Ormat CORRESP Correspondence 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 OMITTED INFORMATION HAS BEEN REPLACED BY [***].

January 13, 2010

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


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

Dear Mr. Owings:

Ormat Technologies, Inc. (the “Company”) acknowledges receipt of the letter dated December 29, 2009 (the “Staff Letter”) from the staff (the “Staff”) of the Division of Corporation Finance of the United States Securities and Exchange Commission (the “SEC”). Set forth below are the Staff’s comments contained in the Staff Letter (in bold face type) followed by our responses.

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

General

We received your letter dated December 21, 2009 that was provided to us via email. Please file this letter as correspondence on EDGAR.

We confirm that we have filed our letter dated December 21, 2009 as correspondence on EDGAR, together with a request for confidential treatment of the areas of interest map attached to that letter.

Financial Statements and Supplementary Data, page 98

Notes to Consolidated Financial Statements, page 104

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

Note 1 — Business and Significant Accounting Policies, page 104

Exploration and drilling costs, page 108

We received the map that illustrates your projects in each area of interest. We understand from previous correspondence that you determine areas of interest by: 1) the geographical proximity of the geothermal resources and their proximity to the same electricity grid, and in certain cases, a common transmission line; 2) the ability to allocate a power purchase agreement to alternate resources in the same geographical area, and; 3) your intention to operate all the power plants in the same area of interest as one complex. Please help us further understand how you decide to assign a project to a particular area of interest. For example, we note that Tungsten Mountain is in area of interest 1. Tell us how and why you determined that this project should be in area of interest 1 and not in area of interest 2 or 3. Similarly, tell us why Smith Creek is in area of interest 3 and not in area of interest 1. As part of your explanation, you may find it useful to provide us with a map that shows the electricity grids in Nevada superimposed to your projects and areas of interest.

We apply the factors outlined in our prior responses to allocate exploration sites within areas of interest:

	•		on a case by case basis

	•		based on known facts and circumstances

	•		without any pre-determined weighting or relative importance assigned to any one of those factors

	•		without any pre-determined minimum number or combination of factors required to determine the outcome.

In some cases, one or more factors may dictate a particular result. More often, however, this involves making business judgments where available information may be limited, subject to change and capable of leading to more than one conclusion. Tungsten Mountain and Smith Creek are examples of this:

	•		The geographic locations of these sites were basically a neutral factor, so these sites could have been assigned to any area of interest.

	•		The proximity of these sites to any electricity grid or common transmission line also was not outcome determinative given the location of the power grid relative to these locations.

	•		Any operating power plants that might be constructed at these sites probably could be operated and maintained from central control rooms and by support staff based in any nearby area of interest, although as described below there were factors that made some potential groupings more attractive from a management and cost perspective than others, based on then-available information.

Accordingly, our management made the following decisions based on available information:

•

Tungsten Mountain was put in area of interest 1, rather than areas of interest 2 or 3, primarily because that allocation gave area of interest 1 the potential to become a four-plant power complex (taking into account our decision not to develop the Buffalo Valley and Grass Valley sites in area of interest 1). That decision gave area of interest 1 the same basic potential “footprint” for future operations as the potential four-plant complexes in areas of interest 2 and 3 (before we abandoned the Rock Hill site in area of interest 3). Of course, four is not a “magic” number for managing geothermal power complexes. However, we think that when geography, road access, technology and other factors permit groupings like this, it makes business sense to have somewhat larger complexes than we now have, where a few plants, often sharing the same geothermal resource, make up our current complexes. Thus, we currently look at each area of interest for exploration as potentially becoming a single complex to manage any resulting power plants, at least initially.¹ The business reasons for this approach are relatively straightforward:

	o		For operating power plants, the most significant cash outflow is operating and maintenance (“O&M”) expense, mostly labor costs, as described below.

	o		Many of these costs (e.g., control room personnel) can be shared among several power plants, as described in more detail below.

	o		For small megawatt power plants this cost savings can be the difference between making a profit or not. For example, if it turns out, after exploration, that a geothermal resource can only support, say, a 15 megawatt facility rather than a 25 megawatt facility initially estimated, we might conclude that the expected revenues from its energy sales would not justify a stand-alone plant and only proceed if that plant could share O&M costs with other plants as part of a complex.

•

Smith Creek was put in area of interest 3, rather than area of interest 1, for reasons similar to those described above for Tungsten Mountain.

As requested, attached hereto asExhibit A is a map showing the Nevada electricity grid associated with our three areas of interest for the Staff’s information. However, as described above, it was not a determinative factor in our decisions concerning Tungsten Mountain or Smith Creek, among other sites in these areas of interest.

