Edgar Filing: ORMAT TECHNOLOGIES, INC.

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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 September 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 41,507,360, par value $0.001 per share.

ORMAT TECHNOLOGIES, INC

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

PART I — UNAUDITED FINANCIAL INFORMATION

ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

ITEM 4. CONTROLS AND PROCEDURES

PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

ITEM 1A. RISK FACTORS

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

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

ITEM 5. OTHER INFORMATION

ITEM 6. EXHIBITS

SIGNATURES

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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 8¼% 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)

September 30,
2007 December 31,
2006 (in thousands) Assets

Current assets:

Cash and cash equivalents $ 20,331

$ 20,254

Marketable securities

8,640

96,486

Restricted cash, cash equivalents and marketable securities

56,895

56,425

Receivables:

Trade

53,561

36,463

Related entity

334

879

Other

5,825

5,277

Due from Parent

—

1,459

Inventories, net

10,460

7,403

Costs and estimated earnings in excess of billings on uncompleted contracts

2,986

11,216

Deferred income taxes

1,852

1,819

Prepaid expenses and other

6,793

4,911

Total current assets

167,677

242,592

Unconsolidated investments

31,992

37,207

Deposits and other

15,449

15,081

Deferred income taxes

5,611

6,172

Property, plant and equipment, net

737,210

624,089

Construction-in-process

166,973

169,075

Deferred financing and lease costs, net

14,292

15,800

Intangible assets, net

48,779

50,086

Total assets $ 1,187,983

$ 1,160,102

Liabilities and Stockholders’ Equity

Current liabilities:

Accounts payable and accrued expenses $ 65,869

$ 70,445

Billings in excess of costs and estimated earnings on uncompleted contracts

8,591

5,803

Current portion of long-term debt:

Limited and non-recourse

8,234

8,482

Full recourse

1,000

Senior secured notes (non-recourse)

27,488

40,054

Due to Parent, including current portion of notes payable to Parent

33,739

82,379

Total current liabilities

144,921

208,163

Long-term debt, net of current portion:

Limited and non-recourse

16,099

22,157

Full recourse

—

1,000

Senior secured notes (non-recourse)

287,791

299,316

Notes payable to Parent, net of current portion

91,912

57,841

Deferred lease income

76,869

78,883

Deferred income taxes

16,450

21,674

Liability for unrecognized tax benefits

4,308

—

Liabilities for severance pay

14,251

13,378

Asset retirement obligation

12,280

16,832

Total liabilities

664,881

719,244

Minority interest

67,697

Contingencies (Note 9)

Stockholders’ equity:

Common stock, par value $0.001 per share; 200,000,000 shares authorized; 38,126,106 and 38,101,888 shares issued and outstanding, respectively

Additional paid-in capital

356,644

353,399

Retained earnings

96,713

85,053

Accumulated other comprehensive income

2,010

2,304

Total stockholders’ equity

455,405

440,794

Total liabilities and stockholders’ equity $ 1,187,983

$ 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 September 30, Nine Months
Ended September 30, 2007 2006 2007 2006 (in thousands, except
per share data) (in thousands, except
per share data) Revenues:

Electricity:

Energy and capacity $ 23,081

$ 33,823

$ 67,481

$ 87,845

Lease portion of energy and capacity

37,654

21,908

90,929

59,043

Lease income

671

2,014

Total electricity

61,406

56,402

160,424

148,902

Products:

Related party

—

3,503

Other

18,061

21,446

64,842

49,850

Total products

18,061

21,446

64,842

53,353

Total revenues

79,467

77,848

225,266

202,255

Cost of revenues:

Electricity:

Energy and capacity

17,184

22,194

60,969

59,736

Lease portion of energy and capacity

16,960

8,814

45,604

26,454

Lease expense

1,311

3,932

Total electricity

35,455

32,319

110,505

90,122

Products

15,046

13,157

55,184

33,269

Total cost of revenues

50,501

45,476

165,689

123,391

Gross margin

28,966

32,372

59,577

78,864

Operating expenses:

Research and development expenses

952

826

2,717

2,489

Selling and marketing expenses

2,043

2,410

7,851

7,931

General and administrative expenses

4,979

4,270

15,888

13,358

Operating income

20,992

24,866

33,121

55,086

Other income (expense):

Interest income

1,171

1,443

4,207

4,905

Interest expense:

Parent

(1,397 )

(2,003 )

(4,544 )

(6,364 ) Other

(7,074 )

(8,018 )

(21,119 )

(22,893 ) Less – amount capitalized

1,487

1,674

3,827

5,716

Foreign currency translation and transaction losses

(96 )

(933 )

(771 )

(1,010 ) Other non-operating income

247

595

372

Income before income taxes, minority interest and equity in income of investees

15,330

17,094

15,316

35,812

Income tax provision

(2,300 )

(4,342 )

(2,297 )

(8,412 ) Minority interest

1,280

(242 )

1,585

(813 ) Equity in income of investees

1,452

1,429

3,864

3,639

Net income

15,762

13,939

18,468

30,226

Other comprehensive income (loss), net of related taxes:

Amortization of unrealized gains in respect of derivative instruments designated for cash flow hedge

(81 )

(90 )

(245 )

(271 ) Change in unrealized gains or losses on marketable securities available-for-sale

(5 )

(49 )

Comprehensive income $ 15,676

$ 13,940

$ 18,174

$ 30,036

Earnings per share – basic and diluted $ 0.41

$ 0.39

$ 0.48

$ 0.89

Weighted average number of shares used in computation of earnings per share:

Basic

38,125

35,588

38,119

34,100

Diluted

38,251

35,609

38,240

34,100

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 Total Shares Amount (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

—

2,604

—

2,604

Cash dividend declared, $0.17 per share

—

(6,480 )

—

(6,480 ) Exercise of options by employees

—

403

—

403

Tax benefit on exercise of options by employees

—

238

—

238

Cumulative adjustment from adoption of FIN No. 48

—

(328 )

—

(328 ) Net income

—

18,468

—

18,468

Other comprehensive loss, net of related taxes:

Amortization of unrealized gains in respect of derivative instruments designated for cash flow hedge (net of related tax of $154,000)

—

(245 )

(245 ) Change in unrealized gains or losses on marketable securities available-for-sale (net of related tax of $37,000)

—

(49 )

(49 ) Balance at September 30, 2007

38,126

$ 38

$ 356,644

$ 96,713

$ 2,010

$ 455,405

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)

Nine Months Ended September 30, 2007 2006 (in thousands) Cash flows from operating activities:

Net income $ 18,468

$ 30,226

Adjustments to reconcile net income to net cash provided by operating activities:

Depreciation and amortization

37,304

31,881

Accretion of asset retirement obligation

864

712

Stock-based compensation

2,604

1,176

Amortization of deferred lease income

(2,015 )

(2,015 ) Minority interest

(1,585 )

813

Equity in income of investees

(3,864 )

(3,639 ) Distributions from unconsolidated investments

9,736

2,920

Changes in unrealized loss in respect of derivative instruments, net

199

358

Gain on severance pay fund asset

(747 )

(643 ) Deferred income tax benefit (provision)

(1,595 )

2,738

Liability for unrecognized tax benefits

554

—

Changes in operating assets and liabilities, net of acquisitions:

Receivables

(17,646 )

(7,257 ) Costs and estimated earnings in excess of billings on uncompleted contracts

