007			2006			2007			2006
Revenues
Electricity Segment		$	55,360		$	48,767		$	99,018		$	92,500		65.9	%		76.1	%		67.9	%		74.4	%
Products Segment			28,692			15,319			46,781			31,907		34.1			23.9			32.1			25.6
Total		$	84,052		$	64,086		$	145,799		$	124,407		100.0	%		100.0	%		100.0	%		100.0	%

Geographical Breakdown of Revenues

For the three months ended June 30, 2007, 83.0% of our revenues attributable to our Electricity Segment were generated in the United States, as compared to 81.1% for the same period in 2006. For the six months ended June 30, 2007, 80.9% of our revenues attributable to our Electricity Segment were generated in the United States, as compared to 83.8% for the same period in 2006.

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


	Revenues in Thousands												% of Revenues for Period Indicated
	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended June 30,						Six Months Ended June 30,
	2007			2006			2007			2006			2007			2006			2007			2006
United States		$	45,966		$	39,529		$	80,154		$	77,544		83.0	%		81.1	%		80.9	%		83.8	%
Foreign			9,394			9,238			18,864			14,956		17.0			18.9			19.1			16.2
Total		$	55,360		$	48,767		$	99,018		$	92,500		100.0	%		100.0	%		100.0	%		100.0	%

For the three and six months ended June 30, 2007, 27.2% and 35.3%, respectively, of our revenues attributable to our Products Segment were generated in the United States, as compared to 0% for the same periods in 2006.

Seasonality

The prices paid for the electricity generated by our domestic projects pursuant to our power purchase agreements are subject to seasonal variations. The prices paid for electricity under the power purchase agreements with Southern California Edison, the Heber 1 and 2 projects, the Mammoth project and the Ormesa project and the prices that will be paid for the electricity under the power purchase agreement for the Brawley project are higher in the summer months of June through September and as a result we receive and will receive in the future higher revenues during such months. The prices paid for electricity pursuant to the power purchase agreements of our projects in Nevada have no significant changes during the year. In the winter, due principally to the lower ambient temperature our power plants produce more energy and as a result we receive higher energy revenues. However, the higher capacity payments payable by Southern California Edison in California in the summer months have a more significant impact on our revenues than that of the higher energy revenues generally generated in winter due to increased efficiency, and as a result our revenues are generally higher in the summer than in the winter. The prices paid for electricity pursuant to the power purchase agreement of the Puna project are partially volatile and are impacted by oil prices; therefore, our revenues may be volatile during the year.

Breakdown of Expenses

Electricity Segment

The principal expenses attributable to our operating projects include operation and maintenance expenses such as salaries and related employee benefits, equipment expenses, costs of parts and chemicals, costs related to third-party services, major maintenance, lease expenses, royalties, startup and auxiliary electricity purchases, property taxes and insurance and, for the California projects, transmission charges, scheduling charges and purchases of sweet water for use in our plant cooling towers. Some of these expenses, such as parts, third-party services and major maintenance, are not incurred on a regular basis. This results in fluctuations in our expenses and our results of operations for individual projects from quarter to quarter. The lease expense related to the Puna lease transactions is included as a separate line item in our Electricity Segment cost of revenues (See ‘‘Liquidity and Capital Resources’’). For management purposes we analyze such costs on a combined basis with other cost of revenues in our Electricity Segment.

Payments made to government agencies and private entities on account of site leases where plants are located are included in cost of revenues. Royalty payments, included in cost of revenues, are made as compensation for the right to use certain geothermal resources and are paid as a percentage of the revenues derived from the associated geothermal rights. For the six months ended June 30, 2007, royalties constituted approximately 4.2% of the Electricity Segment revenues, compared to approximately 5.0% for the same period in 2006.

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Products Segment

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

Cash, Cash Equivalents and Marketable Securities

Our cash, cash equivalents and marketable securities as of June 30, 2007 decreased to $73.0 million from $116.7 million as of December 31, 2006. This decrease is principally due to the combination of the funding of capital expenditures in the amount of $69.4 million, repayments of long-term debt to our parent and third parties in the amount of $36.5 million, a net increase of $17.9 million in restricted cash, cash equivalents and marketable securities and dividend distribution of $4.6 million, offset by $69.6 million net proceeds from the OPC transaction described below and by $14.7 million of cash flows from operating activities.

Critical Accounting Policies

A comprehensive discussion of our critical accounting policies is included in the ‘‘Management’s Discussion and Analysis of Financial Condition and Results of Operations’’ section in our annual report on Form 10-K for the year ended December 31, 2006.

New Accounting Pronouncements

See Note 2 to our Condensed Consolidated Financial Statements set forth in Item 1 of this quarterly report for information regarding new accounting pronouncements.

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Results of Operations

Our historical operating results in dollars and as a percentage of total revenues are presented below. A comparison of the different periods described below may be of limited utility as a result of each of the following: (i) our recent construction of new projects and enhancement of acquired projects, and (ii) fluctuation in revenues from our Products Segment. An accumulation of operational issues in the first quarter of 2007 resulted in both reduced revenues and increased costs for the six months ended June 30, 2007. Such operational issues are not expected to continue and are not indicative of future trends.


	Three Months Ended June 30,								Six Months Ended June 30,
	2007				2006				2007				2006
	(in thousands, except per share data)
Statements of Operations Historical Data:
Revenues:
Electricity Segment		$	55,360			$	48,767			$	99,018			$	92,500
Products Segment			28,692				15,319				46,781				31,907
			84,052				64,086				145,799				124,407
Cost of revenues:
Electricity Segment			35,328				30,936				75,050				57,803
Products Segment			24,214				9,580				40,138				20,112
			59,542				40,516				115,188				77,915
Gross margin:
Electricity Segment			20,032				17,831				23,968				34,697
Products Segment			4,478				5,739				6,643				11,795
			24,510				23,570				30,611				46,492
Operating expenses:
Research and development expenses			1,061				890				1,765				1,663
Selling and marketing expenses			3,822				2,826				5,808				5,521
General and administrative expenses			5,162				4,404				10,909				9,088
Operating income			14,465				15,450				12,129				30,220
Other income (expense):
Interest income			1,621				2,347				3,036				3,462
Interest expense			(7,070	)			(7,741	)			(14,852	)			(15,194	)
Foreign currency translation and transaction gains (losses)			41				(69	)			(675	)			(77	)
Other non-operating income (expense)			(4	)			204				348				307
Income (loss) before income taxes and equity in income of investees			9,053				10,191				(14	)			18,718
Income tax benefit (provision)			(1,992	)			(2,156	)			3				(4,070	)
Minority interest			305				(571	)			305				(571	)
Equity in income of investees			1,181				931				2,412				2,210
Net income		$	8,547			$	8,395			$	2,706			$	16,287
Earnings per share – basic and diluted		$	0.22			$	0.24			$	0.07			$	0.49
Weighted average number of shares used in computation of earnings per share:
Basic			38,123				35,105				38,116				33,343
Diluted			38,255				35,254				38,248				33,475

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	Three Months Ended June 30,						Six Months Ended June 30,
	2007			2006			2007			2006
Statements of Operations Percentage Data:
Revenues:
Electricity Segment		65.9	%		76.1	%		67.9	%		74.4	%
Products Segment		34.1			23.9			32.1			25.6
		100.0			100.0			100.0			100.0
Cost of revenues:
Electricity Segment		63.8			63.4			75.8			62.5
Products Segment		84.4			62.5			85.8			63.0
		70.8			63.2			79.0			62.6
Gross margin:
Electricity Segment		36.2			36.6			24.2			37.5
Products Segment		15.6			37.5			14.2			37.0
		29.2			36.8			21.0			37.4
Operating expenses:
Research and development expenses		1.3			1.4			1.2			1.3
Selling and marketing expenses		4.5			4.4			4.0			4.4
General and administrative expenses		6.1			6.9			7.5			7.3
Operating income		17.2			24.1			8.3			24.3
Other income (expense):
Interest income		1.9			3.7			2.1			2.8
Interest expense		(8.4	)		(12.1	)		(10.2	)		(12.2	)
Foreign currency translation and transaction gains (losses)		0.0			(0.1	)		(0.5	)		(0.1	)
Other non-operating income (expense)		(0.0	)		0.3			0.2			0.2
Income (loss) before income taxes and equity in income of investees		10.8			15.9			(0.0	)		15.0
Income tax benefit (provision)		(2.4	)		(3.4	)		0.0			(3.3	)
Minority interest		0.4			(0.9	)		0.2			(0.5	)
Equity in income of investees		1.4			1.5			1.7			1.8
Net income		10.2	%		13.1	%		1.9	%		13.1	%

Comparison of the Three Months Ended June 30, 2007 and the Three Months Ended June 30, 2006

Total Revenues

Total revenues for the three months ended June 30, 2007 were $84.1 million, as compared with $64.1 million for the three months ended June 30, 2006, which represented a 31.2% increase in total revenues. This increase is attributable both to our Electricity and Products Segments whose revenues increased by 13.5% and 87.3%, respectively, over the same period in 2006.

Electricity Segment

Revenues attributable to our Electricity Segment for the three months ended June 30, 2007 were $55.4 million, as compared with $48.8 million for the three months ended June 30, 2006, which represented a 13.5% increase in such revenues. This increase is primarily attributable to additional revenues of $6.4 million generated in the Unites States as a result of : (i) an increase in our generating capacity and energy generation in the United States from 430,012 MWh in the three months ended June 30, 2006 to 521,380 MWh in the three months ended June 30 2007; (ii) an increase in the energy rates in the Ormesa and Heber 1 and 2 projects under new five-year agreements entered into with Southern California Edison in May 2006 that increased the energy rates payable by Southern

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California Edison beginning May 1, 2007 to $61.5 per MWh for the first year, with an annual escalation of 1% thereafter; (iii) additional revenues generated by the Desert Peak 2 and OREG 1 power plants, which were placed in service in the second and third quarter of 2006, the enhancements of the Ormesa complex and the Steamboat Hills power plants, which were placed in service in the second quarter of 2007, and the new Galena 2 power plant, which was also placed in service in the second quarter of 2007; and (iv) an insurance settlement of $0.5 million during the second quarter of 2007. In addition we generated $1.4 million from our Amatitlan project in Guatemala which started generating electricity in March 2007, but has not yet declared commercial operation. The increase in our Electricity Segment revenues was partially offset by (i) the Brady project whose sales were reduced by 6 MW to 13 MW and such sales are expected to remain at the 13 MW level through the majority of 2007, while drilling for additional resource is being performed; and (ii) a decrease of $0.9 million in revenues from the Momotombo project in Nicaragua as a result of the failure of turbines that we did not manufacture. We are currently in discussion with the entity that granted us the concession regarding the proper way of repairing the failure. We believe that the power plant will return to full operation in the fourth quarter of 2007.

Products Segment

Revenues attributable to our Products Segment for the three months ended June 30, 2007 were $28.7 million, as compared with $15.3 million for the three months ended June 30, 2006, which represented an 87.3% increase in such revenues. This increase is principally attributable to the timing of revenue recognition in accordance with the percentage of completion method for each of our geothermal and recovered energy generation products.

Total Cost of Revenues

Total cost of revenues for the three months ended June 30, 2007 was $59.5 million, as compared with $40.5 million for the three months ended June 30, 2006, which represented a 47.0% increase in total cost of revenues. As a percentage of total revenues, our total cost of revenues for the three months ended June 30, 2007 was 70.8% compared with 63.2% for the same period in 2006. These increases are attributable to increased costs in both our Electricity and Products Segments, as discussed below.

Electricity Segment

Total cost of revenues attributable to our Electricity Segment for the three months ended June 30, 2007 was $35.3 million, as compared with $30.9 million for the three months ended June 30, 2006, which represented a 14.2% increase in total cost of revenues for such segment. This increase is primarily due to the following: (i) an increase of $0.7 million in cost of revenues attributable to the inclusion for a full quarter of the additional cost of revenues being generated by the Amatitlan project in Guatemala, which started generating electricity in March 2007, but has not yet declared commercial operation; and (ii) an increase of $4.3 million in our cost of revenues in the United States (including increased depreciation in the amount of $1.5 million) primarily attributable to costs relating to new and enhanced projects placed in service and to an increase in labor and materials costs in existing plants. The increase in our Electricity Segment cost of revenues was partially offset by an insurance settlement of $0.6 million during the second quarter of 2007. As a percentage of total electricity revenues, the total cost of revenues attributable to our Electricity Segment for the three months ended June 30, 2007 was 63.8% compared with 63.4% for the three months ended June 30, 2006.

Products Segment

Total cost of revenues attributable to our Products Segment for the three months ended June 30, 2007, was $24.2 million, as compared with $9.6 million for the three months ended June 30, 2006, which represented a 152.8% increase in total cost of revenues related to such segment. This increase is attributable to the increase in our Products Segment revenues, a different product

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mix, and an increase in labor, material, construction and transportation costs, which affected our margins in this segment. As a percentage of total Products Segment revenues, our total cost of revenues attributable to this segment for the three months ended June 30, 2007 was 84.4% as compared with 62.5% for the three months ended June 30, 2006.

Research and Development Expenses

Research and development expenses for the three months ended June 30, 2007 were $1.1 million, as compared with $0.9 million for the three months ended June 30, 2006, which represented a 19.2% increase. Such increase reflects fluctuations in the period in which actual expenses were incurred.

Selling and Marketing Expenses

Selling and marketing expenses for the three months ended June 30, 2007 were $3.8 million, as compared with $2.8 million for the three months ended June 30, 2006, which represented a 35.2% increase. The increase was due primarily to an increase in salaries. Selling and marketing expenses for the three months ended June 30, 2007 constituted 4.5% of total revenues for such period, as compared with 4.4% for the three months ended June 30, 2006.

General and Administrative Expenses

General and administrative expenses for the three months ended June 30, 2007 were $5.2 million, as compared with $4.4 million for the three months ended June 30, 2006, which represented a 17.2% increase. Such increase is attributable to an increase in personnel expenses and other administrative expenses as a result of hiring additional personnel in anticipation of our future growth, and as a result of an increase in salaries. General and administrative expenses for the three months ended June 30, 2007 decreased to 6.1% of total revenues for such period, from 6.9% for the three months ended June 30, 2006. Such decrease is principally attributable to the increase in revenues, as described above.

Operating Income

Operating income for the three months ended June 30, 2007 was $14.5 million, as compared with $15.5 million for the three months ended June 30, 2006. Such decrease in operating income was principally attributable to an increase of $1.9 million in operating expenses offset by an increase in gross margin of $0.9 million. Operating income attributable to our Electricity Segment for the three months ended June 30, 2007 was $14.2 million, as compared with $12.4 million for the three months ended June 30, 2006. Operating income attributable to our Products Segment for the three months ended June 30, 2007 was $0.3 million, as compared with $3.1 million for the three months ended June 30, 2006.

Interest Expense

Interest expense for the three months ended June 30, 2007 was $7.1 million, as compared with $7.7 million for the three months ended June 30, 2006, which represented an 8.7% decrease. The $0.6 million decrease is primarily due to principal repayments. The decrease in interest expense was partially offset by a decrease of $1.2 million in interest capitalized to projects.

Income Taxes

Income tax provision for the three months ended June 30, 2007 and 2006 was $2.0 million and $2.2 million, respectively. The effective tax rates for the three months ended June 30, 2007 and 2006 were 22.0% and 21.2%, respectively.

Effective January 1, 2007 , we adopted Financial Accounting Standards Board Interpretation No. 48, Accounting for Uncertainty in Income Taxes, an Interpretation of FASB Statement No. 109 (FIN No. 48). The impact on the income tax provision for the three months ended June 30, 2007 resulting from the adoption of FIN No. 48 was immaterial.

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Minority interest

Minority interest for the three months ended June 30, 2007 includes income of $0.3 million from the sale of limited liability company interests in OPC LLC to institutional equity investors. Minority interest for the three months ended June 30, 2006 includes $0.6 million minority interest in earnings of the Zunil project.

Equity in Income of Investees

Our participation in the income generated from our investees for the three months ended June 30, 2007 was $1.2 million, as compared with $0.9 million for the three months ended June 30, 2006.

Net Income

Net income for the three months ended June 30, 2007 was $8.5 million, as compared with $8.4 million for the three months ended June 30, 2006. While our revenues from the Products Segment increased by 87.3%, the operating income decreased by $2.8 million as a result of lower margins as discussed above. In the Electricity Segment the operating income increased by $1.8 million. Net income for the three months ended June 30, 2007 includes stock-based compensation related to stock options of $1.0 million as compared with $0.3 million for the three months ended June 30, 2006.

Comparison of the Six Months Ended June 30, 2007 and the Six Months Ended June 30, 2006

Total Revenues

Total revenues for the six months ended June 30, 2007 were $145.8 million, as compared with $124.4 million for the six months ended June 30, 2006, which represented a 17.2% increase in total revenues. This increase is attributable both to our Electricity and Products Segment whose revenues increased by 7.0% and 46.6%, respectively, over the same period in 2006.

Electricity Segment

Revenues attributable to our Electricity Segment for the six months ended June 30, 2007 were $99.0 million, as compared with $92.5 million for the six months ended June 30, 2006, which represented a 7.0% increase in such revenues. This increase is partially attributable to additional revenues of $2.6 million generated in the United States as a result of: (i) an increase in our generating capacity and energy generation in the United States from 886,171 MWh in the six months ended June 30, 2006 to 958,505 MWh in the six months ended June 30 2007; (ii) an increase in the energy rates in the Ormesa and Heber 1 and 2 projects under new five-year agreements entered into with Southern California Edison in May 2006 that increased the energy rates payable by Southern California Edison beginning May 1, 2007 to $61.5 per MWh for the first year, with an annual escalation of 1% thereafter; (iii) additional revenues generated by the Gould, Desert Peak 2 and OREG 1 power plants, which were placed in service in the second and third quarter of 2006, the enhancements of the Ormesa complex and the Steamboat Hills power plants, which were placed in service in the second quarter of 2007, and the new Galena 2 power plant, which was also placed in service in the second quarter of 2007; and (iv) an insurance settlement of $0.5 million during the second quarter of 2007. The increase in our U.S. based revenues was partially offset by a decrease primarily attributable to the following: (i) the Steamboat 2 /3 project experienced protracted failures of two of the project’s turbines which were not manufactured by us. We have implemented a temporary fix and are in the process of replacing the faulty equipment with turbines designed and manufactured by us; (ii) the Heber 1 project was shut down during a period of 25 days in order to perform a scheduled overhaul; (iii) the Steamboat Hills project was shut down in December 2006 in order to tie in the new Galena 2 power plant, which occurred in the second quarter of 2007 (the commissioning of the Galena 2 project was postponed from the first quarter to the second quarter of 2007 due to a delay in obtaining the project permit); (iv) the Puna project experienced a decrease in

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revenues as a result of lower energy rates; and (v) beginning March 2007, the Brady project sales were reduced by 6 MW to 13 MW and such sales are expected to remain at the 13 MW level through the majority of 2007, while drilling for additional resource is being performed. This increase is also attributable to: (i) a $2.8 million increase in revenues generated from the Zunil project in Guatemala, which was consolidated as of March 13, 2006; and (ii) revenues of $1.8 million generated from our Amatitlan project in Guatemala, which started generating electricity in March 2007, but has not yet declared commercial operation.

Products Segment

Revenues attributable to our Products Segment for the six months ended June 30, 2007 were $46.8 million, as compared with $31.9 million for the six months ended June 30, 2006, which represented a 46.6% increase in such revenues. This increase is principally attributable to the timing of revenue recognition in accordance with the percentage of completion method for each of our geothermal and recovered energy generation products.

Total Cost of Revenues

Total cost of revenues for the six months ended June 30, 2007 was $115.2 million, as compared with $77.9 million for the six months ended June 30, 2006, which represented a 47.8% increase in total cost of revenues. As a percentage of total revenues, our total cost of revenues for the six months ended June 30, 2007 was 79.0% compared with 62.6% for the same period in 2006. These increases are attributable to increased costs in both our Electricity and Products Segments, as discussed below.

Electricity Segment

Total cost of revenues attributable to our Electricity Segment for the six months ended June 30, 2007 was $75.1 million, as compared with $57.8 million for the six months ended June 30, 2006, which represented a 29.8% increase in total cost of revenues for such segment. This increase is primarily due to the following: (i) additional costs of $1.9 million to repair two wells experiencing mechanical problems in the Puna project; (ii) costs of $2.0 million related to a scheduled overhaul in the Heber 1 project (such an overhaul is performed once every four to five years); (iii) an increase of $2.5 million in the costs related to the Ormesa project, as a result of accelerating well field maintenance work, which was done as a preventive measure to avoid their failure and to assure a higher wellfield availability during the summer, when electricity rates paid under the relevant power purchase agreement are higher; (iv) a $0.8 million expense resulting from the settlement of a legal claim; (v) an increase of $0.9 million in cost of revenues attributable to the Zunil project in Guatemala which was consolidated as of March 13, 2006; and (vi) the inclusion of $1.0 million of additional costs being generated by the Amatitlan project in Guatemala which started generating electricity in March 2007, but has not yet declared commercial operation. The remaining $8.8 million increase in our cost of revenues (including increased depreciation in the amount of $3.0 million) is attributable primarily to costs in the United States relating to new and enhanced projects placed in service and to an increase in labor and materials costs in existing plants. The increase in our Electricity Segment cost of revenues was partially offset by an insurance settlement of $0.6 million during the second quarter of 2007. As a percentage of total electricity revenues, the total cost of revenues attributable to our Electricity Segment for the six months ended June 30, 2007 was 75.8% compared with 62.5% for the six months ended June 30, 2006.

Products Segment

Total cost of revenues attributable to our Products Segment for the six months ended June 30, 2007, was $40.1 million, as compared with $20.1 million for the six months ended June 30, 2006, which represented a 99.6% increase in total cost of revenues related to such segment. This increase is attributable to the increase in our Products Segment revenues, a different product mix, and an increase in labor, material, construction and transportation costs, which affected our margins in this segment. As a percentage of total Products Segment revenues, our total cost of revenues attributable to this segment for the six months ended June 30, 2007 was 85.8% as compared with 63.0% for the six months ended June 30, 2006.

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Research and Development Expenses

Research and development expenses for the six months ended June 30, 2007 were $1.8 million, as compared with $1.7 million for the six months ended June 30, 2006, which represented a 6.1% increase. Such increase reflects fluctuations in the period in which actual expenses were incurred.

Selling and Marketing Expenses

Selling and marketing expenses for the six months ended June 30, 2007 were $5.8 million, as compared with $5.5 million for the six months ended June 30, 2006, which represented a 5.2% increase. The increase was due primarily to an increase in salaries. Selling and marketing expenses for the six months ended June 30, 2007 constituted 4.0% of total revenues for such period, as compared with 4.4% for the six months ended June 30, 2006. Such decrease is principally attributable to the increase in revenues, as described above.

General and Administrative Expenses

General and administrative expenses for the six months ended June 30, 2007 were $10.9 million, as compared with $9.1 million for the six months ended June 30, 2006, which represented a 20.0% increase. Such increase is attributable to an increase in personnel expenses and other administrative expenses as a result of hiring additional personnel in expectation of our future growth, and as a result of an increase in salaries. General and administrative expenses for the six months ended June 30, 2007 increased to 7.5% of total revenues for such period, from 7.3% for the six months ended June 30, 2006.