Please tell us whether you considered having more or less than three areas of interest. Since areas of interest appear to be partially based on management’s decision, please elaborate on how you determined that three areas of interest was the appropriate number to have and why. Furthermore, please tell us whether any project has been moved out of one area of interest to another and why.

We have considered having more or less than three areas of interest in Nevada. As we noted in our prior responses to Staff comments, we considered, among other things, having Nevada be a single area of interest. The factors we considered in determining that three areas of interest was the


¹		Depending on the results of exploration and development, acquisition of new sites and other factors, changes might be made in sites allocated to areas of interest (as described in our response to Staff Comment No. 3).

appropriate number are those set forth in our prior responses to Staff comments. That is, the geographical proximity of the geothermal resources and their proximity to the same electricity grid, the use of, in certain cases, a common transmission line, the ability to allocate (in some cases) a power purchase agreement to alternate resources in the same geographical area, and our intention to operate all the power plants in the same area of interest together as one complex.

The Staff is correct that determining both the number of areas of interest and the projects included in an area of interest involve management decision making. Our management has considerable experience in the geothermal power industry, and these areas of interest reflect its business judgment concerning the most effective method for us to manage our activities under the current circumstances and the facts currently known. If circumstances change, we may have more or fewer areas of interest, and exploration projects could be assigned to new or other areas of interest. For example, it is possible that we may split an existing area of interest into two. This might occur, for example, if the number of potential and/or operating plants in an area increased (or other factors described above change) so that it makes more sense to manage or operate the plants in two separate areas of interest. As we acquire new exploration sites, we may decide to:

	•		add them to existing areas of interest (as we did with Tungsten Mountain when we acquired it in September 2009), or

	•		create new areas of interest, such as by combining the newly acquired sites with other sites not yet explored or developed where we think any operating plants that might be developed from those sites should be managed as part of a complex, as described in our response to Staff Comment No. 2 above.

To date, only one exploration site has been moved from one area of interest to another. That was the Dixie site, which was moved (before the start of exploration work) from area of interest 3 to area of interest 2, because its proximity to our other exploration sites in area of interest 2 facilitates operating it as a part of a complex with the other potential sites in that area of interest.

Please tell us whether your operating power plants continue to be considered part of an area of interest for impairment testing purposes. If operational power plants are no longer within an area of interest, please tell us how you allocated capitalized exploration and development costs from the area of interest to the power plant at the time it became operational. For example, based on the map in your December 21, 2009 letter to us, we assume the Brady and Desert Peak power plants were in area of interest 2 while these projects were in the exploration and development phase. When you determined that you would construct a power plant, explain to us how you allocated a portion of the exploration and development costs related to area of interest 2 to the Brady and Desert Peak complex.

Any operating power plants that result from exploration sites in an area of interest normally will continue to be part of that area of interest for impairment testing purposes, as described below.² None


²		As noted above, our intent is to operate all of the plants resulting from exploration sites in an area of interest as part of a single complex, to the extent feasible. To the extent this occurs, our operating complexes will often cover a broader geographic area than our current complexes, which are typically adjacent power plants that may share the same geothermal resource.

of our existing power plants in Nevada had been part of any area of interest during its exploration phase, since the initial power plant in each complex was acquired as an operating facility, and was not developed as a result of our own exploration activities.³ Based on each facility’s operating experience we developed additional power plants in the same complex. With respect to the Staff’s comments concerning the Brady and Desert Peak power plants, we remind the Staff that we acquired the Brady project — consisting of the Brady plant and the Desert Peak 1 plant — in June 2001 as an already-operating complex. Desert Peak 1 was shut down in the second half of 2006 for the reasons described in our 2006 Annual Report on Form 10-K (p. 26). Desert Peak 2 was constructed by us at a nearby site, commenced commercial operations in the first quarter of 2007, and became part of the Brady complex, as described in our 2007 Annual Report on Form 10-K (p. 27). We did not conduct exploration activities for the Desert Peak 2 plant because it was a proven geothermal resource that had been used by Desert Peak 1.

Consequently, we have not as yet allocated capitalized exploration and development costs from our areas of interest to any resulting power plant. Three of our exploration projects are in the beginning stages of construction — Jersey Valley, McGinness Hills and Carson Lake. We currently anticipate that construction of the Jersey Valley plant will be the first of our exploration projects to become operational. When this occurs, we expect that capitalized exploration costs related to the unsuccessful projects within area of interest 1 (e.g., Buffalo Valley and Grass Valley), together with the Jersey Valley plant costs, will be depreciated over the estimated useful life of the Jersey Valley plant.

