CERTAIN INFORMATION IN THIS LETTER HAS BEEN OMITTED AND FILED SEPARATELY WITH THE SECURITIES AND EXCHANGE COMMISSION. CONFIDENTIAL TREATMENT PURSUANT TO 17 C.F.R. § 200.83 HAS BEEN REQUESTED BY ORMAT TECHNOLOGIES, INC. WITH RESPECT TO THE OMITTED PORTIONS. OMITTED INFORMATION HAS BEEN REPLACED BY [***].

November 25, 2009

Mr. H. Christopher Owings, Assistant Director
Division of Corporation Finance
United States Securities and Exchange Commission
100 F Street NE
Washington, D.C. 20549
Mail Stop 3561

Re: Ormat Technologies, Inc.:
Form 10-K for Fiscal Year Ended December 31, 2008
Filed March 2, 2009
Definitive Proxy Statement on Schedule 14A
Filed March 23, 2009
File No. 001-32347

Dear Mr. Owings:

     Ormat Technologies, Inc. (the “Company”) acknowledges receipt of the letter dated November 17, 2009 (the “Staff Letter”) from the staff (the “Staff”) of the Division of Corporation Finance of the United States Securities and Exchange Commission (the “SEC”). Set forth below are the Staff’s comments contained in the Staff Letter (in bold face type) followed by our responses.

Form 10-K for the Fiscal Year Ended December 31, 2008

1. We note your response to comment 5 in our letter dated September 14, 2009 in which you do not believe Industry Guide 7 applies to your facilities that generate electricity from geothermal sources. Mining activities may employ surface, underground, and in-situ (in-place) technologies to exploit natural resources profitably. Oil & gas activities may be considered a subset of the in-situ mining methods and focus primarily on the profitable extraction of liquid & gaseous hydrocarbons. Other minerals (non-exhaustive listing) extracted by in-situ mining methods are potash, salt, sulfur, uranium, and copper. The exploitation of thermal resources, i.e. hot water, by dewatering mine workings historically has been considered another mining method and was used to reduce operational costs. Your operations do not normally extract minerals, but instead extract heat from select locations and generate a profit. This heat extraction process may be considered renewable provided your process solutions are recycled, process losses are replaced, and the hydrological/thermal balance is maintained at levels

ORMAT TECHNOLOGIES, INC. 6225 Neil Road, Reno, NV 89511-1136 Telephone: (775) 356-9029 Facsimile: (775) 356-9039

consistent with your hydrologic feasibility studies and the expected life of your facility. We will not object to your proposed use of templates to describe your facilities and you may include them as separate exhibits included with your annual filings. Should you assert your geothermal resources are renewable, please include a statement indicating you will operate within the constraints of your most recent hydrologic study and maintain the steady-state operation as outlined in your studies. In addition, please describe the general geological environment for your geothermal facilities, addressing heat source, permeability through faulting/fractures or other means, the potential temperate declination through operations, and scaling/depositional issues as they affect your permeability or solution flow in your filing or your templates.

     In response to the Staff’s comment, we will include in our future Form 10-K filings under the heading “How We Operate and Maintain Our Power Plants” of Item 1. Business (found on page 21 of our Annual Report on Form 10-K for the fiscal year ended December 31, 2008) a statement to the following effect (proposed additional disclosure in bold and double underscored):

“How We Operate and Maintain Our Power Plants. We usually employ one of our subsidiaries, (Ormat Nevada Inc., for our domestic projects) to act as operator of our power plants pursuant to the terms of an operation and maintenance agreement. Our operations and maintenance practices are designed to minimize operating costs without compromising safety or environmental standards while maximizing plant flexibility and maintaining high reliability. Our operations and maintenance practices seek to preserve the sustainable characteristics of the geothermal resources we use to produce electricity and maintain steady-state operations within the constraints of those resources reflected in our relevant geologic and hydrologic studies. Our approach to plant management emphasizes the operational autonomy of our individual plant managers and staff to identify and resolve operations and maintenance issues at their respective projects; however, each project draws upon our available collective resources and experience and that of our subsidiaries. We have organized our operations such that inventories, maintenance, backup and other operational functions are pooled within each project complex and provided by one operation and maintenance provider. This approach enables us to realize cost savings and enhances our ability to meet our project availability goals.”

