Ormat Technologies Inc (ORA) 2008 Q4 法說會逐字稿

Good morning. My name is Nicole, and I will be your conference operator today. At this time, I would like to welcome everyone to the Q4 earnings conference call.

All lines have been placed on mute to prevent any background noise. After the speaker's remarks, there will be a question and answer session. (Operator Instructions). Thank you. I would now like to turn the call over to Miss. Marybeth Csaby with KCSA Strategic Communications. Ma'am, please go ahead.

Thank you, Nicole. Hosting the call today are Dita Bronicki, Chief Executive Officer, Yoram Bronicki, President and Chief Operating Officer, Joseph Tenne, Chief Financial Officer and, Smadar Lavi, Vice President of Corporate Finance and Investor Relations.

Before beginning, we would like to remind you that information provided during this call may contain forward-looking statements relating to current expectations, estimates, forecasts and projections about future events that are forward-looking as defined in the Private Securities Litigation Reform Act of 1995. These forward-looking statements generally relate to the Company's plans, objectives and expectations for future operations, and are based on management's current estimates and projections of future results or trends. Actual future results may differ materially from those projected as a result of certain risks and uncertainties. For a discussion of such risks and uncertainties, please see 'Risk Factors' as described in the Annual Report on Form 10-K filed with the Securities and Exchange Commission on March 5, 2008, and on the Form 10-Q filed with the Securities and Exchange Commission on November 6, 2008.

In addition, during this call statements that may be made that include a financial measure defined as a non-GAAP financial measure by the Securities and Exchange Commission, such as adjusted EBITDA. This measure may be different from non-GAAP financial measures used by other companies. The presentation of this financial information is not intended to be considered in isolation, or as a substitute for the financial information prepared and presented in accordance with GAAP.

Management of ORMAT Technologies believes that adjusted EBITDA may provide meaningful supplemental information regarding liquidity measurement that both management and investors benefit from, referring to this non-GAAP financial measure in assessing ORMAT Technologies' liquidity, and when planning and forecasting future periods. This non-GAAP financial measure may also facilitate management's internal comparison to the Company's historical liquidity.

Before I turn the call over to management, I would like to remind everyone that a slide presentation accompanies this call and can be accessed on ORMAT's website, www.ormat.com, under the events link as found in the investor relations tab.

With that said, I would like to turn the call over to Dita. Dita, the floor is yours.

Thank you, Marybeth, and thank you all for joining us this morning. Following my comments, Yoram will review operations and then Joseph will review the financials. And, as usual, a Q&A session will follow our remarks.

In a time that some or even many industries struggle as a result of the economic crisis, we had a very good quarter and year. I am happy to report strong revenue growth and an increase in our bottom line. We secured additional leases to support our exploration activity and built up a sizeable backlog in our Products segment. And we expect to recognize a substantial part of it in 2009. We are also very happy with the approval of the Stimulus Bill, which we believe will have positive effect on the industry in the future.

Starting with slide four, let me begin with our financial results. In the fourth quarter and the full-year 2008 we exceeded our revenue guidance. Revenues in our Electricity segment are up 11.8% for the quarter and 16.8% for the entire year. And in our Products segment we did exceptionally well, with the fourth quarter and full year up 120.9% and 15.8% respectively.

Turning to slide five, we have met our projection in terms of organic growth by completing construction of more than 100MW during the year. This includes completion of Phase II of Olkaria III power plant in Kenya and the GDL power plant in New Zealand, which we now fully own. In the United States we completed the Heber South project in California; And by the end of 2008 the first 5.5MW unit in North Dakota, out of the four units of OREG 2 projects.

We also substantially completed the construction of the 50MW North Brawley and expect a gradual ramp up of the project, with full capacity in the second quarter of 2009. The slow ramp up is driven mostly by larger than expected quantities of sand within the geothermal reservoir. Experience shows that the solids production gradually declines over the life of the well. However, during the initial operations the removal requires more care in order to safeguard the injection well.

In our Production segment we are entering 2009 with a record backlog of $194 million, based on a number of contracts that we successfully secured in 2008 and early in 2009 for geothermal power plants in the United States, Turkey, New Zealand and recently Costa Rica.

Moving to slide number six, in terms of technology 2008 was an important year for ORMAT. There are four areas that we have been working on and could open new activities to the Company. The first is energy recovery in LNG gasification terminals. Our first project is with ENAGAS of Spain. The second area is power generation from co-produced fluids from oil and gas wells. This is a joint project with the US Department of Energy. We have completed the installation of the OEC unit at the Oil Test Center near Casper, Wyoming, and the project is currently undergoing tests.