8,230

258

Inventories, net

(3,057 )

(656 ) Prepaid expenses and other

(1,882 )

(3,430 ) Deposits and other

(85 )

Accounts payable and accrued expenses

(9,711 )

4,316

Due from/to related entities, net

545

(614 ) Billings in excess of costs and estimated earnings on uncompleted contracts

2,788

(4,950 ) Other liabilities

—

(20 ) Liabilities for severance pay

873

1,609

Due from/to Parent

3,490

1,376

Net cash provided by operating activities

43,468

55,228

Cash flows from investing activities:

Distributions from unconsolidated investments

—

2,000

Marketable securities, net

87,575

(16,451 ) Net change in restricted cash, cash equivalents and marketable securities

(283 )

(5,173 ) Capital expenditures

(145,037 )

(114,858 ) Cash paid for acquisitions, net of cash received

—

(22,760 ) Intangible asset acquired

(1,150 )

—

Decrease in severance pay fund asset, net

(12 )

(432 ) Repayment from unconsolidated investment

Net cash used in investing activities

(58,812 )

(157,581 ) Cash flows from financing activities:

Due to Parent, net

(16,600 )

(16,600 ) Proceeds from the sale of interest rate caps

277

—

Proceeds from exercise of options by employees

403

—

Repayments of short-term and long-term debt

(31,397 )

(18,706 ) Deferred debt issuance costs

—

(720 ) Proceeds from the sale of limited liability company interest in OPC LLC, net of transaction costs

69,218

—

Proceeds from follow-on public offering, net of issuance costs

—

135,053

Cash dividends paid

(6,480 )

(3,794 ) Net cash provided by financing activities

15,421

95,233

Net increase (decrease) in cash and cash equivalents

(7,120 ) Cash and cash equivalents at beginning of period

20,254

26,976

Cash and cash equivalents at end of period $ 20,331

$ 19,856

Supplemental non-cash investing and financing activities:

Increase in accounts payable related to purchases of property, plant and equipment $ 5,135

$ 5,314

Increase (decrease) in asset retirement cost and asset retirement obligation $ (5,416 ) $ 1,028

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 September 30, 2007, the consolidated results of operations for the three and nine-month periods ended September 30, 2007 and 2006, and the consolidated cash flows for the nine-month periods ended September 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 nine-month periods ended September 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.

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 in the three months ended September 30, 2007 and an increase in net income and earnings per share of $514,000 and $0.02, respectively in the nine months ended September 30, 2007.

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 September 30, 2007 and December 31, 2006, the Company had deposits totaling $8,162,000 and $13,068,000, respectively, in six U.S. financial institutions that were federally insured up to $100,000 per account. At September 30, 2007 and December 31, 2006, the Company’s deposits in foreign countries amounted to approximately $19,765,000 and $15,321,000, respectively.

At September 30, 2007 and December 31, 2006, accounts receivable related to operations in foreign countries amounted to approximately $19,381,000 and $16,957,000, respectively. At September 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 51% and 49% of the Company’s accounts receivable, respectively.

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

Southern California Edison Company (‘‘SCE’’) accounted for 41.4% and 36.0% of the Company’s total revenues for the three months ended September 30, 2007 and 2006, respectively, and 32.3% and 31.8% of the Company’s total revenues for the nine months ended September 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 7.0% and 9.2% of the Company’s total revenues for the three months ended September 30, 2007 and 2006, respectively, and 8.6% and 12.4% of the Company’s total revenues for the nine months ended September 30, 2007 and 2006, respectively.

Hawaii Electric Light Company accounted for 15.1% and 13.1% of the Company’s total revenues for the three months ended September 30, 2007 and 2006, respectively, and 14.1% and 15.6% of the Company’s total revenues for the nine months ended September 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 nine-month periods ended September 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

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

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 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.

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

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 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 nine-month periods ended September 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:

September 30,
2007 December 31,
2006 (dollars in thousands) Raw materials and purchased parts for assembly $ 5,990

$ 3,397

Self-manufactured assembly parts and finished products

4,470

4,006

Total $ 10,460

$ 7,403

NOTE 5 — UNCONSOLIDATED INVESTMENTS

Unconsolidated investments in power plant projects consist of the following:

September 30,
2007 December 31,
2006 (dollars in thousands) Mammoth $ 31,797

$ 31,913

OLCL

195

5,294

Total $ 31,992

$ 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:

September 30,
2007 December 31,
2006 (dollars in thousands) Condensed balance sheets:

Current assets $ 6,948

$ 3,425

Non-current assets

75,927

79,942

Current liabilities

1,015

667

Non-current liabilities

3,221

3,130

Partners’ Capital

78,639

79,570

Nine Months Ended
September 30, 2007 2006 (dollars in thousands) Condensed statements of operations:

Revenues $ 12,731

$ 11,496

Gross margin

3,069

1,212

Net income

2,842

1,040

Company’s equity in income of Mammoth:

50% of Mammoth net income $ 1,421

$ 520

Plus amortization of basis difference

445

1,866

965

Less income taxes

(639 )

(367 ) Total $ 1,227

$ 598

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:

September 30,
2007 December 31,
2006 (dollars in thousands) Condensed balance sheets:

Current assets $ 2,192

$ 7,548

Non-current assets

4,632

Current liabilities

1,990

4,782

Stockholders’ equity

244

7,398

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

Nine Months Ended
September 30, 2007 2006 (dollars in thousands) Condensed statements of operations:

Revenues $ 11,224

$ 10,367

Gross margin

5,940

5,085

Net income

2,744

2,733

Company’s equity in income of OLCL:

80% of OLCL net income $ 2,195

$ 2,186

Plus amortization of deferred revenue on intercompany profit

442

1,129

Total $ 2,637

$ 3,315

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 owned the plants for a ten-year period which ended September 25, 2007, at which time they were transferred to PNOC for no further consideration. The Company did not incur 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 Condensed Consolidated Balance Sheets. As the Economic Benefits flow to the institutional equity investors, they are recognized by the Company in minority interest on the Condensed 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 $2.6 million as of September 30, 2007 have been reflected as a component of minority interest on the Condensed Consolidated Balance Sheets and will be amortized to minority interest in the Condensed 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 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:

Risk-free interest rates

4.5 % Expected term (in years)

5.1

Dividend yield

0.54

Expected volatility

35.7

Forfeiture rate

5.0 %

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.

On November 6, 2007, the Company granted options to purchase 30,000 shares of common stock under the 2004 Incentive Plan (see Note 12).

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 from the Company’s power plants pursuant to

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

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.