Capitalized costs associated with projects that are still in the exploration or development stage within area of interest 1 (e.g., McGinness Hills and Leach Hot Springs) will remain in construction-in-process until either development and construction of a plant is complete or a decision is made to abandon the site. If and when we have more than one operational plant within an area of interest, we expect to include any then-unallocated capitalized costs associated with unsuccessful exploration projects to each of the operational plants on a pro rata basis (e.g., based on capacity of the plants) when a decision is made to abandon the site.

We intend to follow the approach outlined above at each of our areas of interest.

Please see our response to Staff Comment No. 5 for additional information about how we test our exploration projects for impairment in an area of interest.

We note that you group your exploration projects into areas of interest and that you consider each area of interest to be an asset group that represents the lowest level for which identifiable cash flows arelargely independent of the cash flows of other groups of assets and liabilities; and, as such, test for impairment under ASC 360-10-35 (formerly SFAS 144) at the area of interest level. We have the following comments:

•

Please tell us how you determine your cash inflows and outflows used for your impairment test.


³		As indicated in our prior responses to Staff comments, we did not conduct any meaningful exploration activities in Nevada prior to 2007. To date, therefore, we have no operational plants as a result of our Nevada exploration activities, just facilities in development and construction.

As noted in our response to Staff Comment No. 4, we have no operational plants as a result of our exploration activities, and, therefore, each of our areas of interest is currently under development. As set forth in paragraph 35-34 of ASC 360-10-35 (formerly paragraph 20 of SFAS 144), cash inflows and outflows used to test recoverability of a long-lived asset group that is under development should be based on “the expected service potential of the asset (group) when development is substantially complete. Those estimates shall include cash flows associated with all future expenditures necessary to develop a long-lived asset (asset group), including interest payments that will be capitalized as part of the cost of the asset (asset group).” Based on this guidance, we consider cash inflows and outflows for an entire area of interest when testing impairment.

Upon a triggering event, such as a decision to abandon further development of one of our exploration projects, we make a determination as to the likely course of action for each of our exploration projects within that particular area of interest. Each of our projects is in varying stages of exploration and development, and therefore management judgment is required to assess the potential outcomes. For those projects for which we have made a decision to construct a power plant, our cash outflows mainly include estimates of future expenditures necessary to construct the plant (including interest costs that will be capitalized), costs to operate and maintain the plant at its estimated capacity, royalties, property tax, insurance and costs incurred at our corporate office that are directly attributable to the operation of the plant. These costs are based on current costs of operating existing power plants and take into account price increases throughout the life of the plant. For those projects for which we will be constructing power plants, our cash inflows are determined in one of two manners:

	•		In the case where we have entered into a power purchase agreement (PPA), the cash inflows are calculated based on the energy rates specified in the PPA and the expected generating capacity. If the useful life of the power plant is expected to exceed the term of the PPA, we estimate the expected future cash inflows on the basis of prevailing energy rates, assuming that we will be able either to extend the term of the PPA, enter into a new PPA or sell the generating capacity in the open market.

	•		In the case where we have not entered into a PPA, we estimate the cash inflows using prevailing energy rates in the marketplace based on the expected useful life of the power plant and its projected generating capacity. This is based on the assumption that we will either enter into a PPA or sell the generating capacity in the open market.

For those projects that are in the exploration stage and for which we have not yet completed our assessment of the resource, we make a determination as to the most likely course of action once exploration activities are complete. Such actions will generally involve either developing and constructing a power plant or, alternatively, abandoning the site. Our determination of the most likely course of action is based on the results of our exploration activities to date at both the site and within all of our areas of interest in Nevada (for the reasons explained below). The following fact pattern illustrates how we perform our impairment test.

In area of interest 1, during 2008 we determined that Jersey Valley and then later that year McGinness Hills both have commercially viable resources. Also late in 2008, we finished exploration activities at Buffalo Valley and Grass Valley and decided not to pursue commercial operations at those sites. At that point, we had not yet acquired land rights at Tungsten Mountain. Because our decision to abandon further development at Buffalo Valley and Grass Valley was considered a triggering event for impairment purposes, we tested area of interest 1 for impairment in connection with our 2008 year-end close. Our cash outflows for the impairment test

included estimates of future expenditures necessary to construct the two plants at Jersey Valley and McGinness Hills (including interest costs that will be capitalized), costs to operate and maintain the plants at their estimated capacity, royalties, property tax, insurance and costs incurred at our corporate office that are directly attributable to the operation of the plants. Our cash inflows were determined based on the expected capacity of the two plants once construction would have been complete using energy prices from a signed PPA in the case of Jersey Valley and prevailing energy rates in the marketplace for McGinness Hills because we did not have a signed PPA for that facility. We utilized a worst case scenario for Leach Hot Springs for purposes of the impairment test, meaning that we assumed our exploration activities would not identify a commercially viable resource at this site. As a result, our cash outflows included estimated costs to complete exploration activities at Leach Hot Springs. Our estimated cash inflows significantly exceeded our cash outflows (and the carrying value of costs capitalized to date within the area of interest) and we concluded that area of interest 1 was not impaired.