     In response to the Staff’s comment, we will supplement the disclosure for our operating power plants to include material information concerning heat source, permeability through faulting/fractures or other means, the potential temperate declination through operations and scaling/depositional issues as they affect our power plant operations. Please see the Sample Template attached hereto as Exhibit A which illustrates this type of disclosure under the headings “Resource Information” and “Temperature Cooling”.

Item 1. Business, page 5

Employees, page 38

Item 2. Properties

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, page 68

OPC Tax Monetization Transaction, page 89

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2. We note your responses to comments nine, 10 and 12 in our letter dated September 14, 2009. Please confirm that you will include this information in future filings.

     We confirm that we will include this information in future filings. Our future filings will include the following disclosures:

• In our future Form 10-K filings, we will include disclosure to the following effect under the heading “Employees” of Item 1. Business: “As of December 31, [insert year], we employed [insert number] employees, of which [insert number] were located in the United States, [insert number] were located in Israel and [insert number] were located in other countries.”

• Item 2. Properties of our future Form 10-K filings will include disclosure to the following effect: “We also occupy an approximately 73,000 square meter office and manufacturing facility (including 7,000 square meters in a new specialized manufacturing building), located in the Industrial Park of Yavne, Israel which we sublease from Ormat Industries.”

• In filings where we discuss the OPC Transaction, we will include disclosure to the following effect: “The bankruptcy of Lehman Brothers Inc. did not affect the OPC Transaction or any other transaction that we entered into with Lehman Brothers Inc. On October 30, 2009, we purchased from Lehman-OPC LLC, an affiliate of Lehman Brothers Inc., all of the Class B membership interests that Lehman-OPC LLC held in OPC. As a result of that transaction, Lehman-OPC LLC retains no further interest in OPC.”

Financial Statements and Supplementary Data, page 98

Notes to Consolidated Financial Statements, page 104

Note 1 — Business and Significant Accounting Policies, page 104

Exploration and drilling costs, page 108

3. We note your response to comment 18 in our letter dated September 14, 2009 and have the following additional comments:

• We note your response to the first bullet point of our prior comment concerning your “area of interest” methodology. You state that the grouping of projects within an area of interest can be analogized to the grouping of accounts under paragraph 10 of SFAS 144 or ASC 360-10-35-23. Please clarify whether this statement indicates that each area of interest is the level at which you test for impairment of your exploration projects because this is the lowest level for which identifiable cash flows are largely independent of the cash flows of other groups of assets and liabilities. If our understanding is correct, please explain to us in more detail how your management is able to effectively manage your various geothermal exploration projects without tracking a lower level of cash flows. In this regard, it appears that your current methodology could result in the poor performance of certain exploration projects being masked by the strong performance of other exploration projects within the same area of interest, and we assume that this would be important information for your management to know. Additionally, it remains unclear

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to us that it would be appropriate under GAAP to not impair the poorly performing geothermal resources within an area of interest.

     We have considered the Staff’s comment above, as well as the comments included in the second and third bullet points below regarding our treatment of capitalized costs associated with unsuccessful exploration projects, including dry hole costs, and supplementally advise the Staff as follows:

     As the Staff is aware, there are no industry-specific accounting standards or guidance for companies in the geothermal industry. Our accounting policy for exploration and development costs was developed by considering practices followed by other companies in the geothermal industry and by considering and/or analogizing to existing authoritative or similar industry guidance. We have reviewed the accounting methodology for exploration and development costs followed by a number of geothermal companies in the U.S. using publicly available information. We have found that geothermal industry accounting practice is diverse in this area with some geothermal companies following an approach that is similar in certain respects to the successful efforts method of accounting that is used in the oil and gas industry. In this regard, we believe there is some diversity in the manner in which the successful efforts method is applied. We believe that some companies expense all costs associated with exploration activities until a feasibility study has determined that the resource is capable of commercial production, while other companies capitalize all such costs until a decision is made to not pursue commercial operations on that resource.

     We have also found that some geothermal companies follow an approach that we believe is similar in certain respects to the full cost method of accounting that is used in the oil and gas industry. These companies generally capitalize all costs associated with the exploration and development of geothermal resources, including dry hole costs. As the Staff is aware, ASC 932-10-05 (formerly SFAS No. 19) and Rule 4-10 specifically exclude the production of geothermal resources. However, as set forth in our response to Comment No. 18 of our letter dated October 12, 2009, we believe that geothermal companies have adopted accounting methodologies that are similar to industry practice in the oil and gas industry for the reasons set forth in that response.

