Ormat CORRESP Correspondence with SEC

Ormat (ORA) CORRESPCorrespondence with SEC

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 OMITTED INFORMATION HAS BEEN REPLACED BY [***].

October 12, 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
Form 8-K
Filed August 6, 2009
File No. 001-32347

Dear Mr. Owings:

Ormat Technologies, Inc. (the “Company”) acknowledges receipt of the letter dated September 14, 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”). Reference is also made to the conversation between Mr. Joseph Tenne, the Company’s Chief Financial Officer, and Ms. Yong Kim on September 16, 2009, during which it was agreed that we would respond to the Staff Letter by October 12, 2009.

We appreciate the Staff’s comments as well as the opportunity this process provides to improve the content of our SEC filings. Where we agree to make requested revisions to our disclosures in future filings with the SEC, such agreement and any such revisions to disclosures made in future filings should not be taken as an admission that prior disclosures were in any way deficient. We supplementally advise the Staff that when we received the Staff Letter, we were, and continue to be, in the process of reviewing our SEC filings with an aim to streamline some of our disclosures and present information about our operations in a clear and concise manner. As a result of that review process, we have determined to revise certain disclosures that we have historically made in our SEC filings. We have noted in our responses below the disclosures that we anticipate will be affected by this internal review process insofar as they may be applicable to the Staff’s comments. Any changes in our future SEC filings made as a result of this review process should not be taken as an admission that prior disclosures were in any way deficient.

ORMAT TECHNOLOGIES, INC.

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

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.

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

Item 1. Business, page 5

Projects under Development, page 11

We note your description of projects as well as your reference to “if implemented.” Please provide the status of each project.

We are currently in the process of developing a number of new projects. For our purposes, we consider a project in development to be a project where we have conducted or are conducting studies and have performed or are performing exploratory drilling to evaluate the potential viability of the geothermal resource, but have not yet drilled a production well on the property. The reference to “if implemented” was intended to convey that, until the geothermal resource has been further evaluated, there can be no assurance that a particular project will proceed to construction and reach commercial operation.

As a result of our internal review process described above, we have determined to omit the chart found on page 11 of our Annual Report on Form 10-K for the fiscal year ended December 31, 2008 (“2008 Annual Report”) in our future filings with the SEC. The information in this chart is mostly repetitive of information provided in other parts of our report (e.g., pages 31-32), so we propose to consolidate the information in one location.

In response to the Staff’s comment, set forth below is a brief summary of the status of each of the projects listed in the chart found on page 11 of our 2008 Annual Report.


Carson Lake		Tests performed on deep wells have identified a shallow resource at low temperature and expected abundant quantities of hot water. We now need to verify the results of those tests by drilling a commercial well. We have applied for drilling permits, but the issuance of the permits is taking longer than we initially anticipated. We currently expect to receive the permits and commence the drilling during the first quarter of 2010.

		We have begun to engineer the equipment for the proposed power plant. Following the completion of that process, we will prepare and submit applications for permits that will allow us to commence construction of the power plant.

		In addition, we will have to negotiate a modification to our power purchase agreement with Nevada Power Company, a subsidiary of NV Energy, Inc., as well as an amendment to our joint venture agreement with Nevada Power Company. We have started preliminary discussions toward such negotiations.


		Assuming verification of the viability of the shallow resource and the successful resolution of negotiations with Nevada Power Company, we anticipate that commercial operation of a 20 MW power plant will occur in 2013.

Mammoth		We continue to negotiate a power purchase agreement with Southern California Edison Company (“SCE”). We were unable to finalize an agreement based on a proposal short-listed by SCE last year, and recently resubmitted a proposal in the framework of the 2009 solicitation. We also need to negotiate an interconnection agreement with SCE.

		In addition, we are negotiating certain modifications to our joint venture agreement with our 50% partner in this project.

		Assuming the successful resolution of the negotiations described above and that we obtain the permits required to commence construction without delays, we anticipate that commercial operation of a 25 MW power plant will occur in 2013.

Imperial Valley		Construction on the project has been delayed as we attempt to secure a land position that is large enough to accommodate the scale of the proposed project. We continue to work on securing additional land for this project.

		We recently reallocated the signed power purchase agreement for this project (which contemplated a 30-100 MW power plant) to our East Brawley project in Imperial County, California. We intend to negotiate a new power purchase agreement for this project.

		Once we secure what we believe to be the appropriate land position, we expect to drill a production well in order to determine the size of the first phase of construction. We currently expect the first phase of the project to be 30 MW and expect commercial operation of the first phase in 2012.

Sarulla		The Sarulla Consortium is in negotiations with the Indonesian government to adjust the tariff of the power purchase agreement, and to introduce other changes which will satisfy lenders requirements. From past experience it is hard to estimate when these negotiations will be concluded. Construction is expected to start after the Sarulla Consortium obtains financing.

McGinness Hills		The first production well was drilled and we are in the process of drilling additional wells. We expect to drill two additional wells before we complete the engineering of the power plant and apply for construction permits.

		We are negotiating a power purchase agreement with Nevada Power Company for an approximately 24-36 MW power plant. We currently anticipate that commercial operation of the power plant will occur in 2012.

Competitive Strengths, page 18

Please balance the discussion of your competitive strengths with a discussion of the challenges you face.

In response to the Staff’s comment, we will include in our future Form 10-K filings a statement to the following effect:

“Although we are confident in our competitive position in light of the strengths described above, we face various challenges in the course of our business operations, including as a result of the risks described in Item 1A — “Risk Factors” below, the trends and uncertainties discussed under Item 7 — “Management’s Discussion and Analysis of Financial Condition and Results of Operations” below, and the competition we face in our different business segments described under “Competition” below.”

The statement above will be inserted under the heading “Competitive Strengths” (which was found on page 18 of our 2008 Annual Report) immediately following the description of what we believe to be our competitive strengths.

Description of our Projects, page 26

Domestic Projects, page 26

Please disclose the following information for each of your material geothermal properties and/or leases:

	•		The nature your company’s ownership or interest in the property or leases.

	•		A description of all interests in your properties or leases, including the terms of all underlying agreements.

	•		A description of the required operating environmental permits.

	•		The basis and duration of your geothermal rights, leases, surface rights, mining claims and/or other means of access or control.

	•		An indication your geothermal leases are located on private, state or federal properties or other concessions.

	•		The conditions that must be met to retain your leases, including quantification and timing of all necessary payments and terms for renewal.

	•		The area of your leases or claims, in either hectares or acres.

Please ensure that you fully discuss the material terms of the land or geothermal lease securing agreements, as required under paragraph (b)(2) of Industry Guide 7.

As discussed more fully in our response to Comment No. 5 below, and for the reasons set forth therein, we have concluded that it would not be appropriate to apply Industry Guide 7 to our operations. Nevertheless, we share the Staff’s goal of improving our investor disclosure. Accordingly, we propose to expand the disclosures contained in our future filings to include

disclosure about our total federal, state and private land leases, the approximate breakdown between federal, state, and private land leases, and a summary of key terms and conditions of leases that are material. We supplementally advise the Staff that we do not regard any lease (or other property) as material unless and until we begin construction of a geothermal power plant on the property, that is, when we drill a production well on the property.

Set forth below is our proposed disclosure regarding our geothermal leases:

“Description of Our Geothermal Leases

We have leases for approximately 373,000 acres of federal, state and private lands in California, Nevada, Utah, Alaska, Hawaii, Oregon and Idaho. The approximate breakdown between federal, state and private leases is as follows:

	•		81% are leases with the U.S. government, acting through the U.S. Department of the Interior, Bureau of Land Management, which we refer to as “BLM”

	•		10% are leases with various states, none of which are currently material

	•		9% are leases with private landowners and/or leaseholders.

In addition, we own approximately 5,000 acres of land in Nevada and California.

Generally speaking, each of the leases within each of the categories has standard terms and requirements, as summarized below.

Bureau of Land Management Geothermal Leases

Certain of our domestic project subsidiaries have entered into geothermal resources leases with the U.S. government, pursuant to which they have obtained the right to conduct their geothermal development and operations on federally-owned land. These leases are made pursuant to the Geothermal Steam Act of 1970, as amended, which we refer to as the Act, and the lessor under such leases is the U.S. government, acting through the BLM.

BLM geothermal leases grant the geothermal lessee the right and privilege to drill for, extract, produce, remove, utilize, sell and dispose of geothermal resources on certain lands, together with the right to build and maintain necessary improvements thereon. The actual ownership of the geothermal resources and other minerals beneath the land is retained in the federal mineral estate. The geothermal lease does not grant to the geothermal lessee the exclusive right to develop the lands although the geothermal lessee does hold the exclusive right to develop geothermal resources within the lands. The geothermal lessee does not have the right to develop minerals unassociated with geothermal production and cannot prohibit others from developing the minerals present in the lands. The BLM may grant multiple leases for the same lands and, when this occurs, each lessee is under a duty to not unreasonably interfere with the development rights of the other. Because BLM leases do not grant to the geothermal lessee the exclusive right to use the surface of the land, BLM may grant rights to others for activities that do not unreasonably interfere with the geothermal lessee’s uses of the same land, which other activities may include recreational use, off-road vehicles and/or wind or solar energy developments.

Certain BLM leases issued before August 8, 2005 include certain covenants that require the projects to conduct their operations under the lease in a workmanlike manner and in accordance with all applicable laws and BLM directives and to take all mitigating actions required by the BLM to protect the surface of and the environment surrounding the land. Additionally, certain leases contain additional requirements, some of which concern the mitigation or avoidance of disturbance of any antiquities, cultural values or threatened or endangered plants or animals, the payment of royalties for timber and the imposition of certain restrictions on residential development on the leased land.

BLM leases entered into after August 8, 2005 require the geothermal lessee to conduct operations in a manner that minimizes impacts to the land, air, water, to cultural, biological, visual and other resources, and to other land uses or users. The BLM may require the geothermal lessee to perform special studies or inventories under guidelines prepared by the BLM. The BLM reserves the right to continue existing leases and to authorize future uses upon or in the leased lands, including the approval of easements or rights-of-way. Prior to disturbing the surface of the leased lands, the geothermal lessee must contact the BLM to be apprised of procedures to be followed and modifications or reclamation measures that may be necessary. Subject to BLM approval, geothermal lessees may enter into unit agreements to cooperatively develop a geothermal resource. The BLM reserves the right to specify rates of development and to require the geothermal lessee to commit to a communitization or unitization agreement if a common geothermal resource is at risk of being overdeveloped.

Typical BLM leases issued to geothermal lessees before August 8, 2005 have a primary term of ten years and will renew so long as geothermal resources are being produced or utilized in commercial quantities, but cannot exceed a period of forty years after the end of the primary term. If at the end of the forty-year period geothermal steam is still being produced or utilized in commercial quantities and the lands are not needed for other purposes, the geothermal lessee will have a preferential right to renew the lease for a second forty-year term, under terms and conditions as the BLM deems appropriate.

BLM leases issued after August 8, 2005 have a primary term of ten years. If the geothermal lessee does not reach commercial production within the primary terms the BLM may grant two five-year extensions if the geothermal lessee: (1) satisfies certain minimum annual work requirements prescribed by the BLM for that lease or (2) makes minimum annual payments. Additionally, if the geothermal lessee is drilling a well for the purposes of commercial production, the primary term (as it may have been extended) may be extended for five years and as long thereafter as steam is being produced and used in commercial quantities (meaning the geothermal lessee either begins producing geothermal resources in commercial quantities or has a well capable of producing geothermal resources in commercial quantities and is making diligent efforts to utilize the resource) but not more than thirty-five years. If, at the end of the extended thirty-five year term, geothermal steam is still being produced or utilized in commercial quantities and the lands are not needed for other purposes, the geothermal lessee will have a preferential right to renew the lease for fifty-five years, under terms and conditions as the BLM deems appropriate.

For BLM leases issued before August 8, 2005, the geothermal lessee is required to pay an annual rental fee (on a per acre basis), which escalates according to a schedule described therein, until production of geothermal steam in commercial quantities has commenced.

After such production has commenced, the geothermal lessee is required to pay royalties (on a monthly basis) on the amount or value of (1) steam, (2) by-products derived from production and (3) commercially de-mineralized water sold or utilized by the project (or reasonably susceptible to such sale or use).

For BLM leases issued after August 8, 2005 (a) a geothermal lessee who has obtained a lease through a non-competitive bidding process will pay an annual rental fee equal to $1.00 per acre for the first ten years and $5.00 per acre each year thereafter and (b) a geothermal lessee who has obtained a lease through a competitive process will pay a rental equal to $2.00 per acre for the first year, $3.00 per acre for the second through tenth year and $5.00 per acre each year thereafter. Rental fees paid before the first day of the year for which the rental is owed will be credited towards royalty payments for that year. For BLM leases issued, effective, or pending on August 5, 2005 or thereafter, royalty rates are fixed between 1-2.5% of the gross proceeds from the sale of electricity during the first ten years of production under the lease. Currently, the royalty rate set by the BLM for geothermal resources produced for the commercial generation of electricity but not sold in an arm’s length transaction is 1.75% for the first ten years of production and 3.5% thereafter. The royalty rate for geothermal resources sold by the geothermal lessee or an affiliate in an arm’s length transaction is 10% of the gross proceeds from the arm’s length sale. The BLM may readjust the rental or royalty rates at not less than twenty year intervals beginning thirty-five years after the date geothermal steam is produced.

In the event of a default under any BLM lease, or the failure to comply with any of the provisions of the Act or regulations issued under the Act or the terms or stipulations of the lease, the BLM may, 30 days after notice of default is provided to the relevant project, (1) suspend operations until the requested action is taken or (2) cancel the lease.

Private Geothermal Leases

Certain of our domestic project subsidiaries have entered into geothermal resources leases with private parties, pursuant to which they have obtained the right to conduct their geothermal development and operations on privately owned land. In many cases, the lessor under these private geothermal leases owns only the geothermal resource and not the surface of the land.