Operating Income

Operating income for the six months ended June 30, 2007 was $12.1 million, as compared with operating income of $30.2 million for the six months ended June 30, 2006. Such decrease in operating income was principally attributable to a $15.9 million decrease in gross margin primarily due to the increase in total cost of revenues as explained above, and an increase of $2.2 million in operating expenses. Operating income attributable to our Electricity Segment for the six months ended June 30, 2007 was $12.6 million, as compared with operating income of $23.7 million for the six months ended June 30, 2006. Operating loss attributable to our Products Segment for the six months ended June 30, 2007 was $0.5 million, as compared with operating income of $6.5 million for the six months ended June 30, 2006.

Interest Expense

Interest expense for the six months ended June 30, 2007 was $14.9 million, as compared with $15.2 million for the six months ended June 30, 2006, which represented a 2.3% decrease. The $0.3 million decrease is primarily due to principal repayments. The decrease in interest expense was partially offset by a decrease of $1.7 million in interest capitalized to projects and an increase of $0.4 million in interest expense for the six months ended June 30, 2007 due to the Zunil project, which was consolidated as of March 13, 2006.

Income Taxes

Income tax benefit for the six months ended June 30, 2007 was $3,000 as compared with income tax expense of $4.1 million for the six months ended June 30, 2006. The effective tax rates for the six months ended June 30, 2007 and 2006 were 21.4% and 21.7%, respectively. Our effective tax rate decreased in the six months ended June 30, 2007 compared with the same period last year due to: (i) a decrease of 2% in the tax rate in Israel commencing January 1, 2007; (ii) a tax credit related to our subsidiaries in Guatemala; and (iii) an increase in production tax credits as a result of new power plants placed in service.

Effective January 1, 2007 , we adopted Financial Accounting Standards Board Interpretation No. 48, Accounting for Uncertainty in Income Taxes, an Interpretation of FASB Statement No. 109 (FIN No. 48). The impact on the income tax benefit for the six months ended June 30, 2007 resulting from the adoption of FIN No. 48 was immaterial.

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Minority interest

Minority interest for the six months ended June 30, 2007 includes income of $0.3 million from the sale of limited liability company interests in OPC LLC to institutional equity investors. Minority interest for the six months ended June 30, 2006 includes $0.6 million minority interest in earnings of the Zunil project.

Equity in Income of Investees

Our participation in the income generated from our investees for the six months ended June 30, 2007 was $2.4 million, as compared with $2.2 million for the six months ended June 30, 2006.

Net Income

Net income for the six months ended June 30, 2007 was $2.7 million, as compared with $16.3 million for the six months ended June 30, 2006. Such decrease in net income was principally attributable to a $15.9 million decrease in gross margin primarily due to the increase in total cost of revenues as explained above, and an increase of $2.2 million in operating expenses. This was partially offset by a decrease in our income tax provision of $4.1 million. Net income for the six months ended June 30, 2007 includes stock-based compensation related to stock options of $1.6 million as compared with $0.6 million for the six months ended June 30, 2006.

Liquidity and Capital Resources

To date, our principal sources of liquidity have been derived from cash flows from operations, proceeds from parent company loans, third party debt in the form of borrowings under credit facilities, issuance by Ormat Funding and OrCal Geothermal of their Senior Secured Notes, project financing (including leases and the tax monetization transaction) and the issuance of our common stock in public offerings. We have utilized this cash to fund our acquisitions, develop and construct power generation plants and meet our other cash and liquidity needs. Our management believes that the outstanding cash, cash equivalents, marketable securities and cash generated from our operations will address our liquidity and other investment requirements. In addition, our shelf registration statement on Form S-3, which was declared effective on January 31, 2006, provides us with the ability to raise additional capital of up to $763 million through the issuance of securities pursuant to the terms and conditions of the shelf registration. As described below, since the capital note in the amount of $50.7 million with our parent is payable upon demand at any time after November 30, 2007, it is presented in current liabilities in our balance sheets as of June 30, 2007 and December 31, 2006.

Loan Agreements with our Parent

In 2003, we entered into a loan agreement with our parent company, Ormat Industries Ltd. (Ormat Industries), which was further amended on September 20, 2004. Pursuant to this loan agreement, Ormat Industries agreed to make a loan to us in one or more advances not exceeding a total aggregate amount of $150.0 million. The proceeds of the loan are to be used to fund our general corporate activities and investments. We are required to repay the loan and accrued interest in full and in accordance with an agreed-upon repayment schedule and in any event on or prior to September 5, 2010. Interest on the loan is calculated on the balance from the date of the receipt of each advance until the date of payment thereof at a rate per annum equal to Ormat Industries’ average effective cost of funds plus 0.3% in dollars, which represented a rate of 7.5% for the advances made during 2003. Interest is calculated on the basis of a year consisting of 360 days. As of June 30, 2007, the outstanding balance of the loan was approximately $72.9 million compared to $89.5 million, as of December 31, 2006.

In addition to the above loan, pursuant to the terms of a capital note, as amended on September 20, 2004, Ormat Industries converted outstanding balances owed by us to Ormat Industries into a subordinated non-interest bearing loan in an amount equal to New Israeli Shekels (NIS) 240.0 million. At any time after November 30, 2007, upon demand by Ormat Industries, we will be required to repay the loan in full. The final maturity of the loan is December 30, 2009. In accordance with the terms of such note, we will not be required to repay any amount in excess of $50.7 million

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(using the exchange rate existing on the date of such note). As of June 30, 2007 and December 31, 2006 the ceiling of $50.7 million is effective. Since the note is payable upon demand at any time after November 30, 2007 it is presented in current liabilities in our balance sheets as of June 30, 2007 and December 31, 2006.

If Ormat Industries demands repayment of the note before December 30, 2009, we expect to fund the repayment from: (i) positive cash flow from our operating activities; (ii) additional proceeds to be raised from the financing and refinancing of our projects; and (iii) corporate borrowing.

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. The second category consists of debt incurred by us or our subsidiaries for general corporate purposes.

OrCal Geothermal Senior Secured Notes – Non-Recourse

On December 8, 2005, OrCal Geothermal Inc. (OrCal), one of our subsidiaries, issued $165.0 million, 6.21% Senior Secured Notes (OrCal Senior Secured Notes) in an offering subject to Rule 144A and Regulation S of the Securities Act of 1933, as amended, for the purpose of refinancing the acquisition cost of the Heber projects. 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, 2007, we were in compliance with the covenants under the OrCal Senior Secured Notes. As of June 30, 2007, there were $150.9 million of OrCal Senior Secured Notes outstanding.

Ormat Funding Senior Secured Notes – Non Recourse

On February 13, 2004, Ormat Funding Corp. (OFC), one of our subsidiaries, issued $190.0 million, 8 ¼ % Senior Secured Notes (OFC Senior Secured Notes) in an offering subject to Rule 144A and Regulation S of the Securities Act of 1933, as amended, for the purpose of refinancing the acquisition cost of the Brady, Ormesa and Steamboat 1/1A projects, and the financing of the acquisition cost of the Steamboat 2/3 project. 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. On December 31, 2006, OFC did not meet the ‘‘debt service coverage ratio’’ and therefore it was restricted from payment of dividends until it meets such ratio. As of June 30, 2007, there were $173.8 million of OFC Senior Secured Notes outstanding.

On May 31, 2007, OFC successfully consummated a consent solicitation, which was launched on May 16, 2007, relating to the OFC Senior Secured Notes. The Consent Solicitation was conducted in order to amend and/or waive certain provisions of the indenture such that our shut down and decommissioning of the Desert Peak 1 plant and the related termination of the fluid supply agreement pursuant to which geothermal resource was supplied to that plant (both of which constituted assets pledged to the Noteholders to secure repayment of the OFC Senior Secured Notes) would not constitute defaults or events of default under the indenture.

Senior Loans from International Finance Corporation (IFC) and Commonwealth Development Corporation (CDC) – Non-Recourse

Orzunil I de Electricidad, Limitada (Orzunil), a wholly owned subsidiary, has senior loan agreements with IFC and CDC. The first loan from IFC, of which $6.4 million was outstanding as of

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June 30, 2007, has a fixed annual interest rate of 11.775%, and matures on November 15, 2011. The second loan from IFC, of which $2.7 million was outstanding as of June 30, 2007, has a fixed annual interest rate of 11.730%, and matures on May 15, 2008. The loan from CDC, of which $7.6 million was outstanding as of June 30, 2007, 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.

Due to hurricane activity, access roads and piping from the wells to the power plant in the Zunil Project were damaged and as a result, the Project was not in operation from October 14, 2005 to March 10, 2006. As a result, Orzunil did not meet the historical ‘‘debt service coverage ratio’’ required at December 31, 2006 and therefore, distributions from the Project were restricted. As of June 30, 2007, Orzunil is in compliance with the requited ‘‘debt service coverage ratio’’ and with all other covenants.

Other Limited and Non-Recourse Debt

The Bank Hapoalim project finance debt, of which $9.8 million was outstanding as of June 30, 2007, bearing an interest rate of 3-month LIBOR plus 2.375% per annum on tranche one of the loan and 3-month LIBOR plus 3.0% per annum on tranche two of the loan, and the Export-Import Bank of the United States project finance debt, of which $1.3 million was outstanding as of June 30, 2007, bearing an interest rate of 6.54% per annum, were entered into by our relevant subsidiaries to finance the Momotombo project and the Leyte project (which was deconsolidated as of April 1, 2004), respectively.

New financing of our projects

Financing of the Amatitlan Project

We intend to refinance our equity investment in the construction of the Amatitlan project in Guatemala. We terminated the mandate letter with the local bank in Guatemala and our discussions are continuing on a non-exclusive basis.

Financing of Phase II of Olkaria III Project

We have engaged a financial institution and received an indicative proposal to arrange long-term financing for the Olkaria III project in Kenya. We expect negotiations and preparation of loan documentation to follow shortly.

Full-Recourse Debt

Our full-recourse third party debt includes an $8.0 million medium term loan from Bank Hapoalim, of which $1.0 million was outstanding as of June 30, 2007, bearing an interest rate of 12-month LIBOR plus 1.7% per annum.

In connection with our acquisition through Ormat Systems Ltd. (Ormat Systems) of the power generation business from our parent, we entered into certain agreements with various banks, of which only those with each of Bank Hapoalim, Bank Leumi and Mizrahi Tefahot Bank remain. Under these agreements, in exchange for such banks’ release of our parent’s guarantee and a release of their security interest over the assets of our subsidiary, Ormat Systems, we and Ormat Systems have agreed to certain negative covenants, including, but not limited to, a prohibition on: (i) creating any floating charge or any permanent pledge, charge or lien over our assets without obtaining the prior written approval of the lender; (ii) guaranteeing the liabilities of any third party without obtaining the prior written approval of the lender; and (iii) selling, assigning, transferring, conveying or disposing of all or substantially all of our assets. In some cases, we have agreed to maintain certain financial ratios such as a debt service coverage ratio and a debt to equity ratio. We do not expect that these covenants or ratios, which apply to us on a consolidated basis, will materially limit our ability to execute our future business plans or our operations. 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.

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We do not expect that any third party debt that we, or any of our subsidiaries, will incur in the future will be guaranteed by our parent.

Most of the loan agreements to which we or our subsidiaries are a party contain cross-default provisions with respect to other material indebtedness owed by us or them to any third party.

On February 15, 2006, our subsidiary, Ormat Nevada, entered into a $25.0 million credit agreement with Union Bank of California (UBOC). Under the credit agreement, Ormat Nevada can request extensions of credit in the form of loans and/or the issuance of one or more letters of credit. UBOC is currently the sole lender and issuing bank under the credit agreement, but is also designated as an administrative agent on behalf of banks that may, from time to time in the future, join the credit agreement as parties thereto. In connection with this transaction, we have entered into a guarantee in favor of the administrative agent for the benefit of the banks, pursuant to which we agreed to guarantee Ormat Nevada’s obligations under the credit agreement. Ormat Nevada’s obligations under the credit agreement are otherwise unsecured by any of its (or any of its subsidiaries’) assets.

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

As of June 30, 2007, one letter of credit in the amount of $0.7 million remained issued and outstanding under this credit agreement with UBOC.

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

Letters of Credit and Off-balance Sheet Arrangements

As described above under ‘‘Full-Recourse Debt’’, on February 15, 2006, our subsidiary, Ormat Nevada, entered into a credit agreement with Union Bank of California.

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

Bank Leumi and Bank Hapoalim have issued such performance letters of credit in favor of our customers from time to time. As of June 30, 2007, Bank Leumi and Bank Hapoalim have agreed to make available to us letters of credit totaling $24.8 million and $18.5 million, respectively. As of such date, Bank Leumi and Bank Hapoalim have issued letters of credit in the amount of $20.3 million and $10.4 million, respectively.

As of the date hereof, we have not had a draw presented against any letter of credit issued or provided on our behalf.

Puna Project Lease Transactions

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

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OPC Tax Monetization Transaction

On June 7, 2007, a wholly owned subsidiary of the Company, Ormat Nevada Inc. (Ormat Nevada), concluded a transaction to monetize production tax credits and other favorable tax attributes, such as accelerated depreciation, generated from certain of its geothermal power projects. Pursuant to the transaction, affiliates of Morgan Stanley & Co. Incorporated and Lehman Brothers Inc. became institutional equity investors in a newly formed subsidiary of Ormat Nevada. The projects involved in the transaction include Desert Peak 2, Steamboat Hills, and Galena 2, all located in Nevada.

Under the transaction structure, Ormat Nevada transferred the aforementioned geothermal power projects to the newly formed subsidiary, OPC LLC (OPC), and sold limited liability company interests in OPC to the institutional equity investors for $71.8 million. Ormat Nevada will continue to operate and maintain the projects and will receive initially all of the distributable cash flow generated by the projects until it recovers the capital that it has invested in the projects, while the institutional equity investors will receive substantially all of the production tax credits and the taxable income or loss (together, the Economic Benefits), and the distributable cash flow after Ormat Nevada has recovered its capital. The institutional equity investor’s return is limited by the term of the transaction. Once the investors reach a target after-tax yield on their investment in OPC (the Flip Date), Ormat Nevada will receive 95% of both distributable cash and taxable income and the investors will receive 5% of both distributable cash and taxable income on a going forward basis. Following the Flip Date, Ormat Nevada also has the option to buy out the investors’ remaining interest in OPC at the then-current fair market value or, if greater, the investors’ capital account balances in OPC. Should Ormat Nevada exercise this purchase option, it would thereupon revert to being sole owner of the projects. The transaction provides for a second closing whereby Ormat Nevada would contribute another geothermal plant currently under construction and receive an additional amount of $46.6 million.

Liquidity Impact of Uncertain Tax positions

As discussed in Note 11 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 $3.6 million as of June 30, 2007. This liability is included in long-term liabilities in our consolidated balance sheet, because we generally do not anticipate that settlement of the liability will require payment of cash within the next twelve months. We are not able to reasonably estimate when we will make any cash payments required to settle this liability, but do not believe that the ultimate settlement of our obligations will materially effect our liquidity.

Dividend

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

Date Declared

Dividend Amount
per Share

Record Date

Payment Date

November 9, 2005

0.03

November 29, 2005

December 6, 2005

March 7, 2006

0.03

March 28, 2006

April 4, 2006

May 9, 2006

0.04

May 23, 2006

May 30, 2006

August 6, 2006

0.04

August 23, 2006

August 30, 2006

November 7, 2006

0.04

November 30, 2006

December 13, 2006

February 27, 2007

0.07

March 21, 2007

March 29, 2007

May 8, 2007

0.05

May 22, 2007

May 29, 2007

August 8, 2007

0.05

August 22, 2007

August 29, 2007

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Historical Cash Flows

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


	Six Months Ended June 30,
	2007				2006
	(in thousands)
Net cash provided by operating activities		$	14,682			$	28,927
Net cash used in investing activities			(38,882	)			(129,822	)
Net cash provided by financing activities			28,850				98,655
Net increase (decrease) in cash and cash equivalents			4,650				(2,240	)

For the six months ended June 30, 2007

Net cash provided by operating activities for the six months ended June 30, 2007 was $14.7 million, as compared with $28.9 million for the six months ended June 30, 2006. Such net decrease of $14.2 million resulted primarily from the decrease in gross margin, as described above. This decrease resulted in a net income of $2.7 million in the six months ended June 30, 2007 as compared with net income of $16.3 million in the in the six months ended June 30, 2006.

Net cash used in investing activities for the six months ended June 30, 2007 was $38.9 million, as compared with $129.8 million for the six months ended June 30, 2006. The principal factors that affected our cash flow used in investing activities during the six months ended June 30, 2007 were a $17.9 million increase in restricted cash, cash equivalents and marketable securities, and capital expenditures of $69.4 million primarily for our facilities under construction, offset by a $48.5 million decrease in marketable securities. The principal factors that affected our cash flow used in investing activities during the six months ended June 30, 2006 were capital expenditures of $80.0 million primarily for our power facilities under construction, $15.4 million used in the acquisition of additional 50.8% of the Zunil project in Guatemala and an increase of $40.3 million in marketable securities derived from the follow-on offering proceeds.

Net cash provided by financing activities for the six months ended June 30, 2007 was $28.9 million, as compared with $98.7 million for the six months ended June 30, 2006. The principal factors that affected the cash flow provided by financing activities during the six months ended June 30, 2007 were $69.6 million in proceeds from the sale of OPC interests, net of transaction costs, relating to the OPC tax monetization transaction, offset by the repayment of long-term debt in the amount of $19.9 million, the repayment of debt to our parent in the amount of $16.6 million and the payment of a dividend to our shareholders in the amount of $4.6 million. The principal factors that affected the cash flow provided by financing activities during the six months ended June 30, 2006 were the proceeds from the follow-on offering of $135.1 million offset by the repayment of short-term and long-term debt in the amount of $16.7 million and the repayment of debt to our parent in the amount of $16.6 million and the payment of a dividend to our shareholders in the amount of $2.4 million.

Capital Expenditures

Our capital expenditures primarily relate to two principal components: the enhancement of our existing power plants and the development of new power plants. In addition, we have budgeted approximately $11 million for the next two years for investment in buildings, machinery and equipment, including drilling equipment that we received at the end of the first quarter of 2007.

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. We currently do not contemplate obtaining any new loans from our parent company.

Phase II of Olkaria III Project. In connection with Phase II of the Olkaria III project, we completed the drilling of the wells and have commenced construction of the 35 MW power plant.

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OrSumas Project. This recovered energy 5 MW project was originally scheduled to be completed in the last quarter of 2007 or the first quarter of 2008. As a result of certain environmental issues identified in this project, we have suspended its implementation until we make a final determination regarding the future of this project.

Puna Project. An enhancement program for the Puna project is currently planned and is intended to increase the output of the project by an estimated 8 MW through the construction of OEC units. We expect that such enhancement program will be completed in 2009. We have not yet entered into a power purchase agreement for the supply of energy from this planned addition.

Heber South Project. We are currently constructing the Heber South project, a 10 MW power plant, which will be located in the Heber known geothermal resource area. Drilling of production and injection wells has been completed and the remaining construction includes the construction of an OEC unit and related facilities. We expect the construction to be completed by the first quarter of 2008.

Galena 3 Project. We are currently constructing the Galena 3 project, which will deliver 17 MW of power generation under a 20-year power purchase agreement with Sierra Pacific Power Company. We expect the construction to be completed by the beginning of 2008.

Brawley Phase I Project. We are currently constructing the Brawley Phase I project, which will deliver approximately 50 MW of power generation under an existing power purchase agreement with Southern California Edison. We expect the construction to be completed by the end of 2008.

OREG 2 project. In connection with the OREG 2 recovered energy project, we plan to construct four power plants along the Northern Border natural gas pipeline. Each of the four facilities will have a net capacity of 5.5MW. These facilities are scheduled to be completed during 2009.

Peetz Project. In connection with the Peetz recovered energy project, we plan to construct a 4 MW power plant along a natural gas pipeline near Denver, Colorado. The facility is scheduled to be completed in mid 2009.

We have budgeted approximately $460 million for the above-described projects (other than OrSumas) and have invested approximately $83 million of such budget as of June 30, 2007. The budgeted amount includes the GDL project in New Zealand which is described in ‘‘Recent Developments’’ above.

In addition to the above projects, our operating projects have capital expenditure budgets of approximately $10 million and we also plan to start other construction and enhancement of additional projects, including exploration work, for a total investment amount of approximately $11 million.

We do not anticipate material capital expenditures in the near term for any of our operating projects, other than those described above and other than new projects beyond 2008.

Exposure to Market Risks

One market risk to which power plants are typically exposed is the volatility of electricity prices. However, our exposure to such market risk is limited currently because our long-term power purchase agreements have fixed or escalating rate provisions that limit our exposure to changes in electricity prices. However, beginning in May 2012, the energy payments under the power purchase agreements for the Heber 1 and 2 projects, the Ormesa project and the Mammoth project will be determined by reference to the relevant power purchaser’s short run avoided costs. The Puna project is currently benefiting from energy prices which are higher than the floor under the Puna power purchase agreement, as a result of the high fuel costs that impact Hawaii Electric Light Company’s avoided costs. In addition, under certain of the power purchase agreements for our projects in Nevada, the price that Sierra Pacific Power Company pays for energy and capacity is based upon California-Oregon border power market pricing.

As of June 30, 2007, 97.7% 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. As

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of such date, $10.8 million, or 2.3 %, of our debt was in the form of a floating rate instrument, exposing us to changes in interest rates in connection therewith. As such, our exposure to changes in interest rates with respect to our long-term obligations is immaterial.

Another market risk to which we are exposed is primarily related to potential adverse changes in foreign currency exchange rates, in particular the fluctuation of the U.S. dollar versus the new Israeli shekel (NIS). Risks attributable to fluctuations in currency exchange rates can arise when any of our foreign subsidiaries borrows funds or incurs operating or other expenses in one type of currency but receives revenues in another. In such cases, an adverse change in exchange rates can reduce such subsidiary’s ability to meet its debt service obligations, reduce the amount of cash and income we receive from such foreign subsidiary or increase such subsidiary’s overall expenses. Risks attributable to fluctuations in foreign currency exchange rates can arise when the currency-denomination of a particular contract is not the U.S. dollar. All of our power purchase agreements in the international markets are either U.S. dollar-denominated or linked to the U.S. dollar. Our construction contacts 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. In the past, we have not used any material foreign currency exchange contracts or other derivative instruments to reduce our exposure to this risk. In the future, we may use such foreign currency exchange contracts and other derivative instruments to reduce our foreign currency exposure 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.

We currently maintain our surplus cash in short-term, interest-bearing bank deposits and auction-rate Securities (deposits of entities with a minimum investment grade rating of AA by Standard & Poor’s Ratings Services).

Concentration of Credit Risk

Our credit risk is currently concentrated with a limited number of major customers: Sierra Pacific Power Company, Southern California Edison and Hawaii Electric Light Company. If any of these electric utilities fails to make payments under its power purchase agreements with us, such failure would have a material adverse impact on our financial condition.

Southern California Edison accounted for 29.4% and 31.1% of our total revenues for the three months ended June 30, 2007 and 2006, respectively, and 27.4% and 29.1% of our total revenues for the six months ended June 30, 2007 and 2006, respectively. Southern California Edison is also the power purchaser and revenue source for our Mammoth project, which we account for separately under the equity method of accounting.

Sierra Pacific Power Company accounted for 9.0% and 12.5% of our total revenues for the three months ended June 30, 2007 and 2006, respectively, and 9.5% and 14.3% of our total revenues for the six months ended June 30, 2007 and 2006, respectively.

Hawaii Electric Light Company accounts for 12.0% and 16.2% of our total revenues for the three months ended June 30, 2007 and 2006, respectively, and 13.5% and 17.1% of our total revenues for the six months ended June 30, 2007 and 2006, respectively.

