Good morning. My name is Julian and I will be your conference operator today. At this time I would like to welcome everyone to the Ormat Technologies second quarter earnings conference call. All lines have been placed on mute to prevent any background noise. After the speakers remarks there will be a question-and-answer session. (Operator Instructions) I would now like to turn the conference over to Marybeth Csaby, of KCSA Strategic Communications. Please go ahead.

Thank you, Julian. Hosting the call today at Dita Bronicki, Chief Executive Office; 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 2, 2009. In addition, during this call, statements that maybe made include financial measures defined as non-GAAP financial measures 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 comparisons 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 at www.ormat.com, under the events calendar link as found in the Investor Relations tab. With that said, I would like to turn the call over to Joseph to review the quarter’s financials. Yoram will provide an update on operations and following Dita’s remarks, we will open the call to questions. Joseph, the floor is yours.

Thank you, Marybeth and good morning everybody. We are including certain financial highlights of our company’s state of operations and balance sheet in our earnings release and in the accompanying slides. I would like begin with a review of the main issues that affected our financial results, starting with slide four. For the second quarter of 2009, total revenues were $100.2 million, a 24.9% increase from revenues of $80.2 million in the second quarter of 2008. As you can see on slide five, in the second quarter of 2009, the product segment had significant contribution with record quarterly revenues of $39.7 million, as compared with $18.4 million for the second quarter of 2008. Most of the increase in revenues was derived from EPC contracts, for the construction of two large geothermal projects in Nevada and in New Zealand. With regards to our electricity segments on slide six, despite the strong growth in total generation in the second quarter which was up 14% year-over-year, total revenues in the electricity segment declined slightly due to expected reduction in Puna revenues, resulting from lower oil prices and the ongoing construction at Puna. Moving to slide seven; the company’s gross margin was 28% compared to 28.7% in the same quarter last year. Gross margin for the electricity segment was 25.8%, compared to 32.8% in the same quarter last year. The decrease is mainly due to a decline in the average revenue rate per megawatt hour from $87 in the second quarter of 2008 to $75 in the second quarter of this year. On the cost side, the decrease in gross margin is due to timing of certain maintenance costs, in order to ensure higher availability during the summer. In the product segment, gross margin was 31.3% compared to 14.9% for the same quarter last…

Thank you Joseph and good morning everyone. I would like to start on slide 14, with the operational highlights for this quarter. Our total U.S. and international generation for the quarter was up 14%, to about 811,000 megawatt hours. The year-over-year increase in our generation is a result of new plants that commenced commercial operation and improved performance in some of our existing power plants. For the first six months of the year, total generation was up 18% to about 1.7 million megawatt hour. Now for an update on our drilling activity in the existing power plants; we have completed the drilling and tie-ins for the new wells in Heber and Amatitlan, and successfully brought both facilities very close to their design capacity. Turning to slide 15; since our last call we have been working to resolve the injection challenges in our North Brawley project. Throughout the quarter we have been redrilling our injection wells using a completion that we believe is far less susceptible to long term damage from being trends solid in the geothermal brine. We expect this work to continue through the third quarter. In parallel, we have continued to test different methods to remove large quantities of sand from the geothermal brine. Based on those results we are now sourcing and installing these controlled devices throughout the brine system, and expect to control our total flow within the next four months, with the plant ramping up gradually, starting in October. With respect to our construction activity, by the end of 2010 we plan to add between 72 and 84 megawatt of generating capacity for both geothermal and recovered energy power plants as you can see in the accompanying slide. Work continued in the 8 megawatt expansion of our Puna plant. We made significant progress with the…