     Our accounting methodology is most analogous to the full cost method. We believe that this accounting methodology best matches how we view and manage our exploration projects. The feasibility analysis we perform before securing a land lease assumes a certain amount of unsuccessful exploration and drilling activities, both prior to identifying a site with a commercially viable resource and during the life of the power plant. Based on years of collective geothermal experience, our management knows that some exploration activities will not lead to commercially viable power production facilities. However, we believe that the benefits obtained from prospects that are successful will be adequate to recover the costs of all exploration activities within an area of interest, including unsuccessful projects.

     The area of interest concept that we use for our exploration projects is analogous in certain respects to the definition of a cost center that is used by companies following the full cost method. While cost centers generally must be established on a country-by-country basis, we concluded that a country-by-country basis would not be appropriate for our activities because a country is an overly broad geographical area, aggregation by country is not the way we view or manage our business, and it is not a practice that is prevalent in the geothermal industry. Instead, we consider geological and economic characteristics of an area when defining a cost center. On this basis and for the reasons set forth in our response to the first bullet point of Comment No. 18 in our letter dated October 12, 2009, we concluded that Nevada is a single cost center. However, we have further divided Nevada into three areas of interest to reflect the manner in which we intend to operate our power plant facilities that are

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ultimately constructed in each area of interest. Specifically, our definition of an area of interest is based on the geographical proximity of the geothermal resources and their proximity to the same electricity grid, the use of, in certain cases, a common transmission line, the ability to allocate (in some cases) a power purchase agreement to alternate resources in the same geographical area, and our intention to operate all the power plants in the same area of interest together as one complex.

     We follow the guidance in ASC 360-10-35 (formerly SFAS No. 144) to test our exploration projects for impairment as further described below. We believe this approach is consistent with the prevailing practice for geothermal companies based on our review of the accounting methodology followed by a number of geothermal companies in the U.S. described above. Our existing power plants are evaluated for impairment separately under ASC 360-10-35 (formerly SFAS No. 144).

     We test for impairment at the area of interest level because we consider this to be the lowest level for which identifiable cash flows are largely independent of the cash flows of other groups of assets or liabilities. There are a number of reasons why our management is able to effectively manage our projects without tracking a lower level of cash flows. Within each of our three areas of interest in Nevada, we have a relatively small number of exploration projects. The cost of unsuccessful exploration projects has not been, and is not expected to become, material, particularly in relation to the total cost to construct a power plant. These exploration projects, if they are developed into power projects, will be managed under a combined operation management. Most of the operational costs are operating and maintenance (“O&M”) costs which are substantially impacted by our central O&M organization contemplated for each area of interest. In view of the importance of O&M costs for the viability of a project, it is the cash flow from the entire area of interest, which is intended to be managed as one unit, that will be the focus of our management. An individual well or an individual exploration site does not have sufficient business viability to justify management review of results at that level. Accordingly, we believe our management has adequate cash flow information to manage our exploration projects without tracking below our established areas of interest. We recognize that our approach might not necessarily be appropriate for every company, particularly much larger companies with many tiers of management or more diverse or expansive exploration programs. Our senior management, however, is satisfied that it has the information it needs to effectively manage our exploration projects using our current area of interest cash flow information.

• We note your response to the fifth bullet point of our prior comment concerning your prospects that do not achieve economic feasibility. Please clarify to us whether all of the capitalized costs related to these three prospects were expensed, as this is unclear from your current response. If any costs related to these prospects were not written off, please further explain your basis in GAAP for continuing to capitalize these costs. In this regard, we note your reference to unsuccessful drilling within an area of interest, and it is unclear to us whether this reference indicates that you have continued to capitalize the costs of these unsuccessful prospects due to the success of other prospects within the areas of interest.

     We supplementally advise the Staff as follows:

     Consistent with the accounting methodology described in our response to the first bullet point above, we have not expensed or written off the costs associated with these three exploration projects. In consideration of the fact that there are no geothermal-specific industry accounting standards or guidance that directly applies to the issue, we believe that continuing to capitalize these costs, within an area of interest, is consistent with ASC 360-10-35 (formerly SFAS No. 144) and prevailing practice for the accounting for dry holes by certain other companies in our industry.