The third area is EGS, the advanced exploration techniques, with the recent grant from the Department of Energy for a second EGS R&D project, this one, near our Brady facility.

The fourth is our R&D work in solar energy. The team that we have assembled works on both indigenous development and screening of applicable technologies. Successful results from this work could constitute an important growth driver for ORMAT in the future years.

And now to slide number seven. The regulatory environment continues to be favorable for renewable energy, both in the US and internationally. In the US the PTC was extended for two years last October, and the Stimulus Act includes a host of provisions that will greatly benefit the renewable energy industry. As far as renewable energy is concerned, the Bill includes four areas; tax incentives, financing, grants and direct action.

More specifically, on the tax incentives side there is a one-year extension of the 50% bonus depreciation. More importantly, the Act calls for a three-year extension of the PTC until 2013, and gives an option to forego PTC and claim a one-time 30% investment tax credit instead. In addition, the Bill gives an option to forego investment tax credits and receive a cash grant from the US Treasury for 30% of the project cost. This grant will be available for projects placed into service in 2009 and 2010, or for those who are starting construction during 2009 or 2010 and are completed by the deadline. The deadline for geothermal projects is 2013. In addition to the grant, the financing aspects of the Bill include a DOE loan guarantee for renewable energy projects that start construction by September 30, 2011. This should substantially reduce cost of debt for renewable energy projects. The Act also authorizes tax credit bonds for special application.

And, looking outside the United States, the regulatory environment continues to be beneficial to ORMAT. During the fourth quarter of 2008 we were able to benefit from a mandate of the Executive Board of the United Nations Framework Convention on climate change. Our Amatitlan geothermal project in Guatemala was official registered as a Clean Development Mechanism, or CDM, as it is called.

The project is expected to offset emission to approximately 83,000 tons of C02 per year. And, as such, it will be eligible to receive certified emission reduction credits, which is equivalent to 1 ton of carbon dioxide, which can be traded or sold. The project has a long-term contract to sell all Amatitlan's credit to European buyer.

Moving to slide eight, in terms of our future, our growth is highly dependant on several variables, including our ability to secure new development leases, our success rates in the exploration activity and the ability to secure capital resources to finance our investment plans.

During 2008 we were successful in securing geothermal rights for approximately 150,000 acres of land, to explore geothermal resources in 12 sites that are located in Alaska, California, Hawaii, Nevada, Oregon and Utah.

The exploration activity was, and will remain, a challenge for our growth plan, and we continue to prepare ourselves for this challenge. The results of exploration of some of these sites were not as successful as we hoped and, consequently, we had to delay the construction of two of [projects, Jersey Valley and Carson Lake. Yoram will elaborate on this later in the call. And, finally, financing on slide nine. I am pleased to say that we have done well in this area, despite what is happening in the credit market. We were able to secure committed lines of credit totaling approximately $348 million. We closed the second stage of our tax monetization transaction where we received approximately $63.0 million. We also received approximately $150 million, net, from the sale of 3.1 million shares of common stock in a block trade. More recently, we signed the credit agreement for a third-party refinancing of our portion of the equity in the Olkaria III project, for up to $105 million with a reasonable cost of debt. We are still in negotiation to enter into a tax equity deal for our North Brawley project. The current financing climate has weakened the tax equity market and narrowed down the number of active players, which translated into escalating yields.

In parallel, the provision of the Stimulus Act gives substantial benefit for geothermal projects. Therefore, we are currently evaluating what makes more sense for ORMAT, and this may affect the structure we will use to finance this project. We are also continuing in the negotiations with the financial institution regarding the refinancing of our equity investment in the Amatitlan project.

With that, let me now turn the call over to Yoram. Yoram?

Thank you, Dita, and good morning everyone. I would like to begin on slide 11. Our US generation for the quarter was up 21.1%, to about 650,000 megawatt hours. For the full year generation was up 13.6%, to about 2 and a quarter megawatt hours. The increase in our overall US generation resulted from both new plants that started commercial operation and improved performance from existing facilities.

In our previous calls we described a few events that offset our overall US power generation. However, all of them were rectified by the fourth quarter, where we enjoyed record generation.

The high oil prices of 2008 provided record revenue out of our Puna plant. As oil prices have been declining since the summer the rates in 2009 will be lower. But, given the generation mix on the big island, the plant enjoys favorable rates, even at the current mid-level oil prices. For example, the rates for this month are similar to the rates that Puna got in the second half of 2005.