Thank you, Yoram. Before I open the call for questions, let me start with slide 21 and talk about the regulatory development. First, the tax credit and ITC grant; as we’ve discussed in previous calls, the Stimulus Act gives companies the option to forego production tax credit or investment tax credit and receive a cash grant from the U.S. Treasury, that will function as an offset of the initial cost of the project. The recently issued guidance, gives more clarity on how to apply and obtain this grant. The grant is a cash payment of 30% of eligible costs, that qualified developers can receive, even if they are not tax payers. The important aspect is that the cash grant can also be claimed on all of the intangible drilling costs at a geothermal project, meaning that between 90% and 95% of the project costs will be qualified for cash grant. Receiving the cash grant can improve significantly the returns of the project. As we mentioned in the last call, we plan to claim the cash grant for the North Brawley project, which is a project that was built at the time when construction costs peaked. For subsequent projects, we will evaluate PTC versus ITC on a case-by-case basis. Second is the loan guarantee program. There are two Department of Energy loan guarantee programs available to renewable energy projects; one called Section 1703, which is under the Energy Act of 2005; and the second, called Section 1704 under the Stimulus Act, which guarantees up to 80% of the loan. To be eligible for 1705 program, projects must begin construction by the end of September 2011 and must create new jobs. We have already filed an application for a loan guarantee for our East Brawley project under the old program and were…

(Operator Instructions) Your first question is from the line of Ben Kallo with Robert W. Baird.

Hi, good morning. I had a couple questions on Brawley specifically. You mentioned ITC was going to cover more of the project than originally you had anticipated, what was the total cost for that project, can you give us that number?

It’s in the order of $300 million.

Okay great, and then when you’re filing the application for that cash grant, does it matter what level the power plant is producing at or is it just on nameplate capacity?

The application for the grant can be applied once the project is placed in service, and placed in service means generation of a certain level of electricity and readiness of the project for operation. So you cannot file an application before you’ve completed construction and you are ready for operation, but the calculation of the grant is based on cost and not on performance.

Okay great, but you mentioned also you’re working on financing for that power plant and you said that you’d have something in the next couple of weeks, but that assumes that would happen before commercial operation?

The commitment, the documentation, can certainly happen before.

Is that something that you could release to the public? When that occurs, you’ll put out a press release on that?

When we sign the commitment?

Yes.

We typically don’t do it when we sign commitments, but we will consider it in this case.

Okay, could you also comment on what the market looks like for new PPAs considering a drop in electricity prices; how much that’s affecting the demand for green power?

I can share with you my personal view; I’m not sure it’s correct or not correct, but our view. Even though we are reading about a decline in electricity demand especially in California, also in Nevada, we see some decline in the increase in the demand. We don’t expect it to impact green power, because all the utilities that I’m aware of are far away from reaching their RPS target and especially the California utilities have signed hundreds of megawatts that I think they know will not come online when expected, and I’m talking especially about the solar thermal projects. So their appetite for green power has not changed despite a decline in electricity demand.

Has pricing stayed stable?

The next question is what will happen to pricing? The big increase in the California MLP prices last year came from two factors; one, was the high gas prices, natural gas prices and the second is the cost of the GHG, Greenhouse Gas Emissions, started to be factored into the long term price of electricity. While gas prices are today very low, probably at the lowest for several years, if you look at the forward-looking curve of gas prices, it is increasing and actually not very long into the future. So even though at least we do not expect gas prices to come back to the levels of last year, we certainly don’t expect them to be as low as they are today. On the other hand, there are people who believe that the price which will be factored into electricity prices in the years to come for GHG is going to increase from what it was last year. So I’m not sure it’s going to stay at the levels of last year, but we don’t expect a very steep decline.

Okay, considering that you expect some increase in electricity prices, how are you handling your PPA negotiations? Are you prolonging them since you do have the financial stability to do that versus the smaller guys out there developing projects or are you waiting to see until electricity prices increase and then sign PPAs?

Depending on what electricity price is at stake, if we have that price that we feel comfortable with we would push. If we think that the price is not as good, maybe we will stall.

Okay, and my final question may be for Yoram. Permitting seems like it’s a bottleneck here and could you talk about anything in legislation. If there is anything that is happening that could maybe facilitate an increase in the permitting process?

I think that maybe it’s not exactly in the legislator, but it is more maybe on the government side of things, whether it’s state or federal, and I think broadly speaking, that it makes little sense for the government to have all these stimulus plans or stimulus money if it cannot be put into work, because the permitting process lags behind. I think that we’re certainly trying to make the involved entities aware of that issue, and that a small investment in providing priority or funding to the relevant agencies could release a lot of work and put a lot of that stimulus money into work, but of course, we can offer our opinion and suggest how things can be done. We have no control over the decision and how much of say, the BLM’s time is dedicated to geothermal, compared to all the other activities that compete on its resources and on the time of its people.