During the third quarter of 2009, we determined that the resource at Jersey Valley would likely support only a 20 megawatt plant rather than our initial estimate of 30 megawatts. This determination was considered a triggering event for impairment purposes. We updated our impairment test to reflect this reduction in estimated capacity at Jersey Valley and energy prices from a recently signed PPA for McGinness Hills. At this point, we were still in the early stages of exploration at Leach Hot Springs. For purposes of the impairment test, we assumed that no commercially viable resources would be identified at Leach Hot Springs, even though the success rate of our exploration projects in Nevada exceeded 50% (i.e., worst case scenario). Again, our cash inflows significantly exceeded our cash outflows (and the carrying value of costs capitalized to date within the area of interest), and we concluded that area of interest 1 was not impaired.

For purposes of impairment testing in our areas of interest that are in the early stages of exploration and development (e.g., area of interest 3), we make assumptions about the likely courses of action within the area based on the results of our exploration activities to date both within the area and in Nevada. For example, if a commercially viable resource has been identified at, say, 50% of our exploration projects in Nevada, we would assume that a similar success rate will occur within each of our areas of interest absent other information to the contrary. We believe it is reasonable to assume a similar success rate amongst our three areas of interest in Nevada due to the similar geological characteristics of the Basin and Range area of Nevada. To illustrate this concept, during the third quarter of 2009, we determined that the resource at Rock Hills would not support commercial operations and performed an impairment test for area of interest 3. At this point, we were in the early stages of exploration at Gabbs, Dead Horse Wells and Smith Creek. For purposes of the impairment test, we assumed that two out of the four exploration projects within area of interest 3 would be successful since our success rate to date in Nevada has been slightly higher than 50%. Our cash outflows mainly included estimated future exploration costs at all sites in the area of interest, and estimates of future expenditures necessary to construct two plants (including interest costs that will be capitalized), costs to operate and maintain the plants at their estimated capacity, royalties, property tax, insurance and costs incurred at our corporate office that are directly attributable to the operation of the plant. Our cash inflows were determined based on the average capacity of the plants that are being developed at our other exploration sites in Nevada using prevailing energy rates in the marketplace with the assumption that similarly sized plants would be constructed within each of our areas of interest in Nevada due to the similar geological features in this area. Our cash inflows significantly exceeded our cash outflows (and the carrying value of costs capitalized to date within the area of interest), and we concluded that area of interest 1 was not impaired.

We also perform a sensitivity analysis to test impairment based on other potential outcomes, including if our success rate is lower than our experience to date. It is important to note that the costs associated with exploration activities have been, and are expected to continue to be, insignificant in relation to the costs to construct and operate a power plant during its useful life. As a result, it is unlikely that the estimated cash flows within an area of interest will not exceed the carrying amount of our assets unless no commercially viable resources are found within an area of interest.

We advise the Staff that we intend to utilize the guidance in paragraph 35-35 of ASC 360-10-35 (formerly paragraph 21 of SFAS 144), to test impairment at the time we have an operational plant within an area of interest.

•

For each inflow, tell us whether it is based on expected future PPAs or another measure. Also, we assume that you estimate your cash inflows by project, such as Wildhorse or Seven Devils. Please confirm this to us or explain why this is not the case.

As described in our response to the first bullet point of the Staff’s comment, we determine expected inflows based on existing or expected future PPAs and/or prevailing energy rates in the market place coupled with the projected generating capacity of each power plant we expect to construct within an area of interest. We confirm to the Staff that we estimate cash inflows by project (which may be for a single plant or a complex, depending on the PPA involved).

•

Regarding your outflows, we note that most of your expected future outflows are operating and maintenance (“O&M”) costs which are substantially impacted by your central O&M organization for each area of interest. Please describe the significant costs that you incur from acquisition of land rights through development and production, and tell us which costs are shared by the projects in the area of interests and which costs are directly attributable to a specific project.

The costs that we incur from acquisition of land rights through development and construction are done on a project-by-project basis and are comprised of:

	•		land acquisition

	•		permitting

	•		exploration

	•		drilling test and production/injection wells

	•		site and equipment design/engineering and

	•		construction.

			These costs are not shared by projects within a given area of interest; each is attributed directly to a specific project.