We have completed construction of 109MW during the year, the majority of them at the very end of the year, which means that the revenues resulting from their addition will be reflected gradually during 2009, with full output expected at the end of the second quarter of 2009.

Looking, now, at our construction, development and exploration activity on slide 12--our drilling plans for 2009 include

Drilling an exploration well in Ormesa which, if successful, will increase the potential for this complex. In Heber South we plan to drill one well that will bring the complex to its designed generating capacity. In the Amatitlan plant in Guatemala we commenced the drilling of additional wells, which we hope will get the plant to its designed generating capacity of 20MW. In the GDL plant in New Zealand we plan to drill another well to provide for redundancy in the resource supply.

In the next two years, as presented in the table on slide 13, we plan to add between 82MW and 94MW of generating capacity from both geothermal and recovered energy power plants. In Puna we plan to add 8MW through the construction of OEC units in 2009. We are still in discussion with the Hawaii Electric Light Company for the sale of this additional power.

In our OREG sector we announced earlier this month that the second OREG 2 unit had commenced commercial operation. We are in final completion of the 4MW Peetz project, and expect the remaining two OREG units and the GRE unit to be completed by the end of the year.

We had hoped to complete the construction of the 30MW East Brawley project in 2009 but, due to delays in obtaining our required permits, this project is now scheduled for 2010. Pending continued success in our exploration work in Jersey Valley -- in the Jersey Valley project, the plant could be completed by late 2010.

Turning to slide 14, describing longer-term projects, Phase 3 of the Mammoth project in California is proceeding and is expected to deliver between 20MW and 30MW of additional generation. We are currently negotiating a long-term contract with Southern California Edison. Our share for the additional power will be 50%, and the other 50% is owned by an unrelated third party. The expected completion in 2011 is due to the long permitting process in this area.

In the Imperial Valley we are in the process of obtaining the exploration permits to pursue the exploration activity in the projects here we have a 50MW PPA with Southern California Edison. We are currently developing and conducting exploration activity on the McGinness Hills project in Nevada.

In the Carson Lake project we completed two wells, and found elevated temperatures but no significant water flow. We are now evaluating the feasibility of utilizing a shallow reservoir to make power. In the Sarulla project the consortium is currently negotiating certain amendments, including an adjustment to commercial term, and intends to proceed with the project after those amendments have become effective.

Based on the exploration results, these projects have a potential capacity of between 151MW and 168MW. These projects under development, if implemented, are expected to come on line after 2010.

Turning to slide 15I would like to provide you with an update on the exploration activity that will support our growth on a longer term basis.

In the past years, ORMAT engaged in what is arguably the largest effort undertaken by a single company to categorize, map, sample and drill Greenfield prospects in the US, at least in the last 20 years. The exploration of Greenfield prospects is characterized by a high degree of uncertainty. North Brawley is a result of this effort. Jersey Valley and East Brawley are expected to be additional projects resulting from our exploration activities.

It is, however, impossible at this point to predict how many megawatt each project will yield. To accelerate the exploration process we have put, in the past years, substantial base of people, equipment and techniques which will allow us to perform this work with better control over cost and schedule. This longer-term exploration will be performed in our various leases in Nevada, Hawaii, Utah, Oregon and Alaska, some of it as soon as this year.

Thank you. And I would like to turn the call to our CFO Joseph Tenne.

Thank you, Yoram, and good morning, everyone. Beginning with slide 17, for the year total revenues were $344.8 million, a 16.5 percent increase from revenues of $296.0 million in the previous year.

Onto slide 18...In our Electricity Segment, total revenues for the year were $252.3 million, a 16.8 percent increase over total revenues of $216.0 million in the previous year. This increase is primarily attributable to a $26.8 million of additional revenues generated as a result of an increase in our electricity generation capacity, from new power plants that came on line, the enhanced performance of existing power plants and an increase in the energy rates in Hawaii and in California.

The increase in our United States Electricity revenue was offset by a decrease in the generation of Steamboat 2 and 3 projects, as a result of the temporary shutdown required to replace the project turbines, a decrease in the generation output of the

Brady complex, a decrease in the generation output of the OREG 1 project and expiration of the "adder" under the Heber 2 Power Purchase Agreement. Also attributable is net increase in revenues of $9.5 million, resulting from our international power plants.