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

Electricity Products Consolidated (dollars in thousands) Three Months Ended September 30, 2007:

Net revenues from external customers $ 61,406

$ 18,061

$ 79,467

Intersegment revenues

—

22,988

Operating income

20,398

594

20,992

Segment assets at period end*

1,089,168

98,815

1,187,983

* Including unconsolidated investments

31,992

—

31,992

Three Months Ended September 30, 2006:

Net revenues from external customers $ 56,402

$ 21,446

$ 77,848

Intersegment revenues

—

12,396

Operating income

19,246

5,620

24,866

Segment assets at period end*

1,024,521

52,676

1,077,197

* Including unconsolidated investments

38,984

—

38,984

Nine Months Ended September 30, 2007:

Net revenues from external customers $ 160,424

$ 64,842

$ 225,266

Intersegment revenues

—

41,465

Operating income

33,013

108

33,121

Segment assets at period end*

1,089,168

98,815

1,187,983

* Including unconsolidated investments

31,992

—

31,992

Nine Months Ended September 30, 2006:

Net revenues from external customers $ 148,902

$ 53,353

$ 202,255

Intersegment revenues

—

48,184

Operating income

42,955

12,131

55,086

Segment assets at period end*

1,024,521

52,676

1,077,197

* Including unconsolidated investments

38,984

—

38,984

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

Three Months Ended
September 30, Nine Months Ended
September 30, 2007 2006 2007 2006 (dollars in thousands) (dollars in thousands) Operating income $ 20,992

$ 24,866

$ 33,121

$ 55,086

Interest expense, net

(5,813 )

(6,904 )

(17,629 )

(18,636 ) Non-operating income (loss) and other, net

151

(868 )

(176 )

(638 ) Total consolidated income before income taxes, minority interest and equity in income of investees $ 15,330

$ 17,094

$ 15,316

$ 35,812

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

NOTE 9 — CONTINGENCIES

One of the Company’s U.S. Subsidiaries (the ‘‘subsidiary’’) had been 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 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. On October 25, 2007, all of the parties entered into a settlement agreement, which provides for the release of any and all claims, demands, and causes of action by and among the parties, and stipulates that the settlement should not be construed as an admission of liability or wrongdoing by any party. The subsidiary was not required to make any payment to any of the parties as part of the settlement agreement.

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.

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

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 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 nine-month period ended September 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.

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. Such dividend was paid on August 29, 2007.

NOTE 11 — INCOME TAXES

The Company’s effective tax rate for the three and nine months ended September 30, 2007 was 15.0%, 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 $3,426,000 from long-term deferred income tax liabilities to liability for unrecognized tax benefits. During the three and nine months ended September 30, 2007, the Company increased its liability for unrecognized tax benefits by $385,000 and $554,000, respectively. The liability for unrecognized tax benefits of $4,308,000 at September 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 in the consolidated statements of operations.

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

The Company and its U.S. subsidiaries file consolidated income tax returns for federal and state purposes. As of September 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.

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 EVENTS

Cash Dividend

On November 6, 2007, the Company’s Board of Directors declared, approved and authorized payment of a quarterly dividend of $2.1 million ($0.05 per share) to all holders of the Company’s issued and outstanding shares of common stock on November 28, 2007, payable on December 12, 2007.

Issuance of Stock

On October 26, 2007, the Company completed a sale of 3,000,000 shares of common stock to Lehman Brothers Inc. in a block trade at a price of $45.90 per share (net of underwriting fees and commissions), under a shelf registration statement filed in early 2006. Net proceeds to the Company after deducting underwriting fees and commissions and estimated offering expenses associated with the offering were approximately $137.4 million.

On October 26, 2007, the Company completed an unregistered sale of 381,254 shares of common stock, to its parent, Ormat Industries Ltd., at a price of $45.90 per share. The proceeds from the unregistered sale were approximately $17.5 million. The shares of common stock issued in the unregistered sale have not been and will not be registered under the Securities Act of 1933, as amended, or any state securities laws, and may not be offered or sold in the United States absent registration or an applicable exemption from the registration requirements of the Securities Act of 1933, as amended.

A portion of the proceeds from the block trade and the unregistered sale of shares will be used to repay a capital note owed to the parent in the amount of $50.7 million which is payable on December 3, 2007. Because the demand note is being refinanced through the issuance of equity securities, it has been included in long-term liabilities in the Condensed Consolidated Balance Sheet as of September 30, 2007.

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

Legal Proceeding

See Note 9 regarding discussion of contingency settled on October 25, 2007.

Options Grant

On November 6, 2007, the Company granted to four non-employee directors non-qualified stock options, under the 2004 Incentive Plan, to purchase 30,000 shares of common stock (7,500 shares each) at an exercise price which is equal to the closing price of the Company’s common stock on November 7, 2007 (since the Company released its quarterly results on November 6, 2007). Such options will expire seven years from the date of grant and will vest on the first anniversary of the date of grant.

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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, the Prospectus Supplement filed with the SEC on October 23, 2007 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 pursuant to power purchase agreements, 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 nine months ended September 30, 2007, our Electricity Segment represented approximately 71.2% of our total revenues, while our Products Segment represented approximately 28.8% of our total revenues during such period.

During the nine months ended September 30, 2007, total Electricity Segment revenues from the sale of electricity by our consolidated power plants were $160.4 million. In addition, revenues from our 50% ownership of the Mammoth Project and from our 80% ownership of the Leyte Project for the nine months ended September 30, 2007 were $15.3 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 nine months ended September 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 and Nicaragua, 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 nine months ended September 30, 2007, revenues attributable to our Products Segment were $64.8 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 nine months ended September 30, 2007, we recognized revenues in our Products Segment of approximately $28.4 million from REG compared to $16.1 million in the same period last year. During the nine months ended September 30, 2007 we received purchase orders for the supply and construction of REG plants in a total amount of $26.2 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 nine months ended September 30, 2007, 82.2% of the electricity revenues generated were 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 nine months ended September 30, 2007 our total revenues increased by 2.1% (from $77.8 million to $79.5 million) and 11.4% (from $202.3 million to $225.3 million), respectively, over the same periods last year. Revenues from the Electricity Segment increased by 8.9% and 7.7%, respectively, while revenues from the Products Segment decreased by 15.8% from the same three-month period last year but increased by 21.5% from the same nine-month period last year.

During the three and nine months ended September 30, 2007, our U.S. power plants generated 501,389 MWh and 1,461,153 MWh, respectively. During the three and nine months ended September 30, 2006, our U.S. power plants generated 423,740 MWh and 1,302,690 MWh, respectively.

Recent Developments

• During the nine months ended September 30, 2007, we have achieved several milestones related to our projects and operations:

• We commenced commercial operation in the Amatitlan project, which currently generates approximately 18 MW.

• 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 drilling of the Brawley production wells. The other drilling rig will be used for our exploration program in Nevada.

• Progress was made in the development of the 330 MW Sarulla project in Indonesia. Initially we will own 25% of the Indonesian special purpose company that will operate the project. We have an option to decrease our minority interest to 12.75% subject to certain approval that we will need to obtain. In August 2007, the Sarulla consortium (consisting of our wholly owned subsidiary, a unit of Medco Energi International, Inc. and Itochu Corp. of Japan) signed a Heads of Agreement for the project. The Heads of Agreement sets forth milestones achieved in the negotiation of various project-related contracts and the parties’ undertaking to expedite such contracts’ finalization and the procurement of all relevant approvals.

• 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.

• We recently reached agreement with Sierra Pacific Power Company and Nevada Power Company, the purchasers of electricity generated by our current and planned geothermal power projects in Nevada, regarding certain amendments to the power purchase agreements for a number of our existing geothermal projects in operation and some of our geothermal projects under development and construction. These amendments (i) provide for a mechanism to share production tax credits with the relevant purchaser pursuant to a reduction in the price for electricity paid by the power purchaser under the relevant power purchase agreement, bringing additional power purchase agreements in line with the production tax

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credit sharing arrangements included in other power purchase agreements with these purchasers in Nevada, (ii) revise certain generation thresholds based on a more definitive understanding of the geothermal resource at the respective projects, and (iii) address certain delays in meeting contract milestones as a result of ordinary course project construction delays. We expect that the power purchasers will submit the amendments shortly to the Public Utilities Commission of Nevada for approval. If the amendments are not approved, we may face claims from the power purchasers under the power purchase agreements stemming from the project delays and the reduced generation.