Typically, the leases grant our project subsidiaries the exclusive right and privilege to drill for, produce, extract, take and remove from the leased land water, brine, steam, steam power, minerals (other than oil), salts, chemicals, gases (other than gases associated with oil), and other products produced or extracted by such project subsidiary. The project subsidiaries are also granted certain non-exclusive rights pertaining to the construction and operation of plants, structures and facilities on the leased land. Additionally, the project subsidiaries are granted the right to dispose of waste brine and other waste products as well as the right to reinject into the leased land water, brine, steam and gases in a well or wells for the purpose of maintaining or restoring pressure in the productive zones beneath the leased land or other land in the vicinity. Because the private geothermal leases do not grant to the lessee the exclusive right to use the surface of the land, the lessor reserves the right to conduct other activities on the leased land in a manner that does not unreasonably interfere with the geothermal lessee’s uses of the same land, which other activities may include agricultural use (farming or grazing), recreational use and hunting, and/or wind or solar energy developments.

The leases provide for a term consisting of a primary term in the range of five to 30 years, depending on the lease, and so long thereafter as lease products are being produced or the project subsidiary is engaged in drilling, extraction, processing or reworking operations on the leased land.

As consideration under most of our project subsidiaries’ private leases, the project subsidiary must pay to the lessor a certain specified percentage of the value “at the well” (which is not attributable to the enhanced value of electricity generation), gross proceeds or gross revenues of all lease products produced, saved and sold on a monthly basis. In certain of our project subsidiaries’ private leases, royalties payable to the lessor by the project subsidiary are based on the gross revenues received by the lessee from the sale or use of the geothermal substances, either from electricity production or the value of the geothermal resource “at the well.”

In addition, pursuant to the leases, the project subsidiary typically agrees to commence drilling, extraction or processing operations on the leased land within the primary term, and to conduct such operations with reasonable diligence until lease products have been found, extracted and processed in quantities deemed “paying quantities” by the project subsidiary, or until further operations would, in such project subsidiary’s judgment, be unprofitable or impracticable, or the project subsidiary may at any time within the primary term terminate the lease and surrender the relevant land. If the project subsidiary has not commenced any such operations on said land (or on the unit area, if the lease has been unitized) or terminated the lease within the primary term, the project subsidiary must pay to the lessor, annually in advance, a rental fee until operations are commenced on the leased land.

If the project subsidiary fails to pay any installment of royalty or rental when due and if such default continues for a period of 15 days after its receipt of written notice thereof from the lessor, then at the option of the lessor, the lease will terminate as to the portion or portions thereof as to which the project subsidiary is in default.

If the project subsidiary defaults in the performance of any obligations under the lease, other than a payment default, and if, for a period of 90 days after written notice is given to it by the lessor of such default, the project subsidiary fails to commence and thereafter diligently and in good faith take remedial measures to remedy such default, the lessor may terminate the lease.”

We supplementally advise the Staff that if there are material differences between these standard terms and conditions and those in a material lease for an Applicable Property (as described in our response to Comment No. 5 below), we will summarize those differences in the description of the Applicable Property.

Because the permitting regime applicable to our operations and our material geothermal plants does not significantly vary, we propose to expand our existing disclosure under “Permitting” to include more detailed information regarding the permitting process for our geothermal operations.

Set forth below is our proposed revised disclosure regarding our permitting status:

“Permit Status

U.S. environmental permitting regimes with respect to geothermal projects center upon several general areas of focus. The first involves land use approvals. These may take the form of Special Use Permits or Conditional Use Permits from local planning authorities or a series of development and utilization plan approvals and right of way approvals where the geothermal facility is entirely or partly on BLM or U.S. Forest Service (USFS) lands. Certain federal approvals require a review of environmental impacts in conformance with the federal National Environmental Policy Act (NEPA). In California, some local permit approvals require a similar review of environmental impacts under a state statute known as the California Environmental Quality Act (CEQA). These federal and local land use approvals typically impose conditions and restrictions on the scope and operation of the geothermal projects.

The second category of permitting focuses on the installation and use of the geothermal wells themselves. Geothermal projects typically have three types of wells: (1) exploration wells designed to define and verify the geothermal resource, (2) production wells to extract the hot geothermal liquids (also known as brine) for the power plant, and (3) injection wells to reinject the brine back into the subsurface resource. In Nevada and on BLM lands, the well permits take the form of geothermal drilling permits for well installation. Approvals are also required to modify wells, including for use as production or injections wells. Those wells in Nevada to be used for injection will also require Underground Injection Control Permits from the Nevada Division of Environmental Protection. Geothermal wells on private lands in California require drilling permits from the California Department of Conservation’s Division of Oil, Gas, and Geothermal Resources (DOGGR). The eventual designation of these installed wells as individual production or injection wells and the ultimate closure of any wells is also reviewed and approved by DOGGR pursuant to a DOGGR-approved Geothermal Injection Program.

A third category of permits involves the regulation of potential air emissions associated with the construction and operation of wells and surface water discharges associated with construction activities. Each well requires a preconstruction air permit before it can be drilled. In addition, the wells that are to be used for production require and those used for injection may require operating air permits. Combustion engines and other air pollutant emissions sources at the projects may also require air permits. For our projects, these permits are typically issued at the county level. Permits are also required to manage stormwater during project construction and to manage drilling muds from well construction, as well as to manage certain discharges to surface impoundments, if any.

A fourth category of permits that are required in both California and Nevada includes ministerial permits such as hazardous materials storage and management permits and pressure vessel operating permits. We are also required to obtain water rights permits in Nevada and may be required to obtain groundwater permits in California to use groundwater resources for makeup water. In addition to permits, there are various regulatory plans and programs that are required, including risk management plans (federal and state programs) and hazardous materials management plans (in California).

In some cases our projects may also require permits, issued by the applicable federal agencies or authorized state agencies, regarding threatened or endangered species, permits to impact wetlands or other waters and notices of construction of structures which may have an impact on airspace. Environmental laws and regulations may change in the future, which may lead to increases in the costs of compliance.

As of the date of this report, all of the material environmental permits and approvals currently required for our projects have been obtained. Although there are some environmental permits and approvals that will be required in the future, we believe that we will be able to obtain those environmental permits and approvals without material delay and without incurring additional material costs.

Our operations are designed and conducted to comply with applicable environmental permit and approval requirements. Non-compliance with any such requirements could result in fines or other penalties.

Environmental Laws and Regulations

Our facilities are subject to a number of environmental laws and regulations relating to development, construction and operation of geothermal facilities. In the United States these may include the Clean Air Act; the Clean Water Act; the Emergency Planning and Community Right-to-Know Act; the Endangered Species Act; the National Environmental Policy Act; the Resource Conservation and Recovery Act; and related state laws and regulations.

Our operations involve significant quantities of brine (substantially all of which we reinject into the subsurface) and scale, both of which can contain materials (such as arsenic, lead and naturally occurring radioactive materials) in concentrations that exceed regulatory limits used to define hazardous waste. We also use various substances, including isopentane, and industrial lubricants, that could become potential contaminants and are generally flammable. Hazardous materials are also used in our equipment manufacturing operations in Israel. As a result, our projects are subject to domestic and foreign federal, state and local statutory and regulatory requirements regarding the use, storage, fugitive emissions and disposal of hazardous substances. The cost of remediation activities associated with a spill or release of such materials could be significant.

Although we are not aware of any mismanagement of these materials, including any mismanagement prior to the acquisition of some of our projects, that has materially impaired any of the project sites, any disposal or release of these materials onto the project sites, other than by means of permitted injection wells, could lead to contamination of the environment and result in material cleanup requirements of responsive obligations under applicable environmental laws. We believe that at one time there may have been a gas station located on the Mammoth project site (which we lease), but because of significant surface disturbance and construction since that time further physical evaluation of the environmental condition of the former gas station site has been impractical. We believe that, given the subsequent surface disturbance and construction activity in the vicinity of the suspected location of the service station, it is likely that environmental contamination, if any, associated with the former facilities and any associated underground storage tanks would have already been encountered if they still existed.”

SeeExhibit A attached hereto to see the proposed disclosure regarding our permitting status tracked to show the changes from the corresponding disclosure contained in our 2008 Annual Report.

In various locations in this section, you disclose that you own or control geothermal facilities or areas of geothermal potential. As you describe your exploration/evaluation projects, please clarify who owns the geothermal energy, what environmental permits are required, and where appropriate, how you intend to acquire or lease related surface rights and/or the associated right-of-way. If you do not own the property rights, please disclose your obligations for your use permits for your material exploration areas.

We believe that our revised and updated disclosure as noted in response to Comment No. 3 above also addresses the questions contained in this Comment.

Please disclose the information required under paragraph (b) of Industry Guide 7 for all your material properties listed under this heading. For any properties identified which are not material, include a statement to that effect, clarifying your intentions. For each material property, include the following information:

	•		The location and means of access to your property, including the modes of transportation utilized to and from the property.

	•		Any conditions that must be met in order to obtain or retain title to the property, whether your have surface and/or mineral rights or a lease agreement.

	•		A brief description of the rock formations and geothermal conditions of existing or potential economic significance on the property.

	•		A description of any work completed on the property and its present condition.

	•		The details as to modernization and physical condition of the plant and equipment, including subsurface improvements and equipment.

	•		A general description of equipment, infrastructure, and other facilities.

	•		The source of power and water that can be utilized at the property.

	•		If applicable, provide a clear statement that the property is without known reserves or geothermal potential and your proposed program is exploratory in nature.

You may refer to Industry Guide 7, paragraphs (b) (1) through (5), for specific guidance pertaining to the foregoing, available on our website at the following address:www.sec.gov/about/forms/industryguides.pdf

Introduction

We do not believe it is appropriate to apply Industry Guide 7 to our operations, because we are not engaged in “significant mining operations.”

Our principal business is generating electricity, and manufacturing equipment that generates electricity, primarily using heat derived either from geothermal resources or so-called waste heat from other manufacturing processes or other equipment, which we refer to as “recovered energy”.

Using heat from a geothermal resource to generate electricity is significantly different from mining operations in many respects. As a matter of normal usage, a mine in this context is typically understood as “a pit or excavation in the earth from which mineral substances are taken.”¹ “Mining normally means an operation that involves the physical removal of rock and earth. A number of substances, notably natural gas, petroleum, and some sulfur, are produced by methods (primarily drilling) that are not classified as mining.”² “Mining in a wider sense comprises extraction of any non-renewable resource. . . .”³ And mining has been defined, generally, as the activity “to remove (a natural resource) from its source without attempting to replace it.”⁴ Most mining industry associations define mining by reference to minerals extracted;⁵ geothermal fluid is rarely mined for minerals.⁶

We respectfully submit that our use of geothermal resources, and the way we extract them, do not resemble mining operations:⁷


¹		Merriam-Webster Dictionary On Line.http://www.merriam-webster.com/dictionary/mine

²		MSN Encarta-Mining.http://encarta.msn.com/encyclopedia_761575410/mining.html

³		Wikipedia-Mining.http://en.wikipedia.org/wiki/Mining. Anon-renewable resourceis a natural resource that cannot be produced, re-grown, regenerated, or reused on a scale which can sustain its consumption rate.Id.

⁴		The Random House Dictionary of the English language, Second Edition, Unabridged.

⁵		See, e.g.,Mineral Information Institute, Common Minerals and Their Uses.http://www.mii.org/commonminerals.php ; National Institute for Occupational Safety and Health-Mininghttp://www.cdc.gov/niosh/mining/statistics/mines.htm ; Global InfoMine-Mine Siteshttp://www.infomine.com/minesite/ .

⁶		We acknowledge, of course, that it may be possible to extract minerals from geothermal fluids in some cases. For example, one geothermal developer is looking to extract lithium from underground geothermal brine in the Salton Sea geothermal resource in Southern California.http://www.greentechmedia.com/articles/read/geothermal-power-lithium-mining-two- in-one-in-california/ But we do not mine our brine and have no current intention to do that.

⁷		To be sure, some of the things we do to find geothermal resources may be similar to what we understand some miners may do to find minerals. Nevertheless, our activities more closely resemble oil and gas exploration and development activities, as described in our response to Comment No. 18, although even then there are significant differences. In any event, “exploration” activity is a relatively small part of our business, taken as a whole. We say this for several reasons:

•

Significant parts of our business do not involve locating geothermal resources, including, for example:

	•		Our recovered energy power plants, which operate from so-called waste heat as described above.

	•		Our Products Segment, which involves manufacturing equipment we sell to others.

	•		Substantially all of our geothermal power plants currently in operation, which did not involve any exploration activities by us.

	•		Any expansion of existing geothermal power plants or new power plants located next to existing geothermal power plants which share the same geothermal resource.

	•		Many of our engineering, procurement and construction engagements for power plants owned by third parties, where any exploration activities were performed by others.

•

While we are exploring a number of properties, it would not be unusual to find that some properties we explore never reach construction or commercial operations. As described in our response to Comment

•

The only thing we “extract” or use is heat.

	•		Substantially all of the geothermal fluid and any minerals in that fluid are reinjected back into the geothermal resource after the heat is extracted.

	•		The geothermal reservoirs from which we extract heat are generally considered a renewable resource if properly managed, although over time there may be some cooling of the resource in some locations.

•

We use wells, not mines or excavations, and the geothermal fluid is circulated from the underground reservoir, through our equipment, and then back for reheating into the underground reservoir, not extracted.

Comment Responses

We do not believe it is appropriate to apply Industry Guide 7 to our operations for the reasons outlined above. However, we share the Staff’s goal of improving our investor disclosures. Accordingly, we propose to provide supplemental disclosures addressing a number of the points covered by that guide, since some of our investors may find it helpful, to some extent, in understanding our operations.

We propose to provide the supplemental information described in more detail below only for our material domestic properties where geothermal fluids are or will be used as a source of heat for a power plant to generate electricity (“Applicable Property”). We do not think this information is appropriate for our recovered energy facilities (which as noted above use waste heat generated by manufacturing processes or other equipment to power turbines). We will include a statement to the effect that we do not regard any property as material unless and until we begin construction of a power plant on the property, that is, when we drill a production well on the property. If any Applicable Property in construction or operation is (or becomes) immaterial, we will include a statement to that effect. Since the geothermal extraction rights and surface rights associated with any particular power plant are often governed by multiple leases (or deeds, easements or rights of way), our disclosure for any Applicable Property will be made with respect to our collective rights and not any particular parcel or lease that is part of the Applicable Property.