Government Grants and Tax Benefits

The U.S. government encourages production of electricity from geothermal resources through certain tax subsidies. We are permitted to claim approximately 10% of the cost of each new geothermal power plant in the United States as an investment tax credit against our federal income taxes. Alternatively, we are permitted to claim a ‘‘production tax credit’’, which in 2006 was 1.9 cents per kWh and which is adjusted annually for inflation. The production tax credit may be claimed for ten years on the electricity output of new geothermal power plants put into service by December 31, 2008. The owner of the project must choose between the production tax credit and the 10% investment tax credit described above. In either case, under current tax rules, any unused tax

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credit has a 1-year carry back and a 20-year carry forward. Whether we claim the production tax credit or the investment credit, we are also permitted to depreciate most of the plant for tax purposes over five years on an accelerated basis, meaning that more of the cost may be deducted in the first few years than during the remainder of the depreciation period. If we claim the investment credit, our ‘‘tax base’’ in the plant that we can recover through depreciation must be reduced by half of the tax credit. If we claim a production tax credit, there is no reduction in the tax basis for depreciation.

Our subsidiary, Ormat Systems, received from Israel’s Investment Center ‘‘Approved Enterprise’’ status under Israel’s Law for Encouragement of Capital Investments, 1959 (the Investment Law), with respect to two of its investment programs. One such approval was received in 1996 and the other was received in May 2004. In respect of the approval from 1996, Ormat Systems has utilized all the tax benefits it was entitled to. As an Approved Enterprise and according to a ruling from the Israeli Tax Authorities, Ormat Systems is exempt from Israeli income taxes with respect to income derived from the approved investment for the years 2004 and 2005 and thereafter such income is subject to reduced Israeli income tax rates of 25% for an additional five years. These benefits are subject to certain conditions set forth in the ruling, 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 must 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.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

ITEM 4. CONTROLS AND PROCEDURES


	a.	Evaluation of disclosure controls and procedures

Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures to ensure that the information required to be disclosed in our filings pursuant to Rule 13a-15 under the Securities and Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms and to ensure that such information is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer as appropriate to allow timely decisions regarding required disclosure. Based on that evaluation as of June 30, 2007, our Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended) were effective.

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


	b.	Changes in internal controls over financial reporting

There were no changes in our internal controls over financial reporting in the second quarter of 2007 that have materially affected or are reasonably likely to materially affect our internal controls over financial reporting.

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PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

There were no material developments in any legal proceedings to which the Company is a party during the six months period ended June 30, 2007 from those previously reported in Part I, Item 3 of our annual report on Form 10-K for the year ended December 31, 2006, other than as described below.

As a result of our acquisition of the Steamboat 1 and 1A plants, our subsidiary Steamboat Geothermal LLC became a party to litigation pending in the Second Judicial District Court in Washoe County, Nevada with Geothermal Development Associates (GDA) and Delphi Securities, Inc. In April 2002, these plaintiffs initiated a lawsuit against the former owner and operator of the Steamboat 1/1A project claiming amounts owed under certain operating agreements. On December 31, 2005 and January 9, 2006, Steamboat Geothermal LLC entered into a sales, settlement and release agreement and an assignment agreement, respectively, with Woodside Properties LLC, the assignee of 37% of Geothermal Development Associates’ right to net operating revenues, whereby Steamboat Geothermal LLC was assigned 37% of the net operating revenues of Steamboat 1 in partial settlement of the above mentioned dispute with GDA and Delphi Securities, Inc. On April 11, 2007, following a successful mediation, the parties reached a final settlement of the remaining claims. As a result of the settlement, we recorded an additional provision of $0.8 million as of March 31, 2007, and paid the total settlement amount to GDA in April 2007. The settlement agreement provides for a mutual release of any and all claims, demands and causes of action by and between the parties and stipulates that the settlement should not be construed as an admission of liability or fault by any party.

In connection with the power purchase agreements for the Ormesa project, Southern California Edison had expressed its intent not to pay the contract rate for power supplied by the GEM 2 and GEM 3 plants to the Ormesa project. Southern California Edison contended that California ISO real-time prices should apply, while management believed that SP-15 prices quoted by NYMEX should apply. Ormesa LLC, a wholly-owned subsidiary of the Company, and Southern California Edison signed an Interim Agreement in 2005 whereby Southern California Edison agreed to procure GEM 2 and GEM 3 power at the then-current energy rate under the July 18, 1984 Ormesa power purchase agreement of 5.37 cents per kWh until May 1, 2007. On April 23, 2007, the parties finalized an agreement with terms that are similar to the arrangement agreed to in the Interim Agreement, whereby 6.5 MW of power from GEM 2 and GEM 3 will be sold to Southern California Edison at the current energy rate of the July 18, 1984 Ormesa power purchase agreement. For the period commencing May 1, 2007, the energy rate is 6.15 cents per kWh. The parties simultaneously entered into other agreements and agreed to release each other from any and all claims relating to the Ormesa projects. Pursuant to these agreements, Ormesa LLC paid Southern California Edison an immaterial amount to consolidate the June 13, 1984 and July 18, 1984 power purchase agreements. Combining these agreements will reduce scheduling fees over the term of the agreement and provide other operational benefits.

From time to time, we (and our subsidiaries) are a party to various other lawsuits, claims and other legal and regulatory proceedings that arise in the ordinary course of our (and their) business. These actions typically seek, among other things, compensation for alleged personal injury, breach of contract, property damage, punitive damages, civil penalties or other losses, or injunctive or declaratory relief. With respect to such lawsuits, claims and proceedings, we accrue reserves in accordance with accounting principles generally accepted in the U.S. We do not believe that any of these proceedings, individually or in the aggregate, would materially and adversely affect our business, financial condition, future results and cash flows.

ITEM 1A. RISK FACTORS

A comprehensive discussion of our risk factors is included in the ‘‘Risk Factors’’ section of our annual report on Form 10-K for the year ended December 31, 2006 filed with the SEC on March 12, 2007.

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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 2007.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

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

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

On May 8, 2007, we held our Annual Meeting of Stockholders. The two directors whose terms expired at the meeting, Lucien Bronicki and Dan Falk, were re-elected by vote of the stockholders at such meeting. In addition, the stockholders voted to ratify the appointment of PricewaterhouseCoopers LLP as our independent auditor for fiscal year 2007 and to approve an amendment to the Company’s 2004 Incentive Compensation Plan to increase the number of shares of Common Stock authorized for issuance pursuant to the plan by 2,500,000 .

The results of the votes were as follows:


Proposal	Votes For		Votes Against/ Withheld		Abstentions		Broker Non-Vote
Election of Director Lucien Bronicki		30,594,283		3,200,426		None		None
Election of Director Dan Falk		30,333,417		3,461,292		None		None
Ratification of appointment of PricewaterhouseCoopers LLP		33,731,772		58,704		4,232		None
Approval of an amendment to the Company’s 2004 Incentive Compensation Plan to increase the number of shares of Common Stock authorized for issuance pursuant to the plan by 2,500,000		31,207,904		452,651		14,015		2,120,139

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

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Exhibit No.			Document
	4	.3	Form of Rights Agreement by and between Ormat Technologies, Inc. and American Stock Transfer & Trust Company, incorporated by reference to Exhibit 4.3 to Ormat Technologies, Inc. Registration Statement Amendment No. 2 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on October 22, 2004.
	4	.4	Indenture for Senior Debt Securities, dated as of January 16, 2006, between Ormat Technologies, Inc. and Union Bank of California, incorporated by reference to Exhibit 4.2 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-3 (File No. 333-131064) to the Securities and Exchange Commission on January 26, 2006.
	4	.5	Indenture for Subordinated Debt Securities, dated as of January 16, 2006, between Ormat Technologies, Inc. and Union Bank of California, incorporated by reference to Exhibit 4.3 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-3 (File No. 333-131064) to the Securities and Exchange Commission on January 26, 2006.
	10	.1 .17	Agreement for Purchase of Membership Interests in 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 10.1 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on June 13, 2007
	10	.21 .2	Amendment No. 2 to the Power Purchase Contract between Ormesa LLC and Ormat Technologies, Inc., and Southern California Edison Company (RAP ID 3012) dated April 23, 2006, as filed herewith.
31.1			Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, filed herewith.
31.2			Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, filed herewith.
32.1			Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, filed herewith.
32.2			Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, filed herewith.
99.1			Material terms with respect to BLM geothermal resources leases incorporated by reference to Exhibit 99.1 to Ormat Technologies, Inc. Registration Statement Amendment No. 2 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on October 20, 2004.
99.2			Material terms with respect to BLM site leases incorporated by reference to Exhibit 99.2 to Ormat Technologies, Inc. Registration Statement on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on July 20, 2004.
99.3			Material terms with respect to agreements addressing renewable energy pricing and payment issues incorporated by reference to Exhibit 99.3 to Ormat Technologies, Inc. Registration Statement on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on July 20, 2004.

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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.


Date: August 8, 2007	By:	/s/ JOSEPH TENNE
		Name: Joseph Tenne Title: Chief Financial Officer

EXHIBIT INDEX


Exhibit No.			Document
	3	.1	Second Amended and Restated Certificate of Incorporation, incorporated by reference to Exhibit 3.1 to Ormat Technologies, Inc. Registration Statement on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on July 20, 2004.
	3	.2	Second Amended and Restated By-laws, incorporated by reference to Exhibit 3.2 to Ormat Technologies, Inc. Registration Statement Amendment No. 2 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on October 22, 2004.
	3	.3	Amended and Restated Limited Liability Company Agreement of OPC LLC dated June 7, 2007, by and among Ormat Nevada Inc., Morgan Stanley Geothermal LLC, and Lehman-OPC LLC, incorporated by reference to Exhibit 3.1 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on June 13, 2007.
	4	.3	Form of Rights Agreement by and between Ormat Technologies, Inc. and American Stock Transfer & Trust Company, incorporated by reference to Exhibit 4.3 to Ormat Technologies, Inc. Registration Statement Amendment No. 2 on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on October 22, 2004.
	4	.4	Indenture for Senior Debt Securities, dated as of January 16, 2006, between Ormat Technologies, Inc. and Union Bank of California, incorporated by reference to Exhibit 4.2 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-3 (File No. 333-131064) to the Securities and Exchange Commission on January 26, 2006.
	4	.5	Indenture for Subordinated Debt Securities, dated as of January 16, 2006, between Ormat Technologies, Inc. and Union Bank of California, incorporated by reference to Exhibit 4.3 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-3 (File No. 333-131064) to the Securities and Exchange Commission on January 26, 2006.
	10	.1 .17	Agreement for Purchase of Membership Interests in 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 10.1 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on June 13, 2007
	10	.21 .2	Amendment No. 2 to the Power Purchase Contract between Ormesa LLC and Ormat Technologies, Inc., and Southern California Edison Company (RAP ID 3012) dated April 23, 2006, as filed herewith.
31.1			Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, filed herewith.
31.2			Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, filed herewith.
32.1			Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, filed herewith.
32.2			Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, filed herewith.

AMENDMENT NO. 2
to the
POWER PURCHASE CONTRACT
Between
SOUTHERN CALIFORNIA EDISON COMPANY
and
ORMESA GEOTHERMAL
RAP ID 3010

This Amendment No. 2 (‘‘Amendment’’) to the above-referenced Power Purchase Contract is entered into by ORMESA LLC, a Delaware limited liability company (‘‘Seller’’) and ORMAT TECHNOLOGIES, INC., a Delaware corporation (‘‘Ormat’’), on the one hand, and SOUTHERN CALIFORNIA EDISON COMPANY, a California corporation (‘‘Edison’’), on the other hand. Seller, Ormat and Edison are sometimes referred to in this Amendment individually as a ‘‘Party’’ and jointly as the ‘‘Parties.’’

RECITALS

This Amendment is entered into with reference to the following facts, among others:


	A.	On July 18, 1984, Edison and Republic Geothermal, Inc. (‘‘Republic’’) executed the Power Purchase Contract (‘‘Contract’’), whereby Edison agreed to purchase energy and capacity from a geothermal power plant (‘‘3010 Project’’) located in East Mesa, Imperial County, California. Edison identifies the 3010 Project as RAP ID 3010. The ‘‘Contract’’ is henceforth deemed to mean the Contract as amended, supplemented, or otherwise modified from time to time.


	B.	On November 6, 1984, Republic assigned all of its rights to and interests in the Contract to Ormat Systems, Inc. Edison consented to the assignment on December 19, 1984.


	C.	On February 27, 1985, Ormat Systems, Inc. assigned all of its rights to and interests in the Contract to Ormesa Geothermal. Edison consented to the assignment on July 22, 1985.


	D.	On December 23, 1988, Edison and Ormesa Geothermal entered into Amendment No. 1 to the Contract (‘‘Amendment No. 1’’), which increased the Contract Capacity, limited energy deliveries under the Contract and limited the Contract Capacity eligible for a Capacity Bonus Payment.


	E.	On June 19, 2001, Edison and Ormesa Geothermal entered into the Agreement Addressing Renewable Energy Pricing and Payment Issues (‘‘Renewable Agreement’’).


	F.	On November 30, 2001, Edison and Ormesa Geothermal entered into Amendment No. 1 to the Renewable Agreement.


	G.	In a filing before the Federal Energy Regulatory Commission (‘‘FERC’’) dated December 30, 2002, Seller represented that it is the successor to Ormesa Geothermal, following a merger between Seller and a number of its subsidiaries.


	H.	In a second filing before FERC, also dated December 30, 2002, Seller represented that it is also the successor to Ormesa Geothermal II, the seller under a separate power purchase contract between Ormat Systems, Inc. and Edison dated June 13, 1984 (‘‘3012 Contract’’), that provides for the sale to Edison of electrical power generated by a separate geothermal plant (‘‘3012 Project’’), which is also located in East Mesa, Imperial County, California. Edison identifies the 3012 Project as RAP ID 3012.


	I.	In 2002, Edison and Seller entered into negotiations to discuss the consolidation of the 3010 and 3012 Projects and the termination of the 3012 Contract.


	J.	On or about November 22, 2002 and April 28, 2003, and subsequently on June 21, 2005, Edison and Seller entered into confidentiality agreements protecting their negotiations from public disclosure.


	K.	On or about May 1, 2003, Edison and Seller reached an agreement, subject to California Public Utilities Commission (‘‘CPUC’’ or ‘‘Commission’’) approval, regarding the consolidation of the 3010 and 3012 Projects and the termination of the 3012 Contract. Edison withdrew its support for the consolidation and termination based upon concerns that the 3010 and 3012 Projects were interconnected with another Qualifying Facility (‘‘QF’’), Geo East Mesa (‘‘GEM’’), which had previously sold its output to Edison under a QF contract that was terminated pursuant to a Commission-approved buyout agreement. Edison alleged that, in view of the interconnection, the consolidation might improperly facilitate sales of GEM-produced power to Edison under the terms of the consolidated QF amendment. Although the Commission initially approved Edison’s and Seller’s agreement regarding the consolidation and termination on October 16, 2003 in Resolution E-3848, on January 22, 2004, the Commission granted Edison’s application for rehearing and vacated Resolution E-3848. Accordingly, the 3010 and 3012 Projects remained separate projects, subject to separate contracts.


	L.	Edison contends that, since approximately June 2003, the 3010 and 3012 Projects have been interconnected with GEM generating units that are not part of the 3010 and 3012 Projects, and that the 3010 and 3012 Projects improperly sold power generated by the GEM generating units to Edison pursuant to the Contract and the 3012 Contract resulting in overpayments by Edison to Seller. Seller disputes Edison’s contentions. This dispute shall henceforth be known as the ‘‘Dispute.’’


	M.	Edison protested a recertification filed by the 3012 Project with FERC disputing the project capacity amount designated by the 3012 Project. After FERC rejected Edison’s protest in part, Edison appealed to the United States Court of Appeals for the District of Columbia Circuit. The Court of Appeals affirmed FERC’s ruling and subsequently denied Edison’s petition for rehearing. This dispute shall henceforth be known as the ‘‘FERC Dispute.’’


	N.	On or about November 6, 2005, Edison and Seller entered into an Interim Agreement (‘‘Interim Agreement’’), effective as of October 1, 2005 and attached hereto as Appendix A, whereby Edison agreed, without prejudicing either Edison’s or Seller’s position in respect of the Dispute, to permit Seller to supply electrical energy deliveries from GEM under the Contract on an interim basis. In the Interim Agreement, the sole payment to be made by Edison to Seller for GEM power is an energy-only price of 5.37 cents/kWh, which is time-differentiated by time-of-delivery period in the manner utilized for energy payments under the Contract. The Interim Agreement, which may be terminated by either Edison or Seller after May 1, 2007, was intended to bridge the interim time period until a final agreement regarding the Dispute and the FERC Dispute could be negotiated and executed by Edison and Seller.


	O.	On or about May 10, 2006, Edison and Seller entered into Agreement No. 2 Addressing Renewable Energy Pricing Issues for the 3010 and 3012 Projects. Those agreements provide for a new fixed energy price starting at 6.15 cents/kWh on May 1, 2007. The agreements are silent about GEM power.


	P.	Pursuant to the Contract and the 3012 Contract, the capacity payment allowance for scheduled maintenance for the 3010 and 3012 Projects may not exceed 840 hours in any twelve month period. On or about March 2006, the 3010 Project used up its allotment of maintenance hours. On July 28, 2006, Seller sent an e-mail to Edison stating that it had made a data entry error and requested an adjustment in maintenance hours credit for the 3010 Project for November 2005 through May 2006 such that the maintenance hours scheduled by Seller for the 3010 Project during that time period be applied solely to mid-peak hours. On January 9, 2007, Edison sent Seller a letter denying Seller’s request. This dispute shall henceforth be known as the ‘‘Maintenance Hours Dispute.’’


	Q.	Edison and Seller have now reached a final agreement on the consolidation of the 3010 and 3012 Projects and the delivery of power from GEM to Edison which provides, among other things, for (i) the potential for Seller to deliver GEM power to Edison from a combined


		project consisting of the 3010 and 3012 Projects and GEM, (ii) an increase in the amount of electricity to be sold to Edison from the combined project of up to 6.5 MW more than the previous amounts that were covered by the Contract and the 3012 Contract, which incremental amount will receive an energy only price as specified below, (iii) the termination of the 3012 Contract and the Interim Agreement, and (iv) the settlement of the Dispute, the FERC Dispute and the Maintenance Hours Dispute. Accordingly, Edison and Seller agree to amend the Contract as set forth herein.


	R.	Concurrently with this Agreement, Edison and Seller are executing: (i) a Contract Termination Agreement that terminates the 3012 Contract (‘‘Termination Agreement’’); and (ii) a Settlement Agreement that settles the Dispute, the FERC Dispute and the Maintenance Hours Dispute between the Parties (‘‘Settlement Agreement’’).


	S.	In addition, Edison has agreed that this Amendment, the Termination Agreement and the Settlement Agreement will take effect without Commission approval in exchange for Seller’s and Ormat’s agreement to, jointly and severally, indemnify Edison for certain amounts if Edison fails to obtain Commission approval for its cost recovery related to the Amendment, the Termination Agreement and the Settlement Agreement. Accordingly, Seller and Ormat have agreed to, jointly and severally, indemnify Edison as provided in Section 2.8, below.


	T.	The rights and obligations of Seller under this Amendment, the Termination Agreement and the Settlement Agreement will confer benefits upon Ormat as Seller’s indirect parent corporation, and therefore, Ormat is willing to provide the indemnification set forth in Section 2.8, below.

AGREEMENT


1.	In consideration of the mutual promises and covenants and agreements hereinafter set forth and for other good and valuable consideration, receipt of which is hereby acknowledged, as of the Effective Date (defined in Section 2.1, below), Edison and Seller agree to amend the Contract as follows:


	1.1	The new RAP ID number for the amended and consolidated Contract shall be RAP ID No. 3104.


	1.2	Sections 1.2a. and 1.2b. shall be deleted in their entirety and replaced as follows:

‘‘a. Nameplate Rating: 63,000 kW including generating units at Ormesa I (3010 Project), Ormesa II (3012 Project), and Geo East Mesa Project.

b. Location: East Mesa, Imperial County, California, as shown in the map attached hereto as Appendix D.’’


	1.3	Section 1.3 shall be deleted in its entirety and replaced as follows:

‘‘1.3 Contract Capacity: 53,000 kW with the following exceptions (for the purpose of ensuring that 6.5 MW of power to be supplied by the Generating Facility will be paid a capacity price of $0/kW-year).

As expressly provided in Section 4.4.8, at Edison’s request, Seller shall make all reasonable efforts to deliver power at an average rate of delivery at least equal to a Contract Capacity of 46,500 kW during periods of Emergency.

As expressly provided in Section 4.4.9 and Appendix F, the Annual Contract Capacity Demonstration Protocol and Criteria requires Seller to demonstrate the ability to provide a Contract Capacity of 46,500 kW.

The Firm Capacity Purchase calculation, as found in Section 8.1.2.1, is based on a Contract Capacity (designated as C in the formula) of 46,500 kW. For the avoidance of doubt, the Period Performance Factor (designated as D in the same formula) is calculated based on the Contract Capacity of 53,000 kW.

The Capacity Bonus Payment calculation, as found in Section 8.1.2.4c, is based on a Contract Capacity (designated as D in the formula) of 42,000 kW. For the avoidance of doubt, the On-Peak Capacity Factor (as found in A in the same formula) is calculated based on the Contract Capacity of 53,000 kW.’’


	1.4	Section 1.4 shall be deleted in its entirety and replaced as follows:

‘‘1.4 Expected annual production: 485,000,000 kWh.’’


	1.5	Section 1.6 shall be deleted in its entirety and replaced as follows:

‘‘1.6 Contract Term: Period in years from October 9, 1987 until November 30, 2017.’’


	1.6	Section 1.8 shall be deleted in its entirety and replaced as follows:

‘‘Seller shall be deemed to have selected Capacity Payment Option B – Firm Capacity, as found at Section 8.1.2.

The Contract Capacity Price for purposes of calculating the capacity payment to be made to Seller pursuant to Section 8.1 shall be $174.52/kW-yr (Firm Capacity).’’


	1.7	Section 2.1 shall be deleted and replaced as follows:

‘‘2.1 3010 Project Adjusted Capacity Price : The $/kW-yr capacity purchase price calculated using the Capacity Payment Schedule attached hereto as Appendix H. For the purposes of calculating the 3010 Project Adjusted Capacity Price using the Capacity Payment Schedule attached hereto as Appendix H, the Year of Initial Delivery shall be 1987 and the Contract Term shall be the time period in years beginning on October 9, 1987 and ending on the date of a reduction or deration pursuant to Section 8.1.2.5b.’’


	1.8	Section 2.2 shall be deleted and replaced as follows:

‘‘2.2 3012 Project Adjusted Capacity Price : The $/kW-yr capacity purchase price calculated using the Capacity Payment Schedule attached hereto as Appendix H. For the purposes of calculating the 3012 Project Adjusted Capacity Price using the Capacity Payment Schedule attached hereto as Appendix H, the Year of Initial Delivery shall be 1988 and the Contract Term shall be the time period in years beginning on March 3, 1988 and ending on the date of a reduction or deration pursuant to Section 8.1.2.5b.’’


	1.9	Section 2.9 shall be deleted and replaced as follows:

‘‘2.9 Contract Capacity Price : The Contract Capacity Price of $174.52/kW-yr, as specified in Section 1.8.’’


	1.10	Section 2.10 shall be amended by adding the following at the end thereof:

‘‘, as specified in Section 1.6.’’