• On October 26, 2007, we completed a sale of 3,000,000 shares of common stock to Lehman Brothers Inc. in a block trade at a price of $45.90 per share (net of underwriting fees and commissions), under a shelf registration statement filed in early 2006. Net proceeds to us, after deducting underwriting fees and commissions and estimated offering expenses associated with the offering, were approximately $137.4 million.

On October 26, 2007, we completed an unregistered sale of 381,254 shares of common stock to our parent, Ormat Industries Ltd., at a price of $45.90 per share. The proceeds from the unregistered sale were approximately $17.5 million. The shares of common stock issued in the unregistered sale have not been and will not be registered under the Securities Act of 1933, as amended, or any state securities laws, and may not be offered or sold in the United States absent registration or an applicable exemption from the registration requirements of the Securities Act of 1933, as amended.

• In August 2007, we secured lease agreements for seven new sites covering approximately 68,900 acres of federal land in Nevada through a competitive auction conducted by the Bureau of Land Management. Our winning bid was for a total amount of approximately $8.2 million. We expect that this additional acreage will support our growth plans in the years to come; however, there is no assurance that all of the leases will yield sufficient (if any) geothermal resources suitable for commercial projects. This is in addition to other lease agreements in Nevada and California that we have signed since the beginning of the year.

• 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.

• In June 2007, we signed a 20-year power purchase agreement with Southern California Edison Company (Southern California Edison) for the sale of 50 MW 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.

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• 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 Nevada Power Company 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 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.

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• 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 nine months 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 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

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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.

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

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

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

• 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 its 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 September 30, Nine Months
Ended September 30, Three Months
Ended September 30, Nine Months
Ended September 30, 2007 2006 2007 2006 2007 2006 2007 2006 Revenues

Electricity Segment $ 61,406

$ 56,402

$ 160,424

$ 148,902

77.3 %

72.5 %

71.2 %

73.6 % Products Segment

18,061

21,446

64,842

53,353

22.7

27.5

28.8

26.4

Total $ 79,467

$ 77,848

$ 225,266

$ 202,255

100.0 %

Geographical Breakdown of Revenues

For the three months ended September 30, 2007, 87.6% of our revenues attributable to our Electricity Segment were generated in the United States, as compared to 84.1% for the same period in 2006. For the nine months ended September 30, 2007, 83.5% of our revenues attributable to our Electricity Segment were generated in the United States, as compared to 84.0% for the same period in 2006. The following table sets forth the geographic breakdown of the revenues attributable to our Electricity Segment for the periods indicated:

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$ 47,461

$ 133,968

$ 125,005

87.6 %

84.1 %

83.5 %

84.0 % Foreign

7,592

8,941

26,456

23,897

12.4

15.9

16.5

16.0

Total $ 61,406

$ 56,402

$ 160,424

$ 148,902

100.0 %

For the three and nine months ended September 30, 2007, 22.6% and 31.8%, respectively, of our revenues attributable to our Products Segment were generated in the United States, as compared to 12.9% and 7.8% 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 nine months ended September 30, 2007, royalties constituted approximately 4.4% of the Electricity Segment revenues, compared to approximately 4.8% for the same period in 2006.

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

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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 September 30, 2007 decreased to $29.0 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 $145.0 million, repayments of long-term debt to our parent and third parties in the amount of $48.0 million and dividend distributions of $6.5 million, offset by $69.2 million net proceeds from the OPC transaction described below, and by $42.7 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 nine months ended September 30, 2007. Such operational issues are not expected to continue and are not indicative of future trends.

Three Months Ended September 30, Nine Months Ended September 30, 2007 2006 2007 2006 (in thousands, except per share data) Statements of Operations Historical Data:

Revenues:

Electricity Segment $ 61,406

$ 56,402

$ 160,424

$ 148,902

Products Segment

18,061

21,446

64,842

53,353

79,467

77,848

225,266

202,255

Cost of revenues:

Electricity Segment

35,455

32,319

110,505

90,122

Products Segment

15,046

13,157

55,184

33,269

50,501

45,476

165,689

123,391

Gross margin:

Electricity Segment

25,951

24,083

49,919

58,780

Products Segment

3,015

8,289

9,658

20,084

28,966

32,372

59,577

78,864

Operating expenses:

Research and development expenses

952

826

2,717

2,489

Selling and marketing expenses

2,043

2,410

7,851

7,931

General and administrative expenses

4,979

4,270

15,888

13,358

Operating income

20,992

24,866

33,121

55,086

Other income (expense):

Interest income

1,171

1,443

4,207

4,905

Interest expense

(6,984 )

(8,347 )

(21,836 )

(23,541 ) Foreign currency translation and transaction losses

(96 )

(933 )

(771 )

(1,010 ) Other non-operating income

247

595

372

Income before income taxes, minority interest and equity in income of investees

15,330

17,094

15,316

35,812

Income tax provision

(2,300 )

(4,342 )

(2,297 )

(8,412 ) Minority interest

1,280

(242 )

1,585

(813 ) Equity in income of investees

1,452

1,429

3,864

3,639

Net income $ 15,762

$ 13,939

$ 18,468

$ 30,226

Earnings per share – basic and diluted $ 0.41

$ 0.39

$ 0.48

$ 0.89

Weighted average number of shares used in computation of earnings per share:

Basic

38,125

35,588

38,119

34,100

Diluted

38,251

35,609

38,240

34,100

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Three Months Ended September 30, Nine Months Ended September 30, 2007 2006 2007 2006 Statements of Operations Percentage Data:

Revenues:

Electricity Segment

77.3 %

72.5 %

71.2 %

73.6 % Products Segment

22.7

27.5

28.8

26.4

100.0

Cost of revenues:

Electricity Segment

57.7

57.3

68.9

60.5

Products Segment

83.3

61.3

85.1

62.4

63.5

58.4

73.6

61.0

Gross margin:

Electricity Segment

42.3

42.7

31.1

39.5

Products Segment

16.7

38.7

14.9

37.6

36.5

41.6

26.4

39.0

Operating expenses:

Research and development expenses

1.2

1.1

1.2

Selling and marketing expenses

2.6

3.1

3.5

3.9

General and administrative expenses

6.3

5.5

7.1

6.6

Operating income

26.4

31.9

14.7

27.2

Other income (expense):

Interest income

1.5

1.9

2.4

Interest expense

(8.8 )

(10.7 )

(9.7 )

(11.6 ) Foreign currency translation and transaction losses

(0.1 )

(1.2 )

(0.3 )

(0.5 ) Other non-operating income

0.3

0.1

0.3

0.2

Income before income taxes, minority interest and equity in income of investees

19.3

22.0

6.8

17.7

Income tax provision

(2.9 )

(5.6 )

(1.0 )

(4.2 ) Minority interest

1.6

(0.3 )

0.7

(0.4 ) Equity in income of investees

1.8

1.7

1.8

Net income

19.8 %

17.9 %

8.2 %

14.9 %

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

Total Revenues

Total revenues for the three months ended September 30, 2007 were $79.5 million, as compared with $77.8 million for the three months ended September 30, 2006, which represented a 2.1% increase in total revenues. This increase is attributable to our Electricity Segment whose revenues increased by 8.9%, offset by a decrease of 15.8% in our Products Segment, over the same period in 2006.