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• We note your response to the second bullet point of our prior comment concerning your capitalization of dry hole costs. Notwithstanding your belief that all dry holes are useful for the discovery of commercially viable resources within an area of interest and for the operation of the power plant thereafter, it remains unclear to us that capitalizing dry holes is appropriate under GAAP or consistent with industry practice. Please provide us with further information as to how you determined this practice was appropriate under GAAP. Additionally, please tell us how you considered prevailing practice for the accounting for dry holes by others in your industry.

     We respectfully refer the Staff to our response to the first bullet point above explaining why we believe capitalizing dry holes is appropriate under GAAP and consistent with prevailing practice for the accounting for dry holes by certain other companies in our industry.

• We have reviewed your process for assessing the economic feasibility of geothermal resources as described in the “Background” portion of your response and in response to the fourth bullet point of our prior comment. We note that your exploration department assesses economic feasibility using any available information about the geological, geochemical and geophysical attributes of the site. We note that you do not acquire land rights until you have determined that an economically feasible geothermal reservoir is probable. We further note that after you acquire land rights to the potential geothermal resource, you conduct surface water analysis, soil surveys, initiate a suite of geophysical surveys and develop a roadmap of fluid-flow conduits and overall permeability to create three-dimensional geothermal reservoir models that are used to identify drill locations. Please explain to us in more detail how you are able to determine that an economically feasible geothermal reservoir is probable prior to conducting the additional analysis and surveys that you perform after acquiring land rights. In this regard, it is unclear to us that enough archival information would be available about the potential resource for you to make this determination without performing the additional analysis and surveys. We note the statement in your response that you make a further determination of the feasibility of the potential resource after conducting the additional analysis and surveys that you perform after acquiring land rights, and it is unclear to us whether this is the point at which you are able to assess whether an economically feasible geothermal reservoir is probable.

     In order to further assist the Staff in understanding how we determine that an economically feasible geothermal resource is probable prior to conducting the additional analysis and surveys we perform after acquiring land rights, we believe it will be helpful to describe the process and steps we undertook, and information we evaluated, as part of a recent such determination. While the underlying facts and circumstances of individual geothermal resources will differ, and thus the exact process and specific steps we would undertake, as well as the type and level of information we would evaluate, will also differ, the following discussion can be considered as a generally applicable illustration of how we reach such a determination.

     In December 2008, we determined that an economically feasible geothermal resource was probable in a certain area in the state of Oregon and proceeded to acquire approximately thirty thousand acres of land in that location. We based our decision to lease this land on a high level of confidence of locating a high temperature resource as a result of approximately two months of work analyzing various data sources. These data sources included:

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• Drilling data indicating high temperature gradients, permeability (lost circulation), and high temperature alteration from shallow- (<500 ft) and intermediate-depth (<2000 feet) wells that Phillips, Aminoil, and Francana drilled in the area in the 1970s;

• Discussions with the Phillips project geologist who drilled most of these wells;

• Geologic and alteration maps from Portland State University;

• Published and proprietary geologic reports from industry, academia, and consultants;

• Archival site-specific mining data and geophysics;

• Satellite imagery; and

• Regional geologic data.

     We then integrated all of this information and data points into a centralized geographic information system (GIS) database.

     Our interpretation of the data in this case suggested that resource temperatures of >300° F can be expected below a depth of approximately 3,000 feet. Furthermore, permeability for production and injection was seen as very likely based on extensive fracturing observed at the surface and major lost circulation zones observed during the prior drilling in this area. It was apparent that high temperature water has moved through the system based on observed alterations. On this basis, we reached a determination that an economically feasible geothermal resource was probable and we moved to acquire the land leases.

     As noted in our initial explanation to the Staff (under the caption “Background” in our October 12, 2009 response letter) the further analysis and surveys we conduct after acquiring land rights help us to further refine our understanding of the geothermal reservoir and studies, and identify drilling locations. As such, while further analysis and surveys performed after we acquire land rights may act to enhance our understanding of the geothermal resource, that is not the point in time at which we make the determination whether an economically feasible geothermal resource is probable.

4. We have reviewed the rollforward provided in response to comment 18 in our letter dated September 14, 2009. Please reconcile the total amounts capitalized at December 31, 2008 and 2007 as presented in the rollforward to the disclosure on page 108 of your Form 10-K that exploration and drilling costs related to uncompleted projects are included in construction-in-process in the consolidated balance sheets and totaled $52,345,000 and $16,677,000 at December 31, 2008 and 2007, respectively.