	1.11	Section 2.11 shall be deleted in its entirety.


	1.12	Section 2.19 shall be deleted and replaced as follows:

‘‘2.19 Generating Facility : All of Seller’s generators, together with all protective and other associated equipment and improvements, necessary to produce electrical power at Ormesa I (3010 Project), Ormesa II (3012 Project) and the Geo East Mesa Project, excluding associated land, land rights, and interests in land. The Generating Facility shall be identified by Edison as RAP ID 3104.’’


	1.13	Section 2.22 shall be amended by adding the following at the end thereof:

‘‘The Interconnecting Utility for this Contract is Imperial Irrigation District (‘‘IID’’). The Seller will deliver to IID at the Highline substation.’’


	1.14	Section 2.28 shall be amended by adding the following at the end thereof:

‘‘The Point of Interconnection for this Contract is Mirage substation.’’


	1.15	The following definitions shall be added to Section 2:

‘‘2.40 Agreement Addressing Renewable Energy Pricing and Payment Issues : The June 19, 2001 Agreements Addressing Renewable Energy Pricing and Payment Issues for the 3010 and 3012 Projects, as amended.

2.41 Agreement No. 2 Addressing Renewable Energy Pricing Issues : The May 10, 2006 Agreements No. 2 Addressing Renewable Energy Pricing Issues for the 3010 and 3012 Projects.

2.42 Amendment No. 2 : Amendment No. 2 to the Contract, which was executed to consolidate the 3010 and 3012 Projects under the Contract, and to provide for Edison accepting energy deliveries from the Geo East Mesa Project under the Contract.

2.43 Capacity Attributes : Any and all current or future defined characteristics, certificates, tags, credits, ancillary service attributes, or accounting constructs, howsoever entitled, including any accounting construct counted toward any resource adequacy requirements, attributed to or associated with any unit of generating capacity of the Generating Facility during the term of the Contract.

2.44 Effective Date of Amendment No. 2 : March 1, 2007.

2.45 Green Attributes : Any and all credits, benefits, emissions reductions, offsets, and allowances, howsoever entitled, attributable to the generation from the Generating Facility, and its displacement of conventional energy generation. Green Attributes include but are not limited to: (i) any avoided emissions of pollutants to the air, soil or water such as sulfur oxides (SO _x ), nitrogen oxides (NO _x ), carbon monoxide (CO) and other pollutants; (ii) any avoided emissions of carbon dioxide (CO ₂ ), methane (CH ₄ ), nitrous oxide, hydrofluorocarbons, perfluorocarbons, sulfur hexafluoride and other greenhouse gases (GHGs) that have been determined by the United Nations Intergovernmental Panel on Climate Change, or otherwise by law, to contribute to the actual or potential threat of altering the Earth’s climate by trapping heat in the atmosphere; (iii) the reporting rights to these avoided emissions, such as Green Tag Reporting Rights; and (iv) Renewable Energy Credits. Green Tag Reporting Rights are the right of a Green Tag Purchaser to report the ownership of accumulated Green Tags in compliance with federal or state law, if applicable, and to a federal or state agency or any other party at the Green Tag Purchaser’s discretion, and include without limitation those Green Tag Reporting Rights accruing under Section 1605(b) of The Energy Policy Act of 1992 and any present or future federal, state, or local law, regulation or bill, and international or foreign emissions trading program. Green Tags are accumulated on a MWh basis and one Green Tag represents the Green Attributes associated with one (1) MWh of energy.

Green Attributes do not include: (i) any energy, capacity, reliability or other power attributes from the Generating Facility; (ii) production tax credits associated with the construction or operation of the Generating Facility and other financial incentives in the form of credits, reductions, or allowances associated with the Generating Facility that are applicable to a state or federal income taxation obligation; (iii) fuel-related subsidies or ‘‘tipping fees’’ that may be paid to Seller to accept certain fuels, or local subsidies received by the Seller for the destruction of particular pre-existing pollutants or the promotion of local environmental benefits; or (iv) emission reduction credits encumbered or used by the Generating Facility for compliance with local, state, or federal operating and/or air quality permits.

2.46 Geo East Mesa or GEM Project : The Geo East Mesa or GEM project includes the GEM 2 & 3 power plants, which are double flash facilities that each utilize: (i) one dual-admission condensing steam turbine and directly coupled generator; (ii) steam separation vessels; (iii) a cooling tower; and (iv) the balance of power plant equipment. The Geo East Mesa or GEM project also includes an 8 MW GEM bottoming geothermal power plant to be installed at or near the location of the other GEM units.

2.47 Governmental Authority : (i) Any federal, state, local, municipal or other government; (ii) any governmental, regulatory or administrative agency, commission, or other authority lawfully exercising or entitled to exercise any administrative, executive, judicial, legislative, police, regulatory or taxing authority or power; or (iii) any court or government tribunal.

2.48 Nameplate Rating : The gross generating capacity of the Generating Facility less Site Use. For purposes of this Contract, Nameplate Rating is that rating specified in Section 1.2a.

2.49 Ormesa I or 3010 Project : The geothermal project originally identifed by Edison as QFID 3010 in the Contract.

2.50 Ormesa II or 3012 Project : The geothermal project originally identified by Edison as QFID 3012 in a June 13, 1984 Power Purchase Contract between Edison and Ormat Systems, Inc.

2.51 Renewable Energy Credit : ‘‘Renewable energy credit’’ as that term is defined in Public Utilities Code Section 399.12(g), as may be amended from time-to-time or as further defined or supplemented by applicable law.

2.52 Resource Adequacy Benefits : The rights and privileges attached to the Generating Facility that satisfy any entity’s resource adequacy obligations, as those obligations are set forth in any Resource Adequacy Rulings and shall include any local, zonal or otherwise locational capacity attributes associated with the Generating Facility.

2.53 Resource Adequacy Rulings : Commission Decisions 04-01-050, 04-10-035, 05-10-042, 06-06-024, 06-07-031 and any subsequent Commission ruling or decision relating to resource adequacy, or any other resource adequacy laws, rules or regulations enacted, adopted or promulgated by any applicable Governmental Authority, as such decisions, rulings, laws, rules or regulations may be amended or modified from time-to-time during the term of the Contract.

2.54 RPS Legislation : The State of California Renewables Portfolio Standard Program, as codified at California Public Utilities Code Section 399.11 et seq ., or any successor to this legislation.

2.55 Site Use : Energy used to operate the Generating Facility’s auxiliary equipment. The auxiliary equipment includes, but is not limited to, forced and induced draft fans, cooling towers, boiler feed pumps, lubricating oil systems, plant lighting, fuel handling systems (including production pumps), injection pumps, control systems, and sump pumps.’’


	1.16	The first sentence of Section 4.4.8 shall be deleted and replaced as follows:

‘‘At Edison’s request, Seller shall make all reasonable efforts to deliver power at an average rate of delivery at least equal to a Contract Capacity of 46,500 kW during periods of Emergency.’’


	1.17	Section 4.4.9 shall be deleted and replaced as follows:

‘‘At least once per year at Edison’s request, Seller shall demonstrate the ability to provide a Contract Capacity of 46,500 kW pursuant to the Annual Contract Capacity Demonstration Protocol and Criteria attached hereto as Appendix F. If Seller fails to demonstrate the ability to provide a Contract Capacity of 46,500 kW pursuant to Appendix F, the Parties acknowledge that the damages sustained by Edison would be difficult or impossible to determine, or that obtaining an adequate remedy would be unreasonably time consuming or expensive, and therefore agree that Seller shall pay Edison liquidated damages as provided in Appendix F. The Parties agree that the liquidated damages as provided in Appendix F constitute a reasonable approximation of the harm or loss to Edison.’’


	1.18	New Sections 4.4.14, 4.4.15, and 4.4.16 shall be added following Section 4.4.13 as follows:

‘‘4.4.14 Seller represents and warrants that Seller has not and will not convey to any person or entity other than Edison any Green Attributes, Capacity Attributes or Resource Adequacy Benefits associated with the output from the Generating Facility throughout the term of the Contract.

Seller shall use commercially reasonable efforts (which shall not involve Seller incurring out-of-pocket costs in excess of $10,000 per year) to ensure (or to support Edison’s efforts to ensure) that, throughout the term of the Contract: (i) the Generating Facility is certified by the California Energy Commission (‘‘CEC’’) as an Eligible Renewable Energy Resource (‘‘ERR’’) for purposes of the RPS Legislation; and (ii) all electrical output delivered to Edison from the Generating Facility is certified by the CEC as an ERR for purposes of the RPS Legislation.

4.4.15 Seller shall dedicate and convey any and all Green Attributes, Capacity Attributes and Resource Adequacy Benefits generated or produced by Seller during the term of the Contract to Edison, and Edison shall be given sole title to all such Green Attributes, Capacity Attributes and Resource Adequacy Benefits.

In addition, Seller shall, at its own cost, take all actions that are commercially reasonable (which shall not involve Seller incurring out-of-pocket costs in excess of $10,000 per year) and execute all documents or instruments necessary to effectuate the use of the Green Attributes, Capacity Attributes and Resource Adequacy Benefits for Edison’s sole benefit throughout the term of the Contract. Seller shall not be required to reduce the output of the Generating Facility in order to effectuate the use of the Green Attributes, Capacity Attributes and Resource Adequacy Benefits by Edison throughout the term of the Contract, other than in connection with periodic testing as may be required by the California Independent System Operator. Subject to the foregoing, such actions shall include, without limitation:


	(a)	Cooperating with and encouraging the regional entity responsible for resource adequacy administration to certify or qualify the Contract Capacity for resource adequacy purposes;


	(b)	Testing the Generating Facility in order to certify the Contract Capacity for resource adequacy purposes;


	(c)	Complying with all current and future California Independent System Operator tariff provisions that address resource adequacy, including but not limited to provisions regarding performance obligations and penalties; and


	(d)	Committing to Edison the full Contract Capacity subject to Section 1.3.

Edison will have the exclusive right, at any time or from time-to-time during the term of the Contract, to sell, assign, convey, transfer, allocate, designate, award, report or otherwise provide any and all such Green Attributes, Capacity Attributes or Resource Adequacy Benefits to third parties; provided, however, any such action shall not constitute a transfer of, or release Edison of its obligations under the Contract and Seller shall not be required to incur any out-of-pocket costs to facilitate such action.

Edison shall be responsible for any costs associated with Edison’s accounting for or otherwise claiming Green Attributes, Capacity Attributes and Resource Adequacy Benefits.

Seller grants, pledges, assigns and otherwise commits to Edison the full Contract Capacity in order for Edison to meet its resource adequacy obligations under any Resource Adequacy Rulings.

Seller also represents, warrants and covenants to Edison that Seller:


	(a)	Has not used, granted, pledged, assigned or otherwise committed; and


	(b)	Will not, during the term of the Contract use, grant, pledge, assign or otherwise commit any portion of the Generating Facility to meet the resource adequacy requirements of, or to confer Resource Adequacy Benefits upon, any entity other than Edison.’’

4.4.16 Seller represents and warrants that: (i) the generating equipment at the 3010, 3012 and Geo East Mesa Projects as of the Effective Date of Amendment No. 2, which equipment is described in Appendix E, (ii) the interconnection configuration described in the drawing attached hereto as Appendix G, and (iii) any agreements or arrangements between Seller and the Imperial Irrigation District (‘‘IID’’) regarding interconnection, scheduling, transmission or retail electric service for or related to the 3010, 3012 and Geo East Mesa Projects as of the Effective Date of Amendment No. 2, shall be preserved for the entirety of the Contract unless written permission to modify such equipment, configuration, agreements or arrangements is obtained from Edison, which permission shall not be unreasonably withheld or delayed; provided that, notwithstanding the foregoing, Seller may, without Edison’s consent, consolidate the agreements or arrangements with IID referenced above (and terminate existing, and enter into new, agreements in connection therewith) so long as there is no material change in the services to be provided thereunder (not including financial provisions as between Seller and IID).’’


	1.19	A new Section 4.5.4 shall be added following Section 4.5.3 as follows:

‘‘Seller and Edison shall follow the maintenance outage scheduling procedure attached hereto as Appendix I.’’


	1.20	Section 7.1 shall be amended by adding the following at the end thereof:

‘‘Unless Edison and Seller agree otherwise in writing, Seller’s electricity deliveries to Edison shall be measured by an IID master meter at the Highline substation as shown on the drawing attached hereto as Appendix G. Payments to Seller will be calculated by deducting line losses from the IID master meter to the Mirage substation.’’

1.21 Section 8.1 shall be deleted and replaced as follows:

‘‘8.1 Capacity Payments

Seller shall sell to Edison and Edison shall purchase from Seller capacity at the price set forth in Section 1.8. Seller shall be paid a monthly capacity payment subject to the conditions herein.’’

1.22 Section 8.1.2 shall be deleted and replaced as follows:

‘‘8.1.2 Capacity Payment Option B – Firm Capacity Purchase

If Seller selects Capacity Payment Option B, Seller shall provide to Edison for the Contract Term the Contract Capacity specified in Section 1.3, and Seller shall be paid as follows:’’


	1.23	The definition of the formula values A, C, & D in Section 8.1.2.1 shall be deleted and replaced as follows:

‘‘Where A = Contract Capacity Price specified in Section 1.8’’

‘‘C = Contract Capacity of 46,500 kW as specified in Section 1.3’’

‘‘D = Period Performance Factor, not to exceed 1.0, is calculated using 53,000 kW for Contract Capacity as specified in Section 1.3, as follows:

[Period kWh Purchased by Edison

Period Performance Factor = (Limited by the Level of Contract Capacity)]

[0.8 x Contract Capacity x (Period Hours minus Maintenance Hours Allowed in Section 4.5)]’’


	1.24	The definition of the formula values ‘‘A and D’’ in Section 8.1.2.4c shall be deleted and replaced as follows:

‘‘Where A = (1.2 x On-Peak Capacity Factor) − 1.02

Where the On-Peak Capacity Factor, not to exceed 1.0, is calculated using 53,000 kW for Contract Capacity as specified in Section 1.3, as follows:

[Period kWh Purchased by Edison

On-Peak Capacity Factor = (Limited by the Level of Contract Capacity)]

[(Contract Capacity) x (Period Hours minus Maintenance Hours Allowed in Section 4.5)]’’

‘‘D = Contract Capacity of 42,000 kW, as specified in Section 1.3.’’


	1.25	Section 8.1.2.5 shall be deleted and replaced as follows:

‘‘ Capacity Reduction


	a.	The Contract Capacity values specified in Section 1.3 may be reduced as a result of a change in Operating Option pursuant to Section 5.2. In addition, the Contract Capacity values specified in Section 1.3 may be derated by Edison pursuant to Section 8.1.2.2a.


	b.	If the Contract Capacity values specified in Section 1.3 are reduced pursuant to Section 5.2 or derated pursuant to Section 8.1.2.5a such that the Contract Capacity of 53,000 kW is reduced or derated below 46,500 kW, then, subject to Section 9.3, Seller shall refund to Edison with interest at the current published Federal Reserve Board three months prime commercial paper rate, a capacity reduction payment (‘‘Capacity Reduction Payment’’). The Capacity Reduction Payment that Seller shall refund to Edison will be based on the sum of (i) the Capacity Reduction Payment for the 3010 Project for the period prior to the Effective Date of Amendment No. 2, calculated as set forth in Section 8.1.2.5c (ii) the Capacity Reduction Payment for the 3012 Project for the period prior to the Effective Date of Amendment No. 2, calculated as set forth in Section 8.1.2.5d, and (iii) the Capacity Reduction Payment for the period after the Effective Date of Amendment No. 2, calculated as set forth in Section 8.1.2.5e.


	c.	The Capacity Reduction Payment for the 3010 Project for the period prior to the Effective Date of Amendment No. 2 shall be an amount equal to the difference between (i) the accumulated Monthly Capacity Payments paid by Edison to the 3010 Project in respect of the 3010 Project Reduction Amount (as defined below) pursuant to Capacity Payment Option B from October 9, 1987 to the Effective Date of Amendment No. 2, and (ii) the total capacity payments which Edison would have paid to the 3010 Project in respect of the 3010 Project Reduction Amount (as defined below) during that time period if based on the 3010 Project Adjusted Capacity Price.

The 3010 Project Reduction Amount shall be 31.5/46.5 of the quantity, in kW, by which the Contract Capacity of 53,000 kW is reduced or derated below 46,500 kW.


	d.	The Capacity Reduction Payment for the 3012 Project for the period prior to the Effective Date of Amendment No. 2 shall be an amount equal to the difference between (i) the accumulated Monthly Capacity Payments paid by Edison to the 3012 Project in respect of the 3012 Project Reduction Amount (as defined below) pursuant to Capacity Payment Option B from March 3, 1988 to the Effective Date of Amendment No. 2, and (ii) the total capacity payments which Edison would have paid to the 3012 Project in respect of the 3012 Project Reduction Amount (as defined below) during that time period if based on the 3012 Project Adjusted Capacity Price.

The 3012 Project Reduction Amount shall be 15/46.5 of the quantity, in kW, by which the Contract Capacity of 53,000 kW is reduced or derated below 46,500 kW.


	e.	The Capacity Reduction Payment for the period after the Effective Date of Amendment No. 2 shall be an amount equal to the difference between (i) the accumulated Monthly Capacity Payments paid by Edison to the Generating Facility in respect of the Generating Facility Reduction Amount (as defined below) pursuant to Capacity Payment Option B after the Effective Date of Amendment No. 2, and (ii) the total capacity payments which Edison would have paid to the Generating Facility in respect of the Generating Facility Reduction Amount (as defined below) during that time period if based on the weighted average of the 3010 Project Adjusted Capacity Price and the 3012 Project Adjusted Capacity Price, weighted based on the original Contract Capacities of the 3010 and 3012 Projects (31,500 kW and 15,000 kW, respectively).

The Generating Facility Reduction Amount shall be the quantity, in kW, by which the Contract Capacity of 53,000 kW is reduced or derated below 46,500 kW.


	1.26	Sections 8.1.2.6 and 8.1.2.7 shall be deleted in their entirety.


	1.27	Section 8.3 shall be amended by adding the following at the beginning thereof:

‘‘Subject to the last paragraph of this Section 8.3,’’

Section 8.3 shall be further amended by adding the following new paragraph at the end thereof:

‘‘Energy pricing for the Generating Facility is subject to the Agreement Addressing Renewable Energy Pricing and Payment Issues for the 3010 Project until May 1, 2007. On and after May 1, 2007, the energy pricing for the Generating Facility will be subject to the Agreement No. 2 Addressing Renewable Energy Pricing Issues for the 3010 Project.’’

1.28 Section 9.3.2 shall be deleted in its entirety.


	1.29	Section 15.1 shall be amended by adding the following at the end thereof:

‘‘Insurance will cover the Generating Facility as described in Section 2.19.’’


	1.30	Appendix D to this Amendment shall be added as Appendix D to the Contract.


	1.31	Appendix E to this Amendment shall be added as Appendix E to the Contract.


	1.32	Appendix F to this Amendment shall be added as Appendix F to the Contract.


	1.33	Appendix G to this Amendment shall be added as Appendix G to the Contract.


	1.34	Appendix H to this Amendment shall be added as Appendix H to the Contract.


	1.35	Appendix I to this Amendment shall be added as Appendix I to the Contract.

OTHER TERMS AND CONDITIONS

In consideration of the mutual promises and covenants and agreements hereinafter set forth and for other good and valuable consideration, receipt of which is hereby acknowledged, as of the Effective Date (defined in Section 2.1, below), the Parties further agree as follows:


2.	Effective Date and Termination


	2.1	This Amendment shall become binding when it is executed by duly authorized representatives of each of the Parties, except that the entirety of Section 1 above (including Sections 1.1 through 1.35) shall only become effective, as of March 1, 2007, on the first day on which each of the following has occurred (‘‘Effective Date’’): (i) execution of the Termination Agreement in substantially the form attached hereto as Appendix B by duly authorized representatives of Edison and Seller; (ii) execution of the Settlement Agreement in substantially the form attached hereto as Appendix C by duly authorized representatives of Edison and Seller; and (iii) payment by Seller to Edison of the sum of $1,150,000 (one million one hundred fifty thousand dollars) as provided in this Amendment and the Settlement Agreement.


	2.2	Concurrently with the execution of this Amendment, Edison and Seller shall execute the Termination Agreement in substantially the form attached hereto as Appendix B.


	2.3	Seller shall pay Edison the sum of $1,150,000 (one million one hundred fifty thousand dollars) within five (5) days after the execution of this Amendment.


	2.4	Concurrently with the execution of this Amendment, Edison and Seller shall execute the Settlement Agreement in substantially the form attached hereto as Appendix C.


	2.5	Edison will issue a final version of the draft letter regarding the William R. Gould Power Plant attached hereto as Appendix K within five (5) days after the Effective Date of this Amendment.


	2.6	The Interim Agreement attached hereto as Appendix A shall terminate and be of no further force or effect, as of March 1, 2007, on the Effective Date of this Amendment.


	2.7	Effective on the Effective Date of this Amendment, the accumulated scheduled maintenance allowance hours for the Generating Facility pursuant to Section 4.5.3 of the Contract, as of March 1, 2007, shall be the prorated combination of the 3010 and 3012 Projects’ maintenance hours. The calculation will be based on the contribution of each of the 3010 and 3012 Projects’ original Contract Capacities toward the Contract Capacity of 46,500 kW (31,500 kW and 15,000 kW respectively), their original contract capacity pricing ($170/kW-yr and $184/kW-yr respectively), and the balance of their scheduled maintenance allowance as of March 1, 2007. An example of the calculation is found attached hereto in Appendix J.


	2.8	Seller and Ormat shall, jointly and severally, indemnify and hold Edison harmless from and against any rate or other disallowance by the Commission resulting from Edison’s entry into (but not administration of) this Amendment, the Settlement Agreement or the Termination Agreement; provided that Seller’s and Ormat’s joint and several liability under this Section 2.8 shall be limited to $4,600,000 (four million six hundred thousand dollars); and provided further that Seller’s and Ormat’s obligations under this Section 2.8 shall expire on the earlier of: (a) the date on which the Commission issues a decision, no longer subject to appeal, approving this Amendment, the Settlement Agreement and the Termination Agreement (subject to Edison’s prudent administration thereof) without modification or conditions unacceptable to Edison, in its reasonable discretion, or (b) the date that is three (3) years after the Effective Date of this Amendment.


	2.9	Edison agrees to make a timely and appropriate request for Commission approval of this Amendment, which may be in its next Energy Resource Recovery Application, and to diligently and in good faith pursue such Commission approval, including timely and properly


		responding to requests for information and taking any reasonable actions as requested by the Commission. Edison agrees to keep Seller informed as to the status of such request for Commission approval and to cooperate in good faith with Seller in connection with such request for Commission approval. Notwithstanding anything in this Amendment to the contrary, Edison shall have no obligation to seek rehearing or to appeal a Commission decision which disallows the recovery by Edison of any amounts paid or to be paid under this Amendment, fails to approve this Amendment, or which contains findings with conditions or modifications unacceptable to any Party.


	2.10	Effective on the Effective Date of this Amendment, the Parties agree that there will be no Capacity Bonus Payment for the Generating Facility pursuant to Section 8.1.2.4 of the Contract for the months of January through May of 2007. The Parties further agree that Seller shall be on probation pursuant to Section 8.1.2.2a of the Contract for the period beginning on March 1, 2007 and ending on October 1, 2007.