The total cost of revenues attributable to our Electricity Segment was $170.1 million, as compared with $148.7 million in the previous year, which presented a 14.4% increase, which reflects increased costs relating to new and enhanced projects that came on line, including depreciation, an increase in labor and material costs in existing plants and liquidated damages to our customers as a result of not meeting the capacity targets under certain Power Purchase Agreements. And in our Products Segment, on slide 19, total revenues for the year were $92.6 million, a 15.8 percent increase over total revenues of $80m in the previous year. Most of the increase in revenues was derived from two large geothermal projects, the Blue Mountain project in Nevada and the Centennial Binary Plant in New Zealand. Total cost of revenues attributed our Products segment for the year was $72.8 million as compared with $68.0 million in 2007, which represented a 6.9% increase.

Moving now to the next slide, for the year the Company's gross margin was 29.6% compared to 26.8% in 2007. Gross margin for the Electricity and Products Segments is presented in slide 20. Now to slide 21Net income for the year was $49.8 million, or $1.12 per share (diluted), as compared to $27.4 million, or 70 cents per share (diluted) for the year ended December 31, 2007. Such increase in net income was primarily attributable to $17.1 million increase in our operating income, $19.3 million decrease in interest expense and $7.3 million increase in minority interest. As a result of the high volume of projects under construction, during the year we were able to capitalize a significant portion of our interest expense.

In 2009, the volume of projects under construction will decrease and as a result our interest expense, net of amounts capitalized, will increase.

This was partially offset, as you can see in the slide, by an increase in income tax provision, impairment of auction rate securities and foreign currency translation and transaction losses, and a decrease in equity in income of investees, and interest income.

Foreign currency translation and transaction losses for the year were $7.7 million, compared to $1.3 million for the year ended December 31, 2007. The $6.4 million increase is primarily due to foreign currency translation losses in the amount of $3.3 million in respect of a loan denominated in New Zealand dollars which was granted to our New Zealand subsidiary, GDL, whose functional currency is the New Zealand dollar, and to losses on forward foreign exchange transactions which do not quality as hedge transactions for accounting purposes.

The foreign currency translation losses in respect of the loan granted to our New Zealand subsidiary will decrease the cost of the equipment which was financed by such a loan.

Net income for the year includes stock based compensation related to stock option of $4.0 million as compared with $3.3 million in the previous year. Now I would like to go over a few quarterly financial highlights beginning with slide 22For the fourth quarter total revenues were $95.5 million, an increase of 35.2% from $70.7 million in the fourth quarter of 2007. Electricity Segment revenues for the quarter were $62.1m, an increase of 11.8%, as compared to $55.5m during the same period in 2007. Products segment revenues for the quarter were $33.4 million, an increase of 120.9% as compared to $15.1 million for the same period in 2007.

Now, on slide 23, net income for the fourth quarter of 2008 was $11.7 million, or $0.26 per share diluted. Net income for the fourth quarter of 2007 was $8.9 million, or 22 cents per share (diluted).

In the quarter ended December 31, 2008 and -- 2007 there were 45.4 million and 40.9 million weighted average shares respectively, using the computation of diluted earnings per share.

As shown in the following slide, Slide 24, Adjusted EBITDA for the year 2008 was $124.7 million, compared to $107.2 million for the year ended December 31, 2007. And for the fourth quarter, Adjusted EBITDA was $31.5 million, compared to $25.2 million for the quarter ended December 31, 2007.

Reconciliation of GAAP net income to adjusted EBITDA is set forth in slide 32.

To the next slide. As of December 31, 2008 the Company had cash and cash equivalents and also marketable securities of $34.4m, compared to $60.7m as of December 31, 2007. During the year most of our cash was used to fund capital expenditure and to repay long-term debt to our parent and to third parties. In the recent of our long-term debt as of the end of December 31, 2008n and the payment schedule are presented in slide -- in the presentation. Finally, if you turn -- in slide 26.

Finally, if you turn to slide 27 you will see that February 242009 our Board of Directors approved the payment of the quarterly dividend of $0.07 per share, pursuant to the Company's dividend policy which targets an annual payout ratio of at least 20% of the Company's net income, subject to Board approval.

The dividend will be paid on March 26 to shareholders of record of the close of business on March 16. The Company expects to pay a dividend of $0.06 per share in the next three quarters, compared to $0.05 per quarter in 2008.

Thank you all. And I would like now to turn the call back to Dita for final remarks.

Thank you, Joseph. Please turn to slide 29, on which you will see our CapEx requirements for 2009. We plan to invest in 2009 $199 million for enhancements of existing projects and development and construction of new projects. In addition, our capital expenditure budget for operating projects is approximately $18 million for 2009.

We expect to invest $32 million in exploration during 2009. Approximately $2 million were budgeted to invest in machinery and equipment for the same period till the end of 2009. To recap, we have in place the capital resources more than necessary to fund our CapEx requirement of about $250 million for the year.