For each material property, include the following information:

•

The location and means of access to your property, including the modes of transportation utilized to and from the property.

For each Applicable Property, we will identify the state and county in which it is located. We will also provide a map showing the general location of our Applicable Properties. A sample map is attached hereto asExhibit B. We will also include a statement to the effect that we have access to the

No. 5, unless and until we commence construction of a power plant, we do not regard a potential geothermal resource, lease or other property as material.

property from public roads, or if that is not the case, the means of access to our property. This disclosure will be made under the heading “Access to Property” in the description for each Applicable Property, as shown in the Sample Templates attached hereto asExhibit C andExhibit D for our operating and construction-stage power plants, respectively. As part of our internal review described above, we have decided to revise in certain respects the descriptions of our projects that currently appear as textual material under the heading “Descriptions of Our Projects,” beginning on page 26 of our 2008 Annual Report. We think presenting this information in a table format like the Sample Templates will make it easier for our investors to read and understand this information.

•

Any conditions that must be met in order to obtain or regain title to the property, whether your have surface and/or mineral rights or a lease agreement.

For each Applicable Property, we will provide this information through the general disclosure of lease terms as set forth in our response to Comment No. 3. In the event there are any material differences in those generally applicable terms for any Applicable Property, those differences will be identified under the heading “Land and Mineral Rights” in the description of the affected Applicable Property, as shown in the Sample Templates.

•

A brief description of the rock formations and geothermal conditions of existing or potential economic significance on the property.

For each Applicable Property that is in operation, we will provide a statement to the effect that “the resource temperature at the [name of Applicable Property] is an average of [insert temperature] degrees Fahrenheit” as shown in the Sample Template under the heading “Resource Information.” SeeExhibit C. We supplementally advise the Staff that we will not provide a similar disclosure for any Applicable Property that is under construction because the average temperature of the geothermal resource will not be measurable or estimable at that stage. SeeExhibit D. We supplementally advise the Staff that the temperature of a geothermal resource can vary from location to location within the resource. Accordingly, we believe it is more meaningful, for purposes of investor understanding, to provide average temperature, based on temperatures recorded at multiple production wells. We do not think descriptions of rock formations or other geothermal conditions would provide particularly meaningful disclosure for most of our investors. We supplementally advise the Staff that the principal factors that affect our use of a geothermal resource are the resource temperature and permeability (or the ability to get geothermal fluids to the surface). By the time we drill production wells, it will be clear that permeability is not an issue; otherwise the site will not become an Applicable Project. Once permeability is established, it generally does not change. However, the temperature of a geothermal resource may change over time, so we will include the resource temperature in our disclosure.

•

A description of any work completed on the property and its present condition.

For each Applicable Property that is under construction, we will provide a brief description of any material work completed on the Applicable Property. This might include, for example, completion of a production well, commencement or completion of equipment manufacturing and installation or testing and commencement of commercial operations (which we currently report in the “Recent Developments” section of our Annual Report on Form 10-K).⁸ We do not think it is


⁸		Please see, for example, page 26 of our 2008 Annual Report where we state “[i]n February 2008, we commenced commercial operation of the Galena 3 project at the Steamboat complex in Nevada.”

appropriate to provide a description of “any work completed” in the complex context of building power plants. That would simply result, in our view, in overly long, detailed information of little practical use to our investors. Please refer to the Sample Template for McGinness Hills for an illustration of the type of disclosure we propose to provide, attached hereto asExhibit D.

For any Applicable Property that is in operation, we do not believe that any supplemental disclosure of work completed is appropriate, unless that work is out of the ordinary course of business and thus warrants disclosure, say, as a material event (e.g., a turbine failure that forces the Applicable Property to shut down operations). In the ordinary course of business, routine maintenance and other work is regularly completed on power plants. We do not believe that our use of geothermal heat to power turbines is a reason to have different disclosures in our Annual Report on Form 10-K (or any Securities Act registration statement incorporating by reference the information in that report) than other reporting issuers whose turbines use other fuels have with respect to work completed on their power plants.

We do not believe it is necessary to make any disclosure about the “present condition” of any Applicable Property for the reasons stated above. We point out that Item 2 of our Annual Report on Form 10-K includes a statement to the effect that “[w]e believe that our current facilities . . . will be adequate for our operations as currently conducted.”

Accordingly, we respectfully ask the Staff to reconsider this comment.

•

The details as to modernization and physical condition of the plant and equipment, including subsurface improvements and equipment.

For each Applicable Property, we will disclose this type of information to the extent that it otherwise would be required to be disclosed under Commission regulations (other than Industry Guide 7) and applicable law. As in the past, as a matter of good disclosure, we would expect to inform our investors of material upgrades we make, although not necessarily “details” of modernization. We typically do this in the “Recent Developments” section of our Annual Report on Form 10-K and our Quarterly Reports on Form 10-Q. For example, on page 24 of our 2008 Annual Report, we said:

“In October 2008, we successfully completed the Steamboat 2/3 upgrade project. The upgrade included the replacement of the four Rotoflow turbines originally installed at these plants with direct drive gearless 11 MW axial turbines, each designed and manufactured by us specifically for geothermal use.”

We do not believe it is appropriate to require “details as to modernization and physical condition of the plant and equipment” for any Applicable Property simply because we use geothermal heat rather than other fuels for our power plant turbines. Reporting issuers that use conventional gas turbines to generate electricity, for example, are to follow the instructions to Item 102 of Regulation S-K. That is, “[d]etailed descriptions of the physical characteristics of individual properties . . . are not required and shall not be provided”. We think the same standard should apply to our power plants and respectfully ask the Staff to reconsider this point.

•

A general description of equipment, infrastructure, and other facilities.

We believe our existing disclosure already complies with this requirement. However, as noted above, we plan to revise our existing disclosures under the heading “Domestic Projects”. The Sample Templates attached hereto asExhibit C andExhibit D illustrate the new disclosures we

propose to make with respect to our description of equipment, infrastructure, and other facilities, consistent, we believe, with Item 102 of Regulation S-K. The applicable disclosures are made under the headings “Technology” (in the case of construction-stage projects, “Projected Technology”), “Plant and Equipment” and “Land and Mineral Rights”.

•

The source of power and water that can be utilized at the property.

We supplementally advise the Staff that for Applicable Properties that are in operation, this disclosure will not include sources of power, since all electric power needed by the plant will be self-generated. In addition, since most of our power plants use air cooling systems, we will disclose sources of water only for power plants that are water cooled. Please see the Sample Template attached hereto asExhibit C for an illustration of the type of disclosure we propose to make for operating power plants.

We do not think disclosures concerning the source of power or water for Applicable Properties under construction would be useful for our investors. We do not think our investors will be concerned whether we use portable power generating equipment or access electricity from an available grid or whether our water comes from wells we dig, on-site storage or connection to a local utility. Accordingly, unless access to power or water otherwise would be “material” for construction of any particular Applicable Property, we propose not to make routine disclosure of this information, and respectfully ask the Staff to reconsider this point.

•

If applicable, provide a clear statement that the property is without known reserves or geothermal potential and your proposed program is exploratory in nature.

We supplementally advise the Staff that this statement will not be applicable to any of our Applicable Properties. This is because we will not drill a production well on a property that is without known reserves or geothermal potential that we think are capable of supporting commercial operations. As noted above, we do not regard any property as material, and thus an Applicable Property, unless and until we drill a production well.

We note your descriptions of your geothermal power generation facilities, which you own and operate, or have under construction or plan to construct. Please insert a small-scale map showing the location of each material property, grouping them as may be appropriate, as required by Instruction3(b) to Item 102 of Regulation S-K. Please note the EDGAR program now accepts Adobe PDF files and digital maps, so please include these maps in any amendments that are uploaded to EDGAR. It is relatively easy to include automatic links at the appropriate locations within the document to GIF or JPEG files, which will allow figures and diagrams to appear in the right location when the document is viewed on the Internet. For more information, please consult the EDGAR manual, and if additional assistance is required, please call Filer Support at (202) 551-3600 for Post-Acceptance Filing Issues or (202) 551-8900 for Pre-Acceptance Filing Issues.

As noted in Comment No. 5 above, we will provide a map showing the general location of our Applicable Properties. A sample map is attached hereto asExhibit B.

Commercial banks are reluctant to finance geothermal projects unless a substantial portion of the required amount and quality of steam generated has been proven to their satisfaction with a high level of certainty. Please disclose your energy reserves that measure the energy potential of your geothermal reservoirs, including a statement as to geothermal

sustainability as it relates to the useful life of your operations. Please disclose both the proven and/or probable energy reserves for your geothermal reservoirs, stating your current estimates of duration for economic power generation, and your estimated rate of decline in productivity and/or utilization. Please note geothermal reserves are specifically excluded from oil and gas producing activities under Regulation SX § 210.4-10.

We understand that geothermal reserves are specifically excluded from oil and gas producing activities under Regulation SX § 210.4-10. For the reasons summarized in our responses to Comments No. 5 and 18, we do not think it is appropriate to apply Industry Guide 7 to our operations. For similar reasons, we do not think it is appropriate to disclose proven and probable reserve information contemplated by that guide. We note that in the supplemental information the Staff suggested we provide in Comment No. 5, the Staff omitted certain items that are in Industry Guide 7, and we understand from our telephone conversation with Mr. George K. Schuler on October 1, 2009 that those omissions were considered and purposeful. One of those omissions was information in the last sentence of paragraph (b)(5), which deals with proven and probable reserves. We think this omission is entirely appropriate in the case of our operations.

Due to the renewable nature of our geothermal resources, the level of power generation at our geothermal power plants is not expected to decline substantially over the useful life of those power plants. Moreover, the useful life of the geothermal power plants is determined without regard to the geothermal resources, and is based entirely on the useful life of the plants and equipment used to generate power from those resources. We disclose the level of power generation the power plant is capable of delivering and the useful life of our geothermal power plants. By providing disclosure with respect to the expected level of power generation and the useful life of our geothermal power plants, we believe we are disclosing all material information necessary for investors to assess the economic potential of our geothermal power plants. Because the reserve information contemplated by Industry Guide 7 would not provide any additional useful information and would never change given the renewable nature of our geothermal resources, we do not believe the reserve information would be material to investors.

We believe that commercial banks’ approach to financing geothermal power plants is more similar to financing conventional fuel power plants, such as those powered by natural gas or coal, and does not affect our conclusion that reserve information contemplated by Industry Guide 7 would not provide additional meaningful information that is material to investors. Over the last five years, we have not financed the development and construction of our geothermal power plants with commercial banks as a funding source on a project finance basis. Rather, we develop and construct our geothermal power plants, and bring them to full commercial operation, using internally generated cash and general liquidity sources. Only when our geothermal power plants have reached commercial operation have we refinanced in the bank or capital markets.

We are aware of the comments provided by the Staff to Raser Technologies, Inc. (“Raser”) and the responses provided by Raser. Consistent with the exchange of comments and responses between the Staff and Raser, we will supplement our disclosure in Item 1A — “Risk Factors” to include specific disclosure of the risk that, absent additional geologic/hydrologic studies, any increase in power generation from our geothermal power plants, or failure to reinject the geothermal fluid, or improper maintenance of the hydrological balance may affect the operational duration of the geothermal resource and cause it to become a wasting asset, and may adversely affect our ability to generate power from the relevant geothermal power plant.

Our Technology, page 34

Please provide basic definitions in lay terms for Organic Rankine Cycle, Steam Rankine Cycle, and Brayton Cycle.

To simplify our disclosure of these technologies, we propose the following changes.

First, we propose to delete the references to the “Steam Rankine Cycle” and “Brayton Cycle” on page 34, the only place those two terms are used. The first sentence under the heading “Our Technology” would read as follows:

“Our proprietary technology may be used in power plants operating according to the Organic Rankine Cycle only or in combination with various other commonly used thermodynamic technologies that convert heat to mechanical power. It can be used with a variety of thermal energy sources, such as geothermal, recovered energy, biomass, solar energy and fossil fuels.”

Second, we propose to add an explanation of the Organic Rankine Cycle, as follows:

“The Organic Rankine Cycle is a process in which an organic fluid such as a hydrocarbon or fluorocarbon (but not water) is boiled in an evaporator to generate high pressure vapor. The vapor powers a turbine to generate mechanical power. After the expansion in the turbine, the low pressure vapor is cooled and condensed back to liquid in a condenser. A cycle pump is then used to pump the liquid back to the vaporizer to complete the cycle. The cycle is illustrated in the figure below.”

Employees, page 38

Please clarify whether the employees located in Israel are your employees or employees of Ormat Industries Ltd.

The employees located in Israel are our employees.

Item 2. Properties, page 61

10.

Please indicate the location of the new specialized industrial building.

The new specialized industrial building is located adjacent to our manufacturing facility in the Industrial Park of Yavne, Israel.

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

Critical Accounting Policies, page 75

Property, plant and equipment, page 75

11.

Please describe how you intend to amortize your capital costs utilizing the above mentioned energy reserves, clarifying the economic duration of your geothermal reserves as they relate to your energy generation facilities. Please expand your disclosure to clarify when your production units are considered to be in a producing or development state to initiate the record of depreciation, depletion, and amortization expenses. Please note geothermal reserves are specifically excluded from oil and gas producing activities under Regulation SX § 210.4-10.

We intend to amortize our capital costs, on a straight-line basis, with respect to each power plant (including costs associated with the exploration and development of the related geothermal resources) when the geothermal power plant is substantially completed and ready for use, which is the date on which power generation commences. The estimated useful life of our power plants ranges between 25 and 30 years, which estimate is based on the ability of the power plant to produce electricity. Because the geothermal fluid is reinjected into the geothermal reservoir for reheating, geothermal resources are renewable and no depletion of the geothermal resource occurs. Accordingly, we believe that it would be inappropriate to apply any method of depletion to our geothermal resources. We supplementally advise the Staff that we have not yet completed construction of any power plant on property on which we have conducted exploration activities.