3.	Except as amended herein, all terms, covenants and conditions in the Contract shall remain in full force and effect.


4.	Terms or words that are capitalized and not defined in this Amendment shall have the same meaning as in the Contract.

None of the provisions of this Amendment, including this Section, shall be considered waived by any Party except when such waiver is given in writing. The failure of any Party to insist in any one or more instances upon strict performance of any of the provisions of this Amendment or to take advantage of any of its rights hereunder shall not be construed as waiver of any such provisions or the relinquishment of any such rights for the future, but the same shall continue and remain in full force and effect.


6.	This Amendment shall not be amended, changed, modified, abrogated, or superseded by a subsequent agreement unless such subsequent agreement shall be in the form of a written instrument signed by all Parties.


7.	This Amendment shall be binding upon and inure to the benefit of the Parties hereto and their respective successors and assigns. Notwithstanding the foregoing, Seller shall not assign any rights or delegate any duties under the Contract, as modified by this Amendment, except as provided in Section 24 of the Contract.


8.	If any provision or provisions of this Amendment shall be held to be invalid, illegal or unenforceable, the validity, legality or enforceability of the remaining provisions hereof shall not in any way be affected or impaired thereby so long as the economic and legal substance of this Amendment are not affected in a manner materially adverse to any Party.


9.	The headings in this Amendment are for purposes of reference only and shall not limit or otherwise affect the meaning hereof.

10.

This Amendment, the Termination Agreement and the Settlement Agreement shall constitute the entire agreement of the Parties as to the subject matter of this Amendment, the Termination Agreement and the Settlement Agreement and shall supersede any and all prior or contemporaneous negotiations, correspondence, undertakings, and agreements between the Parties concerning the particular subject matter of this Amendment, the Termination Agreement and the Settlement Agreement.


11.	This Amendment is the result of negotiation and each Party has participated in the preparation of this Amendment. Accordingly, any rules of construction to the effect that any ambiguity shall be resolved against the drafting Party shall not be employed in the interpretation of this Amendment.


12.	This Amendment shall be governed by, construed and enforced in accordance with the laws of the State of California, without giving effect to choice of law provisions that might apply the laws of a different jurisdiction.


13.	This Amendment may be executed in counterparts, each of which shall be deemed to be an original and all of which, taken together, shall constitute a single document. This Amendment may be executed by signature via facsimile transmission which shall be deemed the same as an original signature.


14.	Each Party represents and warrants that the person who signs below on behalf of such Party has authority to execute this Amendment on behalf of the Party for whom such person signs.

15.

Each notice which any Party gives under or in connection with this Amendment shall be in writing and shall be deemed given as follows: (i) notice by facsimile or hand delivery shall be deemed given at the close of business on the day actually received, if received during business hours on a business day, and otherwise shall be deemed given at the close of business on the next business day; (ii) notice by overnight mail or courier service shall be deemed given on the next business day after it was sent out; and (iii) notice by first class United States mail shall be deemed given two (2) business days after the postmarked date.

Notice shall be addressed to the Parties as follows:


	If to Edison:	Southern California Edison Company Renewable and Alternative Power Department Manager, Contract Administration 2244 Walnut Grove Avenue Rosemead, California 91770 Facsimile: (626) 302-9622

With a copy to:

Southern California Edison Company
Law Department
Manager, Power Procurement Section
2244 Walnut Grove Avenue
Rosemead, California 91770
Facsimile: (626) 302-1904


	If to Seller:	Ormesa LLC c/o Ormat Nevada, Inc. 6625 Neil Road Reno, Nevada 89511 Facsimile: (775) 356-9039


	If to Ormat:	Ormat Technologies, Inc. 6625 Neil Road Reno, Nevada 89511 Facsimile: (775) 356-9039

16.

The execution of, and entry into, this Amendment by Ormat does not in any way make Ormat a party to or otherwise obligate, or subject to liability, Ormat under the Contract or any other agreement or instrument other than this Amendment. Ormat’s obligations under this Amendment are limited to those obligations set forth in Section 2.8 hereof; provided that Sections 2.1 and 3 through 17 of this Amendment are also binding on and/or applicable to Ormat.


17.	IN WITNESS WHEREOF, the Parties hereto have caused this Amendment to be executed by their duly authorized representatives on the dates indicated below the signatures.


SOUTHERN CALIFORNIA EDISON COMPANY , a California corporation			ORMESA LLC , a Delaware limited liability company
By:			By:
Name: Pedro J. Pizarro			Name:
Title: Senior Vice President, PPBU			Title:
Date:			Date:

ORMAT TECHNOLOGIES, INC.,
a Delaware corporation

By:
        Name:
        Title:
        Date:

Southern California Edison

APPENDIX A

Interim Agreement

Appendix A

Interim Agreement

November 8, 2005

Mr. Kevin Payne
Director, QF Resources

2244 Walnut Grove Avenue

Rosemead, CA 91770

Re: Interim Agreement between Ormesa LLC and Southern California Edison Company to Accept Electrical Energy Deliveries from Geo East Mesa Generating Units 2 and 3 on an Interim Basis (QFIDs 3010. 3012)

Dear Mr. Payne:

Attached is an executed Interim Agreement. Please be aware that in executing and performing under the Interim Agreement, Ormesa LLC does not concede any of Edison’s arguments or assertions in connection with our pending dispute and reserves all of its rights in connection therewith. Ormesa views the Interim Agreement as an interim settlement between Ormesa and Edison in which the status quo concerning the dispute is tolled.

As the Interim Agreement indicates, it is our mutual desire to resolve the dispute promptly with a amicable long-term settlement agreement.

Regards,

/s/ Hezy Ram

ORMESA LLC

980 Greg Street • Sparks, Nevada 89431-6039 • Telephone (775) 356-9029 • Facsimile (775) 356-9039

Bruce L. McCarthy

Manager, QF Contract Management
QF Resources
(626) 302-8667
FAX: (626) 302-9622

November 3, 2005

Via Certified Mail

Mr. Hezy Ram
Executive Vice President
ORMAT Nevada Inc.
980 Greg Street
Sparks, NV 89431

Dear Mr. Ram:

SUBJECT:

Interim Agreement between Ormesa LLC and Southern California Edison Company to Accept Electrical Energy Deliveries from Geo East Mesa Generating Units 2 and 3 on an Interim Basis, (QFIDs 3010, 3012)

The purpose of this letter is to memorialize an agreement (“Agreement”) between Ormesa LLC (“Ormesa”) and Southern California Edison Company (“SCE”) whereby SCE agrees to accept electrical energy deliveries from Geo East Mesa (“GEM”) generating units numbers 2 and 3, which are depicted in the attached East Mesa Electrical Schematic [from mid-August 2005] (“GEM electrical generation”) on an interim basis under the terms of the “Ormesa I” power purchase agreement (QFID 3010) (the “Ormesa I PPA”), as modified by the terms of this Agreement. By this Agreement, SCE and Ormesa also agree to modify the measurement per the attached Exhibit A, for payment purposes, of electrical generation under the Ormesa I PPA and the “Ormesa II” power purchase agreement (QFID 3012) (“Ormesa II PPA”).

The sole payment to be made by SCE to Ormesa for GEM electrical generation is an energy-only price of 5.37 cents per kilowatt-hour. This energy-only price shall be time-differentiated by time-of-delivery period in the manner utilized for energy payments in the Ormesa I PPA. There will be no capacity or other payments for GEM electrical generation. The capacity payments for Ormesa I and II shall be determined according to the Ormesa I and II PPAs, but the kWh amount used to determine the capacity and energy payments under these PPAs shall be derived as described in Exhibit A, section 1.01(b). Ormesa hereby conveys to SCE all environmental attributes, capacity attributes and resource adequacy benefits associated with all electrical generation under the Ormesa I and Ormesa II PPAs, including the GEM electrical generation. SCE may count such electrical generation toward any renewable energy procurement requirements and resource adequacy rulings or requirements applicable to SCE.

Mr. Hezy Ram

ORMAT Nevada Inc.

October 24, 2005

Page 2

For purposes of this Agreement, and the Ormesa I and II PPAs, GEM electrical generation, and electrical generation from Ormesa I and II under the Ormesa I and II PPAs, shall be calculated as described in the attached Exhibit A. Ormesa shall provide to SCE prompt and unimpeded access to the SCE meters installed at Ormesa I, Ormesa II, and the IID Highline Substation depicted on the attached East Mesa Electrical Schematic [from mid-August 2005] (“Schematic”), for purposes of administration of this Agreement and to all electronic and other records and files necessary for SCE to determine GEM electrical generation in an accurate and timely fashion.

Ormesa represents and warrants that the existing generating equipment, production and injection well equipment, and interconnection configuration described in the attached Schematic for Ormesa I, Ormesa II, and GEMs, (“Configuration”) as well as any agreements or arrangements between Ormesa and Imperial Irrigation District regarding interconnection, scheduling, transmission or retail electric service for or related to the projects or loads currently affiliated with the Ormesa I PPA and the Ormesa II PPA (collectively, the “IID Agreements”) shall be preserved for the entirety of this Agreement unless written permission to modify the Configuration or the IID Agreements is obtained from SCE, whose permission shall not be unreasonably withheld.

Ormesa represents and warrants that it has full authority to convey the GEM electrical generation. SCE and Ormesa each represent and warrant that the execution and performance of this Agreement are within its powers, have been duly authorized by all necessary action and do not violate any of the terms and conditions of its governing documents or any contracts to which it is a party.

This Agreement shall be effective as of November 1, 2005. SCE shall have the right, in its sole and absolute discretion to terminate this Agreement at any time on written notice given under the terms of the PPA, which termination shall be effective as follows: (i) on the first day of the calendar month immediately following the date on which notice is given provided such notice is given on or before the 25 ^th day of a calendar month, (ii) the first day of the second calendar month after the date such notice is given if the notice is given after the 25 ^th day of a calendar month. Ormesa shall have the right, in its sole and absolute discretion to terminate this Agreement at any time on written notice given under the terms of the PPA, which termination shall be effective, subject to the proviso below, as follows: (i) on the first day of the calendar month immediately following the date on which notice is given provided such notice is given on or before the 25 ^th day of a calendar month, (ii) the first day of the second calendar month after the date such notice is given if the notice is given after the 25 ^th day of the calendar month, provided that no such termination by Ormesa shall be effective before May 1, 2007.

Except as expressly provided herein, the Ormesa I PPA and the Ormesa II PPA shall not be modified and shall remain in full force and effect.

Mr. Hezy Ram

ORMAT Nevada Inc.

October 24, 2005

Page 3

Ormesa and SCE desire to replace this Agreement with a long-term agreement for, among other things, the supply to SCE of GEM electrical generation. Ormesa and SCE shall promptly attempt to negotiate this long-term agreement. However, no such long-term agreement shall be binding upon either of the parties until a definitive agreement is negotiated and executed by authorized representatives of both SCE and Ormesa. SCE and Ormesa expressly preserve all of their respective rights, remedies, claims and defenses arising from or relating to the delivery to SCE of GEM electrical generation during periods before the effective date of this Agreement and after the effective date of any termination of this Agreement.

Sincerely,
/s/ Bruce McCarthy
Bruce McCarthy

Southern California Edison Company
By:	/s/ Kevin M. Payne
	Kevin M. Payne Director, QF Resources

Date:	11/3/05

Ormesa LLC
By:	ORMAT FUNDING CORP.
By:	/s/ Raj Raviv	( Raj Raviv )
	[Print Name]

Title	VICE PRESIDENT

Date	11/6/2005

Southern California Edison

Confidential Information

EXHIBIT A

Monthly Contract Energy Payment Calculation

The contents of this document are subject to restrictions on disclosure.

Exhibit A	Monthly Contract Energy Payment Calculation
Page 1

Southern California Edison

Confidential Information

EXHIBIT A

Table of Contents

EXHIBIT A		1
Table of Contents		2
SCE’S OBLIGATIONS		3
1.01	Payments	3
(a)	Monthly Energy Payment Formula:	3
(b)	Calculated Amounts:	4
1.02	TOD Periods	8
1.03	Energy Payment Allocation Factors	9
Attachment 1		10

The contents of this document are subject to restrictions on disclosure.

Exhibit A	Monthly Contract Energy Payment Calculation
Page 2

Southern California Edison

Confidential Information

EXHIBIT A

Monthly Contract Energy Payment Calculation

SCE’S OBLIGATIONS

1.01

Payments.

(a)

Monthly Energy Payment Formula:

(i)

For the purpose of calculating monthly Energy Payments, Calculated Amounts shall be time-differentiated according to the time period and season of delivery (“TOD Periods”) set forth in Section 1.02 and weighted by the Energy Payment Allocation Factors set forth in Section 1.03 of this Exhibit A and adjusted for losses to Mirage Substation.

(ii)

As set forth in Section 1.02 of this Exhibit A, TOD Periods for the winter season shall be mid-peak, off-peak and super off-peak and TOD Periods for the summer season shall be on-peak, mid-peak and off-peak.

(iii)

Monthly Energy Payments shall equal the sum of the monthly TOD Period Energy Payments for all TOD Periods in the month. Each monthly TOD Period Energy Payment shall be calculated pursuant to the following formula, where “n” is the TOD Period being calculated:

TOD PERIOD _n ENERGY PAYMENT = EP x EF x

La stHo ur

FirstHour

CA _h

Where:

EP =

Energy Price is $0.0537 in $/kWh.

EF =

Energy Payment Allocation Factor for the TOD Period being calculated as set forth in Section 1.03 of this Exhibit A.

CA _h =

The hour, ‘h’, Calculated Amounts as defined in Section 1.01(b) in this Exhibit A for the TOD Period being calculated in kWh.

The contents of this document are subject to restrictions on disclosure .

Exhibit A	Monthly Contract Energy Payment Calculation
Page 3

Southern California Edison

Confidential Information

(b)

Calculated Amounts:

The energy deliveries, in kWh, to SCE from Seller (“Calculated Amounts”) in each TOD hour shall be determined as follows for each project:

(i)

Ormesa I:

CALCULATED AMOUNTS FOR ORMESA I = (M _B - F ₁ x LF) x AF

Where:

M _B	=	Metered Energy in kWh, from SCE Ormesa I meter ‘M _B ’ as shown in Attachment 1 of this Exhibit A
F ₁	=	Ormesa I Factor as set forth in Section 1.01(b)(i)1).
LF	=	Load Factor as set forth in Section 1.01(b)(iv).
AF	=	TOD Loss Adjustment Factor as set forth in Section 1.01(b)(v).

Ormesa I Factor:
factor ‘F ₁ ’ in Section 1.01(b)(i).

ORMESA I FACTOR = M _B / (M _B + M _C )

Where:

M _B	=	Metered Energy in kWh, from SCE Ormesa I meter ‘M _B ’ as shown in Attachment 1 of this Exhibit A
M _C	=	Metered Energy in kWh, from SCE Ormesa II meter ‘M _C ’ as shown in Attachment 1 of this Exhibit A

(ii)

Ormesa II:

CALCULATED AMOUNTS FOR ORMESA II = (M _C - F ₂ x LF) x AF

Where:

M _C

Metered Energy in kWh, from SCE Ormesa II meter ‘M _C ’ as shown in Attachment 1 of this Exhibit A

The contents of this document are subject to restrictions on disclosure .

Exhibit A	Monthly Contract Energy Payment Calculation
Page 4

Southern California Edison

Confidential Information

F ₂	=	Ormesa II Factor as set forth in Section 1.01(b)(ii)l).
LF	=	Load Factor Four as set forth in Section 1.01(b)(iv).
AF	=	TOD Loss Adjustment Factor as set forth in Section 1.01(b)(v).

Ormesa II Factor:
factor ‘F ₂ ’ in Section 1.01(b)(ii).

ORMESA II FACTOR = M _C / (M _C + M _B )

Where:

M _{_C}	=	Metered Energy in kWh, from SCE Ormesa II meter ‘M _C ’ as shown in Attachment 1 of this Exhibit A
M _B	=	Metered Energy in kWh, from SCE Ormesa I meter ‘M _B ’ as shown in Attachment 1 of this Exhibit A
M _A	=	Metered Energy in kWh, from SCE Master meter ‘M _A ’ as shown in Attachment 1 of this Exhibit A.

(iii)

GEM:

CALCULATED AMOUNTS FOR GEM = GN x AF

Where:

GN	=	GEM Net Energy as set forth in Section 1.01(b)(iii)1).
AF	=	TOD Loss Adjustment Factor as set forth in Section 1.01(b)(v).

GEM Net Energy:
factor ‘GN’ in Section 1.01(b)(iii).

GEM NET ENERGY IS:

The greater of:

= [M _A -(M _B + M _C )], or

= Zero (0).

The contents of this document are subject to restrictions on disclosure .

Exhibit A	Monthly Contract Energy Payment Calculation
Page 5

Southern California Edison

Confidential Information

Where:

M _A	=	Metered Energy in kWh, from SCE Master meter ‘M _A ’ as shown in Attachment 1 of this Exhibit A.
M _B	=	Metered Energy in kWh, from SCE Ormesa I meter ‘M _B ’ as shown in Attachment 1 of this Exhibit A.
M _C	=	Metered Energy in kWh, from SCE Ormesa II meter ‘M _C ’ as shown in Attachment 1 of this Exhibit A.

(iv)

L oad Factor to account for hours when Metered Energy at the Highline Substation SCE meter (“Master Meter”) is not greater than SCE Metered Energy from Ormesa I and II:

factor ‘LF’ in Section 1.01(b)(i), (ii), and (iii).

L OAD F ACTOR IS:

The greater of:

= (M _B +M _C -M _A ), or

= Zero (0).

Where:

M _B	=	Metered Energy in kWh, from SCE Ormesa I meter ‘M _B ’ as shown in Attachment 1 of this Exhibit A.
M _C	=	Metered Energy in kWh, from SCE Ormesa II meter ‘M _C ’ as shown in Attachment 1 of this Exhibit A.
M _A	=	Metered Energy in kWh, from SCE Master meter ‘M _A ’ as shown in Attachment 1 of this Exhibit A.

The contents of this document are subject to restrictions on disclosure.
Exhibit A	Monthly Contract Energy Payment Calculation
Page 6

Southern California Edison

Confidential Information

(v)

TOD Adjustment Factor for Losses to Mirage Substation for the calculation month:

factor ‘AF’ in Section 1.01(b)(i), (ii), and (iii).

TOD _n LOSS A DJUSTMENT F ACTOR:

	LastHour		LastHour
= {	∑	(S ₁ +S ₂ )}/{	∑	(A ₁ + A ₂ ) }
	FirstHour		FirstHour

Where :

S ₁	=	Scheduled Energy for Ormesa I as set forth in IID Geothermal Statement for the calculation month to SCE.
S ₂	=	Scheduled Energy for Ormesa II as set forth in IID Geothermal Statement for the calculation month to SCE.
A ₁	=	Actual Energy for Ormesa I as set forth in IID Geothermal Statement for the calculation month to SCE.
A ₂	=	Actual Energy for Ormesa II as set forth in IID Geothermal Statement for the calculation month to SCE

The contents of this document are subject to restrictions on disclosure.
Exhibit A	Monthly Contract Energy Payment Calculation
Page 7

Southern California Edison

Confidential Information

1.02	TOD Periods.

Time of Delivery Periods (“TOD Periods”)
TOD Period	Summer Jun 1 ^st – Sep30 ^th	Winter Oct 1 ^st – May 31st	Applicable Days
On-Peak	Noon – 6:00 p.m.	Not Applicable.	Weekdays except Holidays.
Mid-Peak	8:00 a.m.– Noon	8:00 a.m. – 9:00 p.m.	Weekdays except Holidays.
Mid-Peak	6:00 p.m. – 11:00 p.m.	8:00 a.m. – 9:00 p.m.	Weekdays except Holidays.
Off-Peak	11:00 p.m. – 8:00 a.m.	6:00 a.m. – 8:00 a.m.	Weekdays except Holidays.
	11:00 p.m. – 8:00 a.m.	9:00 p.m. – Midnight	Weekdays except Holidays.
	Midnight – Midnight	6:00 a.m. – Midnight	Weekends and Holidays
Super-Off-Peak	Not Applicable.	Midnight – 6:00 a.m.	Weekdays, Weekends and Holidays

“Holiday” is defined as New Year’s Day, Presidents’ Day, Memorial Day, Independence Day, Labor Day, Veterans Day, Thanksgiving Day, and Christmas Day.

When any Holiday listed above falls on a Sunday, the following Monday will be recognized as an off-peak period. No change will be made for Holidays falling on Saturday.

The contents of this document are subject to restrictions on disclosure.

Exhibit A	Monthly Contract Energy Payment Calculation
Page 8

Southern California Edison

Confidential Information

1.03 Energy Payment Allocation Factors.

Energy Payment Allocation Factors

Season	TOD Period	Calculation Method	Energy Payment Allocation Factor
Summer	On-Peak	Fixed Value.	1.4251
	Mid-Peak	(Total # hours in month - (1.4251 x # Summer On-Peak hours in month)- (0.8526 x # Summer Off-Peak hours in month)) / #Summer Mid-Peak hours in month	Calculated Value
	Off-Peak	Fixed Value.	0.8526
Winter	Mid-Peak	Fixed Value.	1.2185
	Off-Peak	(Total # hours in month - (1.2185 x # Winter Mid-Peak hours in month)- (0.7760 x # Winter Super-Off-Peak hours in month)) / #Winter Off-Peak hours in month	Calculated Value
	Super-Off-Peak	Fixed Value.	0.7760

The contents of this document are subject to restrictions on disclosure .

Exhibit A	Monthly Contract Energy Payment Calculation
Page 9

Southern California Edison

Confidential Information

Attachment 1

Ormesa/GEM Meter Configuration

*** End of Exhibit A ***

The contents of this document are subject to restrictions on disclosure .

Exhibit A	Monthly Contract Energy Payment Calculation
Page 10

Southern California Edison

APPENDIX B

Form of Termination Agreement

Appendix B

Form of Termination Agreement

CONTRACT TERMINATION AGREEMENT
between
ORMESA LLC
and
SOUTHERN CALIFORNIA EDISON COMPANY
(RAP ID 3012)

This Contract Termination Agreement (‘‘Agreement’’) is entered into by ORMESA LLC, a Delaware limited liability company (‘‘Seller’’) and SOUTHERN CALIFORNIA EDISON COMPANY, a California corporation (‘‘Edison’’). Seller and Edison are sometimes referred to herein individually as a ‘‘Party’’ and collectively as the ‘‘Parties.’’

RECITALS

This Agreement is entered into with reference to the following facts, among others:


	A.	On June 13, 1984, Edison and Ormat Systems, Inc. (‘‘Ormat’’) entered into a Power Purchase Contract (‘‘PPC’’), under which Ormat delivered to Edison, in exchange for compensation, electrical power generated by a geothermal project (‘‘3012 Project’’) located in East Mesa, Imperial County, California. Edison identifies the 3012 Project as RAP ID 3012. The ‘‘PPC’’ is henceforth deemed to mean the PPC as amended, supplemented, or otherwise modified from time to time.


	B.	On April 30, 1987, Ormat assigned all of its rights to and interests in the PPC to Ormat Energy Systems, Inc. (‘‘Ormat Energy’’). On that date, Ormat Energy also assigned all of its rights to and interests in the PPC to Ormesa Geothermal II. On July 28, 1987, Edison consented to the assignments.


	C.	On June 19, 2001, Edison and Ormesa Geothermal II entered into the Agreement Addressing Renewable Energy Pricing and Payment Issues (‘‘Renewable Agreement’’).


	D.	On November 30, 2001, Edison and Ormesa Geothermal II entered into Amendment No. 1 to the Renewable Agreement.


	E.	In a filing before the Federal Energy Regulatory Commission (‘‘FERC’’) dated December 30, 2002, Seller represented that it is the successor to Ormesa Geothermal II, following a merger between Seller and a number of its subsidiaries.