Okay, thank you very much.

Your next question is from the line of Timothy Arcuri with Citi.

Hi guys, its Seth actually. I just want a little further detail on the product segment here. Can you kind of given an outlook for, it looks like backlog came down a little bit here, what the outlook is for kind of the remainder of the year and just kind of some expectations around kind of where; I know it’s going to be bumpy and lumpy but what the kind of outlook is there?

The backlog is $117 million. We estimate our revenues for the total year to be what we said in the guidance, so clearly we are going to start the year with whatever we have today, with a potentially lower backlog than last year, and this is why we say that we do not expect the high volume of products of this year to repeat itself next year, with several factors which may change it. If stimulus money is going to be really released faster, then some of the developers who have projects on their drawing board, may release their projects and we might get a piece of that action. Not all of that action, but a piece of that action. If solar moves to the next stage faster than what we expect it today, it will have a very big impact on our product segment. Things may change and this is why we always say about the product segment. It is less predictable. The electricity segment is predictable. We knew that the revenues this year are going to be lower than last year, because we knew that oil prices which were so low in the first quarter, are going to have a long term impact on the rates in Puna, but our generation was predicted and 14% increased in our generation, in the growth in the electricity segment. In the product segment it’s less predictable.

What’s the kind of timing for completion on Blue Mountain and Centennial?

Blue Mountain is virtually complete. I mean those are in the press releases issued by Blue Mountain. The plant didn’t undergo yet testing, but the construction is virtually complete. Centennial will go until the middle of next year I believe.

Then just one last quick question; I was curious about your thoughts in terms of your cash balances here with where the stock has gone at this point. Is there any consideration for maybe shoring up cash balances and funding there with some equity in the near future or not?

I can never say ahead of time when there will be a circumstance that will justify another equity offering, but the way our balance sheet is today, very low leverage, it makes most sense to continue to fund with debt than with equity.

Alright, thank you.

Our next question is from the line of Paul Clegg with Jefferies.

Hi, thanks for taking my question. I’m trying to understand the gain from equity sale at the OPC level for tax equity that runs through the income statement. Basically, which facility is that going to fund and how should we think about that type of gain as an item on your income statement going forward? Should we see any more of that type of impact for the rest of this year for example?

The amount of the gain is dependent on the tax benefit that we get and this is accelerated depreciation and PTC. Now in the future, in this year there shouldn’t be a big change, but in the future, once accelerated depreciation is utilized then it will go down of course, because it will be only PTC.

Okay, can you say how much of it in this quarter was actually cash of the gain?

Cash to the investors? Nothing.

Nothing, okay so it’s really just an accounting. On CapEx, it was a little bit higher than what we are looking for and I think you’re holding CapEx guidance flat for the year, but you’re also looking at a delay at North Brawley. So I was wondering, what the puts and takes are there, that we would think that was a delay in North Brawley, you might have somewhat lower CapEx.

The lower CapEx is not resulting from North Brawley. On the contrary, North Brawley has a cost increase, because we are dealing with the sand issue and the well completion issue. The reduction in the CapEx for this year is coming from a delay in East Brawley. As Yoram mentioned there is the permitting delay and the lessons learned from North Brawley, a combination of both, which delayed East Brawley and a delay in exploration which is probably the most helping one, because the delay in exploration is coming from the delay in getting permits to explore this site. This means that at the start of construction of the project, they are supposed to be built and the results of those explorations might also be delayed.

Okay, thanks very much.

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

Good morning. Just a couple of clarifications first; with the electricity segment revenues going from a 87 megawatt hour to 75, is that all attributable to Puna?

A lot of this is Puna and there is also the phenomenon that we had described in the past, which is the rates on some of our newer PPAs are not as high as older PPAs and as we bring more new PPAs or we brought more PPAs, the dates to say, 2005 to 2007, 2008, the combined rate is reduced, but Puna is really the biggest factor.

Okay and in terms of North Brawley, you’re going to start the ramp up October. When do you expect that to be operating at full capacity?

The fine line in my statement, that we hope to control all the brine flow in four months, meaning that we’ll have full brine capacity and therefore full generation.