Electricity Segment

Revenues attributable to our Electricity Segment for the three months ended September 30, 2007 were $61.4 million, as compared with $56.4 million for the three months ended September 30, 2006, which represented a 8.9% 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 423,740 MWh in the three months ended September 30, 2006 to 501,389 MWh in the three months ended September 30, 2007; and (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. In addition we generated $1.4 million from our Amatitlan

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project in Guatemala, which started generating electricity in March 2007. 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 $2.5 million in revenues from the Momotombo project in Nicaragua as a result of the failure of a turbine that we did not manufacture. The Momotombo power plant recently returned to full operation.

Products Segment

Revenues attributable to our Products Segment for the three months ended September 30, 2007 were $18.1 million, as compared with $21.4 million for the three months ended September 30, 2006, which represented a 15.8% decrease in such revenues. This decrease 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 September 30, 2007 was $50.5 million, as compared with $45.5 million for the three months ended September 30, 2006, which represented an 11.0% increase in total cost of revenues. As a percentage of total revenues, our total cost of revenues for the three months ended September 30, 2007 was 63.5% compared with 58.4% 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 September 30, 2007 was $35.5 million, as compared with $32.3 million for the three months ended September 30, 2006, which represented a 9.7% increase in total cost of revenues for such segment. This increase is primarily due to the following: (i) an increase of $0.4 million in cost of revenues attributable to the Amatitlan project in Guatemala, which started generating electricity in March 2007, but has not yet declared commercial operation; and (ii) an increase of $1.8 million in our cost of revenues in the Momotombo project in Nicaragua mainly as a result of the failure of a turbine that we did not manufacture, as described above. The remaining increase in our cost of revenues 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 the reversal of an accrual in the amount of $1.1 million due to the settlement of a dispute during the third 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 September 30, 2007 was 57.7% compared with 57.3% for the three months ended September 30, 2006.

Products Segment

Total cost of revenues attributable to our Products Segment for the three months ended September 30, 2007 was $15.0 million, as compared with $13.2 million for the three months ended September 30, 2006, which represented a 14.4 % increase in total cost of revenues related to such segment. This increase is attributable to 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 three months ended September 30, 2007 was 83.3% as compared with 61.3% for the three months ended September 30, 2006.

Research and Development Expenses

Research and development expenses for the three months ended September 30, 2007 were $1.0 million, as compared with $0.8 million for the three months ended September 30, 2006, which represented a 15.3% increase. Such increase reflects fluctuations in the period in which actual expenses were incurred.

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Selling and Marketing Expenses

Selling and marketing expenses for the three months ended September 30, 2007 were $2.0 million, as compared with $2.4 million for the three months ended September 30, 2006, which represented a 15.2% decrease. The decrease was due primarily to a decrease in selling and marketing costs relating to the Products Segment, offset partially by an increase in salaries. Selling and marketing expenses for the three months ended September 30, 2007 constituted 2.6% of total revenues for such period, as compared with 3.1% for the three months ended September 30, 2006. Such decrease is principally attributable to a decrease in costs relating to the Products Segment, as described above.

General and Administrative Expenses

General and administrative expenses for the three months ended September 30, 2007 were $5.0 million, as compared with $4.3 million for the three months ended September 30, 2006, which represented a 16.6% 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 September 30, 2007 increased to 6.3% of total revenues for such period, from 5.5% for the three months ended September 30, 2006.

Operating Income

Operating income for the three months ended September 30, 2007 was $21.0 million, as compared with $24.9 million for the three months ended September 30, 2006. Such decrease in operating income was principally attributable to a decrease in gross margin in our Products Segment due to a decrease in Products Segment revenues and an increase in cost of revenues of the Products Segment, as described above. Operating income attributable to our Electricity Segment for the three months ended September 30, 2007 was $20.4 million, as compared with $19.2 million for the three months ended September 30, 2006. Operating income attributable to our Products Segment for the three months ended September 30, 2007 was $0.6 million, as compared with $5.6 million for the three months ended September 30, 2006.

Interest Expense

Interest expense for the three months ended September 30, 2007 was $7.0 million, as compared with $8.3 million for the three months ended September 30, 2006, which represented a 16.3% decrease. The $1.3 million decrease is primarily due to principal repayments. The decrease in interest expense was partially offset by a decrease of $0.2 million in interest capitalized to projects.

Income Taxes

Income tax provision for the three months ended September 30, 2007 and 2006 was $2.3 million and $4.3 million, respectively. The effective tax rates for the three months ended September 30, 2007 and 2006 were 15.0% and 25.4%, respectively. Our effective tax rate decreased in the three months ended September 30, 2007 compared with the same period last year due to: (i) an increase in production tax credits as a result of new power plants placed in service; (ii) a decrease of 2% in the tax rate in Israel commencing January 1, 2007; and (iii) a tax credit related to our subsidiaries in Guatemala.

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 September 30, 2007 resulting from the adoption of FIN No. 48 was immaterial.

Minority interest

Minority interest for the three months ended September 30, 2007 includes income of $1.3 million from the sale of limited liability company interests in OPC LLC to institutional equity investors in June 2007. Minority interest for the three months ended September 30, 2006 includes $0.2 million minority interest in earnings of the Zunil project.

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Equity in Income of Investees

Our participation in the income generated from our investees for the three months ended September 30, 2007 was $1.5 million, as compared with $1.4 million for the three months ended September 30, 2006. On September 25, 2007, our equity investee, Ormat Leyte Co. Ltd. transferred its power plants to PNOC-Energy Development Corporation pursuant to a Build, Operate, and Transfer agreement. We did not incur any material financial loss as a result of such transfer, although going forward this will reduce our foreign generation capacity by 49 MW with a commensurate impact on equity in income of investees and net income.

Net Income

Net income for the three months ended September 30, 2007 was $15.8 million, as compared with $13.9 million for the three months ended September 30, 2006, a 13.1% increase. Such increase in net income was principally attributable to: (i) a $1.3 million decrease in interest expense; (ii) a $2.0 million decrease in income tax provision and (iii) a $1.5 million increase in minority interest as described above. This was partially offset by a decrease in our operating income of $3.9 million as follows: (i) in the Products Segment, operating income decreased by $5.0 million as a result of a decrease in revenues and due to lower margins as discussed above; and (ii) in the Electricity Segment, operating income increased by $1.2 million. Net income for the three months ended September 30, 2007 includes stock-based compensation related to stock options of $1.0 million as compared with $0.5 million for the three months ended September 30, 2006.

Comparison of the Nine Months Ended September 30, 2007 and the Nine Months Ended September 30, 2006

Total Revenues

Total revenues for the nine months ended September 30, 2007 were $225.3 million, as compared with $202.3 million for the nine months ended September 30, 2006, which represented an 11.4% increase in total revenues. This increase is attributable both to our Electricity and Products Segment whose revenues increased by 7.7% and 21.5%, respectively, over the same period in 2006.