	F.	In a separate filing before FERC, also dated December 30, 2002, Seller represented that it is the successor to Ormesa Geothermal, the seller under a separate power purchase contract between Republic Geothermal, Inc. and Edison dated July 18, 1984 (‘‘3010 Contract’’), that provides for the sale to Edison of electrical power generated by a separate geothermal plant (‘‘3010 Project’’), which is also located in East Mesa, Imperial County, California. Edison identifies the 3010 Project as RAP ID 3010.


	G.	In 2002, the Parties entered into negotiations to discuss the consolidation of the 3010 and 3012 Projects and the termination of the PPC.


	H.	On or about November 22, 2002 and April 28, 2003, and subsequently on June 21, 2005, the Parties entered into confidentiality agreements protecting their negotiations from public disclosure.


	I.	On or about May 1, 2003, the Parties reached an agreement, subject to California Public Utilities Commission (‘‘CPUC’’ or ‘‘Commission’’) approval, regarding the consolidation of the 3010 and 3012 Projects and the termination of the PPC. Edison withdrew its support for the consolidation and termination based upon concerns that the 3010 and 3012 Projects were interconnected with another Qualifying Facility (‘‘QF’’), Geo East Mesa (‘‘GEM’’), which had previously sold its output to Edison under a QF contract that was terminated pursuant to a Commission-approved buyout agreement. Edison alleged that, in view of the interconnection, the consolidation might improperly facilitate sales of GEM-produced power to Edison under


		the terms of the consolidated QF contract. Although the Commission initially approved the Parties’ agreement regarding the consolidation and termination on October 16, 2003 in Resolution E-3848, on January 22, 2004, the Commission granted Edison’s application for rehearing and vacated Resolution E-3848. Accordingly, the 3010 and 3012 Projects remained separate projects, subject to separate contracts.


	J.	Edison contends that, since approximately 2003, the 3010 and 3012 Projects have been interconnected with GEM generating units that are not part of the 3010 and 3012 Projects, and that the 3010 and 3012 Projects improperly sold power generated by the GEM generating units to Edison pursuant to the 3010 Contract and the PPC resulting in overpayments by Edison to Seller. Seller disputes Edison’s contentions. This dispute shall henceforth be known as the ‘‘Dispute.’’


	K.	Edison protested a recertification filed by the 3012 Project with FERC disputing the project capacity amount designated by the 3012 Project. After FERC rejected Edison’s protest in part, Edison appealed to the United States Court of Appeals for the District of Columbia Circuit. The Court of Appeals affirmed FERC’s ruling and subsequently denied Edison’s petition for rehearing. This dispute shall henceforth be known as the ‘‘FERC Dispute.’’


	L.	On or about November 6, 2005, the Parties entered into an Interim Agreement (‘‘Interim Agreement’’), effective as of October 1, 2005, whereby Edison agreed, without prejudicing either Party’s positions in respect of the Dispute, to permit Seller to supply electrical energy deliveries from GEM under the 3010 Contract on an interim basis. In the Interim Agreement, the sole payment to be made by Edison to Seller for GEM power is an energy-only price of 5.37 cents/kWh, which is time-differentiated by time-of-delivery period in the manner utilized for energy payments under the Contract. The Interim Agreement, which may be terminated by either Party after May 1, 2007, was intended to bridge the interim time period until a final agreement regarding the Dispute and the FERC Dispute could be negotiated and executed by the Parties.


	M.	On or about May 10, 2006, the Parties entered into Agreement No. 2 Addressing Renewable Energy Pricing Issues for the 3010 and 3012 Projects. Those agreements provide for a new fixed energy price starting at 6.15 cents/kWh on May 1, 2007. The agreements are silent about GEM power.


	N.	Pursuant to the 3010 Contract and the PPC, the capacity payment allowance for scheduled maintenance for the 3010 and 3012 Projects shall not exceed 840 hours in any twelve month period. On or about March 2006, the 3010 Project used up its allotment of maintenance hours. On July 28, 2006, Seller sent an e-mail to Edison stating that it had made a data entry error and requested an adjustment in maintenance hours credit for the 3010 Project for November 2005 through May 2006 such that the maintenance hours previously scheduled by Seller for the 3010 Project during that time period be applied solely to mid-peak hours. On January 9, 2007, Edison sent Seller a letter denying Seller’s request. This dispute shall henceforth be known as the ‘‘Maintenance Hours Dispute.’’


	N.	The Parties have now reached a final agreement on the consolidation of the 3010 and 3012 Projects and the delivery of power from GEM to Edison which provides, among other things, for (i) the potential for Seller to deliver GEM power to Edison from a combined project consisting of the 3010 and 3012 Projects and GEM, (ii) an increase in the amount of electricity to be sold to Edison from the combined project of up to 6.5 MW more than the previous amounts that were covered by the 3010 Contract and the PPC, which incremental amount will receive an energy only price, (iii) the termination of the PPC and the Interim Agreement, and (iv) the settlement of the Dispute, the FERC Dispute and the Maintenance Hours Dispute. Accordingly, the Parties agree to terminate the PPC as set forth herein.


	O.	Concurrently with this Agreement, the Parties and Ormat Technologies, Inc. are executing Amendment No. 2 to the 3010 Contract (‘‘Amendment No. 2’’) to effectuate the consolidation of the 3010 and 3012 Projects under the 3010 Contract; and the Parties are executing a Settlement Agreement that settles the Dispute, the FERC Dispute and the Maintenance Hours Dispute between the Parties (‘‘Settlement Agreement’’).

AGREEMENT


1.	TERMINATION OF THE PPC

Notwithstanding anything to the contrary in the PPC, on the Effective Date (as defined below), the PPC shall terminate as of March 1, 2007. The ‘‘Effective Date’’ is the first day on which each of the following has occurred: (i) execution of this Agreement by duly authorized representatives of both of the Parties; (ii) payment by Seller to Edison of the sum of $1,150,000 (one million one hundred fifty thousand dollars) as provided in Amendment No. 2 and the Settlement Agreement; (iii) execution of Amendment No. 2 by duly authorized representatives of the Parties and Ormat Technologies, Inc.; and (iv) execution of the Settlement Agreement by duly authorized representatives of both of the Parties.


2.	INDEMNIFICATION

Upon termination of the PPC and continuing thereafter, Seller shall indemnify and hold Edison harmless from and against any and all claims, damages, demands, losses, expenses, debts, accounts, obligations, costs, expenses, liens, actions or causes of action and other liabilities (including without limitation reasonable legal and accounting fees and costs) of any nature suffered or incurred by Edison that arise out of or relate to or are in connection with any claims or judgment brought or obtained by any third party or other person claiming rights as a Seller under the PPC.


3.	RELEASES

Upon termination of the PPC and continuing thereafter, Seller, on its own behalf and on behalf of each of its successors and assigns by operation of law or otherwise, releases and forever discharges Edison, and each of its past, present and future shareholders, officers, directors, employees, representatives, insurers, attorneys, parent corporations, subsidiary corporations and/or other affiliates, and successors and assigns, whether by operation of law or otherwise, from any and all claims arising out of or relating to Edison’s performance, failure to perform, breach of covenants and warranty, or any other claims relating to the PPC or termination of the PPC by Edison, including but not limited to, any obligation to purchase energy or capacity under the PPC; provided that this release shall not affect Edison’s and/or Seller’s rights and/or obligations under Sections 2.7, 2.8 and 2.10 of Amendment No. 2. This release does not extend to payment for power deliveries by Seller to Edison in the ordinary course of business under the PPC before the effective date of the PPC termination, which deliveries have not been paid for by Edison as of the effective date of the PPC termination.

Upon termination of the PPC and continuing thereafter, Edison, on its own behalf and on behalf of each of its successors and assigns by operation of law or otherwise, releases and forever discharges Seller, and each of its past, present and future shareholders, officers, directors, employees, representatives, insurers, attorneys, parent corporations, subsidiary corporations and/or other affiliates, and successors and assigns, whether by operation of law or otherwise, from any and all claims arising out of or relating to Seller’s performance, failure to perform, breach of covenants and warranty, or any other claims relating to the PPC or termination of the PPC by Edison, including but not limited to, any obligation to sell energy or capacity under the PPC; provided that this release shall not affect Edison’s and/or Seller’s rights and/or obligations under Sections 2.7, 2.8 and 2.10 of Amendment No. 2.

Seller and Edison expressly waive and relinquish all rights and benefits afforded by Section 1542 of the Civil Code of California in any way relating to the foregoing releases as set forth in the two preceding paragraphs and do so understand and acknowledge the significance and consequences of such specific waiver of Section 1542. Section 1542 of the Civil Code of California states as follows:

‘‘A general release does not extend to claims which the creditor does not know or suspect to exist in his or her favor at the time of executing the release, which if known by him or her must have materially affected his or her settlement with the debtor.’’


4.	NO THIRD PARTY BENEFICIARIES

The Parties do not intend to create rights in, or grant remedies to, any third party as a beneficiary of this Agreement or of any duty, covenant, obligation or understanding established under this Agreement.


5.	ENTIRETY

This Agreement, Amendment No. 2 and the Settlement Agreement constitute the full and complete understanding of the Parties concerning the subject matter contained therein, and any prior agreements, representations, and understandings are hereby terminated and canceled in their entireties and are of no further force and effect.


6.	NON-WAIVER

None of the provisions of this Agreement shall be considered waived by a Party except when such waiver is given in writing. The failure of any Party at any time or times to enforce any right or obligation with respect to any matter arising in connection with this Agreement shall not constitute waiver as to future enforcement of that right or obligation or of any other right or obligation of this Agreement.


7.	AMENDMENT, FURTHER ASSURANCES

Any amendments or modifications to this Agreement shall be in writing and agreed to by each Party. Each Party agrees to execute and deliver all further instruments and documents, and take any further actions that may be reasonably necessary to effectuate the purposes and intent of this Agreement.


8.	SECTION HEADINGS

Section headings appearing in this Agreement are inserted for convenience only and shall not be construed as interpretation of text.


9.	CONSTRUCTION


	(a)	Neither Party to this Agreement shall be deemed to have drafted any part of this Agreement, and no ambiguity in the provisions of this Agreement shall be construed against any Party for having drafted any part of this Agreement.


	(b)	The Parties acknowledge that this Agreement is and will be the product of each Party’s concessions and unique circumstances.


10.	GOVERNING LAW

This Agreement shall be interpreted, governed, and construed under the laws of the State of California as if executed and to be performed wholly within the State of California (without giving effect to choice of laws provisions that might apply the laws of a different jurisdiction).


11.	COUNTERPARTS AND EXECUTION

This Agreement may be signed in counterparts, each of which shall be deemed an original and all of which shall constitute a single instrument. This Agreement may be executed by signature via facsimile transmission which shall be deemed the same as an original signature.


12.	SUCCESSORS AND ASSIGNS

This Agreement shall be binding upon and inure to the benefit of the Parties hereto and their respective successors and assigns.


13.	EFFECTIVE DATE

This Agreement shall become binding when it is executed by duly authorized representatives of each of the Parties, except that the PPC shall terminate as provided in Section 1.


14.	NOTICES

Each notice which any Party gives under or in connection with this Agreement shall be in writing and shall be deemed given as follows: (i) notice by facsimile or hand delivery shall be deemed given at the close of business on the day actually received, if received during business hours on a business day, and otherwise shall be deemed given at the close of business on the next business day; (ii) notice by overnight mail or courier service shall be deemed given on the next business day after it was sent out; and (iii) notice by first class United States mail shall be deemed given two (2) business days after the postmarked date.

Notice shall be addressed to the Parties as follows:


	If to Edison:	Southern California Edison Company Renewable and Alternative Power Department Manager, Contract Administration 2244 Walnut Grove Avenue Rosemead, California 91770 Facsimile: (626) 302-9622

With a copy to:

Southern California Edison Company
Law Department
Manager, Power Procurement Section
2244 Walnut Grove Avenue
Rosemead, California 91770
Facsimile: (626) 302-1904


	If to Seller:	Ormesa LLC c/o Ormat Nevada, Inc. 6625 Neil Road Reno, Nevada 89511 Facsimile: (775) 356-9039


15.	COMMISSION APPROVAL

Edison agrees to make a timely and appropriate request for Commission approval of this Agreement, which may be in its next Energy Resource Recovery Application, and to diligently and in good faith pursue such Commission approval, including timely and properly responding to requests for information and taking any reasonable actions as requested by the Commission. Edison agrees to keep Seller informed as to the status of such request for Commission approval and to cooperate in good faith with Seller in connection with such request for Commission approval. Notwithstanding anything in this Agreement to the contrary, Edison shall have no obligation to seek rehearing or to appeal a Commission decision which disallows the recovery by Edison of any amounts paid or to be paid under this Agreement, fails to approve this Agreement, or which contains findings with conditions or modifications unacceptable to any Party.


16.	SIGNATURE CLAUSE

Each Party represents and warrants that the person who signs below on behalf of such Party has authority to execute this Agreement on behalf of such Party without the further concurrence or approval of any person, entity or court, and that all requisite approvals and consents to enter into, and bind such Party to, this Agreement have been obtained.


17.	SIGNATURES

IN WITNESS WHEREOF, the Parties hereto have caused this agreement to be executed by their duly authorized representatives on the dates indicated below the signatures.


SOUTHERN CALIFORNIA EDISON COMPANY , a California corporation			ORMESA LLC , a Delaware limited liability company
By:			By:
Name: Pedro J. Pizarro			Name:
Title: Senior Vice President, PPBU			Title:
Date:			Date:

Southern California Edison

APPENDIX C

Form of Settlement Agreement

Appendix C

Form of Settlement Agreement

SETTLEMENT AGREEMENT

This Settlement Agreement (the ‘‘Agreement’’) is entered into by and between ORMESA LLC, a Delaware limited liability company (‘‘Ormesa’’), on the one hand, and SOUTHERN CALIFORNIA EDISON COMPANY, a California corporation (‘‘Edison’’), on the other hand. Ormesa and Edison are sometimes referred to in this Agreement individually as a ‘‘Party’’ and jointly as the ‘‘Parties.’’

RECITALS

This Agreement is entered into with reference to the following facts, among others:


	A.	On July 18, 1984, Edison and Republic Geothermal, Inc. as ‘‘Seller’’ executed the Power Purchase Contract (as amended, supplemented, or otherwise modified from time to time, the ‘‘3010 Contract’’), whereby Edison agreed to purchase energy and capacity from a geothermal power plant (the ‘‘3010 Project’’) located in East Mesa, Imperial County, California. Edison identifies the 3010 Project as RAP ID 3010. On November 6, 1984, Republic Geothermal, Inc. assigned all of its rights to and interests in the 3010 Contract to Ormat Systems, Inc. Edison consented to the assignment on December 19, 1984. On February 27, 1985, Ormat Systems, Inc. assigned all of its rights to and interests in the 3010 Contract to Ormesa Geothermal. Edison consented to the assignment on July 22, 1985. In a filing before the Federal Energy Regulatory Commission (‘‘FERC’’) dated December 30, 2002, Ormesa represented that it is the successor to Ormesa Geothermal, following a merger between Ormesa and a number of its subsidiaries.


	B.	Among other things, the 3010 Contract provides that Edison shall pay Seller an energy payment for electric energy deliveries from the 3010 Project pursuant to an energy payment option selected by Seller. The 3010 Contract also specifies that Edison shall pay Seller a separate capacity payment for the electric power production capacity from the 3010 Project that Seller dedicates to Edison.


	C.	On June 13, 1984, Edison and Ormat Systems, Inc. as ‘‘Seller’’ entered into a Power Purchase Contract (as amended, supplemented, or otherwise modified from time to time, the ‘‘3012 Contract’’), whereby Edison agreed to purchase energy and capacity from another geothermal power plant (the ‘‘3012 Project’’) located in East Mesa, Imperial County, California. Edison identifies the 3012 Project as RAP ID 3012. On April 30, 1987, Ormat Systems, Inc. assigned all of its rights to and interests in the 3012 Contract to Ormat Energy Systems, Inc. On that date, Ormat Energy Systems, Inc. also assigned all of its rights to and interests in the 3012 Contract to Ormesa Geothermal II. On July 28, 1987, Edison consented to the assignments. In a filing before FERC dated December 30, 2002, Ormesa represented that it is the successor to Ormesa Geothermal II, following a merger between Ormesa and a number of its subsidiaries.


	D.	Among other things, the 3012 Contract provides that Edison shall pay Seller an energy payment for electric energy deliveries from the 3012 Project pursuant to an energy payment option selected by Seller. The 3012 Contract also specifies that Edison shall pay Seller a separate capacity payment for the electric power production capacity from the 3012 Project that Seller dedicates to Edison.


	E.	In 2002, the Parties entered into negotiations to discuss the consolidation of the 3010 and 3012 Projects and the termination of the 3012 Contract. On or about November 22, 2002 and April 28, 2003, and subsequently on June 21, 2005, the Parties entered into confidentiality agreements protecting their negotiations from public disclosure.


	F.	On or about May 1, 2003, the Parties reached an agreement, subject to California Public Utilities Commission (‘‘CPUC’’ or ‘‘Commission’’) approval, regarding the consolidation of the 3010 and 3012 Projects and the termination of the 3012 Contract. Edison withdrew its support for the consolidation and termination based upon concerns that the 3010 and 3012 Projects were interconnected with another Qualifying Facility (‘‘QF’’), Geo East Mesa (‘‘GEM’’), which had previously sold its output to Edison under a QF contract that was


		terminated pursuant to a Commission-approved buyout agreement. Edison alleged that, in view of the interconnection, the consolidation might improperly facilitate sales of GEM-produced power to Edison under the terms of the consolidated QF contract. Although the Commission initially approved the Parties’ agreement regarding the consolidation and termination on October 16, 2003 in Resolution E-3848, on January 22, 2004, the Commission granted Edison’s application for rehearing and vacated Resolution E-3848. Accordingly, the 3010 and 3012 Projects remained separate projects, subject to separate contracts.


	G.	Edison contends that, since approximately 2003, the 3010 and 3012 Projects have been interconnected with GEM generating units that are not part of the 3010 and 3012 Projects, and that the 3010 and 3012 Projects improperly sold power generated by the GEM generating units to Edison pursuant to the 3010 and 3012 Contracts resulting in overpayments by Edison to Ormesa. Ormesa disputes Edison’s contentions. The dispute described in this Recital G shall henceforth be known as the ‘‘Dispute.’’


	H.	On February 3, 2004, Ormesa filed an application with FERC for recertification that the net capacity of the 3012 Project is 16.57 MW (FERC Docket No. QF86-681-005). In March 4, 2004, Edison protested Ormesa’s application for recertification. On April 16, 2004, FERC granted Ormesa’s application for recertification that the net capacity of the 3012 Project is 15.22 MW. FERC also ruled that the 3012 Project could sell an additional 1.35 MW purchased from another QF without jeopardizing its QF status. Ormesa and Edison both requested rehearing from FERC. On September 22, 2004, FERC denied rehearing. On November 22, 2004, Edison filed a petition for review of FERC’s orders to the United States Court of Appeals for the District of Columbia Circuit (U.S. Court of Appeals for the District of Columbia Circuit, Case No. 04-1396). On March 24, 2006, the Court of Appeals affirmed FERC’s rulings. On May 8, 2006, Edison filed a petition for panel rehearing which was denied by the Court of Appeals on June 2, 2006. This dispute described in this Recital H shall henceforth be known as the ‘‘FERC Dispute.’’


	I.	On or about November 6, 2005, the Parties entered into an Interim Agreement (‘‘Interim Agreement’’), effective as of October 1, 2005, whereby Edison agreed, without prejudicing either Party’s positions in respect of the Dispute, to permit Ormesa to supply electrical energy deliveries from GEM under the 3010 Contract on an interim basis. In the Interim Agreement, the sole payment to be made by Edison to Ormesa for GEM power is an energy-only price of 5.37 cents/kWh, which is time-differentiated by time-of-delivery period in the manner utilized for energy payments under the 3010 Contract. The Interim Agreement, which may be terminated by either Party after May 1, 2007, was intended to bridge the interim time period until a final agreement regarding the Dispute and the FERC Dispute could be negotiated and executed by the Parties.


	J.	Pursuant to the 3010 and 3012 Contracts, the capacity payment allowance for scheduled maintenance for the 3010 and 3012 Projects may not exceed 840 hours in any twelve month period. On or about March 2006, the 3010 Project used up its allotment of maintenance hours. On July 28, 2006, Ormesa sent an e-mail to Edison stating that it had made a data entry error and requested an adjustment in maintenance hours credit for the 3010 Project for November 2005 through May 2006 such that the maintenance hours scheduled by Ormesa for the 3010 Project during that time period be applied solely to mid-peak hours. On January 9, 2007, Edison sent Ormesa a letter denying Ormesa’s request. The dispute described in this Recital J shall henceforth be known as the ‘‘Maintenance Hours Dispute.’’


	K.	The Parties have now reached a final agreement on the consolidation of the 3010 and 3012 Projects and the delivery of power from GEM to Edison which provides, among other things, for (i) the potential for Ormesa to deliver GEM power to Edison from a combined project consisting of the 3010 and 3012 Projects and GEM, (ii) an increase in the amount of electricity to be sold to Edison from the combined project of up to 6.5 MW more than the


		previous amounts that were covered by the 3010 Contract and the 3012 Contract, which incremental amount will receive an energy only price, (iii) the termination of the 3012 Contract and the Interim Agreement, and (iv) the settlement of the Dispute, the FERC Dispute and the Maintenance Hours Dispute.


	L.	By this Agreement, the Parties wish to settle and resolve the Dispute, the FERC Dispute and the Maintenance Hours Dispute as specified in this Agreement and to avoid further litigation with respect to the 3010 and 3012 Contracts and GEM deliveries.


	M.	Concurrently with this Agreement, the Parties and Ormat Technologies, Inc. are executing Amendment No. 2 to the 3010 Contract (‘‘Amendment No. 2’’) to effectuate the consolidation of the 3010 and 3012 Projects under the 3010 Contract; and the Parties are executing a Contract Termination Agreement that terminates the 3012 Contract (‘‘Termination Agreement’’).

AGREEMENT


1.	Effective Date

This Agreement shall become binding when it is executed by duly authorized representatives of each of the Parties, except that the entirety of Sections 4 and 5 below shall only become effective at 12:01 a.m. on the first day on which each of the following has occurred (‘‘Effective Date’’): (i) execution of Amendment No. 2 by duly authorized representatives of the Parties and Ormat Technologies, Inc.; (ii) execution of the Termination Agreement by duly authorized representatives of the Parties; and (iii) payment by Ormesa to Edison of the sum of $1,150,000 (one million one hundred fifty thousand dollars) as provided in Amendment No. 2 and this Agreement.


2.	Other Agreements

Concurrently with this Agreement, the Parties and Ormat Technologies, Inc. shall execute Amendment No. 2 and the Parties shall execute the Termination Agreement.


3.	Settlement Payment

Ormesa shall pay Edison the sum of $1,150,000 (one million one hundred fifty thousand dollars) within five (5) days after the execution of Amendment No. 2.