Okay and just one other question. There’s been some consolidation among some of the smaller geothermal entities, also some new technologies being installed by your competitors. I’m just wondering what at this point your view is of the general competitive landscape, and at this point if any of these entities might be big enough for you to buy?

I think it was slide 17 that we listed, what we thought were the biggest factors affecting growth and I’d say that the first two are; you need to have land, but you also need to explore it and actually approve and turn the acreage of empty land into actual resource and I think that this is where one can hope that the smaller entities that have land positions, truly have resource under those lands, but it’s far from being certain and even after you have resource, there is the question of whether you can economically develop it. So, I think that probably for the entities, if they do this of their own free will, then probably for them it works well, but I think that until they have actually proven their properties, they remain just prospects. It takes a lot of effort to actually prove it. It’s not even one discovery well; to prove that indeed you have 30 megawatts. So to say, if land or the value of land is highly dependent upon what work was actually done on it and as you can see in BLM lease sales, it goes from a few dollars an acre to maybe thousands of dollars an acre, depending on what is there and that’s our view on the land positions of other players. As far as new technologies, of course we have a view and that it’s true if somebody owns the key to a technology that is unique, then it could be better for that company than when there is multitude of players, but the advantage that we offer is that our equipment, we don’t sell technology, we sell a solution in the product, in one that is well tested and has been running for 20 years and for an operator, that should be a great comfort and a great differentiating factor. A lot of the other players have started pretty much where we stopped 20 years ago, and if you take a close look at this, I think that it’s telling quite a lot.

Okay, thank you very much.

Your next question is from the line of Noah Houser[Ph] with Barclays Capital.

Hey everyone, thanks for taking my question. My first one is around the loan guarantee program and the chatter that’s going around about $2 billion that was earmarked initially for the program going over to the Clunkers. I wasn’t sure if you guys had any additional color that you could give us around what you’re hearing and how that changes or meet the outlook a little bit longer term?

I’m not sure to what position that goes back to Clunkers you are talking about?

It appears that in the house bill, that was going to funnel $2 billion more dollars over to the Cash for Clunkers program for the autos, that $2 billion was going to come from the money that was going to go for the renewable loan guarantee program.

I don’t know. If its $2 billion, the total loan guarantee estimate that was issued when the Stimulus Act was enacted was $60 billion, I’m not familiar with it, but I don’t know that it will have any impact.

Okay and then just kind of one other one; it seems that the effects from foreign currency transactions to translation kind of flips back and forth. Can you just give us a little bit more color around the biggest drivers that move that and what we can best watch to have an idea how it’s going to move quarter-to-quarter, year-to-year?

It’s very difficult to estimate it, and the reason for that is it most relates to the fluctuation of the dollar against the Israeli currency, where our manufacturing operations are. It depends on how we hedge it and what is the result of the hedge. The accounting treatment for debt is that we are not considering it a hedge for accounting purposes because of the very complicated write up, so it might change from quarter-to-quarter and we cannot expect that the dollar is strengthening and devaluating against the Israeli currency. Also part of it relates to a loan that we have in New Zealand. The impact this quarter was not so much, but we gave a loan to a New Zealand company in New Zealand dollars and it depends also on the valuation of the U.S. dollars or the New Zealand dollars. Once again, it seems this company’s functional currency is New Zealand dollar, then the impact is immediately in P&L.

Okay, that’s everything. Thank you.

Thank you.

Your next question is from the line of Angie Storozynski with Macquarie.

Thank you. I have three questions. Starting from the product segment, the $117 million in backlog, when would that be realized? Is that just for 2010 or beyond?

No, there is nothing beyond 2010.

Okay, now the two projects, the Blue Mountain and Centennial, that contributed so highly to the second quarter; I mean, I’m just basically trying to realize if the fact that the backlog is coming down and that coincides with lower commodity prices. Are you seeing less of a demand for your product, because the commodity price environment has changed? Is there any link between these two?

The simple answer is no. There is no linkage between commodity prices and demand for a product and by the way, we are starting to see an increase in commodity prices in the last few weeks.

Could you disclose the total amount you applied for in the federal funds, so all these applications for loan guarantees and I think the drilling program?