Electricity Segment

Revenues attributable to our Electricity Segment for the nine months ended September 30, 2007 were $160.4 million, as compared with $148.9 million for the nine months ended September 30, 2006, which represented a 7.7% increase in such revenues. This increase is partially attributable to additional revenues of $9.0 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 1,302,690 MWh in the nine months ended September 30, 2006 to 1,461,153 MWh in the nine months ended September 30 2007, mainly as a result of additional generation from 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; (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; and (iii) 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

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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) 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; and (v) a decrease of $3.2 million in revenues from the Momotombo project in Nicaragua as a result of the failure of turbines that we did not manufacture. This increase is also attributable to: (i) a $2.6 million increase in revenues generated from the Zunil project in Guatemala, which was consolidated as of March 13, 2006; and (ii) revenues of $3.2 million generated from our Amatitlan project in Guatemala, which started generating electricity in March 2007.

Products Segment

Revenues attributable to our Products Segment for the nine months ended September 30, 2007 were $64.8 million, as compared with $53.4 million for the nine months ended September 30, 2006, which represented a 21.5% 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 nine months ended September 30, 2007 was $165.7 million, as compared with $123.4 million for the nine months ended September 30, 2006, which represented a 34.3% increase in total cost of revenues. As a percentage of total revenues, our total cost of revenues for the nine months ended September 30, 2007 was 73.6% compared with 61.0% 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 nine months ended September 30, 2007 was $110.5 million, as compared with $90.1 million for the nine months ended September 30, 2006, which represented a 22.6% 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 $0.7 million in cost of revenues attributable to the Zunil project in Guatemala which was consolidated as of March 13, 2006; (vi) the inclusion of $1.4 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; and (vii) an increase of $1.2 million in our cost of revenues in the Momotombo project in Nicaragua as a result of the failure of turbines that we did not manufacture, as described above. The remaining increase in our cost of revenues 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 and the reversal of an accrual of $1.1 million due to the settlement of a dispute during the third quarter of 2007. As a percentage of total electricity revenues, the total cost of revenues attributable to our Electricity Segment for the nine months ended September 30, 2007 was 68.9% compared with 60.5% for the nine months ended September 30, 2006.

Products Segment

Total cost of revenues attributable to our Products Segment for the nine months ended September 30, 2007 was $55.2 million as compared with $33.3 million for the nine months ended

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September 30, 2006, which represented a 65.9% 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 nine months ended September 30, 2007 was 85.1% as compared with 62.4% for the nine months ended September 30, 2006.

Research and Development Expenses

Research and development expenses for the nine months ended September 30, 2007 were $2.7 million, as compared with $2.5 million for the nine months ended September 30, 2006, which represented a 9.2% increase. Such increase reflects fluctuations in the period in which actual expenses were incurred.

Selling and Marketing Expenses

Selling and marketing expenses for the nine months ended September 30, 2007 were $7.8 million, as compared with $7.9 million for the nine months ended September 30, 2006, which represented a 1.0% decrease. The decrease was due primarily to a decrease in selling and marketing costs relating to the Products Segment, offset partially by an increase in salaries. Selling and marketing expenses for the nine months ended September 30, 2007 constituted 3.5% of total revenues for such period, as compared with 3.9% for the nine months ended September 30, 2006.

General and Administrative Expenses

General and administrative expenses for the nine months ended September 30, 2007 were $15.9 million, as compared with $13.4 million for the nine months ended September 30, 2006, which represented a 18.9% 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 nine months ended September 30, 2007 increased to 7.1% of total revenues for such period, from 6.6% for the nine months ended September 30, 2006.

Operating Income

Operating income for the nine months ended September 30, 2007 was $33.1 million, as compared with operating income of $55.1 million for the nine months ended September 30, 2006. Such decrease in operating income was principally attributable to a $19.3 million decrease in gross margin primarily due to the increase in total cost of revenues as explained above, and an increase of $2.7 million in operating expenses. Operating income attributable to our Electricity Segment for the nine months ended September 30, 2007 was $33.0 million, as compared with operating income of $43.0 million for the nine months ended September 30, 2006. Operating income attributable to our Products Segment for the nine months ended September 30, 2007 was $0.1 million, as compared with operating income of $12.1 million for the nine months ended September 30, 2006.

Interest Expense

Interest expense for the nine months ended September 30, 2007 was $21.8 million, as compared with $23.5 million for the nine months ended September 30, 2006, which represented a 7.2% decrease. The $1.7 million decrease is primarily due to principal repayments. The decrease in interest expense was partially offset by a decrease of $1.9 million in interest capitalized to projects and an increase of $0.4 million in interest expense for the nine months ended September 30, 2007 due to the Zunil project, which was consolidated as of March 13, 2006.

Income Taxes

Income tax provision for the nine months ended September 30, 2007 was $2.3 million, as compared with $8.4 million for the nine months ended September 30, 2006. The effective tax rates for

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the nine months ended September 30, 2007 and 2006 were 15.0% and 23.5%, respectively. Our effective tax rate decreased in the nine months ended September 30, 2007 compared with the same period last year due to: (i) an increase in production tax credits as a result of new power plants placed in service ; (ii) a decrease of 2% in the tax rate in Israel commencing January 1, 2007; and (iii) a tax credit related to our subsidiaries in Guatemala.

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 nine months ended September 30, 2007 resulting from the adoption of FIN No. 48 was immaterial.

Minority interest

Minority interest for the nine months ended September 30, 2007 includes income of $1.6 million from the sale of limited liability company interests in OPC LLC to institutional equity investors in June 2007. Minority interest for the nine months ended September 30, 2006 includes $0.8 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 nine months ended September 30, 2007 was $3.9 million, as compared with $3.6 million for the nine months ended September 30, 2006. On September 25, 2007, our equity investee, Ormat Leyte Co. Ltd. transferred its power plants to PNOC-Energy Development Corporation pursuant to a Build, Operate, and Transfer agreement. We did not incur any material financial loss as a result of such transfer, although going forward this will reduce our foreign generation capacity by 49 MW with a commensurate impact on equity in income of investees and net income.

Net Income

Net income for the nine months ended September 30, 2007 was $18.5 million, as compared with $30.2 million for the nine months ended September 30, 2006, a decrease of 38.9%. Such decrease in net income was principally attributable to a $19.3 million decrease in gross margin primarily due to the increase in total cost of revenues as explained above, and an increase of $2.7 million in operating expenses. This was partially offset by a decrease in our income tax provision of $6.1 million, a $1.7 million decrease in interest expense and a $2.4 million increase in minority interest as described above. Net income for the nine months ended September 30, 2007 includes stock-based compensation related to stock options of $2.6 million as compared with $1.2 million for the nine months ended September 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 $623 million through the issuance of securities pursuant to the terms and conditions of the shelf registration.

As described in ‘‘Recent Developments’’, on October 26, 2007, we completed a sale of 3,000,000 shares of common stock to Lehman Brothers Inc. in a block trade at a price of $45.90 per share (net of underwriting fees and commissions), under a shelf registration statement filed in early 2006, and on

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the same date we completed an unregistered sale of 381,254 shares of common stock to our parent, Ormat Industries Ltd., at a price of $45.90 per share. Net proceeds from both sales to us, after deducting underwriting fees and commissions and estimated offering expenses associated with the offering, were approximately $154.9 million. A portion of the proceeds from the block trade and the unregistered sale of shares will be used to repay a capital note owed to the parent in the amount of $50.7 million on December 3, 2007 (See ‘‘Loan Agreement with our Parent’’).