4.	Mutual Releases

Effective upon the Effective Date, Edison (on behalf of itself, its predecessors, successors, and assigns by operation of law or otherwise), on the one hand, and Ormesa (on behalf of itself, its predecessors, successors, and assigns by operation of law or otherwise), on the other hand, shall be deemed to have released, and forever discharged, as of the Effective Date, each other and each other’s present and former affiliates, parents, directors, officers, shareholders, partners, employees, agents, representatives, attorneys, insurers, predecessors, assigns, and successors in interest, from any and all claims, actions, causes of action, regulatory challenges, liabilities, breaches of contract, offsets, defenses, demands, losses, and damages of any kind whatsoever, whether known or unknown, asserted or unasserted, suspected or unsuspected, which may now exist or which may hereafter accrue, arising out of, relating to, concerning, or connected with: (1) the Dispute; (2) the FERC Dispute; provided that Edison reserves the right to enforce, on a prospective basis from and after November 23, 2004 – the date on which FERC’s denial of Ormesa’s application for rehearing with respect to FERC’s order on Ormesa’s application for recertification of the 3012 Project became final – the QF certifications of the 3010 Project, the 3012 Project and any other generating facility, consistent with FERC precedent; and (3) the Maintenance Hours Dispute and the use, scheduling and/or crediting of maintenance hours for

the 3010 and 3012 Projects, prior to the Effective Date; provided this release shall not affect the Parties’ rights and/or obligations pursuant to Sections 2.7, 2.8 and 2.10 of Amendment No. 2.

Edison’s prospective release associated with the FERC Dispute, as set forth in subclause (2) above, shall apply to the generating facilities owned or controlled by Ormesa, as well as to the generating facilities owned or controlled by any affiliate of Ormesa. Edison’s reservation of rights in subclause (2) above is without prejudice to any defenses or counterclaims that Ormesa or its affiliates may assert.


5.	Waiver of Civil Code § 1542

Each of the Parties believes it is fully familiar with the facts giving rise to this Agreement and the releases contained herein, and agrees that this Agreement shall remain fully effective and binding as to each of them even if the facts turn out to be different from what they now believe them to be. Each of the Parties further acknowledges that the releases set forth in Section 4 of this Agreement extend to claims which are presently unknown as well as to known claims. As to the specific matters released in Section 4, each of the Parties waives the benefits of California Civil Code § 1542, which provides:

This waiver of California Civil Code § 1542 applies to the specific matters released in Section 4 of this Agreement only, and is not intended to create a general release as to all claims, or potential claims, related to the 3010 and 3012 Contracts or between the Parties.


6.	Confidentiality


	6.1	The terms and conditions of this Agreement are confidential. Therefore, except for disclosing that the Dispute, the FERC Dispute and the Maintenance Hours Dispute have been settled and except as otherwise provided in this Section, each of the Parties agrees, for a period of three (3) years from the Effective Date, not to voluntarily disclose the terms and conditions of this Agreement to any third party without the prior written consent of the other Party. The Parties, or any of them, may make such disclosures as are required by law, after taking reasonable precautions to protect the confidentiality of relevant materials, and may make Securities and Exchange Commission filings which describe this settlement only in summary terms or otherwise by revealing only the minimum detail required by applicable law and in a manner consistent with the confidential nature of this Agreement. If any Party is served with a subpoena, request for production, or other form of discovery (‘‘Discovery Request’’) which requires disclosure of the Agreement or any of its terms or conditions, such Party shall promptly give written notice thereof to the other Party and, unless otherwise expressly required, shall not comply with the Discovery Request until the other Party has had a reasonable opportunity (not to exceed the deadline set by applicable law for compliance with the Discovery Request) to challenge it. In addition, the Parties may disclose this Agreement and its terms and conditions to the following persons, provided that the disclosing Party shall be responsible for any disclosure by the recipients (other than courts and public agencies) that is not authorized by this Agreement:


	a.	the Commission and its divisions and state and federal tax authorities, and attorneys and consultants representing any of the Parties in proceedings pending or to be commenced before such authorities, to the extent necessary to comply with applicable law or to the extent reasonably necessary in any regulatory proceeding specifically related to the 3010 and 3012 Contracts and the Interim Agreement or the Parties’ performance under the 3010 and 3012 Contracts and the Interim Agreement, provided that in making such disclosures, the disclosing Party shall take such steps as are reasonable to maintain the confidentiality of the Agreement and its terms and conditions with respect to third parties other than such authorized regulatory authorities, attorneys, and consultants;


	b.	the Parties’ accountants, lawyers, and their staffs, to the extent necessary in connection with the preparation, review, or audit of financial records or financial statements and to the extent necessary to comply with applicable tax and securities laws and regulations; and


	c.	a court (under seal or mutually satisfactory protective order, if permitted by the court) and to attorneys of the Parties and other professionals in connection with any action to enforce this Agreement pursuant to Code of Civil Procedure section 664.6, or suit for breach thereof.


	6.2	The Parties agree that monetary damages would not be sufficient to compensate a Party hereto for any breach of the provisions of Section 6.1, and further agree that equitable remedies, including injunctive relief, would be appropriate to enforce those provisions.


7.	Representations and Warranties by Edison

Edison represents and warrants that: (i) it has not assigned or transferred, or purported to assign or transfer, voluntarily, involuntarily, or by operation or law, any claims, causes of action, or rights alleged in, arising out of, or relating to any of the matters being released pursuant to Section 4 of this Agreement; and (ii) the person signing this Agreement in a representative capacity on its behalf has full authority to do so without the need to obtain any consent or approval which has not been obtained.


8.	Representations and Warranties by Ormesa

Ormesa represents and warrants that: (i) it has not assigned or transferred, or purported to assign or transfer, voluntarily, involuntarily, or by operation of law, any claims, causes of action, or rights alleged in, arising out of, or relating to any of the matters being released pursuant to Section 4 of this Agreement; and (ii) the person signing this Agreement in a representative capacity on its behalf has full authority to do so without the need to obtain any consent or approval which has not been obtained.


9.	Further Cooperation

The Parties agree to cooperate promptly and fully in providing and/or executing such additional documents and taking such other actions as may be reasonably necessary to effectuate the provisions of this Agreement. Edison further agrees to make a timely and appropriate request for Commission approval of this Agreement, which may be in its next Energy Resource Recovery Application, and to diligently and in good faith pursue such Commission approval, including timely and properly responding to requests for information and taking any resonable actions as requested by the Commission. Edison agrees to keep Ormesa informed as to the status of such request for approval and to cooperate in good faith with Ormesa in connection with such request for Commission approval. Notwithstanding anything in this Agreement to the contrary, Edison shall have no obligation to seek rehearing or to appeal a Commission decision which disallows the recovery by Edison of any amounts paid or to be paid under this Agreement, fails to approve this Agreement, or which contains findings with conditions or modifications unacceptable to any Party.


10.	Review of Agreement and Construction

The Parties acknowledge that their designated representatives have read and understand this Agreement and further acknowledge that, in entering into this settlement, they have been advised by attorneys of their choice. Further, each Party has cooperated and participated in the drafting and preparation of this Agreement. Hence, in any construction to be made of this Agreement, the same shall not be construed against any Party on the basis that the Party was the drafter.


11.	Unique Circumstances; No Effect on Other Parties and Agreements

The Parties acknowledge that this Agreement is and will be the product of each Party’s concessions and unique circumstances, and that this Agreement is not intended to set a precedent for Edison’s transactions with sellers or other power suppliers or other facilities.


12.	No Admission

Each Party acknowledges that neither this Agreement nor Amendment No. 2 or the Termination Agreement (nor any of the provisions contained in this Agreement, Amendment No. 2 or the Termination Agreement) constitute an admission of liability as to any claim, and each Party expressly denies any such liability. Neither this Agreement nor Amendment No. 2 or the Termination Agreement constitutes a finding of fact with respect to any matters that may exist or may arise between the Parties or their affiliates, nor may they be used by any Party as evidence for any purpose, except solely for the enforcement or interpretation of this Agreement, Amendment No. 2 and/or the Termination Agreement.


13.	No Other Representations

Each of the Parties acknowledges that no other Party or any other person has made any promises, representations, or warranties which are not expressly contained in this Agreement, Amendment No. 2 or the Termination Agreement to induce any of the Parties to enter into this Agreement, Amendment No. 2 and the Termination Agreement, and the Parties acknowledge that they have not entered into this Agreement, Amendment No. 2 or the Termination Agreement in reliance on any promises, representations, or warranties not contained therein. This Agreement, Amendment No. 2 and the Termination Agreement shall constitute the entire agreement between the Parties concerning the subject matters of this Agreement, Amendment No. 2 and the Termination Agreement and shall supersede any previous communications on these subjects.


14.	Successors and Assigns

Each provision of this Agreement shall inure to the benefit of, and be binding on, the successors and assigns of the Parties.


15.	Amendments

This Agreement shall not be amended or modified by any of the Parties, except by an instrument in writing executed by both Parties.


16.	Waiver

None of the provisions of this Agreement, including this Section, shall be considered waived by either Party except when such waiver is given in writing. The failure of either Party to insist in any one or more instances upon strict performance of any of the provisions of this Agreement or to take advantage of any of its rights hereunder shall not be construed as waiver of any such provisions or the relinquishment of any such rights for the future, but the same shall continue and remain in full force and effect.


17.	Governing Law and Construction


18.	Expenses

Except as provided in this Agreement, each of the Parties shall pay its own costs and expenses, including attorneys’ fees, incurred in connection with the Dispute, the FERC Dispute, the Maintenance Hours Dispute and the negotiation and preparation of this Agreement, Amendment No. 2 and the Termination Agreement and their implementation, including but not limited to costs and expenses incurred in preparing stipulations, making motions, and obtaining Commission approval of this Agreement.


19.	Execution and Counterparts

This Agreement may be executed in counterparts, each of which will be deemed to be an original and all of which taken together shall constitute a single instrument. This Agreement may be executed by signature via facsimile transmission which shall be deemed the same as an original signature.


20.	Headings

The headings used in this Agreement are for convenience and reference purposes only, and shall not be construed as the actual terms of the Agreement.


21.	Notices

Notice shall be addressed to the Parties as follows:


	If to Edison:	Southern California Edison Company Renewable and Alternative Power Department Manager, Contract Administration 2244 Walnut Grove Avenue Rosemead, California 91770 Facsimile: (626) 302-9622

With a copy to:

Southern California Edison Company
Law Department
Manager, Power Procurement Section
2244 Walnut Grove Avenue
Rosemead, California 91770
Facsimile: (626) 302-1904


	If to Ormesa:	Ormesa LLC c/o Ormat Nevada, Inc. 6625 Neil Road Reno, Nevada 89511 Facsimile: (775) 356-9039


22.	Signatures

IN WITNESS WHEREOF, the Parties hereto have caused this agreement to be executed by their duly authorized representatives on the dates indicated below the signatures.


SOUTHERN CALIFORNIA EDISON COMPANY , a California corporation			ORMESA LLC , a Delaware limited liability company
By:			By:
Name: Pedro J. Pizarro			Name:
Title: Senior Vice President, PPBU			Title:
Date:			Date:

Southern California Edison

APPENDIX D

East Mesa Lease Map

Appendix D

East Mesa Lease Map

APPENDIX D

Southern California Edison

APPENDIX E

Equipment of Consolidated Projects

Appendix E

Equipment of Consolidated Projects

Appendix E

Equipment of Consolidated Projects

3010 Project Equipment

Ormesa 1

Unit	KW rating	KVA	Generator Brand	Generator Serial No.	Application
OEC 1	12,000	15,000	Brush	410063	Binary
OEC 32	1,200		Ormat	527-5	Binary
OEC 2	10,000	12,500	Kato	15013-01	Binary
OEC 31	1,200		Ormat	534-4	Binary

Ormesa 1E

Unit	KW rating	KVA	Generator Brand	Generator Serial No.	Application
OEC1	1, 200		Ormat	534-3	Binary
OEC 2	1,200		Ormat	527-6	Binary
OEC 3	1,200		Ormat	BB 550-1	Binary
OEC 4	1,200		Ormat	BB 550-10	Binary
OEC 5	1,200		Loher	5-106-397	Binary
OEC 6	1,200		Ormat	BB 636-3	Binary
OEC 7	1,200		Ormat	BB 650-20	Binary
OEC 8	1,200		Ormat	527-4	Binary
OEC 9	1,200		Ormat	527-3	Binary
OEC 10	1,200		Ormat	527-1	Binary
OEC 11	1,200		Ormat	AF-581-2	Binary
OEC 12	1,200		Ormat	AF-581-1	Binary

Ormesa 1H

Unit	KW rating	KVA	Generator Brand	Generator Serial No.	Application
OEC 11	1,200		Ormat	AP-531-2	Binary
OEC 21	1,200		Ormat	AC-653-8	Binary
OEC 12	1,200		Ormat	BB 636-4	Binary
OEC 22	1,200		Ormat	AC-653-3	Binary
OEC 13	1,200		Ormat	AD-531-1	Binary
OEC 23	1,200		Ormat	AC-653-10	Binary
OEC 14	1,200		Keller	10122004147938	Binary
OEC 24	1,200		Ormat	AC-653-2	Binary
OEC 15	1,200		Ormat	AC-653-1	Binary
OEC 25	1,200		Ormat	AC-653-6	Binary
OEC 16	1,200		Ormat	AC-653-9	Binary
OEC 26	1,200		Ormat	AC-653-5	Binary

3012 Project Equipment

Unit	KW rating	KVA	Generator Brand	Generator Serial No.	Application
OEC 21	12,000	15,000	Brush	410041-01	Binary
OEC 22	12,000	15,000	Brush	410041-02	Binary

GEM Equipment

Unit	KW rating	KVA	Generator Brand	Generator Serial No.	Application
GEM 2	18,500	24,000	Mitsubishi	188181801	Flash
GEM 3	18,500	24,000	Mitsubishi	288181801	Flash
GEM Bottoming	8,000	10,000	Kato	17965	Binary

Appendix E

-1-

Southern California Edison

APPENDIX F

Annual Contract Capacity Demonstration Protocol and Criteria

Appendix F

Annual Contract Capacity Demonstration Protocol and
Criteria

Southern California Edison

APPENDIX F

ANNUAL CONTRACT CAPACITY DEMONSTRATION PROTOCOL AND CRITERIA

1)	Annual Contract Capacity Demonstration Date :

An Annual Contract Capacity Demonstration (“Capacity Demonstration”) shall be held on a non-holiday weekday, within the Peak Months, that is agreed to by Edison and Seller. If, by June 1 of a particular year, Edison and Seller have not agreed upon a date for the Capacity Demonstration, Edison shall select a date for that year. At its discretion, Edison may request that the Capacity Demonstration be held on a non-holiday weekday in a non-Peak Month.

Either Party may request to reschedule the originally scheduled Capacity Demonstration date upon one week’s written Notice sent by facsimile transmission or e-mail to the other Party. However, the Capacity Demonstration may only be rescheduled once per year. Moreover, once the Capacity Demonstration has commenced, subject to Section 7b below, it cannot be terminated or rescheduled for any reason whatsoever.

2)	Capacity Demonstration Period :

The Capacity Demonstration period shall commence at 12:00 p.m. (noon) on the selected day and end at 6:00 p.m. of the same day.

3)	Satisfactory Demonstration :

Seller shall operate at a rate of delivery (net of line losses to the Point of Interconnection as specified below) which is equal to or greater than a Contract Capacity of 46,500 kWh/h, as specified in Sections 1.3 and 4.4.9 of the Contract, during each and every Edison metering interval within the Capacity Demonstration period.

For the Capacity Demonstration, the rate of delivery (kWh/h) means the energy (kWh) recorded by the Testing Tools, as defined in Section 4 below, within an Edison metering interval times the number of intervals within an hour, adjusted for the Interconnecting Utility loss factors. The Interconnecting Utility is Imperial Irrigation District (“IID”). For example, a 15-minute energy recording would be multiplied by four to obtain the rate of delivery in kWh/h units, and then multiplied by 0.97 to adjust for a 3% IID loss factor.

Appendix F

Annual Contract Capacity Demonstration Protocol and
Criteria

Southern California Edison

During the Capacity Demonstration, the IID loss factors to be utilized shall be those published for the period of the Capacity Demonstration, or those for the prior year if the current year loss factors are not available before the Capacity Demonstration begins.

4)	Testing Tools :

The rate of delivery for the Capacity Demonstration is to be determined using Edison’s meter, installed and maintained at Seller’s expense, as shown on Appendix H and Edison’s data recorder.

5)	Representation and Access :

Edison representatives (normally one to three) may attend the setup and operation of the Capacity Demonstration.

Edison representatives may also, concurrently with the Capacity Demonstration, conduct a site inspection of the Generating Facility and associated facilities, systems and equipment.

Edison shall have access to and copies of control room logs, control system display screens, and instrumentation data before, during and after the Capacity Demonstration.

Generating Facility personnel may be present during both the Capacity Demonstration and site inspection at the Seller’s option.

6)	Cost of Capacity Demonstration :

Each Party shall bear its own costs of the Capacity Demonstration.

7)	Remedial Action for Failing the Capacity Demonstration :

Should the Seller fail to operate at a rate of delivery (net of line losses to the Point of Interconnection as specified above) which is equal to or greater than a Contract Capacity of 46,500 kWh/h, as specified in Sections 1.3 and 4.4.9 of the Contract, during each and every Edison metering interval during the Capacity Demonstration period, Seller shall pay to Edison as liquidated damages $50/kW based on the difference between 46,500 kWh/h and Seller’s lowest rate of delivery during any Edison metering interval during the Capacity Demonstration period.

If the Seller fails to demonstrate Contract Capacity of a 46,500 kW due to an abnormal and unforeseeable operating condition, as verified and determined at Edison’s sole discretion, an additional Capacity Demonstration may be scheduled, provided there is time remaining within the current year’s Peak Months or such other month as Edison may select.

Appendix F

Annual Contract Capacity Demonstration Protocol and
Criteria

Southern California Edison

APPENDIX G

Metering One Line

Appendix G

Metering One Line

ORMSEA Metering One Line

Southern California Edison

APPENDIX H

Capacity Payment Schedule

Appendix H

Capacity Payment Schedule

APPENDIX H

TABLE P

SOUTHERN CALIFORNIA EDISON COMPANY

ANNUAL CAPACITY PAYMENT SCHEDULE FOR STANDARD OFFER NO. 2

FOR FIRM POWER PURCHASES

Line No.	Year of Initial Delivery	$/kW – yr. (Based on 80% CF) Contract Term (Years)
		1	5	10	15	20	25	30
		(1)	(2)	(3)	(4)	(5)	(6)	(7)
1.	1982	66	74	85	97	106	113	118
2.	1983	70	80	92	105	114	121	127
3.	1984	76	86	100	113	123	131	137
4.	1985	81	93	108	122	132	141	147
5.	1986	87	100	117	131	143	152	158
6.	1987	94	107	127	142	154	163	170
7.	1988	101	117	137	153	166	176	184
8.	1989	109	128	149	165	179	189	198

Appendix H, Amendment No.2

Table P

Southern California Edison

APPENDIX I

Maintenance Outage Scheduling Procedures

Appendix I

Maintenance Outage Scheduling Procedures

Qualifying Facility
Maintenance Outage Scheduling Procedures

I.	Applicability

The Qualifying Facility Maintenance Outage Scheduling Procedures (“Maintenance Procedures”) apply to the scheduling of an outage on a QF generating facility as a result of planned maintenance to keep the generating facility in suitable operating condition. A maintenance outage, whether full or partial, must be scheduled prior to the actual event and must be of a predetermined duration. These Maintenance Procedures are applicable only to firm capacity contracts with a provision for maintenance credit.

II.	Contract Provisions

Presented in this section is a general overview of the standard contract provisions concerning scheduled maintenance, as well as some of SCE’s administrative principles derived from these provisions. The standard provisions may not be found in all QF contracts. The QF should always refer to its contract for any variations in the scheduled maintenance provisions. In the event of a conflict between the QF’s contract and the overview in this Section II, the QF’s contract shall govern.

Many Standard Offer and negotiated firm capacity contracts establish the following notification requirements for scheduled outages:

	Outage Duration	Notification Required
	Less than 1 day	24 hours
	1 day or more (except Major Overhaul)	1 week
	Major Overhaul*	6 months

Notification requirements in each contract will be strictly enforced.

*A Major Overhaul is a one-day-or-more maintenance outage that is scheduled six months or more in advance. During a Major Overhaul, the unit may not carry any load, except for testing purposes. A Major Overhaul may not be scheduled to occur during peak months, currently June, July, August, and September.

Many Standard Offer and negotiated firm capacity contracts provide for adjustments to firm capacity and bonus payments for scheduled maintenance. The adjustments may be summarized as follows:

	TOU Period Performance Factor	=	TOU Preiod kWhs
			0.8 x Contract Capacity x (TOU Period Hours – TOU Allowable Maintenance Hrs)

and

	TOU Period Capacity Factor	=	TOU Preiod kWhs
			Contract Capacity x (TOU Period Hours – TOU Allowable Maintenance Hrs)

SCE calculates Allowable Maintenance Hours (i.e., maintenance credit or capacity credit) as follows, by TOU period:

Allowable Maintenance Hours (TOU period) = Sum of the Hourly Credit Values for the TOU period

Note: These procedures are subject to change as necessary.

Southern California Edison

Page 1

April 4, 2007

Qualifying Facility
Maintenance Outage Scheduling Procedures

Hourly Credit Value is defined in Section IV-B-1.

Many Standard Offer and negotiated firm capacity contracts also set the following allowances for scheduled maintenance:

Scheduled maintenance shall not exceed a total of 30 on-peak hours in a calendar year.

Scheduled maintenance, not including Major Overhauls, shall not exceed a total of 840 hours in any 12-month period.

Unused hours from the 840-hour allotment may be accumulated up to a maximum of 1080 hours to be used for Major Overhauls.

The hours from the 840-hour allotment may be used on a non-consecutive basis by scheduling separate maintenance outages. This is in direct contrast to the accumulated hours, which can only be used consecutively once a year. Moreover, all maintenance hours must be used in one-hour increments.

The 30-on-peak-hour allotment is part of, not in addition to, the 840-hour allotment. The number of available hours in the on-peak allotment shall never be more than the number of unused hours in the 840-hour allotment.

Many Standard Offer and negotiated firm capacity contracts further require the QF to make reasonable efforts to scheduled routine maintenance outside the Peak Months, currently June, July, August, and September.

III.	Scheduling Procedure

All maintenance outages must be reported to SCE in advance. The QF is solely responsible for meeting the advance notice requirement.

Notifications of maintenance schedule and requests for maintenance credit should be directed to SCE via the Web-based QF Outage Scheduling System (“Web Scheduler”) at:

http://www3.sce.com/sscc/qf/qf.nsf

If the Web Scheduler is unavailable, notifications of maintenance schedule and requests for maintenance credit should be e-mailed to SCE at GenerationOutage@sce.com .

Please have the following information ready when scheduling maintenance:

RAP ID (QFID)

Web Scheduler Password

Unit Number (if applicable)

Outage Period*

Date and time the unit is expected to be taken off-line

Date and time the unit is expected to return to service

Scheduled Output**

Capacity output, in kW, which will be on-line during Outage Period

Reason for Outage

Capacity Credit Period ***

Date and time maintenance credit is requested to begin

Note: These procedures are subject to change as necessary.

Southern California Edison

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April 4, 2007

Qualifying Facility
Maintenance Outage Scheduling Procedures

Date and time maintenance credit is requested to end

*If capacity credit is requested for an outage, the Outage Period must be the same as the Capacity Credit Period. If the Outage Period is different from the Capacity Credit Period, no credit will be given.

**For QFs which track Maintenance Hours separately for each generating unit, please provide the expected Scheduled Output for the unit being scheduled for maintenance.

***The Capacity Credit Period information is not applicable if the QF requests that no credit be applied to the outage.

After an outage has been scheduled through the Web Scheduler, a confirmation of receipt can be printed for verification. The QF is solely responsible for data accuracy.