     We supplementally advise the Staff as follows:

     In the response to Comment No. 18 of the Staff’s letter dated September 14, 2009, we included a rollforward of the total amounts capitalized for the exploration projects under development listed on page 11 of our 2008 Annual Report in our letter dated October 12, 2009. In response to the Staff’s comment above, we have included a rollforward of the total amounts capitalized related to uncompleted exploration projects that are included in construction-in-process at December 31, 2008 and 2007 as set forth below (the amounts are presented in thousands):

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Confidential Treatment Requested by Ormat Technologies, Inc.

	Nevada
	Northern Area of		Eastern Area of		Southern Area of
	Interest (1)		Interest (2)		Interest (3)		California (4)		Total
Balance January 1, 2007	$	[***]	$	[***]	$	[***]	$	[***]	$	844
Change in 2007		[***]		[***]		[***]		[***]		15,833
Balance December 31, 2007		[***]		[***]		[***]		[***]		16,677
Change in 2008		[***]		[***]		[***]		[***]		35,668
Balance December 31, 2008	$	[***]	$	[***]	$	[***]	$	[***]	$	52,345

(1) Northern Area of Interest

	McGinness Hills (5)		Grass Valley		Jersey Valley		Buffalo Valley		Total
Balance January 1, 2007	$	[***]	$	[***]	$	[***]	$	[***]	$	[***]
Change in 2007		[***]		[***]		[***]		[***]		[***]
Balance December 31, 2007		[***]		[***]		[***]		[***]		[***]
Change in 2008		[***]		[***]		[***]		[***]		[***]
Balance December 31, 2008	$	[***]	$	[***]	$	[***]	$	[***]	$	[***]

(2)	Carson Lake Project.
(3)	Southern Area of Interest

	Gabbs Valley		Rock Hills		Other		Total
Balance January 1, 2007	$	[***]	$	[***]	$	[***]	$	[***]
Change in 2007		[***]		[***]		[***]		[***]
Balance December 31, 2007		[***]		[***]		[***]		[***]
Change in 2008		[***]		[***]		[***]		[***]
Balance December 31, 2008	$	[***]	$	[***]	$	[***]	$	[***]

(4)	Imperial Valley Project.
(5)	The amounts included in the rollforward in our response to Comment No. 18 of our letter dated October 12, 2009 included $[***] relating to upfront bonus payments made to secure land leases. Such amounts are not included in construction-in-process at December 31, 2008 and 2007, and therefore have been excluded from this rollforward.

Note 12 — OPC Tax Monetization Transaction, page 128

5. We are continuing to consider your response to comments 21 and 27 in our letter dated September 14, 2009. To assist us in better understanding your accounting for this transaction, please respond to the following additional comments:

• We note your response to the third bullet point of comment 21. The component of minority interest income labeled as “Net loss attributable to noncontrolling interest” in the table in your response appears to solely relate to the 5% residual interest of the Class B Members, based on the information in footnote three to this table. Please explain to us in more detail how you determined the amount of net loss to allocate to the noncontrolling interest. In doing so, tell us how you considered paragraph 25 of SOP 78-9, or ASC 970-323-35-17, in determining your earnings allocation.

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     As noted in our response to Comment No. 27 of our letter dated October 12, 2009, the Class B membership units provide a 5% residual economic interest in the OPC assets. The 5% residual interest is perfected on achievement by the investors of a contractually stipulated return that triggers the Flip Date. This 5% residual interest represents a noncontrolling interest which is “true equity” and is not subject to mandatory redemption or guaranteed payments.

     In order to calculate the 5% residual economic interest, we calculated 5% of the net assets of OPC as of each reporting date. Under the arrangement, cash is distributed each period in accordance with the cash allocation percentages stipulated in the agreements. Ormat Nevada is currently allocated the cash earnings of OPC, and therefore the amount allocated to the 5% residual interest represents the noncash loss of OPC which principally represents depreciation on the property, plant and equipment. For 2008, this amount was $300,000 which is approximately 5% of the depreciation expense of OPC.

     We believe this method of allocating earnings/losses to the investors is appropriate and consistent with paragraph 25 of ASC 970-323-35-17 (formerly SOP 78-9), after considering the substance of the transaction and the portion of net assets that will be retained by the investors on the Flip Date.