Loan Agreements with our Parent

In 2003, we entered into a loan agreement with our parent company, 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 September 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 (which is the dollar equivalent based on the exchange rate existing on the date of such note). As of September 30, 2007 and December 31, 2006 the ceiling of $50.7 million is effective. Since the note was payable upon demand at any time after November 30, 2007 it was presented in current liabilities in our balance sheet as of December 31, 2006. On October 26, 2007, we received a demand from Ormat Industries to repay the loan on December 3, 2007. (See ‘‘Recent Developments’’). Because the demand note is being refinanced through the issuance of equity securities, it has been included in long-term liabilities in our balance sheet as of September 30, 2007.

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 September 30, 2007, we were in compliance with the covenants under the OrCal Senior Secured Notes. As of September 30, 2007, there were $145.9 million of OrCal Senior Secured Notes outstanding.

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Ormat Funding Senior Secured Notes – Non Recourse

On February 13, 2004, Ormat Funding Corp. (OFC), one of our subsidiaries, issued $190.0 million, 8¼% 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 September 30, 2004. The OFC Senior Secured Notes are collateralized by substantially all of the assets of OFC and those of its wholly owned subsidiaries and are fully and unconditionally guaranteed by all of the wholly owned subsidiaries of OFC. There are various restrictive covenants under the OFC Senior Secured Notes, which include limitations on additional indebtedness and payment of dividends. On December 31, 2006 and June 30, 2007, 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 September 30, 2007, there were $169.4 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 in Guatemala, has senior loan agreements with IFC and CDC. The first loan from IFC, of which $6.1 million was outstanding as of September 30, 2007, has a fixed annual interest rate of 11.775%, and matures on November 15, 2011. The second loan from IFC, of which $2.0 million was outstanding as of September 30, 2007, has a fixed annual interest rate of 11.730%, and matures on May 15, 2008. The loan from CDC, of which $7.1 million was outstanding as of September 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 September 30, 2007, Orzunil is in compliance with the required ‘‘debt service coverage ratio’’ and with all other covenants.

Credit Facility Agreement (The Momotombo project) – Limited Recourse

Ormat Momotombo Power Company (Momotombo), a wholly owned subsidiary in Nicaragua, has a loan agreement with Bank Hapoalim, of which $9 million was outstanding as of September 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. Tranche one of the loan matures on September 5, 2010, and is payable in 32 quarterly installments of $298,000 and tranche two of the loan matures on December 5, 2010, and is payable in 28 quarterly installments of $424,000. There are various restrictive covenants under this loan, which include limitations on Momotombo’s ability to make distributions to its shareholders.

Due to a failure of a turbine that was not manufactured by Ormat, the Momotombo Project has not been in full operation from June 2007. As a result, Momotombo did not meet the ‘‘debt service

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coverage ratio’’ required at September 30, 2007, and therefore, distributions from the Project are restricted. The power plant recently returned to full operation.

In October 2007, Momotombo reached an agreement with Bank Hapoalim, pursuant to which Bank Hapoalim allowed Momotombo to use the funds in the ‘‘Debt Service Reserve Account’’ for the repair of the damaged turbine. As a result, Momotombo does not comply with the required ‘‘Debt Service Reserve Account’’. In accordance with the terms of the credit facility Momotombo has a 180-day period to replenish the ‘‘Debt Service Reserve Account’’. As the power plant recently returned to full operation, we believe that Momotombo will comply with the ‘‘Debt Service Reserve Account’’ covenant within the 180-day period.

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 exclusivity of the mandate letter with the local bank in Guatemala and are currently in discussions with other financial institutions.

Financing of Phase II of Olkaria III Project

We have engaged a financial institution that is leading a syndicate for the purpose of arranging long term financing for the Olkaria III project in Kenya. The syndicate is in the process of conducting due diligence related to the potential financing. 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 September 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 Israeli banks. 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 Israeli 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.

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

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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 September 30, 2007, three letters of credit in the amount of $12.3 million remained issued and outstanding under this credit agreement with UBOC.

In September 2007, we entered into two separate credit agreements with two commercial banks, each for $30 million. Under these credit agreements, we or our Israeli subsidiary, Ormat Systems, can request extensions of credit in the form of loans and/or the issuance of one or more letters of credit. Each of the credit agreements has a term of three years.

Loans and draws under the credit agreements or under any letters of credit will bear interest at the respective bank’s cost of funds plus a margin. Our (or Ormat Systems’) obligations under the credit agreements are unsecured, but we are subject to a negative pledge in favor of the banks and certain other customary restrictive covenants.

As of September 30, 2007 and as of the date of this report, no loans or letters of credits were outstanding under such credit agreements.

Our management believes that we are currently in compliance with our covenants with respect to our third-party debt, except as described above regarding the Bank Hapoalim loan.

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 September 30, 2007, Bank Leumi and Bank Hapoalim have agreed to make available to us letters of credit totaling $24.1 million and $21.8 million, respectively. As of such date, Bank Leumi and Bank Hapoalim have issued letters of credit in the amount of $20.2 million and $11.9 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

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second half of 2005 (for production and injection) was completed on December 30, 2005. Pursuant to a 31-year head lease, PGV leased its geothermal power plant to the abovementioned financing parties in return for deferred lease payments by such financing parties to PGV in the aggregate amount of $83.0 million.

OPC 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 $4.3 million as of September 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 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 November 6, 2007 $ 0.05

November 28, 2007 December 12, 2007

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Historical Cash Flows

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

Nine Months Ended September 30, 2007 2006 (in thousands) Net cash provided by operating activities $ 43,468

$ 55,228

Net cash used in investing activities

(58,812 )

(157,581 ) Net cash provided by financing activities

15,421

95,233

Net increase (decrease) in cash and cash equivalents

(7,120 )

For the nine months ended September 30, 2007

Net cash provided by operating activities for the nine months ended September 30, 2007 was $43.5 million, as compared with $55.2 million for the nine months ended September 30, 2006. Such net decrease of $11.8 million resulted primarily from the decrease in gross margin, as described above. This decrease resulted from a net income of $18.5 million in the nine months ended September 30, 2007, as compared with $30.2 million in the nine months ended September 30, 2006.

Net cash used in investing activities for the nine months ended September 30, 2007 was $58.8 million, as compared with $157.6 million for the nine months ended September 30, 2006. The principal factors that affected our cash flow used in investing activities during the nine months ended September 30, 2007 were capital expenditures of $145.0 million primarily for our facilities under construction, offset by an $87.6 million decrease in marketable securities. The principal factors that affected our cash flow used in investing activities during the nine months ended September 30, 2006 were capital expenditures of $114.9 million primarily for our power facilities under construction, $22.8 million used in the acquisition of additional 79% of the Zunil project in Guatemala and a net increase of $16.5 million in marketable securities derived from the follow-on offering proceeds.

Net cash provided by financing activities for the nine months ended September 30, 2007 was $15.4 million, as compared with $95.2 million for the nine months ended September 30, 2006. The principal factors that affected the cash flow provided by financing activities during the nine months ended September 30, 2007 were $69.2 million in net 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 $31.4 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 $6.5 million. The principal factors that affected the cash flow provided by financing activities during the nine months ended September 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 $18.7 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 $3.8 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. 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 have completed the drilling of the wells and are currently in the process of constructing the 35 MW power plant.

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.

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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 5.5 MW. 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 during 2009.