SCE’s Real-Time Generation Desk and/or local switching center should also be informed of the maintenance outage. The Real-Time Generation Desk telephone number is (626) 307-4410.

IV.	Maintenance Credit Evaluation

After a request for maintenance credit has been submitted, evaluation of maintenance credit does not take place until SCE receives the QF’s Production Output data. Production Output, in kWh per hour, is defined as the QF’s power delivery on which its capacity payment is calculated. Once the Production Output data is available, SCE calculates the maintenance credit (and the associated allotment debit) following these steps:

A Benchmark Capacity shall be determined for every scheduled maintenance outage. Benchmark Capacity is defined as the highest hourly Production Output, not to exceed Contract Capacity, at or after the time of outage notification, and before the start of the outage. If the outage is rescheduled, the most recent notification time shall be used in defining Benchmark Capacity. If the outage is extended, or its Scheduled Output is updated, the previous notification time shall be used in defining Benchmark Capacity.

In the special case of a less-than-one-day maintenance outage that directly follows another less-than-one-day maintenance outage, Benchmark Capacity of the outage that follows is defined as the highest hourly Production Output, not to exceed Contract Capacity, between these two outage periods. In the event of back-to-back, less-than-one-day outages, Benchmark Capacity for the second outage shall be zero.

For each hour in the Outage Period, an Hourly Credit Value and Hourly Debit Value shall be calculated:

Hourly Credit Value is based on the difference between Benchmark Capacity and Production Output for the hour, or the difference between Benchmark Capacity and Scheduled Output for the hour, whichever difference is smaller.

Hourly Credit Value = ( Delta / Benchmark Capacity ) * 1 hour

where Delta is the greater of

Benchmark Capacity minus the greater of Scheduled Output or Production Output

Note: These procedures are subject to change as necessary.

Southern California Edison

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April 4, 2007

Qualifying Facility
Maintenance Outage Scheduling Procedures

zero

Hourly Debit Value is based on the difference between Benchmark Capacity and Scheduled Output for the hour, unless this difference is less than Scheduled Output Deviation for the hour, in which case Hourly Debit Value shall be based on the deviation amount. (Scheduled Output Deviation is defined as the absolute difference between Production Output and Scheduled Output.)

Hourly Debit Value = Normalized Delta * 1 hour

where Normalized Delta is the greatest of

( Benchmark Capacity - Scheduled Output ) / Benchmark Capacity

( Scheduled Output - Production Output ) / Scheduled Output

( Production Output - Scheduled Output ) / Production Output

In case of division by zero, the value being calculated shall be zero.

For each hour in the Outage Period, the Hourly Credit Value shall be applied, by TOU, to the Performance Factor and/or the Capacity Factor, according to Section II-B, and the associated Hourly Debit Value shall be deducted, by TOU where applicable, from the appropriate allotment(s) in Section II-C. Once the allotment balance reaches zero or becomes negative (i.e., the hours available for scheduled maintenance have been exhausted), no more Hourly Credit Values shall be applied to the Performance or Capacity Factor.

After all the Hour Credit Values and Hourly Debit Values have been applied, the final monthly TOU Allowable Maintenance Hours and allotment balances shall be rounded to the nearest whole number. However, all intermediate computations leading up to the final result shall be carried out with appropriate numeric precision.

Note: The above description of the evaluation process assumes that the outage request was properly submitted with sufficient advance notice and was approved by SCE. Any deviation from the proper scheduling protocol can result in reduced maintenance credit or increased allotment debit.

V.	Other Procedures and Administrative Principles

A maintenance outage, except for a Major Overhaul, may be rescheduled if the request to reschedule is received by SCE via the Web Scheduler no later than 5:00 a.m. on the day before the outage was previously scheduled to begin. For example, if the outage was previously scheduled to begin on Monday, the request to reschedule must be received by SCE no later than 5:00 a.m. on Sunday. The new outage must also meet the notification requirements stated in Section II-A. An outage may be rescheduled more than once.

A Major Overhaul may be rescheduled provided:

Note: These procedures are subject to change as necessary.

Southern California Edison

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April 4, 2007

Qualifying Facility
Maintenance Outage Scheduling Procedures

The scheduling requirements for the original outage have been met;

The rescheduled outage begins six months or more after the original (first) outage notification date and time;

The notification to reschedule is made at least one week before the outage was previously scheduled to begin; and

There is at least a one-month period between the notification to reschedule and the commencement of the rescheduled outage.

A Major Overhaul may be rescheduled more than once.

All maintenance outages may be extended by notifying SCE of the extension via the Web Scheduler no later than 5:00 a.m. on the day before the outage was previously scheduled to end. For example, if the outage was previously scheduled to end on Monday, the request for extension must be received by SCE no later than 5:00 a.m. on Sunday. An outage may be extended more than once.

Note: For less-than-one-day outages, the extension cannot result in a total outage duration greater than 23 hours.

If the scheduled maintenance is canceled, a cancellation notice is required and must be received by SCE via the Web Scheduler no later than 5:00 a.m. on the day before the outage was scheduled to begin.

The Scheduled Output should always follow the Production Output as closely as possible. If a change in the Production Output is anticipated or occurs during a maintenance outage prior to 5:00 a.m. on the day before the outage is scheduled to end, the Scheduled Output should be updated as soon as possible via the Web Scheduler. Multiple updates can be submitted if necessary. Scheduled Output cannot be updated after the outage is over.

SCE’s Real-Time Generation Desk and/or local switching center should also be informed of any changes in the outage schedule.

A maintenance outage must not overlap another outage already scheduled on the same unit.

Maintenance credit will be given from the 840-hour allotment unless the QF notifies SCE of the outage (Major Overhaul) six months or more in advance. If notice is given at least six months in advance, the credit will be given from the accumulated hours. Should the QF use up all of its available accumulated hours during a Major Overhaul, additional credit may be taken from the 840-hour allotment, up to the allowable limit, provided a written request has been submitted to SCE.

In determining the beginning and ending of an outage, all times are rounded to the nearest hour. For examples, 11:29 = 11:00 and 11:30 = 12:00. For a less-than-one-day outage, the rounding shall never result in a duration of more than 23 hours. Also, 24:00 will be treated as 00:00 of the following day. For example, 1/1/2000 24:00 will become 1/2/2000 00:00.

VI.	Non-Compliance

A material failure to comply with the Maintenance Procedures will result in loss of claimed maintenance credits. SCE also reserves the right to seek recovery of any and all losses it incurs as a result of a QF’s

Note: These procedures are subject to change as necessary.

Southern California Edison

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April 4, 2007

Qualifying Facility
Maintenance Outage Scheduling Procedures

failure to comply with these Maintenance Procedures, including, but not limited to, recovery of imbalance charges paid by SCE. In addition, repeated failure to comply with the Maintenance Procedures may be deemed by SCE to be a material breach of contract and SCE may seek to rely on such repeated failure as justifying contract termination.

Note: These procedures are subject to change as necessary.

Southern California Edison

Page 6

April 4, 2007

Southern California Edison

APPENDIX J

Maintenance Hour Allowance for Capacity Credit

Appendix J

Maintenance Hour Allowance for Capacity Credit

APPENDIX J

Maintenance Hour Allowance for Capacity Credit

	Contract Capacity	Capacity Price		Maint Allowance Balance as of 12/31/06 (hrs)	Maint Hr factor	Maint Allowance Balance w/ Consolidation as of 12/31/06 (hrs)
Ormesa I	31,500	$	170.00	365	0.659889094	241
Ormesa II	15,000	$	184.00	194	0.340110906	66
Consolidated	46,500	$	174.52		1.000000000	307

Ormesa 1 (QFID 3010)		Hours			Ormesa II (QFID 3012)		HOURS
From	To	Allowed	Annual Used	Balance	From	To	Allowed	Annual Used	Balance
1/1/2006	2/1/2006	98	671	169	1/1/2006	2/1/2006	36	420	420
2/1/2006	3/1/2006	75	739	101	2/1/2006	3/1/2006	47	433	407
3/1/2006	4/1/2006	108	840	0	3/1/2006	4/1/2006	37	444	396
4/1/2006	5/1/2006	0	840	0	4/1/2006	5/1/2006	37	443	397
5/1/2006	6/1/2006	15	840	0	5/1/2006	6/1/2006	72	466	374
6/1/2006	7/1/2006	0	840	0	6/1/2006	7/1/2006	46	512	328
7/1/2006	8/1/2006	16	735	105	7/1/2006	8/1/2006	13	462	348
8/1/2006	9/1/2006	44	723	117	8/1/2006	9/1/2006	53	463	377
9/1/2006	10/1/2006	0	739	101	9/1/2006	10/1/2006	0	495	435
10/1/2006	11/1/2006	62	797	43	10/1/2006	11/1/2006	84	450	390
11/1/2006	12/1/2006	74	545	195	11/1/2006	12/1/2006	170	611	229
12/1/2006	1/1/2006	81	573	267	12/1/2006	1/1/2006	87	682	158
1/1/2007	2/1/2007			365	1/1/2007	2/1/2007			194

Consolidated of Ormesa I & II		HOURS
From	To	Allowed	Annual Used	Balance
1/1/2006	2/1/2006	77	586	254
2/1/2006	3/1/2006	65	635	205
3/1/2006	4/1/2006	84	705	135
4/1/2006	5/1/2006	13	705	135
5/1/2006	6/1/2006	34	713	127
6/1/2006	7/1/2006	16	728	112
7/1/2006	8/1/2006	15	652	188
8/1/2006	9/1/2006	47	635	205
9/1/2006	10/1/2006	0	625	215
10/1/2006	11/1/2006	69	679	161
11/1/2006	12/1/2006	107	633	207
12/1/2006	1/1/2007	83	610	230

1/1/2007	2/1/2007			307

NOTE: Major Overhaul hours allowed for both Ormesa I and II, as of December 31, 2006, are at the maximum allotment of 1,080 hours at each facility. Therefore, the Major Overhaul hours balance for the Consolidation of 3010 and 3012 is 1,080 hours. If either Ormesa I or II utilize maintenance hours from this category, prior to the Effective Date, a similar calculation as above will be performed to determine the Consolidation Major Overhaul hours balance.

Appendix J

-1-

Maintenance Hour Allowance for Capacity Credit

APPENDIX J

SOUTHERN CALIFORNIA EDISON		RAP ID:	3010
		Payment from:	12/01/2006
		Payment to:	01/01/2007
	Contract Manager:	Number of days:	31
P.O. Box 800	Michele Walker	Statement ID:	51318
Rosemead, CA	626-302-8908	Date prepared:	01/26/2007
91770

MAINTENANCE HOURS ALLOWANCE

UNIT: 1

ANNUAL

MAINTENANCE HOURS ALLOWED: 840

PAYMENT FROM	TO	ALLOWED	ON PEAK	MID PEAK	OFF PEAK	SUP OFF PEAK	ANNUAL USED	PERIOD END BALANCE



01/01/2006	02/01/2006	98	0	44	33	21	671	169
02/01/2006	03/01/2006	75	0	40	21	14	739	101
03/01/2006	04/01/2006	108	0	41	41	26	840	0
04/01/2006	05/01/2006	0	0	0	0	0	840	0
05/01/2006	06/01/2006	15	0	8	3	4	840	0
06/01/2006	07/01/2006	0	0	0	0	0	840	0
07/01/2006	08/01/2006	16	16	0	0	0	735	105
08/01/2006	09/01/2006	44	10	15	19	0	723	117
09/01/2006	10/01/2006	0	0	0	0	0	739	101
10/01/2006	11/01/2006	62	0	27	20	15	797	43
11/01/2006	12/01/2006	74	0	31	27	16	645	195
12/01/2006	01/01/2007	81	0	35	29	17	573	267

MAJOR OVERHAUL

MAJOR OVERHAUL HOURS ALLOWED: 1080

ROLLOVER			UNUSED ANNUAL HOURS				YEAR END BALANCE



2003				677				1080
2004				754				1080
2005				267				1080

PAYMENT FROM	TO	ALLOWED	ON PEAK	MID PEAK	OFF PEAK	SUP OFF PEAK	YTD USED	YTD AVAILABLE

NOTES

Outages shall not exceed 30 peak hours for the peak months or 840 hours (35 days) in any 12 month period.

Page 1 of 1

Appendix J, Amendment No. 2

3010 maintenance Hours Allowance

Southern California Edison

APPENDIX K

Draft Letter and

Specifications for Gould Facility

Appendix K

Draft Letter and Specifications for Gould Facility

Southern California Edison

APPENDIX K

DRAFT Letter

[Month Day ], 2007

VIA FIRST CLASS MAIL

Mr. Stuart Hemphill

Director of Renewable and Alternative Power

Southern California Edison Company

P.O. Box 800

2244 Walnut Grove Avenue

Rosemead, CA 91770

RE: Installation of the William R. Gould Power Plant and Sale of Power to SCPPA

Dear Mr. Hemphill:

I am writing this letter on behalf of OrCal Geothermal Inc. (“OrCal”) to request Southern California Edison Company’s (“Edison”) confirmation of certain matters related to the new William R. Gould Power Plant (“Gould Plant”). By way of background, OrCal’s lenders hold as security certain assets, including (i) the Power Purchase Contract between Southern California Edison Company (“Edison”) and Heber Geothermal Company (“HGC”), executed on August 26, 1983, as amended by Amendment No. 1 to the Power Purchase Contract, executed as of December 11, 1984, and Amendment No. 2 to the Power Purchase Contract, executed as of August 7, 1995 (“HGC PPA”); and (ii) the Power Purchase Contract between Edison and Second Imperial Geothermal Company (“SIGC”), executed on August 16, 1985, as amended by Amendment No. 1 to the Power Purchase Contract, executed as of October 23, 1987, Amendment No. 2 to the Power Purchase Contract, executed as of July 27, 1990, and Amendment No. 3 to the Power Purchase Contract, executed as of November 24, 1992 (“SIGC PPA”).

As we have discussed, OrHeber 2 Inc., an affiliate of OrCal, plans to install and own the Gould Plant. The Gould Plant is comprised of geothermal generating units located at or near the site of the HGC facility that sells its power to Edison pursuant to the HGC PPA

Appendix K

Draft Letter and Specifications for Gould Facility

Southern California Edison

(“HGC Facility”) and a geothermal generating unit located at or near the site of the SIGC facility that sells its power to Edison pursuant to the SIGC PPA (“SIGC Facility”). A technical description of the Gould Plant, and its interconnection and metering arrangements is attached hereto. OrHeber 2 Inc. will sell the combined output from the Gould Plant units, in excess of various site requirements, to the Southern California Public Power Authority (“SCPPA”).

OrCal and OrHeber 2 Inc. request that Edison confirm in writing our prior discussions that the installation and continued operation of the Gould Plant in accordance with the specifications attached hereto, and the sale of the output therefrom to SCPPA, does not constitute a default under either the Heber PPA or the SIGC PPA. Similarly, OrCal and OrHeber 2 Inc. request Edison to confirm that the Gould Plant is not considered to be part of the generating facilities covered by either the HGC PPA or the SIGC PPA. Your signature below will confirm the foregoing; provided that, Edison will fully reserve its rights to withdraw its confirmation of the foregoing: (i) in the event that that the Gould Plant is not operated in accordance with the attached specifications; or (ii) in the event of any amendments or modifications to the Heber PPA or the SIGC PPA, and further fully reserves its rights to seek to apply to the Heber PPA, the Heber Facility, the SIGC PPA and/or the SIGC Facility any decisions(s) by any court, the Federal Energy Regulatory Commission or other governmental authority related to the issues in the appeal currently pending before the U.S. Court of Appeals for the District of Columbia Circuit, SCE v. FERC , Case No. 04-1396. Edison shall have the right, at reasonable times, upon reasonable advance notice and in accordance with reasonable plant safety and security protocols, to inspect the HGC Facility, SIGC Facility and Gould Plant from time to time for the purpose of monitoring compliance with the attached specifications.

Thank you very much for your assistance and cooperation with this matter.

Very truly yours,

Hezy Ram

SOUTHERN CALIFORNIA EDISON COMPANY
By:
	Stuart Hemphill, Director of Renewable and Alternative Power
cc:	Bruce McCarthy Joseph Karp

Appendix K

Draft Letter and Specifications for Gould Facility

Southern California Edison

APPENDIX K

SPECIFICATIONS FOR GOULD FACILITY

The proposed Gould Generating Facility will consist of two plants, Gould 1 and Gould 2 and will operate in parallel with two geothermal plants currently selling their entire output to Edison as qualifying facilities identified as follows.

1.	Heber	QF 3001
2.	Second Imperial	QF 3021

These specifications describe equipment and administrative procedures that must be installed and implemented to ensure that energy created by the Gould plant is accounted for separately, that it will not be intermingled with the QF energy accounting for the Heber and Second Imperial Projects, and that Gould plant operation will not disadvantage energy production from the existing QF units.

These specifications also describe various wells, cooling towers and pumps associated with QF 3001, QF 302l and the Gould plant. It is acknowledged that these items may be replaced, modified or supplemented with additional equipment in the ordinary course of business (for example, as field conditions, technology or equipment operating parameters change over time) and that such changes will not be considered to be inconsistent with these specifications.

QF 3001 is located at “portion of the East half of Tract 45, APN 054-250-36-01, 20 acres, Township 16 South, Range 14 East, SBB&M”. The address is 895 Pitzer Road, Heber, California. QF 3001 is comprised of one (1) Mitsubishi 52 MW turbine generator, eleven (11) production wells, nineteen (19) injection wells, six (6) cell Marley counter flow cooling tower, two (2) 900 hp main circulating water pumps, four (4) 900 hp brine return booster pumps and three (3) 3500 hp injection pumps.

Appendix K

Draft Letter and Specifications for Gould Facility

Southern California Edison

The 11 artesian flow directionally drilled production wells with no pumps installed are located on an island adjacent to the facility and are dedicated to QF 3001. The injection wells and pumps associated with QF 3001 are supplied by the QF 3001 project. There is no installed backup power or capability to supply the injection pump power from any other source other than the QF 3001 facility.

QF 3021 is located at “portion of the East half of Tract 44, APN 054-250-31-01, 39.99 Acres, Township 16 South, Range 14 East, SBB&M”. The address is 855 Dogwood Road, Heber, California. QF 3021 is comprised of six (6) Ormat Energy Converter (OEC) 4.5 MW turbine generators and six (6) 3.5 MW OEC turbine generators for a total of 48 MW nameplate, twelve (12) production wells with 800 hp down hole pumps, eleven (11) injection wells, two (2) Hamon six (6) cell counter flow cooling towers, six (6) 450 hp main cooling water pumps and five (5) 700 hp injection pumps.

The production wells associated with QF 3021 can be supplied either from the QF 3021 project or from the Gould 2 project. The 13.2kv feeders for the production pumps supplied by the Gould 2 project, and previously supplied by the IID, are located on the 1200 amp bus connecting the Gould 2 generator to the IID Heber Imperial Substation. Synchronized transfer switches for the production pumps allow for switching between the Gould 2 13.2kv source and the Heber 2 13.8kv source. QF 3021 does not utilize any injection pumps in order to inject its geothermal brine into the injection wells.

The Gould plant located near QF 3001 (Gould 1) shall consist of one (1) 7 MW OEC turbine generator, one (1) 3.5 MW OEC turbine generator and one (1) OEC turbine driving mechanically a 3000 hp booster pump and four (4) cell Marley counter flow cooling tower with three (3) 350 hp main cooling water pumps. There are no production or injection wells for Gould 1. The heat source for Gould 1 is the injected brine, at nominally 212 F, from Heber 1.

Energy from this plant shall pass through the existing revenue meter and will be counted with the QF 3001 energy. To provide for the separation of energy from these two sources, new

Appendix K

Draft Letter and Specifications for Gould Facility

Southern California Edison

revenue metering shall be installed at the Gould 1 facility. IID shall subtract the Gould energy from the total measured at the existing revenue meter. Ormat shall add an additional set of test switches to the Gould facility metering PT and CT circuits and provide adequate panel space to enable SCE to add the ir own revenue meter. Ormat shall install and maintain a dedicated analog telephone line within the metering cabinet to provide for reading the meter. The meter shall be a Landis Gyr model 2510 or equivalent. The meter and socket shall be supplied and maintained by SCE. SCE shall be provided access to the meter for reading and maintenance.

The Gould plant located near QF 3021 (Gould 2) shall consist of one (1) 16MW OEC turbine generator and three (3) cell Marley counter flow cooling tower with three (3) 300 hp main cooling water pumps.

The energy from this plant shall be delivered to the IID system through an interconnection which is separate from the interconnection supporting QF 3021. The interconnection which shall be used for the Gould 2 plant is currently used part of the time to supply the needs for the field production pumping load for 3021. The interconnection for QF 3021 can also be connected to the field production pumping load associated with 3021. In general, the pumps are not simultaneously connected to both interconnections except for a few seconds during switching. Ormat shall install logic in their control system to prevent the systems being interconnected for more than 1.5 seconds for switching to prevent the intermingling of energy between the systems. Ormat shall provide the logic diagrams and wiring diagrams (if applicable) to SCE and shall forward changes and updates as they occur in the future as long as the plants are physically capable of cross feeding energy. Ormat shall provide access to SCE to examine the operation of the system and shall demonstrate the proper operation of the logic to prevent anything other than momentary interconnection of the systems on request.

Appendix K

Draft Letter and Specifications for Gould Facility

Exhibit 31.1

Ormat Technologies, Inc.
Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

I, Yehudit Bronicki, certify that as of the date hereof:


1.	I have reviewed this quarterly report on Form 10-Q of Ormat Technologies, Inc.;


2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;


4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:


	(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


	(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under his/her supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


	(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


	(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and


5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s Board of Directors (or persons performing the equivalent function):


	(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and


	(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 8, 2007

By: /s/ YEHUDIT BRONICKI

Yehudit Bronicki
Chief Executive Officer and President

Exhibit 31.2

Ormat Technologies, Inc.
Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

I, Joseph Tenne, certify that as of the date hereof:


1.	I have reviewed this quarterly report on Form 10-Q of Ormat Technologies, Inc.;


2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;


4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:


	(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


	(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under his/her supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


	(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


	(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and


5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s Board of Directors (or persons performing the equivalent function):


	(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and


	(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 8, 2007

By: /s/ JOSEPH TENNE

Joseph Tenne
Chief Financial Officer

Exhibit 32.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER
PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

I, Yehudit Bronicki, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the quarterly report of Ormat Technologies, Inc. on Form 10-Q for the three months ended June 30, 2007 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that information contained in such quarterly report on Form 10-Q fairly presents in all material respects the financial condition and results of operations of Ormat Technologies, Inc. as of and for the periods presented in such quarterly report on Form 10-Q. This written statement is being furnished to the Securities and Exchange Commission as an exhibit accompanying such quarterly report and shall not be deemed filed pursuant to the Securities Exchange Act of 1934.

Date: August 8, 2007

By: /s/ YEHUDIT BRONICKI

Name: Yehudit Bronicki
Title: Chief Executive Officer and President

Exhibit 32.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER
PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

I, Joseph Tenne, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the quarterly report of Ormat Technologies, Inc. on Form 10-Q for the three months ended June 30, 2007 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that information contained in such quarterly report on Form 10-Q fairly presents in all material respects the financial condition and results of operations of Ormat Technologies, Inc. as of and for the periods presented in such quarterly report on Form 10-Q. This written statement is being furnished to the Securities and Exchange Commission as an exhibit accompanying such quarterly report and shall not be deemed filed pursuant to the Securities Exchange Act of 1934.

Date: August 8, 2007

By: /s/ JOSEPH TENNE

Name: Joseph Tenne
Title: Chief Financial Officer