• Your response to comment 27 indicates that, upon the adoption of SFAS No. 160, given the legal form of your OPC tax monetization transaction, you do not believe that most of the existing minority interest balance met the definition to be classified as equity, and as such, you reclassified such amounts as a liability consistent with the guidance in EITF 88-18 or ASC 470-10-25. Please explain to us in more detail why you believe your OPC tax monetization transaction is within the scope of EITF 88-18 given that your investors purchased equity interests in class B membership units. Also tell us how you considered whether the contractually agreed upon percentage/allocation of profits and losses and tax benefits were more akin to equity return rights than rights to future revenues.

     We refer the Staff to our response to the second bullet point of Comment No. 21 in our letter dated October 12, 2009 where we stated that ASC 470-10-25 (formerly EITF No. 88-18) relates to a transaction where a company “receives cash from an investor and agrees to pay the investor for a defined period a specified percentage or amount of revenue or of a measure of income (for example, gross margin, operating income, or pretax income) of a particular product line, business segment, trademark, patent or contractual right.” We believe that the OPC Transaction, while structured as a purchase of an equity interest, is in substance a financing given that 95% of the economic interest will revert back to Ormat Nevada once the specified return is met, and therefore is most appropriately accounted for following the guidance in ASC 470-10-25 (formerly EITF No. 88-18). Specifically, we received cash from the investors and agreed to “pay” them a specified return. This return is in the form of tax benefits which include the production tax credits, operating tax gains and losses (principally depreciation expense), and cash. We believe that tax benefits should be viewed as a “measure of income” as discussed in ASC 470-10-25 (formerly EITF No. 88-18), and the contractually agreed upon terms provide for a right to “future revenues” (in the form of tax benefits). The investors will continue to receive these tax benefits and cash until they achieve an internal rate of return as stipulated in the agreement, at which time all but 5% of their economic interests (represented by their equity interests) will revert back to the Company, thereby setting a limit on the period of time they will receive a return. Therefore, except for the 5% interest retained by the investors after achievement of the specified return, the investment in this entity does not have characteristics that are representative of an equity interest. We believe that this arrangement is, in economic substance, the type of arrangement that is addressed by ASC 470-10-25 (formerly EITF No. 88-18).

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     We also considered the motivation of the investors and Ormat Nevada for entering into the transaction. We believe the investors’ primary motivation was to obtain a specified return on its investment through the receipt of tax benefits, rather than to share in the profits of OPC as an equity interest holder. The transaction was structured as a sale of equity interests for the purpose of enabling the investors to receive substantially all of the tax benefits of OPC. The investors’ motivation is supported by the fact that their involvement in the operations of OPC is limited to protective, rather than participating, activities, up to the Flip Date. Once the Flip Date occurs, the economic interest in OPC will substantially revert to Ormat Nevada, with the investors retaining only a nominal 5% interest.

     Our primary motivation for entering into the transaction was to obtain financing. We have consistently included a discussion of the OPC Transaction in the “Liquidity and Capital Resources” section of Item 7 of our Form 10-K and Part I, Item 2 of our Form 10-Q filings as we view it as a financing transaction.

     We refer the Staff to our response to the second bullet point of Comment No. 21 of our letter dated October 12, 2009 for a discussion of our conclusion that the transaction qualifies for treatment of debt under ASC 470-10-25 (formerly EITF No. 88-18).

• Please tell us how you considered whether this financing should be accounted for under SFAS 66 as an in-substance real estate transaction.

     ASC 976-605-25 (formerly SFAS No. 66) establishes guidance for recognition of profit on sales of real estate. The standard was intended to be broadly applied to transactions including sales of partnership interests (paragraph 101) if in substance the sales are sale of real estate. ASC 360-20-15 (formerly FIN No. 43 and EITF 00-13) provide further guidance for applying ASC 976-605-25 (formerly SFAS No. 66) and identify certain exceptions for its application.

     The guidance in ASC 360-20-15 (formerly FIN No. 43) provides for certain exclusions from ASC 976-605-25 (formerly SFAS No. 66), including the sale of the stock or net assets of a subsidiary or a segment of a business if the assets of that subsidiary or that segment, as applicable, contain real estate, unless the transaction is, in substance, the sale of real estate. Our view is that the OPC Transaction has been structured as a sale of certain economic benefits rather than the sale of real estate, as the economic benefits the investors are purchasing are not real estate, but rather are tax benefits and an allocation of the operating cash of OPC.