	•		For costs that are shared, please tell us why you do not, or cannot, allocate those costs to each project using a reasonable method.

There are no shared costs in our exploration projects. With regard to our operating power plants and complexes, the only significant shared costs are O&M expenses, which are described in more detail in our description of cash outflows below. There are ways to allocate shared O&M costs to each power plant within a given complex. However, we generally do not do that. Our management’s view is that a plant-by-plant allocation of shared O&M costs:

	•		is not useful information for management to have in managing our operating activities and may even be misleading for management’s understanding of the costs of operation;

	•		requires tracking of costs at a level which is not cost effective accounting or information management; and

	•		requires setting criteria for allocating the tracked costs (e.g., by megawatt capacity) that often results in arbitrary selections that do not produce meaningful information in the management context, for the reasons outlined below.

We supplementally advise the Staff that our management approaches the development and operation of geothermal projects on a long-term, complex-by-complex basis. Although we focus on a particular site and potential power plant for purposes of the initial exploration and development of each particular plant, our experience shows that projects may evolve, and resources may be added or subtracted. Therefore, the “complex” rather than the “plant” is at the center of our management analysis and determinations.

Accordingly, in each project we typically start with the development of a relatively small power plant and, when feasible, gradually expand it through the years as we gain more knowledge and understanding of the geothermal resource. In that process we may find, for example, that optimal utilization of the geothermal resource, within the complex as a whole, differs from our initial development plan, and we will then implement the necessary adjustments that may involve one or more plants and other resources within a given complex. Accordingly, it is very difficult to allocate costs associated with specific wells, for example, to a specific power plant within a given complex, because wells, piping, transmission lines and other facilities may be shared by several power plants in that complex. Our Heber and Ormesa projects in California and our Steamboat complex in Nevada are examples of complexes in which resources and other facilities are being shared by a number of power plants.

Another example is our use of so-called “bottoming units” in some of our complexes. These are essentially add-on power units that generate electricity from the spent geothermal fluid produced by flash-technology power plants operated in some of our complexes. In such cases it is very difficult to allocate the cost of the bottoming unit, the cost of producing and injecting the brine, the cost of chemicals, and the cost of manpower to monitor and operate the performance of the plant and well field to each of the plants within the complex involved in this process.

The operation and maintenance of our power plants is also done on a complex-by-complex basis. As each of our complexes generally consists of several power plants, we have one central room that controls all of the power plants, and one maintenance group that services all of the power plants in a given complex. Our management approach is to try to maximize the total output of the complex shifting our attention and manpower where it is needed most at any given time. We do not see a practical way of allocating these costs between specific power plants within a given complex.

Accordingly, in our management’s view, any cost or resource allocation between specific plants within a given complex will not contribute to a more efficient operation of that complex, but will only add an unnecessary burden on our day-to-day management, accounting, and monitoring processes.

•

Please tell us why you consider your areas of interest to be the lowest level for which identifiable cash flows are largely independent of the cash flows from other assets and liabilities. Explain why cash flows for each project are not largely independent from each other. In this regard, it appears that you could sell or abandon one project without impacting the viability of the projects around it.

As the Staff is aware, significant judgment is involved in determining the lowest level of identifiable, largely independent cash flows. In practice, several approaches have been developed to provide a framework with which to determine the appropriate grouping level. QIIA1. of KPMG’s “Guide to Accounting for the Impairment of Long-Lived Assets — An Analysis of FASB Statement 144” discusses factors that should be considered when determining whether the cash flows of an asset group are largely independent of the cash flows of other asset groups. One approach focuses on the degree to which a company’s total cash flows depend on the activities of one or more other asset groups of the company. Specifically, QIIA1. says “...if the cash flows of an asset group result from significant shared operating activities, an asset grouping at a higher level may be justified.” It further says that “[t]he extent to which shared services relate to the operations of the assets under evaluation, e.g., procurement, sales, marketing, and research and development, is an important factor in determining whether an asset group has cash flows that are largely independent of the cash flows of other asset groups.”

As discussed above and in our December 17, 2009 call with the Staff, our O&M activities are a key driver in the success of our plants and represent the majority of our cash outflows for such plants. Our plan is to share O&M costs among all operating plants constructed in an area of interest. The grouping of our exploration projects is based on the manner in which we intend to operate the plants that are constructed in our areas of interest. We view an area of interest as one development project and consider all costs incurred to develop the asset group, beginning with land acquisition and continuing through exploration, development and production, as necessary for the generation of revenues. The other cash outflows at our operational plants (which are described below in our response to Staff Comment No. 6) are necessary costs of operating our plants, but the activities associated with those outflows have no direct bearing on the success of the plant.