As to the outlook for 2009, we expect our 2009 Electricity segment revenue to be between $280 million $290. This is based on our current assumptions for the rates of Puna and our current assumptions for the ramp up of Brawley. We also expect an additional $9 million of revenues from our share of electricity revenue generated by a subsidiary, which is accounted for under the equity method.

With regard to our Products Segment, we expect that our 2009 revenues will be between $100 million and $120 million.

Let me end my remarks by summarizing the key takeaway for the quarter and the year. First, we saw a strong top line growth in both the Electricity and Products segments. The backlog in our Products segment has grown, and is substantial. Despite some minor delays in two of the projects our generating portfolio continues to grow, and we continue to add the necessary resources to move forward with our growth plan.

And, finally, we are well funded to support our growth and we continue to explore innovative ways to fund this growth. . As always, we remain committed to managing our business responsibly for this challenging period. And I would like to thank you all for your support.

Operator, at this time I would like to open the call for

(Operator Instructions).

Your first question is from Ben Kallo of Stanford Group.

Hi, good morning.

Good morning, Ben.

Could you guys give us a little bit more detail around Carson Lake? You mentioned it briefly. And then also, on Amatitlan and the plan there for financing that project.

Hi, Ben, it's Yoram. On Carson Lake we've done two -- or we have drilled two fairly deep wells to try and identify a deep - hot deep resource. From our results, it is not there. But as we drilled into the deep resource we've identified a lower temperature, potentially prolific resource, we call the shallow resource. We will explore that. If this deems to be productive and a commercial project can be built around it we'll do that. But, of course, until we have proven that it is a viable resource, there is nothing more that we can say.

And then, on Amatitlan, does financing require that you have the next round of drilling finished?

No, no.

Okay. So what's timing for financing that project? Can you give us any more detail on that?

You know, in final -- timing in financing is something that you have estimate, but it doesn't always happen or doesn't always close when you estimate. But we -- as it looks now, it will be done before the summer. And just to emphasize, the drilling is to the project is generating today at around 17MW. And the drilling is in order to bring it to the 20MW, unrelated to the financing.

Okay. And then my last question is, as far as PTC versus the ITC, what are the different IRRs that you see, if you take the ITC up front? And then, is that -- are you guys looking at that for volume instead of entering into some kind of tax monetization?

Okay, the general answer is that, depending on the capital cost of the project, sometimes ITC is more favorable and sometimes PTC is more favorable. As you know, there is a big variance in the capital cost of a geothermal project. And depending on the capital cost, regardless of the source of funding, sometimes ITC is more favorable and sometimes PTC is more favorable.

Specifically with respect to tax monetization, the new Act has opened various forms of tax monetization. You can do the traditional partnership flip But you can do leases, you can do other forms of innovative financing, depending on the conditions of each specific project. We do not have yet specific plans for North Brawley. We are evaluating what would make most sense, especially that there is also the possibility to get a grant in view of ITC. So this is still under evaluation.

Okay, thank you.

The next question is from Greg Orrill of Barclays.

Thanks very much. Two questions. First, on Puna, I was wondering if you could elaborate a little bit more on what your assumption there is for the oil prices in your revenues guidance, and how that impacts the project.

And then, second, what are you seeing in California in terms of new rates -- new contracted rates for plants, when you consider what RECs are worth and the environment for power?

Okay. On Puna, we have assumed that the rate that we got for February will more or less be maintained for the year. So we have not assumed further decline of oil prices from where they are today, maybe a slight decline, but not a substantial decline. Of course, we don't have the crystal ball to know what will happen, and it can be better, and it can be a further decline. But, as Yoram mentioned, the correlation between the oil price and the rate is not one-to-one because of the specific circumstances on the island.

With respect to California, we have not seen new prices. But what we have seen is a strong appetite or, I would even say, hunger of the utilities to get more and more Renewable energy. They increased their target of 30%. It is really taken seriously by the utilities in California.

And what would that translate to in terms of -- I guess, the terminology would be avoided cost for power?

My guess would be as good as yours, because I do not know. But I would assume that market conditions will dictate a higher price for renewable energy than for conventional energy. How much higher, I cannot guess.

Okay. Thanks, Dita.

Your next question is from Dan Mannes of Avondale.

Good morning, everybody. A couple clarification questions. First, as it relates to the North Brawley financing, you mentioned the grant. But then, on the slide you talk about the grant being 30% of the equipment cost. Is there a nuance there, or is it 30% of the total installed cost or just of, for instance, the equipment?