We have considered the Staff’s comment above, as well as the portion of Comment No. 18 concerning our disclosures at the top of page 76 of our 2008 Annual Report, and will include in our future Form 10-K filings the disclosure contained in our response to that portion of Comment No. 18 (beginning on page 32).

OPC Tax Monetization Transaction, page 89

12.

Please disclose whether this or any other transaction with Lehman Brothers Inc. has been affected by their bankruptcy.

Lehman Brothers’ bankruptcy has not affected the Tax Monetization Transaction, or any other transaction that we entered into with Lehman Brothers.

Financial Statements and Supplementary Data, page 98

Consolidated Statements of Operations and Comprehensive Income, page 101

13.

We note that the minority interest reflected in your statements of operations increases your net income rather than decreasing it. Please confirm to us, if true, that this is because OPC incurred losses in fiscal years 2007 and 2008. If our assumption is incorrect, please explain to us in reasonable detail why minority interest is effectively an income item in your statements of operations.

Please refer to our response to Comment No. 21 for a description of our accounting for the OPC Tax Monetization Transaction and the calculation of amounts related to minority interest as reflected in the consolidated statement of operations.

Consolidated Statements of Cash Flows, page 103

14.

We note that you have classified distributions from unconsolidated investments as both operating activities and investing activities. Please explain to us the difference between the amounts classified as operating activities and those classified as investing activities, and consider clarifying the descriptions of these line items to make the difference more apparent to your readers.

We receive cash distributions from our unconsolidated investees accounted for under the equity method. Those cash flows that do not exceed our share of the accumulated earnings (from the date of our initial investment) of the unconsolidated investees are considered areturn on investment, and are classified as an operating activity in our statement of cash flows (in accordance with SFAS No. 95,Statement of Cash Flows, par. 22(b)). Cash distributions which exceed our share of the accumulated earnings of such unconsolidated investees are treated as areturn of investment and are classified as an investing activity in the statement of cash flows. In future filings, the line item titled “Distributions from unconsolidated investments” in operating activities will be modified to read “Return on investments in unconsolidated investees”. The line item titled “Distributions from unconsolidated investments” in investing activities will be modified to read “Return of investments in unconsolidated investees”.

15.

We note that several line items in your cash flow statements are presented on a net basis, including marketable securities, net; net change in restricted cash, cash equivalents and marketable securities; increase in severance pay fund asset, net; and due to parent, net. For each of these items, please tell us how you considered the guidance in paragraphs 11-13 of SFAS 95 when determining that net presentation was appropriate.

In response to the Staff’s comment, we supplementally advise the Staff as follows:

•

“Marketable Securities, net” and “Net changes in restricted cash, cash equivalents and marketable securities”

As discussed in Note 1 to our consolidated financial statements included in our 2008 Annual Report, “Marketable Securities” consist of debt securities (mainly auction rate securities and commercial paper). Restricted cash, cash equivalents and marketable securities consist of funds that will be used to satisfy obligations due under the terms of certain long-term debt agreements and the Puna project lease transactions that require us to maintain certain debt service reserve, cash collateral

and operating fund accounts. Such funds are invested primarily in money market accounts and commercial paper with a minimum investment grade of “AA” and in illiquid auction rate securities. At December 31, 2008, our investments in marketable securities and restricted marketable securities were classified as available-for-sale securities.

Paragraphs 11-13 of SFAS No. 95 state that certain items may qualify for net reporting “because their turnover is quick, their amounts are large, and their maturities are short.” Based on this guidance, we have presented cash flows related to marketable securities and restricted cash, cash equivalents and marketable securities on a net basis rather than itemizing cash in-flows and out-flows.

The following table demonstrates that the turnover is quick and amounts are large for these securities in the years ended December 31, 2006, 2007 and 2008 (the amounts are presented in millions):


	Quarter Ended															Balance at
	March 31,			June 30,			September 30,			December 31,			Total Change			December 31,
	2006			2006			2006			2006			for the Year			2006

Marketable securities:
Purchases	$	67		$	181		$	49		$	87		$	384
Sales		(101	)		(107	)		(73	)		(51	)		(332	)

Net	$	(34	)	$	74		$	(24	)	$	36		$	52		$	96


Restricted cash, cash equivalent, and marketable securities:
Purchases	$	39		$	39		$	43		$	45		$	166
Sales		(40	)		(42	)		(34	)		(34	)		(150	)

Net	$	(1	)	$	(3	)	$	9		$	11		$	16		$	56


	Quarter Ended															Balance at
	March 31,			June 30,			September 30,			December 31,			Total Change			December 31,
	2007			2007			2007			2007			for the Year			2007

Marketable securities:
Purchases	$	6		$	78		$	27		$	74		$	185
Sales		(50	)		(83	)		(66	)		(65	)		(264	)

Net	$	(44	)	$	(5	)	$	(39	)	$	9		$	(79	)	$	16


Restricted cash, cash equivalent, and marketable securities:
Purchases	$	55		$	39		$	51		$	50		$	195
Sales		(62	)		(14	)		(69	)		(71	)		(216	)

Net	$	(7	)	$	25		$	(18	)	$	(21	)	$	(21	)	$	35


	Quarter Ended															Balance at
	March 31,			June 30,			September 30,			December 31,			Total Change			December 31,
	2008			2008			2008			2008			for the Year			2008

Marketable securities:
Purchases	$	1		$	—		$	—		$	—		$	1
Sales		(14	)		—			—			—			(14	)

Net	$	(13	)	$	—		$	—		$	—		$	(13	)	$	2


Restricted cash, cash equivalent, and marketable securities:
Purchases	$	44		$	42		$	51		$	50		$	187
Sales		(41	)		(42	)		(36	)		(74	)		(193	)

Net	$	3		$	—		$	15		$	(24	)	$	(6	)	$	27

In the first quarter of 2008, we liquidated most of our marketable securities. The purchases and sales activity was presented on a net basis in the consolidated statement of cash flows because purchases were immaterial.

The maturities of the securities are longer than 90 days; however, due to the fact that the interest rates are reset each period, generally every 7 to 35 days, their actual maturities are considered to be short. The short-term nature of these securities is further demonstrated by the volume of cash in-flows and cash out-flows as shown in the table above.

For the reasons set forth above, we believe it is appropriate and consistent with the guidance in paragraphs 11-13 of SFAS No. 95 to present cash flows related to marketable securities and restricted cash, cash equivalents and marketable securities on a net basis in cash flows from investing activities rather than separately presenting cash in-flows and out-flows.

•

“Severance pay fund asset”

Please see our response to Comment No. 16.

•

“Due to parent”

This line item represents repayments of a long-term loan to our parent. On further reflection, we have determined that the use of the word “net” in this line item is not necessary, and we will omit the word “net” in future filings.

16.

We note the line item within investing activities titled “Increase in severance pay fund asset, net.” We also note your disclosures concerning severance payments within Note 19 to your financial statements. Please explain to us in more detail what these uses of cash represent, why you retain an asset on your books for these funded amounts rather than reflecting them as payments to a third party (the severance payment fund), whether actual severance payments are ultimately made out of this severance pay fund asset or whether actual severance payments are made by a separate severance pay fund, and if you pay the actual severance payments, how you reflect the actual severance payments within your cash flow statement.

The severance pay fund asset relates to government mandated severance arrangements with our Israeli employees. We have two forms of severance arrangements: defined contribution plans and

defined benefit plans. Please refer to additional information on these arrangements in the SEC’sInternational Financial Reporting and Disclosure Issues dated November 2004 (Appendix — Country Specific Issues — Israel). The amounts that we have deposited in defined contribution plans are not reflected in the balance sheet because the severance pay risks associated with these plans have been irrecoverably transferred to pension funds and insurance policies that are in the name of our employees. In contrast, the amounts that we have deposited in the defined benefit plans are recorded as an asset on our balance sheet because there is no legal defeasance, as we are the beneficiary of these defined benefit plans.

The line item within investing activities titled “Increase in severance pay fund asset, net,” reflects the monthly deposits that we make into the defined benefit plans, less the amounts of severance payments made to retired employees from these defined benefit plans. The payments made to retired employees are included as a reduction in “Increase in severance pay fund asset, net” in cash flows from investing activities with a corresponding reduction in “Liabilities for severance pay” in cash flows from operating activities. These amounts were immaterial in the years ended December 31, 2008 ($51,000), 2007 ($638,000) and 2006 ($145,000) and, therefore, were presented on a net basis in the consolidated statements of cash flows.

Notes to Consolidated Financial Statements, page 104

Note 1 — Business and Significant Accounting Policies, page 104

General

17.

We note on page 20 under the heading “How we obtain development sites and geothermal resources” that in certain cases you enter into one or more geothermal resource leases (or subleases) or a concession or other agreement granting you the exclusive right to extract geothermal resources from specified areas of land, and in other cases you own the land where the geothermal resource is located. We have the following comments:

	•		For those cases where you access geothermal resources via a lease or similar agreement, please explain to us in reasonable detail how you account for such leases, including the authoritative GAAP literature you are relying upon, and provide a significant accounting policy explaining this to your readers. In this regard, the only specific discussion of leases that we noted in your financial statements was your discussion of the lease-leaseback transactions related to the Puna Project as described in Note 11.

	•		For those cases where you access geothermal resources via a lease or similar agreement, please tell us whether you incurred any lease acquisition costs to obtain these leases, and if so, how you account for such costs. If you have these costs, please address these in the requested significant accounting policy.

	•		For those cases where you own the land where the geothermal resource is located, please tell us where these geothermal resources are included in the detail of your property, plant and equipment as seen in Note 7, and clarify this matter to your readers. Also explain to us in reasonable detail, and disclose to your readers, your depreciation policy for these geothermal resources as this is unclear to us from your current disclosures on pages 107 and 108.

Introduction

As described in Note 20 to our financial statements, we control certain rights to geothermal fluids through certain land leases with the BLM, various states or through private leases. In consideration for certain leases, we typically pay an up-front bonus payment, which is a component of the competitive lease process. In addition, we undertake to pay nominal, fixed annual rent payments for the period from the commencement of the lease through the completion of construction. Upon the commencement of power generation, we begin to pay to the lessors long-term royalty payments based on the utilization of the geothermal resources as defined in the respective agreements. Such payments are contingent on the power plant’s revenues. Typically these leases are for a primary period of ten years and will renew so long as geothermal resources are being produced or utilized in commercial quantities, but cannot exceed a period of forty years after the end of the primary term. The royalty payments are typically the same for the entire term of the lease, as described in our response to Comment No. 3. However, if at the end of such 40-year period, geothermal steam is still being produced or utilized in commercial quantities and the applicable leased lands are not needed for other purposes, the project will have a preferential right for a renewal of the lease for a second 40-year term, in accordance with such terms and conditions as the BLM deems appropriate. In the event we abandon further evaluation or exploration of a potential geothermal resource, we have the right to terminate the relevant lease and cease making the nominal, fixed annual rent payments. The up-front bonus payments made by us to acquire the right to explore the land under lease are not refunded.

Comment Responses

•

For those cases where you access geothermal resources via a lease or similar agreement, please explain to us in reasonable detail how you account for such leases, including the authoritative GAAP literature you are relying upon, and provide a significant accounting policy explaining this to your readers. In this regard, the only specific discussion of leases that we noted in your financial statements was your discussion of the lease-leaseback transactions related to the Puna Project as described in Note 11.

The up-front bonus payments and other related costs, such as legal fees, are capitalized and included in property, plant and equipment. We account for our up-front bonus payments as a contract-based intangible asset as defined in paragraph 39 of SFAS No. 141,Business Combinations. Our lease terms, as described above, result in a lease term that is considered indefinite. During the period from acquisition of the lease to the point when the geothermal project is complete and ready to commence power generation, the acquisition cost is accounted for as an intangible asset with an indefinite life. In accordance with paragraph 16 of SFAS No. 142,Goodwill and Other Intangible Assets, such assets are not subject to amortization until the point when their useful life is determined to no longer be indefinite. In our case, this occurs when the geothermal project is complete and ready to commence power generation.

Once power generation commences, we amortize the lease acquisition costs relating to such power plant over the useful life of the power plant (usually 25-30 years). This amortization period is limited to the useful life of the power plant since there is no assurance that we will construct a new geothermal plant on the property in order to extend our right to access the geothermal resource beyond the useful life of the power plant.

We recognize the contingent long-term lease royalties as part of cost of revenues when the contingency is resolved (i.e., when the related revenues are earned) in accordance with SFAS No. 29,Determining Contingent Rentals, an amendment of FASB Statement No. 13. Although lease

agreements relating to rights to explore or exploit natural resources are outside the scope of SFAS No. 13,Accounting for Leases, and related guidance, we have adopted a similar accounting treatment with respect to these leases and in particular with respect to the accounting for contingent payments (i.e., the royalty payments), since there is no other authoritative GAAP literature we consider appropriate for these royalties.

In future filings, we will add the following disclosure in Note 1 to our consolidated financial statements:

“The Company capitalizes up-front bonus payments paid to acquire power project leases and related costs, such as legal fees. Such costs are amortized over the useful life of the power plant once power generation commences. Long-term royalty payments that are contingent on the power plant’s revenues are expensed when the related revenues are earned. Such amounts are included in electricity cost of revenues on the consolidated statements of operations and comprehensive income.”

•

For those cases where you access geothermal resources via a lease or similar agreement, please tell us whether you incurred any lease acquisition costs to obtain these leases, and if so, how you account for such costs. If you have these costs, please address these in the requested significant accounting policy.

As described above, we incur up-front bonus payments in the competitive lease process and related costs, such as legal fees. We will add the disclosure detailed above to Note 1 to our consolidated financial statements.

•

For those cases where you own the land where the geothermal resource is located, please tell us where these geothermal resources are included in the detail of your property, plant and equipment as seen in Note 7, and clarify this matter to your readers. Also explain to us in reasonable detail, and disclose to your readers, your depreciation policy for these geothermal resources as this is unclear to us from your current disclosures on pages 107 and 108.