     ASC 976-605-25 (formerly SFAS No. 66) states that any option giving the seller the right to repurchase the property or any obligation on the part of the seller to repurchase the property, including terms which could allow the buyer to compel the seller to repurchase the property (e.g., certain right of first refusal arrangements used as exit strategies for the buyer), would preclude sale recognition and result in the transaction being accounted for as a financing, leasing or profit sharing arrangement. The Company has a purchase option for the 5% interest that would be retained after the investors achieve their specified return. As such, we believe the sale of the 5% interest would not result in gain recognition.

• Also, we note your Form 8-K filed on November 3, 2009 and disclosure in your September 30, 2009 Form 10-Q regarding your purchase of 300 of the outstanding 1,000 class B membership interests from Lehman Brothers Inc. for $18.5 million during the fourth quarter of 2009. We also note that this transaction will result in a pre-tax gain of $13.0 million during the fourth quarter of 2009. Please update us with any changes to the accounting for this transaction.

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     We supplementally advise the Staff that we have not changed the accounting for this transaction. As we disclosed in the September 30, 2009 Form 10-Q, in October 2009, we acquired Lehman-OPC LLC’s thirty percent interest in OPC for a price of $18.5 million. Because a substantial portion of the Class B membership units sold to the investors was accounted for as debt, the repurchase of these interests from Lehman-OPC LLC at a discount resulted in a pre-tax gain. The gain associated with the repurchase of the 5% residual interest from Lehman-OPC LLC was recorded in equity during the fourth quarter of 2009.

Proxy Statement on Schedule 14A

Compensation Discussion and Analysis, page 16

Objectives, page 16

Determination of Amounts and Formulas for Compensation, page 17

Annual Bonus, page 18; Group II, page 18

Group I page 18

Stock Options, page 19

Transactions with Related Persons, page 32

6. We note your responses to comments 29, 30, 31, 33 and 34 in our letter dated September 14, 2009. Please confirm that you will include this information in future filings.

     We confirm that we will include this information in future filings. Our future filings will include the following disclosures:

• The sub-heading “Annual Salary” under the heading “Determination of Amounts and Formulas for Compensation” of the Compensation and Discussion Analysis included in our future Proxy Statements on Schedule 14A will include disclosure to the following effect: “The Compensation Committee does not undertake or commission a formal study or survey to benchmark compensation to a particular industry or to particular companies. Rather, the members of the Compensation Committee evaluate the executive compensation using their accumulated individual knowledge and industry experience. The Compensation Committee takes into account publicly available compensation information with respect to companies that have a similar market cap or similar annual revenues, and that operate under a business structure similar to ours (although not necessarily in the same industry segment).”

• In filings where we discuss the approval process within our parent company for related party transactions, we will include disclosure to the following effect: “Our parent company’s approval process for related party transactions such as compensation arrangements requires approval by our parent’s Audit Committee and Board of Directors, followed by approval of a majority of the shareholders of our parent, which majority must include at least one third of the shareholders present at the meeting who have no interest in the related party transaction.”

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• The sub-heading “Group II” under the heading “Annual Bonus” of the Compensation Discussion and Analysis included in our future Proxy Statements on Schedule 14A will include disclosure to the following effect: “The determination of the amount of an annual bonus paid to each Group II executive is based on a number of factors, including specific results of our performance, such as revenue growth, profitability, and the attainment of specific short-term and strategic business goals, but with a subjective determination of each NEO’s performance and contribution to these results made by the CEO and Chairman, who are intimately involved in our day-to-day activities and work closely with our officers. No fixed criteria are used in making these determinations.”

• The heading “Stock Options” of the Compensation Discussion and Analysis included in our future Proxy Statements on Schedule 14A will include disclosure to the following effect: “As the CEO and the Chairman are intimately involved in our day-to-day activities and work closely with our officers, they have the knowledge to make a subjective determination of the individual executive’s contribution to our growth and success. No specific criteria are used in making these determinations.”

• The Transactions with Related Persons section of our future Proxy Statements on Schedule 14A will include disclosure to the following effect: “Each of the related party transactions discussed below is on terms that are at least as favorable to us as would have been obtained in an arm’s length transaction.”

* * * * * *

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     We acknowledge that the Company is responsible for the adequacy and accuracy of the disclosure in its filing and that Staff comments or changes to disclosures in response to Staff comments do not foreclose the Commission from taking any action with respect to the filing. We also represent that we will not assert Staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.