It is not necessarily the case that we could sell or abandon one project without impacting the viability of the projects around it. For example, as explained in our response to Staff Comment No. 2, it may not be economically viable to operate a smaller capacity plant as a stand-alone facility without sharing O&M costs with other plants in a complex. Accordingly, we would be unlikely to sell an operating plant in an area of interest, if the remaining operating plants (and any plants then in construction in that area of interest) could not still be operated profitably as a complex without that plant. Of course, we may be forced to abandon exploration projects if our exploration and development activities indicate that a site will not support a commercially viable power plant. When we do that, however, we evaluate what, if any, impact that has on our ability to develop and operate any remaining sites as a profitable complex of operating plants. And we might conclude, for example, that additional sites may need to be added for the area of interest to become a profitable complex of operating plants, before proceeding with further development in that area of interest.

We note that you test for impairment of your operating power plants either on a plant-by-plant basis or more commonly, at the complex level, which are cases where several power plants are operated as a complex. We have the following comments:

•

Please tell the significant differentiating factors that cause you to test for impairment on a plant-by-plant basis versus at the complex level. We assume this is based on PPAs in place. Please confirm this to us or explain why this is not the case.

The significant factor that determines whether we test for impairment on a plant-by-plant basis or at the complex level is whether the facility is operated as a stand-alone power plant, like our plant in Puna, Hawaii, or operated as part of a complex, like our Ormesa, Heber, Steamboat and Brady complexes, where O&M activities are shared. The determination of the basis on which we test for impairment normally is not based on the power purchase agreements for those plants.

•

Please tell us how you determine your cash inflows and outflows used for your impairment test.

The cash inflows for our power plants are calculated based on the energy rates specified in the relevant PPAs and the projected generating capacity of the power plants within a complex. If the useful life of the power plant is expected to exceed the term of the PPA, we estimate the expected future cash flows on the basis of prevailing energy rates, assuming that we will be able either to extend the term of the PPA, enter into a new PPA, or sell the generating capacity in the open market.

The cash outflows are mainly based on the following projected costs:

	(i)		O&M costs which generally represent the majority of cash outflows for our operating power plants, with labor being the largest cost item;

	(ii)		royalties paid for usage of the resource, which are generally 4% of project revenues and generally represent approximately 6% of our total operating costs;

	(iii)		insurance costs, which are part of company-wide insurance policies and generally represent approximately 5% of our total operating costs; and

	(iv)		property taxes, which are based on the value of each power plant within a given complex and generally represent approximately 7% of our total operating costs.⁴

As noted in our response to Staff Comment No. 5, our projected cash outflows are based on current costs of operating existing power plants and take into account estimated future price increases.

•

Please describe each significant inflow and outflow and tell us whether each item is related to a single plant or whether the item is shared or overlaps between plants.

Our significant inflows are comprised of capacity and energy revenues under PPAs as described above. Those inflows may be for a single plant or for a complex, depending on the PPA involved, as


⁴		The operating cost percentages noted in clauses (ii) through (iv) are based on outflows with respect to our Nevada operating power plants that occurred during the nine-month period ending September 30, 2009.

described above. Our most significant outflows for our operating plants are O&M costs. O&M costs are the only significant costs that are shared. Our other significant cash outflows are as described in our response to the preceding bullet, and those costs are allocated to single plants or complexes where plants are operated as a complex.

•

Please tell us whether any cash inflows or outflows are shared or overlap between exploration projects within an area of interest and operating power plants. For example, tell us whether the same maintenance personnel may service an operating plantand service an exploration project in an area of interest that is close by. If so, tell us how you allocate such items to the operating power plant and to the area of interest when performing your impairment tests.

We do not share cash inflows or outflows between exploration projects and operating power plants within an area of interest. With few exceptions, our power plant personnel are distinct from our exploration, development and construction personnel.

For each project in Nevada, please provide us with the information below.

•

The date you acquired land rights or the lease.


Name of Projects		Year acquired
Wildhorse		27% of the land was leased in September 2006 and the rest in December 2007

Seven Devils		October 2007

Dixie		October 2007

Carson Lake		35% of the land was leased in December 2005 and the rest in October 2006

Leach Hot Springs		78% of the land was leased in July 2006 and the rest in August 2008

Buffalo Valley		August 2003

Jersey Valley		30% of the land was leased in August 2003 and the rest in August 2005

Grass Valley		August 2003

Tungsten Mountain		September 2009


Name of Projects		Year acquired
McGinness Hills		95% of the land was leased in October 2007 and the rest in April 2009

Smith Creek		72% of the land was leased in August 2003 and the rest in January 2008

Gabbs		September 2006

Dead Horse Wells		October 2007

Rock Hill		October 2003

•

The status of each project as of your latest balance sheet date. For example, the status of a project could be: lease acquired but no further action taken, in process of performing geochemical and geophysical surveys, in process of obtaining drilling permits, drilling gradient or slim holes, abandoned, or in process of constructing a power plant/complex. These are only suggested categories and should be modified based on how you assess the status of a project.