Our ownership of land where the geothermal resource is located is included in the line item titled “Land” in the table in Note 7. As the amount of this asset is immaterial ($16,105,000 as of December 31, 2008, and $10,156,000 as of December 31, 2007), we have not disclosed it in further detail. The carrying value of our geothermal resource development costs are included in “Geothermal and recovered energy generation power plants, including geothermal wells” in the detail of our property, plant and equipment as seen in Note 7. Such costs are depreciated over the useful life of the geothermal power plant. In future filings, we will disclose this policy in Note 1 and the amount of land where our geothermal resource is located in Note 7.

Exploration and drilling costs, page 108

18.

We note you capitalize costs incurred in connection with the exploration and development of geothermal resources on an “area of interest” basis, and that those costs include dry hole costs, the cost of drilling and equipping production wells and other directly attributable costs. We further note that these costs are capitalized and amortized over their estimated useful lives when production commences. Please address the following comments:

	•		Please explain to us in more detail your methodology involving an “area of interest” basis, including explaining how you determine an area of interest and your basis in GAAP for using this methodology.

	•		Please explain to us your basis in GAAP for capitalizing dry hole costs. Your response should address whether these dry holes can be used for any other purpose. If not, it would be unclear to us why these costs would result in an asset, regardless of whether you are assessing individual wells or whether you are assessing a larger group of wells. Please provide us with any additional information that would assist us in understanding this matter.

	•		Please tell us and describe each type of exploration, drilling and development cost incurred and your accounting policy for each cost. For any costs that are capitalized, cite the relevant authoritative GAAP literature, or accepted practice, that you relied upon or analogized to for your accounting.

	•		We note from your disclosure at the top of page 76 that you do not commence exploration activities until feasibility studies have determined that the project is capable of commercial production. Please provide us with a reasonably detailed description of your process for assessing economic feasibility, including whether these studies are prepared internally or whether you hire a third party to conduct them, the factors that these studies assess, whether you assume a certain number of dry holes, and whether there is a minimum probability factor that must be achieved before a project is deemed economically feasible. Please also describe to us the costs that are incurred in establishing feasibility, quantify those costs for each period presented on your statement of operations, and tell us where those costs are classified on your statement of operations. As these are areas of management judgment that may impact your financial statements, please expand your disclosures within your Critical Accounting Policy to provide more detailed information to your readers about the above matters.

	•		We note on page 20 that you do not expect to succeed in developing every resource that undergoes exploration activity and will cease exploration activities that will not support commercial operations. Please provide us with more information about your projects that do not achieve economic feasibility, including explaining to us the factors that would trigger this conclusion and quantifying for us the number of projects that you determined did not achieve economic feasibility in each of the fiscal years covered in this report.

	•		Please tell us and consider disclosing the total amount of exploration, drilling and development costs expensed for each period in which a statement of operations and comprehensive income is presented and the line item that these costs are included in.

	•		For each project under development listed on page 11, please provide us with a rollforward of the costs capitalized for each project, including any write-offs. Regarding the Carson Lake project, if you continue to have capitalized costs recorded for this project, please tell us your basis for these costs given your exploration has shown that the deep resource cannot support a commercial project.

We may have further comments upon reviewing your response.

Background

Our exploration activities begin with the process of identifying potential geothermal resources. It normally take us one to two years from the time we start active exploration of a particular geothermal resource to the time we have an operating production well, assuming we conclude the resource is commercially viable. We determine the economic feasibility of potential geothermal resources internally, with all available data and external assessments vetted through our exploration department.

Our determination of economic feasibility is based on the following process. We evaluate historic geologic and geothermal information and databases, and at times receive additional information from other industry participants. The next step is the creation of a digital, spatial geographic information systems database containing all pertinent information, including thermal water temperature gradients derived from historic drilling, geologic mapping information (formations, structure, topography, etc.), and any available archival information about the geophysical properties of the potential resource. We also assess other relevant information, such as infrastructure (roads, transmission), natural features (springs, lakes, etc.), and man-made features (old mines, wells, etc.). If our initial assessment indicates that an economically feasible geothermal reservoir is probable, we then initiate obtaining rights to the land on which the potential geothermal resource is located, either by lease or purchase.

Following the acquisition of land rights to the potential geothermal resource, we conduct surface water analyses and soil surveys to determine proximity to possible heat flow anomalies and up-flow/permeable zones and augment our digital database with the results of those analyses. We then initiate a suite of geophysical surveys (e.g., gravity, magnetics, resistivity, magnetotellurics and spectral surveys) to assess surface and sub-surface structure (faults, fractures, etc.) and develop a roadmap of fluid-flow conduits and overall permeability. All pertinent geophysical data are then used to create three dimensional geothermal reservoir models that are used to identify drill locations.

Before we initiate exploratory drilling, we make a further determination of the feasibility of the potential resource based on the results of the above-described process, particularly the results of the geochemical and geophysical surveys. If the results from geochemical and geophysical surveys are poor (i.e., low derived resource temperatures), we will significantly lower our assessment of the feasibility of the prospect and may not proceed to exploration. The costs we incur for these activities are immaterial.

The main types of exploration, development and drilling costs we incur include:

•

Geological, geochemical and geophysical studies;

	•		Drilling of temperature gradients;

	•		Drilling of slim holes;

	•		Access roads to drilling locations;

	•		Full size production and/or injection wells; and

	•		Flow tests.

Once we have confirmed the viability of the geothermal resource through our exploration and development activities, we then proceed to drilling a production well on the property and commence construction of the geothermal plant.

Capitalization Policy

There are no geothermal-specific industry accounting standards or guidance, and industry practice is diverse. Our capitalization policy for exploration activities is based in part on practices followed by certain other companies in the geothermal industry and on our consideration of and/or analogies to the following authoritative or industry guidance:

	•		Rule 4-10 of Regulation S-X,Financial Accounting and Reporting for Oil and Gas Producing Activities Pursuant to the Federal Securities Laws and the Energy Policy and Conservation Act of 1975

	•		PwC’s edition of “Financial Reporting in the Mining Industry”

	•		SFAS No. 67,Accounting for Costs and Initial Rental Operations of Real Estate Projects

	•		PwC’s Accounting and Reporting Manual Section 9772.2 —Real Estate Cost Capitalization and Allocation

	•		CON 6,Elements of Financial Statements

	•		SFAS No. 144,Impairment or Disposal of Long-Lived Assets.

We believe that many geothermal companies in the U.S. have analogized to Rule 4-10 of Regulation S-X,Financial Accounting and Reporting for Oil and Gas Producing Activities Pursuant to the Federal Securities Laws and the Energy Policy and Conservation Act of 1975and Statement of Financial Accounting Standards (“SFAS”) No. 19,Financial Accounting and Reporting by Oil and Gas Producing Companies. Although these pronouncements do not apply to the production of geothermal resources, these companies have adopted the accounting model used in the oil and gas industry (at least partially) for the following reasons:

Much of the geological and other data we consider in locating geothermal resources and deciding where to make test drillings are similar to the data we understand is evaluated in connection with on-shore oil and gas exploration.

	2.		The technology and equipment used to drill our wells is similar to that used by oil and gas exploration companies. Indeed, many of the third party contractors we use to drill our wells also contract to drill oil and gas wells.

	3.		The drilling permitting process in most states where we operate is the same for our wells and for oil and gas wells, and is administered by the same regulatory agencies in those states.

	4.		Geothermal companies are treated more like oil and gas companies than mining companies for Federal income tax purposes.

It is also important to note, however, that while our exploration activities are similar in some respects to the oil and gas industry, one key difference is that geothermal heat is a renewable resource. The geothermal fluid we use to generate electricity is reinjected back to the geothermal heat source to be heated again, rather than permanently extracted and consumed like oil and gas reserves. Therefore, we believe the depreciation methods followed by the non-renewable extractive industry (i.e., units of production), such as oil and gas, are not applicable to geothermal companies.

In addition, we believe it would not be appropriate to analogize our exploration activities to the mining industry as the process of locating geothermal resources and drilling wells more closely resembles oil and gas exploration and development activities than it does mining operations for the reasons outlined above. Therefore, while we have considered the accounting policies for exploration activities in the mining industry in the context of our operations, we have not adopted an accounting model that is based on industry practice for U.S. companies in the mining industry.

In certain respects, our exploration activities can be analogized to the development of a real estate project which is often developed over a period of years. For real estate projects, costs typically capitalized include acquisition and development costs. PwC’s Accounting and Reporting Manual Section 9772.2 indicates that development costs typically capitalized include “market research/feasibility studies, land improvements, structures and equipment, interest costs, property taxes and insurance...”

To determine at what point during the extractive process an asset should be recognized, we consider that activity in the context of the definition of an asset and the asset recognition criteria in the conceptual framework. An asset is defined in CON 6,Elements of Financial Statements, as “something that has probable future economic benefits obtained or controlled by a particular entity as a result of past transactions or events.” We understand that the FASB and IASB have tentatively adopted a revised definition of an asset which says that “an asset is a present economic resource to which the entity has a right or other access that others do not have.” This revised definition does not change the conceptual basis supporting our capitalization policy as described in this response.

The costs we incur prior to acquiring legal rights to explore are expensed on our consolidated statements of operations. This treatment is consistent with the conceptual definition of an asset because until the right to explore is secured, an entity cannot demonstrate that probable future economic benefits have been obtained as a result of those activities. It is important to note that we do not secure land leases unless our internal feasibility analyses have determined that it is probable the geothermal resource may be commercially viable. To date, our exploration activities have occurred primarily in the State of Nevada. Our rights to geothermal fluids in this state are acquired for the most part through land leases with the BLM. In consideration for BLM leases, we typically pay an up-front bonus payment which is a component of the competitive lease process. Please refer to our response to Comment No. 17 for a discussion of how we account for up-front bonus payments.

Once we secure the legal rights to explore, we begin to capitalize costs incurred during exploration activities because they increase our understanding of the resource and help us determine the best area on which to commence development activities, thus representing an enhancement to the legal right asset. We believe such costs meet the definition of an asset as they are incurred to generate future economic benefits. While not directly analogous to the real estate industry, this treatment is also consistent with the conceptual framework generally accepted by companies in that industry.

Comment Responses

•

Please explain to us in more detail your methodology involving an “area of interest” basis, including explaining how you determine an area of interest and your basis in GAAP for using this methodology.

We consider geological and economic characteristics when determining an area of interest. Substantially all of our exploration activities are located in Nevada. The geothermal systems of Nevada are located in the region known as the Basin and Range, an area linked to tectonic extension, rifting and high heat flow. The Earth’s crust in north-western Nevada is the thinnest in the Basin and Range and is characterized by extensive deep faulting and fracturing, which allows water to circulate in the hot, primarily volcanic, rock formations. In line with this methodology, we are of the opinion that Nevada, where most of our geothermal resources under exploration are located, can be considered one area of interest. However, we have further divided Nevada into three areas of interest based on the following factors:

	1.		The geographical proximity of the geothermal resources and their proximity to the same electricity grid.

	2.		The ability to allocate a power purchase agreement to alternate resources in the same geographical area.

	3.		An intention to operate all the power plants in the same area of interest together as one complex.

The grouping of projects within an area of interest can be analogized to the grouping of accounts under paragraph 10 of SFAS No. 144,Impairment or Disposal of Long-Lived Assets(“SFAS No. 144”), which says that the group should represent the lowest level for which identifiable cash flows are largely independent of the cash flows of other groups of assets and liabilities. Since the projects ultimately generate cash through the sale of electricity, we have determined the asset group or area of interest based on the three factors described above.

We test our exploration projects for impairment using the provisions of SFAS No. 144. Factors which could trigger an impairment include, among others, negative industry or economic trends, a determination that a suspended project is not likely to be completed, unsuccessful drilling within an area of interest, significant increase in costs necessary to complete a project or legal factors relating to our business. When a triggering event occurs, we compare the carrying amount of the asset, including estimated future expenditures necessary to develop the asset, which includes construction of a geothermal plant, to estimated future net undiscounted cash flows expected to be generated from the power plant through power generation. If our assets are considered to be impaired, the impairment to be recognized would be measured by the amount by which the carrying amount of the asset exceeds its fair value.

•

Please explain to us your basis in GAAP for capitalizing dry hole costs. Your response should address whether these dry holes can be used for any other purpose. If not, it would be unclear to us why these costs would result in an asset, regardless of whether you are assessing individual wells or whether you are assessing a larger group of wells. Please provide us with any additional information that would assist us in understanding this matter.

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. This does not mean that the exploration project is unsuccessful. It is only when we have not identified any commercially viable resource in an area of interest or when the amount of unsuccessful exploration activities are significantly higher than expected such that they will make the area of interest uneconomical, that we could be required to record an impairment charge. However, even if we experience a higher than expected amount of unsuccessful exploration activities, it would not necessarily result in an impairment charge because the cost of such activities are typically insignificant in relation to the total cost of a geothermal power plant.

We believe that all drilling (including slim holes and full size wells) that does not result in commercially viable wells (loosely called dry holes) is useful for the discovery of commercially viable resources within an area of interest and for the operation of the power plant thereafter. Non-commercial wells are used as observation wells enabling analysis of the behavior of the reservoir, such as interference between wells, decline of water table and the like. A non-commercial well can be a basis for a directional drilling from the wellbore. For example, in our McGinness project we had a dry slim hole from which we were able to infer the location of the fault and this enabled us to site and drill a successful full size production well. All of the drilling costs are incurred with the knowledge that some of our prospects will not result directly in the discovery of commercially viable resources. We expect that the benefits obtained from the prospects that are successful together with the benefits from past discoveries will be adequate to recover the costs of all of our exploration activities within an area of interest and thus, will generate future economic benefits. We confirm this belief when we test our exploration projects for impairment in accordance with SFAS No. 144. Please see our discussion above regarding how we test our exploration projects for impairment in accordance with SFAS No. 144.

•

Please tell us and describe each type of exploration, drilling and development cost incurred and your accounting policy for each cost. For any costs that are capitalized, cite the relevant authoritative GAAP literature, or accepted practice, that you relied upon or analogized to for your accounting.