     We trust that the responses provided above address the issues raised in the Staff Letter. If you have any questions or require further clarification, please do not hesitate to contact the undersigned or Joseph Tenne, our Chief Financial Officer, at Tel: 1-775-356-9029.

Sincerely,
 

/s/ Yehudit Bronicki

Yehudit Bronicki 

Chief Executive Officer
Ormat Technologies, Inc. 

VIA EDGAR AND BY HAND

cc:	Securities and Exchange Commission Mr. Ronald E. Alper, Esq. Ms. Yong Kim Mr. George K. Schuler Ms. Jennifer Thompson
	Chadbourne & Parke LLP Mr. Noam Ayali, Esq. Mr. Charles E. Hord, III, Esq.

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Exhibit A

Sample Template (operational project): Steamboat Complex

Location:	Steamboat, Washoe County, Nevada
Generating Capacity:	84 MW
Number of Power Plants:	7 (Steamboat 1A, Steamboat 2/3, Burdette, Steamboat Hills, Galena 2 and Galena 3).
Technology:	Binary system (except for Steamboat Hills, which utilizes a single flash system).
Plant and Equipment:	The following is a general summary of the material plant and equipment used at this project.
Subsurface Improvements:	23 production wells and 9 injection wells connected to the plants through a gathering system.
Material Equipment:	12 individual air cooled Ormat Energy Converter (OEC) units and one steam turbine, together with the balance of plant equipment such as generators, power transmission lines, transformers, pumps, valves, pipelines and a cooling tower for the steam turbine unit.
Age:	The Steamboat 1A plant commenced commercial operation in 1988 and the other plants commenced commercial operation in 1992, 2005, 2007 and 2008. During 2008 we replaced the four turbines at Steamboat 2/3 and repowered Steamboat 1A.
Land and Mineral Rights:	The total Steamboat area comprises 1,309 acres, of which 41% are private leases, 41% are BLM leases and 18% are private land owned by us (with percentages determined by acreage). The leases are held by production. The scheduled expiration dates for all of these leases are after the expected useful life of the power plants.
	The project’s rights to use the geothermal and surface rights under the leases are subject to various conditions, as described in “Description of Our Geothermal Leases”.
	We have easements for the transmission lines we use to deliver power to our power purchasers.
Resource Information:	The resource temperature is an average of 300 degrees Fahrenheit.
	The Steamboat geothermal field is a typical Basin and Range geothermal reservoir. Large and deep faults that occur in the rocks allow circulation of ground water to depths exceeding 10,000 ft below the surface. Horizontal zones of permeability permit the hot

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	water to flow eastward in an out-flow plume.
	Steamboat Hills and Galena 2 power plants produce hot water from fractures associated with normal faults. The rest of the power plants acquire their geothermal water from the horizontal out-flow plume. The water in the Steamboat reservoir has a low total solids concentration. Scaling potential is very low unless the fluid is allowed to flash which will result in calcium carbonate scale. Injection of cooled water for reservoir pressure maintenance prevents flashing.
Temperature Cooling	Observed cooling during the past 20 years of production at Steamboat is 2°F per year.
Access to Property:	Direct access to public roads from leased property and access across leased property under surface rights granted pursuant to the leases.
Sources of Water:	Water is provided by condensate and the local utility.
Power Purchaser:	Sierra Pacific Power Company (for Steamboat 1A, Steamboat 2/3, Burdette, Steamboat Hills, and Galena 3) and Nevada Power Company (for Galena 2).
Power Contract Expiration Date:	2018, 2022, 2026, 2018 and 2028 (for Steamboat 1A, Steamboat 2/3, Burdette, Steamboat Hills, and Galena 3, respectively) and 2027 (for Galena 2).
Financing:	OPC Transaction (Steamboat Hills, Galena 2 and Galena 3) and OFC Senior Secured Notes (Steamboat 1A, Steamboat 2/3 and Burdette).
Supplemental Information:	We have experienced protracted failures of two of the Steamboat 2/3 plant’s turbines, which were not manufactured by us. We replaced the four turbines of this plant during 2008 and successfully upgraded the plant and brought the plant back to its original capacity. As a consequence of the failure, Sierra Pacific Power Company raised certain contractual issues that we are addressing with them. We do not expect that these issues will have a material effect on our business or results of operation.

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