Name of Projects		Status
Wildhorse		Lease acquired but no further action has yet been taken.

Seven devils		Lease acquired but no further action has yet been taken.

Dixie		We completed exploration studies and are awaiting permits to start exploration drilling at the site.

Carson Lake		We drilled full-size exploration wells and are awaiting full size well-drilling permits.

Leach Hot Springs		We completed exploration studies and are awaiting permits to start exploration drilling at the site.

Buffalo Valley		We drilled slim holes, abandoned these holes, and reclaimed roads and drill pads.

Jersey Valley		The project is currently under construction.


Name of Projects		Status
Grass Valley		We drilled slim holes, abandoned these holes, and reclaimed roads and drill pads.

Tungsten Mountain		We acquired 400 acres in the project area, and we plan to start physical exploration work once we secure more acreage.

McGinness Hills		The project is currently under construction.

Smith Creek		We started exploration studies.

Gabbs		We completed exploration studies and are awaiting permits to start exploration drilling at the site.

Dead Horse Wells		We completed exploration studies and are awaiting permits to start exploration drilling at the site.

Rock Hill		We drilled slim holes, abandoned these holes, and reclaimed roads and drill pads.

•

Whether each project was determined to be economically feasible. In your response, please identify the location of the three projects that you have indicated to us you concluded were not economically feasible and explain, if applicable, how this impacts the status you have assigned to the related larger area.

As described in our response to the bullet point above, there are three projects that we found not economically feasible at this time: Grass Valley, Buffalo Valley and Rock Hill. Grass Valley and Buffalo Valley are located in area of interest 1. Rock Hill is located in area of interest 3. In each case, the status of the related larger area of interest was not impacted.

•

The total amount of costs related to each project, including those expensed and those capitalized. The costs should be quantified by the following categories: costs incurred prior to obtaining land rights/lease, lease costs, pre-development exploration costs, including drilling slim holes, and development/construction costs.

Costs incurred prior to obtaining land rights/lease are not identified by project and are expensed as incurred.

The following table summarizes our other costs corresponding to the categories identified in this bullet point as of September 30, 2009 (amounts in thousands of dollars):

Confidential Treatment Requested by Ormat Technologies, Inc.

Capitalized costs

Pre-

Development

development

and

Lease Costs

Up-front Bonus

Exploration

Construction

Which Have

Name of Projects

Lease Costs

Costs

Total

Been Expensed

Wildhorse

[***]

Seven Devils

[***]

Dixie

[***]

Carson Lake

[***]

Leach Hot Springs

[***]

Buffalo Valley

[***]

Jersey Valley

[***]

Grass Valley

[***]

Tungsten Mountain

[***]

McGinness Hills

[***]

Smith Creek

[***]

Gabbs

[***]

Dead Horse Wells

[***]

Rock Hill

[***]


	•	The total number of dry holes drilled and, of those dry holes, how many you were able to use for other purposes and how many, if any, you were unable to use. Also quantify the number, if any, that have been or are in process of being reclaimed.

We have drilled a total of eleven slim holes at our development sites in Nevada. Six of these slim holes were drilled at sites for which we have determined not to pursue further development. Those sites are Grass Valley, Buffalo Valley and Rock Hill. In each case, we did not encounter a sufficiently high temperature resource and therefore decided to plug and abandon the slim holes, and we have reclaimed their well pads and roads in compliance with Bureau of Land Management (“BLM”) requirements.

The other five slim holes are located in two projects that we are currently developing, namely McGinness Hills and Jersey Valley. At the McGinness Hills project, we drilled two successful slim holes that were instrumental in defining the development program of the geothermal resource. At the Jersey Valley project, we drilled three slim holes. The first slim hole encountered high temperature and high permeability, but had to be plugged and abandoned due to mechanical problems at the well bore. The second slim hole did not encounter sufficiently high temperature, but it is being used to define the edge of the reservoir and also will be used as an observation well. The third slim hole encountered high temperature and high permeability, but due to its small diameter is not capable of being used as an injection or production well. It will be used as an observation well for purposes of monitoring trends in the reservoir during production.