Please refer to a detailed description of how we expense our exploration costs prior to acquiring legal rights to explore in the “Background” section. Please also refer to a detailed description of our exploration activities prior to obtaining rights to the land in the “Background” section. By the time we decide to acquire such legal rights, the results of our feasibility analyses have determined that it is probable the potential resource will support commercial operations. Our exploration, drilling and development costs incurred after we acquire legal rights are capitalized and include, among others, drilling of temperature gradients, drilling of slim holes, access roads to drilling locations, full size production and/or injection wells and flow tests. We believe this accounting model is consistent with the conceptual definition of an asset as defined in CON 6.

•

We note from your disclosure at the top of page 76 that you do not commence exploration activities until feasibility studies have determined that the project is capable of commercial production. Please provide us with a reasonably detailed description of your process for assessing economic feasibility, including whether these studies are prepared internally or whether you hire a third party to conduct them, the factors that these studies assess, whether you assume a certain number of dry holes, and whether there is a minimum probability factor that must be achieved before a project is deemed economically feasible. Please also describe to us the costs that are incurred in

establishing feasibility, quantify those costs for each period presented on your statement of operations, and tell us where those costs are classified on your statement of operations. As these are areas of management judgment that may impact your financial statements, please expand your disclosures within your Critical Accounting Policy to provide more detailed information to your readers about the above matters.

Please refer to the discussion under the caption “Background” at the beginning of our response to this Comment 18, which sets forth a reasonably detailed description of our process for assessing economic feasibility. As part of this assessment, we take into account that not all of the wells that we drill may be commercial. However, we do not assume a specific number of non-commercial wells, nor do we use a minimum probability factor that must be achieved before we determine that a project may be commercially viable. Our evaluation and analysis process is handled by our exploration department. The costs that we incur as part of this process are general and administrative in nature (e.g., employee salaries and benefits) and vendor payments, such as for mapping and laboratory work. For the years ended December 31, 2008 and 2007, such costs totaled $924,000 and $314,000, respectively. For the year ended December 31, 2006, such costs were less than $300,000. We believe these amounts are immaterial. They have been included in electricity cost of revenues on the consolidated statements of operations for the relevant periods. Unless these amounts for any future years are otherwise material, we do not propose to provide a separate detailed breakdown of such costs in our financial statements. However, we will revise our disclosure in future filings to provide more detailed information regarding the process of establishing feasibility as part of our discussion of our Critical Accounting Policies by replacing the second paragraph under our discussion of “Property, Plant and Equipment” with the following:

“We capitalize costs incurred in connection with the exploration and development of geothermal resources on an area-of-interest basis. We define an area of interest based on the geological structure of the area, the geographical proximity of the geothermal resources and their proximity to the same electricity grid, the ability to allocate a power purchase agreement to alternate resources in the same geographical area, and an intention to operate all the power plants in the same area of interest together as one complex. We begin capitalizing the exploration and development costs once we acquire legal rights to the land, which is done once we make an initial assessment that an economically feasible geothermal reservoir is probable on that land. Prior to reaching such a determination, we expense all exploration costs as incurred and include such amounts in cost of electricity revenues.

In most cases, we obtain the right to conduct our geothermal development and operations on land owned by the Bureau of Land Management, various states or with private parties. In consideration for certain of these leases, we may pay an up-front bonus payment which is a component of the competitive lease process. The up-front bonus payments and other related costs, such as legal fees, are capitalized and included in property, plant and equipment. All development costs which are incurred after we acquire legal rights to the land, including any dry hole costs and the cost of drilling and equipping production and injection wells, and other directly attributable costs, are capitalized and included in construction-in-process. All such costs, including the up-front bonus payments made to secure land leases, will be depreciated over their estimated useful lives when the related geothermal power plant is substantially complete and ready for use. A geothermal power plant is substantially complete and ready for use when electricity generation commences. Although we do not commence exploration activities until feasibility analyses indicate that the geothermal resources in an area are capable of supporting commercial generation

of electricity, it is possible that no such geothermal resources will be found in an area of interest and exploration activities will be abandoned. In this case, capitalized exploration and development costs would be expensed.

We generally reach a determination of economic feasibility based on a process that involves an evaluation of historic geologic and geothermal information, creation of a digital spatial database containing relevant technical information, assessment of other relevant information such as available infrastructure and natural- and man made- features. Following the acquisition of land rights, we conduct further various studies and surveys, including water and soil analyses, and we augment our database with the results of these studies. We then initiate a suite of geophysical surveys to assess the resource and determine drilling locations.”

•

We note on page 20 that you do not expect to succeed in developing every resource that undergoes exploration activity and will cease exploration activities that will not support commercial operations. Please provide us with more information about your projects that do not achieve economic feasibility, including explaining to us the factors that would trigger this conclusion and quantifying for us the number of projects that you determined did not achieve economic feasibility in each of the fiscal years covered in this report.

We expect that, of our many prospects, a certain portion will not support commercial operations due to the lack of sufficiently high temperature, the lack of permeability or both. There have been three prospects that we have determined will not support commercial operations during the years covered by our 2008 Annual Report. In all three cases, the geochemical and/or geophysical information was good, but, upon drilling of slim holes, commercial temperatures were not encountered. Thus, during 2008, we decided to focus our exploration and development activities on other projects and not to pursue further exploration or development of these sites at this time. As discussed on page 30, unsuccessful drilling within an area of interest is considered an impairment triggering event. Please refer to a discussion of how we test our exploration and development projects for impairment under SFAS No. 144 on page 30.

•

Please tell us and consider disclosing the total amount of exploration, drilling and development costs expensed for each period in which a statement of operations and comprehensive income is presented and the line item that these costs are included in.

Please see our response, beginning on page 32, to the Staff’s comment above concerning our disclosures at the top of page 76 of our 2008 Annual Report.

•

For each project under development listed on page 11, please provide us with a rollforward of the costs capitalized for each project, including any write-offs. Regarding the Carson Lake project, if you continue to have capitalized costs recorded for this project, please tell us your basis for these costs given your exploration has shown that the deep resource cannot support a commercial project.

Below is a rollforward table of all costs capitalized for the exploration projects under development listed on page 11 of our 2008 Annual Report, which are included in the consolidated

Confidential Treatment Requested by Ormat Technologies, Inc.

balance sheets during the years ended December 31, 2008, 2007 and 2006 (the amounts are presented in thousands):⁹

McGinness Hills

Imperial Valley

Carson Lake

Balance January 1, 2006

[***

]

[***

]

[***

]

Change in 2006

[***

]

[***

]

[***

]

Balance December 31, 2006

[***

]

[***

]

[***

]

Change in 2007

[***

]

[***

]

[***

]

Balance December 31, 2007

[***

]

[***

]

[***

]

Change in 2008

[***

]

[***

]

[***

]

Balance December 31, 2008

[***

]

[***

]

[***

]

With respect to the Carson Lake project, our geothermal resource includes deep and shallow resources. Although we have determined that the deep resource will likely not support a commercial power plant, we are pursuing exploration of the shallow resource at that site. It should be emphasized that our exploratory drilling of the deep resource uncovered the shallow resource. We identified the shallow resource as we were drilling through the shallow zone. After concluding that the deep well is non-commercial, we perforated the well at the shallow resource and found low temperature water in abundant quantities. We continue to believe that the resource is probable of supporting commercial operations and, therefore, consistent with our capitalization policy described above, we have continued to capitalize our development costs related to this project.

Earnings per share, page 111

19.

Please present a reconciliation of the numerators and denominators of your basic and diluted earning-per-share computations, consistent with the guidance in paragraph40(a) of SFAS 128, or tell us why you do not believe a reconciliation is required. Also, please disclose the number of stock options that could potentially dilute basic earnings per share in the future and were not included in the computation of diluted earnings per share because to do would have been antidilutive. Refer to paragraph40(c) of SFAS 128.

We do not have any other equity securities that could potentially dilute basic earnings per share, except for employee stock options. Accordingly, no reconciliation is needed for the numerator because the net income used for calculating basic and diluted earnings per share is the same.

The table below shows the reconciliation of the denominator of our basic and diluted earnings-per-share computations:


⁹		The Mammoth and Sarulla projects are not included in our consolidated balance sheets and, therefore, we have not included this information for those projects in the table below.


	Year Ended December 31,
	2008		2007		2006
	(in thousands)
Weighted average number of shares used in computation of basic earnings per share		44,182		38,762		34,593
Add:
Additional shares from the assumed exercise of employee stock options		116		118		114

Weighted average number of shares used in computation of diluted earnings per share		44,298		38,880		34,707

The number of stock options that could potentially dilute future earnings per share and were not included in the computation of diluted earnings per share because to do so would have been antidilutive, was 875,648, 661,312 and 327,088, respectively, for the years ended December 31, 2008, 2007 and 2006.

Because these amounts are immaterial, we did not include the disclosures in our financial statements. To enhance our disclosures, however, we will include the information above in future filings.

Note 10 — Long-Term Debt and Credit Agreements, page 123

20.

We note your disclosures here and in the first risk factor on page 59 that the debt agreements of certain of your subsidiaries contain restrictive covenants that may limit the ability of your subsidiaries to pay dividends to you. Please tell us how you considered the guidance in Rules 5-04 and 4-08(e)(3) of Regulation S-X when concluding that you did not need to provide Schedule I — Condensed Financial Information of Registrant. Also refer to SAB Topic 6.K.2.

We considered the guidance in Rule 4-08(e)(3) of Regulation S-X (“Rule 4-08(e)(3)”) which requires certain disclosures in the financial statements when “the restricted net assets of consolidated and unconsolidated subsidiaries and the parent’s equity in the undistributed earnings of 50 percent or less owned persons accounted for by the equity method together exceed 25 percent of consolidated net assets as of the end of the most recently completed fiscal year.” We also considered the interpretive guidance in SAB Topic 6.K.2. For purposes of the test, minority interests are not included in the computation of net assets. As disclosed in Note 10 of the 2008 financial statements and in the risk factor on page 59 of our 2008 Annual Report, the debt agreements of certain of our subsidiaries contain restrictive covenants that may limit the ability of our subsidiaries to pay dividends to us. In addition, a portion of the net assets of our wholly-owned subsidiary in Hawaii, Puna Geothermal Ventures, is restricted under the terms of certain lease agreements. The sum of the restricted net assets of our subsidiaries and our equity in the undistributed earnings of our 50 percent or less owned investments was less than 25% of our consolidated net assets (after deducting our minority interests) as of December 31, 2008. Accordingly, we did not include the disclosures required by Rule 4-08-(e)(3) in our 2008 financial statements.

In addition, Rule 5-04 of Regulation S-X (“Rule 5-04”) requires a schedule prescribed by Rule 12-04 of Regulation S-X when “restricted net assets (Rule 4-08(e)(3)) of consolidated subsidiaries exceed 25 percent of consolidated net assets as of the end of the most recently completed fiscal year.” The restricted net assets of our subsidiaries were less than 25% of our consolidated net assets

(excluding our minority interests) as of December 31, 2008. Accordingly we did not include Schedule I — Condensed Financial Information of Registrant in our 2008 Annual Report.

Note 12 — OPC Tax Monetization Transaction, page 128

21.

We note that you entered into agreements with affiliates of Morgan Stanley & Co. Incorporated and Lehman Brothers Inc., under which those investors have purchased, for cash, interests in a newly formed subsidiary of Ormat Nevada, OPC LLC (“OPC”), entitling the investors to certain tax benefits (such as production tax credits and accelerated depreciation) and distributable cash associated with four geothermal projects. We also note that you will continue to operate and maintain the projects and will receive initially all of the distributable cash flow generated by the projects until you recover the capital that you have invested in the projects, while the investors will receive substantially all of the production tax credits and the taxable income or loss, and the distributable cash flow after you have recovered your capital. We further note that you retain the controlling voting interest in OPC and therefore will continue to consolidate OPC throughout the life of the agreement, and that you have the option to buy out the investors’ remaining interest in OPC following the flip date. To help us better understand your accounting, please respond to the following comments:

	•		We assume from your disclosures that you determined that you should account for OPC based on a voting interest model rather than a variable interest model. Please confirm our assumption, or explain this matter to us in more detail. If you are consolidating OPC based on your voting interest, please tell us and revise your disclosure to better explain what your voting rights are related to this entity as compared to the voting rights of the other investors.

	•		We note that you accounted for this transaction as a financing. Please explain to us in more detail why you consider this transaction to be a financing and the authoritative accounting literature that you are relying upon in accounting for this transaction. If not clear from your response, provide us with your analysis under SFAS 95 to support reflecting your sale of interests in OPC to the third-party investors as financing activities.

	•		Please explain to us in reasonable detail how you calculate the earnings or loss allocation to the minority interest holders as reflected on your statement of operations. In this regard, we note your disclosure that interest expense, representing the investors’ targeted yield on the balance of their investment, is charged to minority interest. Please explain to us why the investors’ yield is deemed to be interest expense. Also tell us what other items are included in minority interest on your statement of operations, including how you consider tax benefits in determining minority interest. Please revise your disclosure to better explain how the minority interest allocation is determined.

In response to the Staff’s comment, we supplementally advise the Staff as follows:

•

We assume from your disclosures that you determined that you should account for OPC based on a voting interest model rather than a variable interest model. Please confirm our assumption, or explain this matter to us in more detail. If you are consolidating OPC based on your voting interest, please tell us and revise your disclosure to better

explain what your voting rights are related to this entity as compared to the voting rights of the other investors.

We confirm that we account for OPC based on a voting interest model. Our voting rights in OPC are based on a capital structure that is comprised of Class A and Class B membership units. We own, through our subsidiary, Ormat Nevada, all of the Class A membership units, which represent 75% of the voting rights in OPC. The investors own all of the Class B membership units, which represent 25% of the voting rights of OPC. Under the OPC LLC Agreement, most operational decisions in OPC are decided by the vote of a majority of the membership units. Certain major decisions, as defined, require a super majority vote of the members (i.e., 85% of the vote). Accounting Research Bulletin No. 51,Consolidated Financial Statements(“ARB 51”), affirms that consolidation is appropriate when one entity has a controlling financial interest in another entity and that the usual condition for a controlling financial interest is ownership of a majority voting interest. ARB 51 also acknowledges that in some circumstances, control may not rest with the majority owner. EITF 04-5 provides guidance for consolidation when a limited partner has certain rights. The EIFT applies to limited partnerships or similar entities that have governing provisions similar to a limited partnership. Because the structure and terms of OPC are similar to that of a limited partnership, we have applied the guidance in EITF 04-5 to the OPC Tax Monetization Transaction.