No, no. There is a nuance. Maybe equipment -- equipment is the term of the law -- of the tax law. But this means that the - what is excluded from the grant, then, is transmission lines, building and the intangible portion of the drilling cost.

Okay, got it. And then, in terms of the grant, the funding of the grant, is that also conditioned on the plant reaching commercial operations, or can that be drawn during construction at all?

The traditional way of recognizing ITC, which is going to be applicable for the grant as well, is when the project is placed in service. Placed in service means starting to generate electricity in commercial terms, not necessarily commercial -- it's not commercial terms, commercial quantities, not necessarily commercial operation.

Like in the case of Brawley, if the commercial operation expected to be 50MW, the ITC will be eligible when we reach, I don't know, 20MW or whatever is considered. And there is an assessment element in it. Whatever is considered commercial quantity. Certainly, 1MW is not a commercial quantity. Where exactly it is in between, I don't know. One of the changes in this Stimulus Act is that for projects whose construction period is over two years, you can claim the grant also as construction proceeds.

Okay. One other quick question. On the CapEx guidance you gave, which was approximately $250m, if you contrast that with what you're implied guidance was in your Q3 call, it's dropped about $130m. Can you maybe give us a little bit of granularity of maybe what's been moved out of '09 CapEx?

The delay -- the main number is the delay in Brawley. East Brawley. East Brawley was expected to be completed in 2009, it was expected to be an actual site construction as we speak. And, unfortunately, we have not received all the permits. California became a little more difficult. With all the encouragement of renewable energy, permitting is not coping with that and the process of permitting takes longer. And as we speak, we do not yet have the permits for East Brawley and that's why it is delayed to 2010. As a result of it, the CapEx is delayed. Partially it will be done in 2009, but partially only in 2010.

So, as we model this out, should we assume that East Brawley doesn't come on line until fairly late in 2010 then?

Yes.

Okay. And is there any impact from some of those -- from some of the Nevada projects that look like now are either post 2011 or maybe off the charts, things like Carson and Buffalo?

Buffalo and Jersey really were always in our assumptions. It's one part of this agreement which was to be applied either to Buffalo or to Jersey Valley. We think that Jersey Valley will come on line in 2010. And we are very optimistic about McGinness, but this is an optimism before we did the actual exploration. Once we do the exploration, we'll know the results.

Okay. But, Carson, you had mentioned that you hadn't come.

Carson, we need to evaluate if the shallow resource is really a solution -- a viable solution or economic solution for that project. We know that there is a shallow resource. We saw it during the drilling, but we didn't measure it. And for this we need to do some extra work, which we expect to do during the year, in order to get to the answer, is it a viable project or isn't it a viable project? What are the quantities? What are the temperatures? Is it a viable project? So it's early to say. But Carson is -- was assumed to be 15 megawatts, so it's not a big change.

Okay. And then, just lastly, on Puna, two questions there. First, in Yoram's comments you mentioned what time period the revenues should correspond to, and I couldn't quite catch that. Did you say second half of '05 as the timeframe it should correspond to?

Yes, that's what he said.

Okay. And then, secondly, on Puna, relative to the negotiations with HELCO currently, how does the current negotiations correspond with the timing of adding equipment? And do you need to do any incremental drilling, i.e., is there a risk as those negotiations drag out that this one falls into 2010 as well?

There is always a risk, but I think that you need to think of Puna against a backdrop of what the State of Hawaii is trying to achieve in terms of their own RPS. And geothermal being the most viable form of renewable energy, I don't think -- I think that there's -- negotiation is always fun, but I don't think that there's a big risk that that part will not be built. And the beauty of that aspect is that there is very little drilling that needs to be done. And we don't see that as being contingent upon the negotiation with HELCO. So the answer is we're -- we feel that this is -- there's excellent reasons to think that this will be -- will get built in 2009.

Got it. Thank you very much.

Your next question is from Emily Christy of RBC Capital Markets.

Morning.

Good morning.

Question on Sarulla. Do you have any time expectations for that, in terms of (inaudible) receiving Product revenue for that?

I'm embarrassed to say because, if some of you remember, what I've said about Sarulla each time, I think I've said a year each time we are talking. And it is still a year. Until we finalize the Power Purchase Agreement to a point where we are satisfied with date or the consortium as a w hole is satisfied with it, we cannot start the financing process. So -- and, as long as we didn't finalize the Power Purchase Agreement, it is this theoretical one year. Negotiations are now -- are going on now, as we speak. But they need to be concluded positively so that the clock will start running.