We have budgeted approximately $470 million for the above-described projects (other than OrSumas) and have invested approximately $130 million of such budget as of September 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 requirements for the rest of 2007 and 2008 of approximately $32 million. We plan to start other construction and enhancement of additional projects, including exploration work, for a total investment amount of approximately $67 million for the rest of 2007, 2008 and 2009 and we also plan to invest approximately $27 million in machinery and equipment, including drilling equipment.

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 September 30, 2007, 97.8% 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 of such date, $10.1 million, or 2.2 %, 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.

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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 41.4% and 36.0% of our total revenues for the three months ended September 30, 2007 and 2006, respectively, and 32.3% and 31.8% of our total revenues for the nine months ended September 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 7.0% and 9.2% of our total revenues for the three months ended September 30, 2007 and 2006, respectively, and 8.6% and 12.4% of our total revenues for the nine months ended September 30, 2007 and 2006, respectively.

Hawaii Electric Light Company accounts for 15.1% and 13.1% of our total revenues for the three months ended September 30, 2007 and 2006, respectively, and 14.1% and 15.6% of our total revenues for the nine months ended September 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 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

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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 September 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 third 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 nine months period ended September 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.

One of our U.S. Subsidiaries, Ormat Inc., had been 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 Henrys were the sole shareholders of MPS Generation, Inc. (MPSG). Our subsidiary entered into a supply contract with MPSG dated as of December 29, 2003, under which our 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

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November 15, 2005, the Henrys answered Basin’s complaint in the bankruptcy proceeding and also filed a third-party complaint against our subsidiary, alleging that to the extent the Henrys are found personally liable to Basin for MPSG’s debts, the Henrys have claims against our 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, our subsidiary filed an answer denying the Henrys’ claims and asserting counterclaims against the Henrys. Our 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 our subsidiary. On May 11, 2006, the Bankruptcy Court entered an order denying our subsidiary’s motion to dismiss the Henrys’ claims against it, but staying the Henrys’ litigation against our 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 our subsidiary similar to those claims raised by the Henrys. On October 25, 2007, all of the parties entered into a settlement agreement, which provides for the release of any and all claims, demands, and causes of action by and among the parties, and stipulates that the settlement should not be construed as an admission of liability or wrongdoing by any party. The subsidiary was not required to make any payment to any of the parties as part of the settlement agreement.

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 and the Prospectus Supplement filed with the SEC on October 23, 2007 with the exception of the following risk factor, which we have updated to reflect recent FERC activity:

If any of our domestic projects lose their current Qualifying Facility status under PURPA, or if amendments to PURPA are enacted that substantially reduce the benefits currently afforded to Qualifying Facilities, our domestic operations could be adversely affected.

Most of our domestic projects are Qualifying Facilities pursuant to the Public Utility Regulatory Policies Act of 1978, as amended, which we refer to as PURPA, which largely exempts the projects from the Federal Power Act, which we refer to as FPA, and certain state and local laws and regulations regarding rates and financial and organizational requirements for electric utilities.

PUHCA was repealed on February 8, 2006. If any of our domestic projects were to lose its Qualifying Facility status, such project could become subject to the full scope of the FPA and applicable state regulation. The application of the FPA and other applicable state regulation to our domestic projects could require our operations to comply with an increasingly complex regulatory regime that may be costly and greatly reduce our operational flexibility.

In addition, pursuant to the FPA, the FERC has exclusive rate-making jurisdiction over wholesale sales of electricity and transmission of public utilities in interstate commerce. These rates may be based on a cost of service approach or may be determined on a market basis through competitive bidding or negotiation. Qualifying Facilities are largely exempt from the FPA. If a domestic project were to lose its Qualifying Facility status, it would become a public utility under the FPA, and the rates charged by such project pursuant to its power purchase agreements would be subject to the review and approval of the FERC. The FERC, upon such review, may determine that the rates

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currently set forth in such power purchase agreements are not appropriate and may set rates that are lower than the rates currently charged. In addition, the FERC may require that some or all of our domestic projects refund amounts previously paid by the relevant power purchaser to such project. Such events would likely result in a decrease in our future revenues or in an obligation to disgorge revenues previously received from our domestic projects, either of which would have an adverse effect on our revenues. Even if a project does not lose its Qualifying Facility status, pursuant to a final rule issued by FERC for projects above 20 MW, if a project’s power purchase agreement is terminated or otherwise expires, and the subsequent sales are not made pursuant to a state’s implementation of PURPA, that project will become subject to FERC’s ratemaking jurisdiction under the FPA.

Moreover, a loss of Qualifying Facility status also could permit the power purchaser, pursuant to the terms of the particular power purchase agreement, to cease taking and paying for electricity from the relevant project or, consistent with FERC precedent, to seek refunds of past amounts paid. This could cause the loss of some or all of our revenues payable pursuant to the related power purchase agreements, result in significant liability for refunds of past amounts paid, or otherwise impair the value of our projects. If a power purchaser were to cease taking and paying for electricity or seek to obtain refunds of past amounts paid, there can be no assurance that the costs incurred in connection with the project could be recovered through sales to other purchasers or that we would have sufficient funds to make such payments. In addition, the loss of Qualifying Facility status would be an event of default under the financing arrangements currently in place for some of our projects, which would enable the lenders to exercise their remedies and enforce the liens on the relevant project.

Pursuant to the Energy Policy Act of 2005, the FERC was also given authority to prospectively lift the mandatory obligation of a utility under PURPA to purchase the electricity from a Qualifying Facility if the utility operates in a workably competitive market. Existing power purchase agreements between a Qualifying Facility and a utility are not affected. The FERC has issued regulations under which it would allow a utility to apply to eliminate its mandatory purchase obligation from Qualifying Facilities in certain regions of the country. The regions do not currently include areas in which our domestic 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 rulemaking leading to the issuance of the regulations, the 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 the project in the region under Federal law upon termination of the existing power purchase agreement or with respect to new projects, which could have an adverse effect on our revenues.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

There were no unregistered sales of equity securities of the Company during the third fiscal quarter of 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 except as described above regarding the Bank Hapoalim credit facility.

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

No matters were submitted to a vote of our security holders in the quarter ending on September 30, 2007.

ITEM 5. OTHER INFORMATION

None.

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ITEM 6. EXHIBITS

Exhibit No. Document

1 .1

Amended and Restated Underwriting Agreement, dated as of October 23, 2007, between Lehman Brothers Inc. and the Company, incorporated by reference to Exhibit 1.1 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on October 24, 2007.

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.

3 .4

Subscription Agreement dated as of October 22, 2007, incorporated by reference to Exhibit 3.1 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on October 24, 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 , incorporated by reference to Exhibit 10.21.2 to Ormat Technologies, Inc. Quarterly Report on Form 10-Q to the Securities and Exchange Commission on August 8, 2007.

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.

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Exhibit No. Document

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: November 6, 2007 By: /s/ JOSEPH TENNE Name: Joseph Tenne
Title: Chief Financial Officer

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EXHIBIT INDEX

Exhibit No. Document

1 .1

3 .1

3 .2

3 .3

3 .4

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 (FileNo. 333-117527) to the Securities and Exchange Commission on October 22, 2004.

4 .4

4 .5

10 .1.17

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, incorporated by reference to Exhibit 10.21.2 to Ormat Technologies, Inc. Quarterly Report on Form 10-Q to the Securities and Exchange Commission on August 8, 2007.

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.

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Exhibit No. Document

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

99 .2

99 .3