The consensus reached in EITF No. 04-5 was that the general partners are presumed to control a limited partnership unless the limited partners have either (a) the substantive ability to liquidate the limited partnership or otherwise remove the general partners without cause or (b) substantive participating rights. Protective rights would not overcome the presumption of consolidation.

In the OPC Tax Monetization Transaction, no member has a right to voluntarily resign or otherwise withdraw from the LLC without a super majority vote of the remaining members and no member may be removed without cause. In addition, dissolution of the LLC prior to the termination date set forth in the LLC Agreement requires a super majority vote of the members. The withdrawal of any member from the LLC will not result in the dissolution of the LLC. Based on these factors, we believe that the investors do not have the substantive ability to dissolve the LLC or otherwise remove Ormat Nevada without cause.

EITF 04-5 distinguishes between participating rights and protective rights. Paragraph 14 of EITF 04-5 sets forth actions that if permitted to be blocked by the limited partners would be considered protective rather than participating rights. Our consideration of whether the investors’ rights would be considered protective rather than participating was based on the following factors:

	•		While the investors have certain rights that could be considered substantive participating rights (e.g., hiring employees, setting compensation and bonuses, and approval over certain transactions), the management, operations and administration of OPC are performed under contract by Ormat Nevada. Ormat Nevada is outside of the investors’ control and OPC does not have any employees. As such, this right does not result in the investors having substantive decision making participation. The investors also have approval over certain transactions. However, these transactions are not expected to occur in the ordinary course of business. Examples of such transactions include the sale of OPC assets with a fair market value in excess of $2 million, incurrence or guarantee of debt in excess of $4 million, and settlement of legal matters for amounts in excess of $4 million, among others.

	•		The investors have the right to veto the annual operating budget until the Flip Date only if the aggregate expense amount has increased by more than 10% over the budgeted expense amount reflected in the prior year’s annual budget. If the investors do not approve the budget, it reverts to a 10% increase over the budgeted expense amount reflected in the prior year’s annual budget. Therefore, the right of the investors to veto the annual operating budget in these circumstances is not considered a substantive participating right.

	•		On the Flip Date (as defined in Note 12), Ormat Nevada’s economic and voting interest will increase to 95% while the investors’ economic and voting interest will decrease to 5%. Following the Flip Date, the respective rights of the Class A and Class B membership units will be allocated on the basis of their voting rights.

Based on the considerations described above, we believe that the investors’ rights are more protective than participative and do not overcome the presumption of consolidation contained in ARB 51.

We intend to revise our disclosure in future filings to better describe our voting rights related to OPC as compared to the other investors by adding the following to our existing disclosure:

“The Company’s voting rights in OPC are based on a capital structure that is comprised of Class A and Class B membership units. The Company owns, through its subsidiary, Ormat Nevada, all of the Class A membership units, which represent 75% of the voting rights in OPC. The investors own all of the Class B membership units, which represent 25% of the voting rights of OPC. Other than in respect of customary protective rights, all operational decisions in OPC are decided by the vote of a majority of the membership units. Following the Flip Date, Ormat Nevada’s voting rights will increase to 95% and the investor’s voting rights will decrease to 5%. Ormat Nevada retains the controlling voting interest in OPC both before and after the Flip Date and therefore has continued to consolidate OPC.”

•

We note that you accounted for this transaction as a financing. Please explain to us in more detail why you consider this transaction to be a financing and the authoritative accounting literature that you are relying upon in accounting for this transaction. If not clear from your response, provide us with your analysis under SFAS 95 to support reflecting your sale of interests in OPC to the third-party investors as financing activities.

We accounted for the OPC Tax Monetization Transaction as a financing based on the guidance in EITF No. 88-18, Sales of Future Revenues (“EITF 88-18”). EITF No. 88-18 relates to an issue where “an enterprise 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. It is assumed that immediate income recognition is not appropriate due to the facts and circumstances...”

We believe the issue in EITF No. 88-18 is relevant for certain of the characteristics in the OPC Tax Monetization Transaction. In the OPC Tax Monetization Transaction, the investors acquired through a cash transaction an interest in OPC through a purchase of Class B membership units from Ormat Nevada. The investors’ interest will provide them with production tax credits

generated by the facilities, operating tax gains or losses from plant operations, as well as cash once the capital account of Ormat Nevada is reduced to zero. The investors’ return is capped by the return stipulated in the agreements. In the transaction, the investors receive a contractually agreed upon percentage/allocation of the tax benefits. The investors will realize “cash” from the tax benefits solely through reduction of their own current tax liability but only if and to the extent the investors have taxable income from sources other than the geothermal facilities to offset. The investors retain all risk for monetizing their share of the tax benefits. There is no recourse to Ormat Nevada to recover the cash if the investors are unable to monetize the tax benefits.

The first issue deliberated by the Task Force in EITF 88-18 was whether the enterprise should classify the proceeds from the investor as debt or deferred income. The Task Force reached a consensus on this issue that any one of the following factors creates a rebuttable presumption that classification as debt is appropriate:

1. The transaction does not purport to be a sale (that is, the form of the transaction is debt).

2. The enterprise has significant continuing involvement in the generation of the cash flows due the investor (for example, active involvement in the generation of the operating revenues of a product line, subsidiary, or business segment).

3. The transaction is cancelable by either the enterprise or the investor through payment of a lump sum or other transfer of assets by the enterprise.

4. The investor’s rate of return is implicitly or explicitly limited by the terms of the transaction.

5. Variations in the enterprise’s revenue or income underlying the transaction have only a trifling impact on the investor’s rate of return.

6. The investor has any recourse to the enterprise relating to the payments due the investor.

We have concluded that the proceeds from the investors should be classified as debt because Ormat Nevada has significant continuing involvement in the generation of the cash flows and production tax credits due the investors as they are responsible for operating the geothermal plants and generating cash flow to the investors (Factor #2). In addition, the investors’ rate of return is limited by the terms of the transaction. Once the investors have received a stipulated internal rate of return, the interest in earnings of the plants substantially reverts back to Ormat Nevada (Factor #4).

Given that the presence of any of the above criteria creates a rebuttable presumption of debt classification, we believe the transaction qualifies for treatment of debt under EITF 88-18. However, it is also noted that this transaction does not fit directly into an EITF 88-18 model given the transaction is structured as a purchase of an equity interest. As such, before the adoption of SFAS No. 160,Noncontrolling Interest in Consolidated financial Statements — an amendment of ARB No. 51(“SFAS No. 160”), we believed a minority interest classification of what would otherwise be debt under EITF 88-18 was an acceptable presentation. Please refer to our response to Comment No. 27 for a discussion of the impact of adopting SFAS No. 160.

•

Please explain to us in reasonable detail how you calculate the earnings or loss allocation to the minority interest holders as reflected on your statement of operations. In this

regard, we note your disclosure that interest expense, representing the investors’ targeted yield on the balance of their investment, is charged to minority interest. Please explain to us why the investors’ yield is deemed to be interest expense. Also tell us what other items are included in minority interest on your statement of operations, including how you consider tax benefits in determining minority interest. Please revise your disclosure to better explain how the minority interest allocation is determined.

We follow a debt attribution model. The minority interest on the consolidated statement of operations reflects the effect of reducing the debt to the investors through the realization of production tax credits and other tax related items offset by the interest component of the transaction which is treated as a financing pursuant to EITF 88-18. OPC will also make cash payments to the Class B Members once Ormat Nevada recovers its capital. These payments will be reflected as a direct reduction to the minority interest recorded on the consolidated balance sheet. The following table highlights the components of amounts recorded as minority interest on the consolidated statement of operations for the years ended December 31, 2008 and 2007:


	Year Ended December 31,
	2008			2007
	(in thousands)

Recognition of tax benefits allocted to investors (1)	$	18,307		$	6,494
Interest on cash received from investors (2)		(7,441	)		(2,762	)
Net loss attributable to noncontrolling interest (3)		300			150

	$	11,166		$	3,882


(1)		Represents the value of production tax credits and taxable income or loss generated by OPC allocated to the Class B Members in accordance with the OPC agreements.

(2)		Represents interest expense using the Class B Members’ targeted yield on the balance of the amount paid by them and amortization of transaction costs using the effective interest method.

(3)		Represents allocation of net loss on the 5% residual to the Class B Members (see further discussion in response to Comment No. 27).

Please note that upon adoption of SFAS No. 160, the unamortized liability associated with the sale of equity interests in OPC was reclassified to non-current liabilities. Please refer to our response to Comment No. 27 for a discussion of the impact of adopting SFAS No. 160 and our proposed disclosure of the allocation of net income/loss to noncontrolling interest.

Note 14 — Stock-Based Compensation, page 130

Stock Option Plans, page 131

The 2004 Incentive Compensation Plan, page 131

22.

Since options granted under your 2004 incentive compensation plan fully vest in 48 months and expire 10 years from the grant date, please tell us why, as of December 31, 2008, there are options outstanding with a weighed average remaining contractual life of less than 6 years that are not shown as exercisable in your table on page 132. Refer to paragraph A240.d of SFAS 123(R).

Options with an exercise price which exceeds the market price of our shares as of December 31, 2008 were not included as exercisable options in the table. We will include all options exercisable in our stock option table in future filings.

Note 19 — Employee Benefit Plan, page 143

Severance plan, page 143

23.

Please explain to us the difference between the total amount of future benefits expected to be paid of $11,980 as seen in your table in the middle of page 144 and the total amount accrued as of December 31, 2008 in the line item “Liabilities for severance pay.”

As explained in Note 19, the amount shown on the balance sheet as “Liabilities for severance pay” represents our liability to our Israeli employees that is accounted for under the guidance of EITF Issue No. 88-1,Determination of Vested Benefit Obligation for a Defined Benefit Pension Plan, using what is commonly referred to as the “shut down” method, where a company records the undiscounted obligation as if it were payable at each balance sheet date. The amount of $11,980 as seen in the table in the middle of page 144 represents the cash amounts expected to be paid in the next ten years following December 31, 2008 upon reaching normal retirement age and is based on the last monthly salary, but includes also amounts to be earned until retirement. Furthermore, the amount of $11,980 stated within the table in the middle of page 144 refers only to those employees that will reach normal retirement age within the next ten years, whereas total amount accrued as of December 31, 2008 in the line item “Liabilities for severance pay” refers to all of our Israeli employees.

Item 9A. Disclosure Controls and Procedures, page 18

24.

We note your disclosure that “the Chief Executive Officer and Chief Financial Officer concluded as of December 31, 2008, that the disclosure controls and procedures are effective in ensuring that all material information required to be filed in this Annual Report on Form 10-K has been recorded, processed, summarized and reported when required and the information is accumulated and communicated, as appropriate, to allow timely decisions regarding required disclosure.” As you have included a portion of the definition of disclosure controls and procedures in your disclosure, you must include the entire definition. Please revise to clarify, if true, that your disclosure controls and procedures are also designed to ensure that information required to be disclosed in the reports that you file or submit under the Exchange Act is accumulated and communicatedto your management, including your chief executive officer and chief financial officer,to allow timely decisions regarding required disclosure. See Exchange Act Rule 13a-15(e). We note that the complete definition was included in the certifications for the Forms 10-Q for the periods ended March 31, 2009 and June 30, 2009.

Future filings will be amended to include the entire definition as included in certifications for the Forms 10-Q for the periods ended March 31, 2009 and June 30, 2009.

Part III

Item 10. Directors and Executive Officers of the Registrant, page 149

Directors and Executive Officers Information, page 149

25.

Please provide Mr. Worenklein’s employment from September 2008 to the present. See Item 401(e) of Regulation S-K.

Mr. Worenklein has not been employed since September 2008. In future filings, we will reflect that Mr. Worenklein retired from U.S. Power in 2008.

Exhibits

Exhibits 31.1 and 31.2

26.

The certifications must correspond exactly to those set forth in Item 601(b)(31) of Regulation S-K. In this regard, in paragraph4(d) you replaced the word “our” with “his/her.” In addition, you did not include the parenthetical in paragraph4(d). We note, however, that these changes were made in the certifications for the Forms 10-Q for the periods ended March 31, 2009 and June 30, 2009. Please advise.

Future filings will be revised to address the Staff comment.

Form 10-Q for the Period Ended June 30, 2009

Note 6 — Noncontrolling Interest, page 16

27.

We note that upon the adoption of SFAS 160, the amount that was previously classified on your balance sheet as minority interest was largely reclassified to a liability account, with only a small portion reclassified to noncontrolling interest with total equity. Similarly, we note that the amount that was previously classified on your statements of operations as minority interest was largely reclassified to non-operating income/expense line items, with only a small portion reclassified to net loss attributable to noncontrolling interest. Please explain to us in more detail why your adoption of SFAS 160 resulted in these reclassifications to liability and non-operating income/expense accounts, including better explaining to us what is represented by these liability and non-operating income/expense items. Also explain to us what is represented by the portion of the amount previously classified as minority interest that was reclassified to noncontrolling interest, and why this received different treatment upon your adoption of SFAS 160.

In response to the Staff’s comment, we supplementally advise the Staff as follows:

Balance Sheet Reclassification

Upon adoption of SFAS No. 160, we considered the following two balance sheet classifications:

(1) Presentation of the existing minority interest balance as a liability.

(2) Presentation of the existing minority interest balance as equity.

We believe the classification as minority interest was acceptable before SFAS No. 160 was adopted. However, upon adoption of SFAS No. 160, given the legal form of the transaction and the mezzanine classification, we did not believe it met the definition to be classified as equity. Therefore, we classified such amounts as a liability rather than equity. This classification is also consistent with the guidance in EITF 88-18.