And in the negotiations I know you can't give specifics, but are the sides that far apart that it's something you wouldn't want to say will be resolved within a year, or is there any more clarity on what's the hold up?

The hold up is the process of negotiation. Our internal plan is to complete it within the next two months. But will it really happen? I'm not -- I cannot say.

Okay. And then, moving on to the new technology avenues that you spoke about, with respect to the solar, is that going to be in conjunction with your geothermal projects or separate? And then would you be involved as an operator or in the manufacturing and building products side of it? Where do you see yourself falling in that spectrum?

Our geothermal basis is certainly a very good point to start from because we have, in some areas, a large surface and warm sunny places, and that can certainly be a point to start from. But the way we're thinking about solar is not limited to where we have geothermal operations.

And our view is that what we would like to do with solar is very similar to what we have been doing in geothermal, and this is, have some control over core elements of the technology and mostly build, own and operate power plants. So -- however, granted, we're at an early stage and it's almost undefined at this stage. But if we had a choice, this is where we'd like to go to.

Okay. And then just one more question on the oil and gas recovery project. Has that advanced to the point where you see it as a viable commercial application in the near term?

There are areas where it is a viable commercial application, a lot like geothermal. It is -- there is a big scatter between numerous small sources of hot water or hot fluids. But then there are a few locations where the fluids are in large enough volume that it makes sense to build a project -- to build initial projects there. After that, it's a huge potential, but you have to work real hard with numerous small units to tap into this. And for this to be commercially viable you need to have a regulatory environment that mandates this. Technically speaking, we -- the technology is there.

Okay. Thank you very much.

Your next question is from Preetesh Munshi of Piper Jaffrey.

-- Thank you for taking my question. A lot of my questions have been answered. But can you comment on the financing environment for project financing? Given the Stimulus Bill and the attractive provisions there, are you seeing any favorable changes there or expect any favorable changes there?

Two responses. One, there is an ability to do project financing in the current environment already for good projects. Costs are higher than they were last year or two years ago, but there is an ability to do it. What the Stimulus Act will do is it opens the possibility of DOE loan guarantees, which means that it opens the possibility for very low cost of debt.

Now, the reality in the last three years has been that there is -- there was a program of DOE loan guarantee, part of the Energy Act of 2005, which didn't make -- didn't go anywhere. We have not participated in it, but if you hear the other developers, applications have been submitted and it has taken them very long to process them, to approve them. And no approval has been received under this program so far. The current administration in the Secretary of Energy went loud and clear to say they are going to change it. They are going to make this process fast and efficient. Let's hope and see.

Great. And can you just -- in the current environment there are concerns that the energy consumption, especially in the US, might actually fall by 1% or 2%. So, on the demand side of things, what are you seeing in terms of the RFP activities now versus a couple of -- or a few months ago? And also, can you comment a little bit on the activities on the international front? Like there were news recently in Indonesia , building up bidding -- opening up bidding for 15 geothermal fields and similar activities in Kenya and other countries. So can you first talk a little bit about the RFP activities in the US and then some more color on the international activities?

It is correct that demand is dropping in the United States, probably not only in the United States. And the natural result of a reduction in demand for electricity is a reduction in demand of the utilities for renewable -- for new electricity. But this is not the case with respect to renewable energy, because the RPS mandates require the utilities to increase the share of their renewable energy [over the year]. And this increase is higher than the reduction in demand. So we do not see an impact of it on the appetite of the utilities for renewable energy. On the contrary, we see an increased appetite for renewable energy in the utilities with whom we work; that's Nevada, California, etc.

Great.

Internationally, it is true that Indonesia has launched a very aggressive new build of renewable energy. But it is not translated yet into specifics. They have to decide what is the rate at which they're going to buy renewable energy. And there was a proposal on the table earlier this -- actually later last year, the last part of 2008. They are now in the process of revising it. We need to watch them. And we are watching them very closely, but we don't know. It's not something which will happen in the next quarter.

Okay.

It's here longer term.

Great, thank you very much.

You're welcome.

Your next question is from Angie Storozynski of Macquarie Capital.

Thank you. I've got a couple of questions. With the pullback in raw material prices, should we expect that the cost of new builds for geothermal plants is going to come down as well?

And also, for the Products, I'm basically trying to figure out what your future gross margins will be for Products line, which will be impacted by raw materials. But also capacity needs or your financing needs will depend on the cost of new builds and new power plants. So if you could comment on this issue.