In addition to the eleven slim holes described above, we also drilled a full size hole at our Carson Lake project. Based on our geological model we found that the resource in Carson Lake is very deep and therefore it was not practical to drill a slim hole and we had to drill a full size hole. We encountered high temperature but very low permeability and therefore decided not to use the full size hole as an injection or production well. It is being used as an observation well for purposes of monitoring trends in the reservoir during production.

Please describe your internal approval process for determining whether a project will move forward. In doing so, tell us the milestones that must be achieved at each step of your research, exploration, development and production process and the person responsible for approving its advancement or abandonment. For example, when explaining your internal approval process to determine whether a lease should be acquired, tell us who determines that a lease should be obtained and who authorizes that decision. Furthermore, tell us whether any decision making authority is limited by dollar amount and whether Board of Director approval is required for any decision.

As we noted in our prior responses to Staff comments, we determine the economic feasibility of potential geothermal resources internally, by our exploration department. Our internal approval process may be divided into three stages: (i) the bidding stage, (ii) the exploration stage, and (iii) the development stage. A formal approval by our President or CEO is required prior to bidding on a particular site and prior to commencing development activities, with informal periodic reviews taking place throughout the process.

The first stage, which involves the determination of whether and at what cost to bid on a particular site, begins with an evaluation of all available geological and geothermal information and databases by our exploration department. 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.).

After performing our initial assessment of a potential site, a formal review meeting is held between the exploration department and our President or CEO. All pertinent geological information is presented verbally at the meeting, and we estimate exploration, development and construction costs on a dollar per megawatt of estimated generating capacity basis for purposes of evaluating the feasibility of a project from the specific site. Based on this information, our President or CEO makes a determination as to whether, and if so, up to what price, to bid on a site at a BLM auction.

The second stage, exploration, follows the acquisition of land rights to the potential geothermal resource. The decision at this point is not if to start exploration activity at a specific site, but when to do it and at what priority. This decision is approved by the EVP Resource group. 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 and financial model 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 actual exploratory drilling, our exploration department conducts a further determination of the feasibility of the potential resource based on the results of the additional work done after the acquisition. If the results from geochemical and geophysical surveys are poor (i.e., low derived resource temperatures), or if the results of the temperature gradient holes are not satisfactory, we will significantly lower our assessment of the feasibility of the prospect and may not proceed with exploration. The exploration stage may include the drilling of up to three commercial size wells. Although there is no formal review process during this stage, our exploration department conducts periodic reviews of its progress and findings. Any determination to discontinue the potential project must be approved by our President or CEO.

At the third stage, prior to deciding whether to move into the development stage, which is the majority of the investment in a project, we assess the potential generating capacity of the power plant, the estimated costs of development and construction, and the projected revenues. Our estimates of development and construction costs and projected revenues are functions of the potential size of the plant. For purposes of these assessments, the exploration department provides estimates on the flow and temperature that the site should be able to support. Based on this data, the engineering department prepares a rough conceptual design and the construction department estimates costs; the engineering department estimates the output of the proposed plant to be built on the site; and the business development department estimates the electricity rate at which energy can be sold from the plant. This information is then used to create a financial model to further fine-tune our determination of the economic feasibility of the proposed project. A formal review meeting is held among representatives of our exploration, business development, construction, engineering, and contracts administration departments, and our President or CEO. The complete project budget is reviewed at the meeting, and our President or CEO makes a determination whether to proceed with the development of the project.

Board of Directors approval is not required for any decision as to whether to proceed or to discontinue a project at any of the above-described stages.

Form 10-Q for the Quarterly Period Ended September 30, 2009

We have reviewed your response to prior comment 5 from our letter dated November 17, 2009. We note that you describe the sale of tax credits related to your OPC Tax Monetization Transaction as “Income attributable to sale of equity interests” on your income statement. Please consider changing this line item to read “Income attributable to sale of production tax credits” or a similar caption to clearly convey how this income was generated.

In response to the Staff comment we considered changing the line item to read “Income attributable to sale of production tax credits”. However, we think that that caption omits information about all the sources of income (loss) associated with the OPC transaction, such as taxable income and loss allocations. Since this heading is explained in some detail in the footnotes to our financial statements, we propose to change the caption to read, “Income attributable to sale of tax benefits.”

* * * * * *

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

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

Sincerely,

/s/ Yehudit Bronicki

Yehudit Bronicki
Chief Executive Officer
Ormat Technologies, Inc.

VIA EDGAR AND BY HAND


cc:		Securities and Exchange Commission
		Mr. Ronald E. Alper, Esq. Ms. Yong Kim Mr. George K. Schuler Ms. Jennifer Thompson


		Chadbourne & Parke LLP Mr. Noam Ayali, Esq. Mr. Charles E. Hord, III, Esq.

Ormat (ORA) CORRESPCorrespondence with SEC