Income Statement Reclassifications

The adoption of SFAS No. 160 also changed the income statement presentation of amounts relating to the OPC Tax Monetization Transaction. The minority interest income as presented before the adoption of SFAS No. 160 consisted of a financing charge and income related to recognition of tax benefits received by the investors. The financing charge is based on the rate of return stipulated in the agreements.

Consistent with the debt presentation on the balance sheet, we concluded that the finance charge should be included in interest expense on the income statement. In addition, we concluded that the portion related to non-cash attributes, including production tax credits and other favorable tax attributes allocated to the investors, should be recorded in other non-operating income/expense on the consolidated statement of operations because they are unrelated to our operating activities.

Noncontrolling Interest

As noted in our response to Comment No. 21, the Class B membership units are provided with a 5% residual economic interest in OPC. The 5% residual interest is perfected on achievement by the investors of a contractually stipulated return that triggers the Flip Date. The actual Flip Date is not known with certainty and is determined by the operating results of OPC. This residual 5% represents a noncontrolling interest which is “true” equity and is not subject to mandatory redemption or guaranteed payments. Under SFAS No. 160, noncontrolling interests are presented on the balance sheet as a component of equity and therefore we have reclassified the 5% residual minority interest from “minority interest” to “noncontrolling interests” on the balance sheet upon adoption of SFAS No. 160.

We will update our disclosure in the notes to the 2009 consolidated financial statements to include a description of the allocation of income or losses to the noncontrolling interest in OPC.

Form 8-K Filed August 6, 2009

28.

We note your presentation of non-GAAP measures that you call EBITDA and Adjusted EBITDA in your press release. We have the following comments:

	•		Please tell us whether the measures that you call EBITDA and Adjusted EBITDA are performance measures, liquidity measures, or both. Please note that it is only appropriate to reconcile such measures to net income if these are performance measures. Please refer to Question 15 of our Frequently Asked Questions Regarding the Use of Non-GAAP Financial Measures (our Non-GAAP FAQ), available on our website athttp://www.sec.gov/divisions/corpfin/faqs/nongaapfaq.htm.

	•		Additionally, as indicated in Question 15 of our Non-GAAP FAQ, if these are performance measures you also should comply with the disclosure requirements of Question 8 of our Non-GAAP FAQ, and it is unclear to us how your current disclosures

			comply with this guidance. Please provide us with your analysis of how your current disclosures comply with Question 8, including but not limited to how you have met the burden of demonstrating the usefulness of these measures. If these measures are liquidity measures, please disregard this bullet point.

	•		You state that you believe that these measures are used by securities analysts, investors and others to evaluate your ability to service and/or incur debt. Based on this disclosure, it appears that the measures you call EBITDA and Adjusted EBITDA measure your liquidity, not your operating performance. If true, please revise your disclosures to reconcile these measures to cash flows from operating activities and also disclose the balances for cash flows from investing and financing activities, consistent with Question 12 of our Non-GAAP FAQ.

•

We note that the measure you call EBITDA is net income before interest, taxes, depreciation and amortization, equity income of investees and other non-operating expense/income. As indicated in Question 14 of our Non-GAAP FAQ, our adopting release No. 33-8176 defined EBITDA as net income before interest, taxes, depreciation and amortization, and measures that are calculated differently should not be characterized as EBITDA. Please revise your title for this measure accordingly.

In response to the Staff’s comment, we advise the Staff as follows:

	•		The measures that we call EBITDA and Adjusted EBITDA are liquidity measures. We will revise future filings to clarify this terminology.

	•		Since these measures are liquidity measures, we are not responding to the second bullet point.

	•		Since the measures we call EBITDA and Adjusted EBITDA measure our liquidity, not our operating performance, we will revise our disclosures in future filings to reconcile these measures to cash flows from operating activities and we will also disclose the balances for cash flows from investing and financing activities.

	•		We will revise our characterization of EBITDA as “net income before interest, taxes, depreciation and amortization”, and we will use the term Adjusted EBITDA for measures that are calculated differently. We will also provide a reconciliation between EBITDA and Adjusted EBITDA.

Proxy Statement on Schedule 14A

Compensation Discussion and Analysis, page 16

Objectives, page 16

29.

On page 16, you state, “[w]e do not benchmark to a particular industry or companies, but we informally consider published data, such as labor indices, in formulating our executive compensation packages.” On page 17, you indicate that the Compensation Committee provides guidance on base salaries that reflect “the Compensation Committee’s interpretation of competitive compensation averages for individuals with similar

		responsibilities at companies with similar financial, operating and industry characteristics, in similar locations....”

		Please clarify how the Compensation Committee interprets competitive compensation averages if it does not benchmark compensation. Explain how the Committee determines which companies it uses for comparative purposes.

The Compensation Committee has not undertaken or commissioned 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).

Determination of Amounts and Formulas for Compensation, page 17

Annual Bonus, page 18

Group I. page 18

30.

Please describe the “requisite approval process within [your] parent company.”

Our parent company’s approval process for related party transactions 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 shall include at least one third of the shareholders present at the meeting who have no interest in the related party transaction.

Group II. page 18

31.

Please reconcile the following statements made on page 18: “[t]he determination of the amount of the annual bonus paid to each Group II executive is based on a number of factors, including our performance evaluated on specific criteria, such as revenue growth, profitability, and attainment of short-term and strategic business goals, in relation to individual executive performance” and “[t]here are no specific metrics for such evaluation, which is based on our CEO’s and Chairman’s subjective determination of both the individual performance of each NEO and the performance of the NEOs as a group.” Clarify whether targets are set for the specific criteria. Please also provide the bases on which the CEO’s and Chairman’s subjective determinations are made.

The determination of the amount of an annual bonus is based on 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 by the CEO and Chairman of each executive’s performance and contribution to these results along with our other executives. We do not generally set quantifiable targets for measuring each individual executive’s performance against these specific performance results. Rather, as the CEO and the Chairman are intimately involved in our day-to-day activities and our officers, they have the knowledge to make a subjective determination regarding each executive’s performance and the extent to which the executive’s performance contributed to the achievement of these results. No fixed criteria are used in making these

determinations. We believe that this description is accurate and does not contain any inconsistency that needs to be reconciled for fair disclosure.

Stock Options, page 19

32.

Please disclose whether you have established targets for Company performance and stockholder return in determining a named executive officer’s stock option award.

Specific quantitative targets have not been established for the allocation of the basket of options to Group II executives and this will be disclosed in future filings.

33.

Please provide the basis for determining the named executive officer’s contribution to the Company’s growth and success.

The CEO and the Chairman are intimately involved in our day-to-day activities and our officers. With this knowledge, the CEO and Chairman make a subjective determination of the individual’s contribution to our growth and success. No specific criteria are used.

Transactions with Related Persons, page 32

34.

We note your discussion regarding approval of related party transactions on page 35, but we also note that some of your related party transactions were entered into in prior periods. Please indicate whether each of the transactions is on terms that are at least as favorable to the company as would have been obtained in an arm’s length transaction.

We confirm that each of the transactions is on terms that are at least as favorable to us as would have been obtained in an arm’s length transaction.

* * * * * *

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.

VIAEDGARANDBYHAND

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.

Exhibit A

Permit Status

Our projects are required to comply with numerous domestic and foreign federal, regional, state and local statutory and regulatory environmental standards and to maintain numerous environmental permits and governmental approvals that are required for their operation. Some of the environmental permits and governmental approvals that have been issued to the projects contain conditions and restrictions, including restrictions or limits on emissions and discharges of pollutants and contaminants, or may have limited terms.

For example, while our power generation operations produce electricity without emissions of certain pollutants such as nitrogen oxide, and with far lower emissions of other pollutants such as carbon dioxide, some of our projects do emit air pollutants in quantities that are subject to regulation under applicable environmental air pollution laws. Such operations typically require air permits. Especially critical to our geothermal operations are those permits and standards applicable to the construction and operation of geothermal wells and brine reinjection wells. In the United States, injection wells are regulated under the federal Safe Drinking Water Act Underground Injection Control, which we refer to as UIC, program. Because fluids are reinjected to enhance utilization of

US environmental permitting regimes with respect to geothermal projects center upon several general areas of focus. The first involves land use approvals. These may take the form of Special Use Permits or Conditional Use Permits from local planning authorities or a series of development and utilization plan approvals and right of way approvals where the geothermal facility is entirely or partly on BLM or U.S. Forest Service (USFS) lands. Certain federal approvals require a review of environmental impacts in conformance with the federal National Environmental Policy Act (NEPA). In California, some local permit approvals require a similar review of environmental impacts under a state statute known as the California Environmental Quality Act (CEQA). These federal and local land use approvals typically impose conditions and restrictions on the scope and operation of the geothermal projects.

Our operations are designed and conducted to comply with applicable permit requirements. Non-compliance with any such requirements could result in fines or other penalties. We are not aware of any non-compliance with such requirements that would be likely to result in material fines or penalties. However, the Heber 1 and 2 projects received a notice from the California Division of Oil, Gas and Geothermal Resources that the pressure levels at some of the geothermal fluid injection wells were too high.(2) production wells to extract the hot geothermal liquids (also known as brine) for the power plant, and (3) injection wells to reinject the brine back into the subsurface resource. In Nevada and on BLM lands, the well permits take the form of geothermal drilling permits for well installation. Approvals are also required to modify wells, including for use as production or injections wells. Those wells in Nevada to be used for injection will also require Underground Injection Control Permits from the Nevada Division of Environmental Protection. Geothermal wells on private lands in California require drilling permits from the California

A-1

Department of Conservation’s Division of Oil, Gas, and Geothermal Resources (DOGGR). The eventual designation of these installed wells as individual production or injection wells and the ultimate closure of any wells is also reviewed and approved by DOGGR pursuant to a DOGGR-approved Geothermal Injection Program.

A fourth level of permits, that are required in both California and Nevada, include ministerial permits such as hazardous materials storage and management permits and pressure vessel operating permits. We are also required to obtain water rights permits in Nevada and may be required to obtain groundwater permits in California to use groundwater resources for makeup water. In addition to permits, there are various regulatory plans and programs that are required, including risk management plans (federal and state programs) and hazardous materials management plans (in California).

As of the date of this~~annual~~ report, all of the materialenvironmentalpermits and approvals currently required~~to operate~~for our projects have been obtained~~and are currently valid. As of the date of this annual report, we have obtained and are in compliance with all of the material~~. Although there are some environmental permits and approvals~~currently required for our projects that are under construction or enhancement. There are some permits that need to be obtained~~that will be required in the future.We, we believethatwe will be able to obtain thoseenvironmentalpermits and approvals without material delay and without incurring additional material costs.

Our operations are designed and conducted to comply with applicableenvironmental permit and approval requirements.Non-compliance with any such requirements could result in fines or other penalties.

Environmental Laws and Regulations

A-2

~~Geothermal~~Our operations~~can produce~~involve significant quantities of brine~~and scale, which builds up on metal surfaces in our equipment with which the brine comes into contact. These wastematerials, some of which are currently reinjected into the subsurface,~~(substantially all of which we reinject into the subsurface) and scale, both of which can contain materials (such as arsenic, lead and naturally occurring radioactive materials) in concentrations that exceed regulatory limits used to define hazardous waste. We also use various substances, including isopentane, and industrial lubricants, that could become potential contaminants and are generally flammable. Hazardous materials are also used~~and generated in connection with~~in our equipment manufacturing operations in Israel. As a result, our projects are subject to~~numerous~~ domestic and foreign federal, state and local statutory and regulatory~~standards relating to~~requirements regarding the use, storage, fugitive emissions and disposal of hazardous substances. The cost of~~any investigation,~~ remediation~~and/or cleanup~~ activities~~in connection~~associated with a spill or~~other~~ release of such~~contaminants~~materials could be significant.

Although we are not aware of any mismanagement of these materials, including any mismanagement prior to the acquisition of some of our projects, that has materially impaired any of the project sites, any disposal or release of these materials ontothe project sites, other than by means of permitted injection wells, could lead to contamination of the environment and result in material cleanup requirements~~or other~~of responsive obligations under applicable environmental laws. We believe that at one time there may have been a gas station located on the Mammoth project site (which we lease), but because of significant surface disturbance and construction since that time further physical evaluation of the environmental condition of theof theformer gas station site has been impractical. We believe that, given the subsequent surface disturbance and construction activity in the vicinity of the suspected location of the service station, it is likely that environmental contamination, if any, associated with the former facilities and any associated underground storage tanks would have already been encountered if they still existed.

A-3

Exhibit B

Sample Map

B-1

Exhibit C

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.

Access to Property:		Direct access to public roads from leased property and access across leased property under surface rights granted pursuant to the leases.

C-1


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 Tax Monetization 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.

C-2

Exhibit D

Sample Template (construction-stage project): McGinness Hills


Location:	Lander County, Nevada

Projected Generating Capacity:	(est.) 24-36 MW

Projected Technology:	Binary system.

Plant and Equipment:	The following is a general summary of the material plant and equipment currently used at this project.

Subsurface Improvements:	One production well completed and tested.

Material Equipment:	Drilling equipment for wells.

Condition:	In construction since the summer of 2009. Basic well field site preparation has been completed. Permits to drill have been obtained. One production well drilled. Drilling for an additional well has begun. We expect to drill one additional well before we complete the engineering of the power plant and apply for construction permits.

Land and Mineral Rights:	Leases from BLM for approximately 5,120 contiguous acres. The leases are currently held by payment of annual rentals, as described in “Description of Our Geothermal Leases”. Unless steam is produced in commercial quantities, the primary term for these leases will expire as follows:

	Expiration Date	Acreage Affected

	September 30, 2017		5,120

	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”.

Resource Information:	The expected average temperature of the resource cannot be estimated as only one production well has been drilled.

Access to Property:	Direct access to public roads from leased property and access across leased property under surface rights granted in leases from BLM.

Power Purchaser:	Negotiations of a power purchase agreement are underway with Nevada Power Company.

D-1

D-2

Power Contract Expiration Date:

Expected to be 20 years after date of commercial operation.

Financing:

General corporate funds.

Supplemental Information:

Commercial operation of the power plant is expected in 2012.