And the second one is, what's the growth expectation -- what are the growth expectations going forward, because it looks like we're adding -- you're adding about, well, between 50MW to 60MW per annum over -- between '08 and '10? If I recall correctly, the plans were, well, almost double this rate, so almost 100MW per annum. What is the run rate going forward, say, beyond 2010?

The first question is the one that I cannot quantify, but I can refer to it conceptually. We do see cost of raw materials today at the level that they have been two years ago, so definitely a substantial reduction of cost of raw materials. We have not seen the same reduction yet in the cost of engineered equipment, you know, when you buy compressors, when you buy transformers. We have seen a certain reduction, but of pumps, valves, whatever, but not the full part of it because, there, there is the labor cost and there is the opportunity cost. So we cannot see a reduction equal to the reduction in raw materials but, certainly, a substantial reduction in new build.

As to the growth plan, we had to reduce our growth plan for 2009 and 2010 as we have announce today, due to slower progress on the exploration side and delays in permitting. This we are working very hard to catch up, which means to do more exploration sites in parallel so that, going to 2011 and beyond, we could go back to the rate of growth that we were planning, maybe not 100MW, maybe 80MW or maybe more than 100MW, depending on the results of the exploration. And it is too early to say what these numbers will be.

Okay, that's great. But, trying to quantify the margins again, historically, your Product margins were about, well, anywhere between 15% to 20%. I'm talking about gross margins. And for Electric -- for the Electric segment it was about 35%, 36%. Is it -- do you think that these margins are sustainable? Should we assume a higher, lower number? I know that Product margins are very product specific or contract specific, but is it possible that, now, with a pullback in raw material prices, the margins might expand for Products or not?

No, we are trying to avoid to give a guidance on margins. But let me respond conceptually to you. The reduction in the Product margin in 2007/2008 was the result in the huge increase, I would say, of an uncontrolled increase in cost of raw material. So it's only natural that when a pendulum move to the other side, we will see a result on the other side.

And just the last question. What were the penalties for insufficient capacity factors at some of the plants, the PPAs? I never heard about it before. Is it something that happened in the fourth quarter? And does it have to do with any maintenance work? What happened there?

This has to do with -- or it varies between plants. But, basically, it was the prolonged equipment problems that prevented us from generating the power that we agreed to under the PPA. If you have a short-term problem, it's generally -- you can generally overcome it. And that does not require a penalty.

But if, in a case like Steamboat 2 and 3, where our conclusion was that the equipment issues are too significant to be repaired, and that we actually had to go into a replacement of all the power units and a complete shutdown of the plants and so on, there is -- it's too long of a process to be able to go through it without an impact, which is the case.

And there are other areas that if you have a continuous resource decline and you really cannot -- there is no way to make it up by equipment if the resource is just not there. And the contracts have mechanisms that address it.

Okay, thank you.

Your next question is from Paul Clegg of Jefferies.

Thanks for taking my question. Most of my questions have been answered at this point, but maybe a couple of residual ones. Are you seeing any lack of access to capital causing pullback in interest and REG solutions, you know, customers who want to make the investment but just cannot come up with the funding right now?

No, we have not seen it. We've seen a very strong Product segment backlog, no. The answer is no.

And then maybe a follow up on the previous questioner's comments. Can you talk about how potential project returns for geothermal have changed in the current financing environment? You mentioned that the cost of funding has gone up a little bit, and then raw material cost reductions in -- potentially benefiting in the future. But are they enough to offset the funding cost increase impact to get even project returns? Or are we actually seeing project returns go down as a result of that funding cost impact?

I don't think that they will go down. It's always the question of to which project do you apply it? The funding cost may increase for a project which have been built on the -- during the high construction phase. So on a specific project it may be -- it may have a negative impact.

On the other hand, on new projects, a new build, we definitely don't think that the funding costs will offset construction costs. And I want to emphasize again, the DOE loan guarantee program which will reduce funding costs, not increase funding costs, and that's a huge opportunity. The DOE loan guarantee program is not for innovative projects. It's not for -- it's for any renewable energy projects. And it's -- there is some $60b budget for it. So it's a huge potential for financing at low financing cost.

That's very helpful. Thank you.

Vijay Singh of Janco Partners.

Yes, my questions have been answered. Thank you.

At this time, there are no further questions. Miss. Bronicki, do you have any closing remarks?

I would like, once again, to thank you for your participation in today's call and your continued support for ORMAT. We are extremely encouraged by the prospects afforded to us into the renewable energy as a whole, as well as the confidence in our ability to benefit from these opportunities.

We look forward to future communication. Thank you.

Thank you. This concludes today's conference. You may now disconnect.

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