I prefer to disclose it once they are approved. I prefer to disclose once we know what is approved.

Okay, and lastly I just want to go back to the question about PPAs, and you were saying that you don’t see any increase in appetite for PPAs and that State renewable portfolio standards are far to be fulfilled, but especially in California we’re seeing utilities assigning PPAs with solar companies, and we’re hearing that the compliance, especially with California, RPS would be on a best effort basis and so not necessarily you would need to have the capacity in place to be compliant with the standard. How do you think that may impact your growth prospects in the State?

From everything we hear and feel from the utility, they are taking seriously their RPS target and are making every effort to fulfill it, so I don’t think it will reduce the demand for renewable energy.

Okay, thank you.

I’d like to add to it another thing. I think that one should recognize that it’s not enough to fulfill the demand like a capacity requirement, but also the utilities would need some renewable energy to be of a base load nature, which is geothermal. There’s only so much that can be taken as an intermittent solar on the grid and as it becomes more sizeable in the California energy mix, then actually there is more need for renewable energy like geothermal, which is base load.

Okay thank you.

Your next question is from the line of Brian Shore with Avondale Partners.

Good morning everybody, just a couple of quick questions, most of ours have been asked already. I guess first on the power side and particularly on margins and cost, can you guys sort of walk through a little bit in more detail, why they were a little bit more depressed than usual this quarter and then sort of your expectations for margins on the power side, on the back half of the year?

I think that actually costs have not varied that much. On the operational side we have fairly good cost control and the variances there are not huge. The margin has been largely determined by rates that have changed. I think that’s the way that you should look at this. Of course, Puna is always a plant with favorable rates and having to do a redrill program now had an impact on us, but if you take the reverse look at it saying that this redrill work had to be done, then it’s probably a good thing that we have done most of it during times of rather lower rates than higher rates. The fact that this happened in quarters that are traditionally strong quarters for us puts a spotlights on it, but that’s just the way that it is. We always want to do better, there’s always better to have better PPAs rather than weaker PPAs, but all in all, I don’t think there was anything dramatic that happened on the power side.

Okay, so the maintenance that you guys talked about, that was mostly at Puna?

No, there’s maintenance across the Board. We always have some maintenance that is done in preparation for the peak period. We try to do a lot of this in the fourth quarter and in the first quarter, because this is when ambient conditions are the easiest, but there is some that is done on second quarter and is reflected in that, but it is true. I would say within $1 or $2 per megawatt hour in operating cost, it’s not the big picture. The big picture is just a very different mix of rates for this quarter and then some lower generation because of work and other issues that affect our total net megawatt hours and since the number that we disclose is an average number, or comes out as an average, this is how we see it.

Okay, that’s helpful, and then I guess just following up real quickly on North Brawley, you guys mentioned doing redrilling as well as some of the solid content issues, the sand issues, can you sort of walk through I guess maybe on the redrilling side, what’s precipitating that?

Yes, if you imagine a system where the production wells produce sand and fairly substantial quantities of sands. We’re talking dozens of pounds per hour of sand that is being produced by each well. Then clearly that sand won’t be missed on the production zone, but if it gets into an injection zone, it’s not the greatest thing to have, because basically it’s as if you were pouring sandbags into your injection well and intuitively you would understand that this would cause grief. So first we’re trying to get the sand out of the hot water as best we can, to reduce the number of bags that we pour into the injection well, but then once the sand is in the injection well, we need to design the well in a way that the clean out process would be the most efficient, so that whatever sand did make it into the well could be taken back out and won’t be stuck between the well bore and the reservoir, because once it gets out of the casing or out of the liner, it’s very hard to pull it back out. This requires a slightly different completion in the injection zone itself, moving from smaller liner to a solid liner with perforations is less susceptible. So it’s a fairly standard solution and each carry. The slot liner has its advantages and it allows for higher injectivity, on the other hand it’s not as easy to clean, at least not in our situation, but that’s fairly standard.

Okay, that’s helpful and then just lastly, moving I guess over to the East Brawley project and I guess two things here; one, can you maybe shed a little light on where you are in the permitting process there? I know you mentioned some improvement, maybe a little bit more color there. Then just verify I guess the issues that you’re seeing at North Brawley and the delays at North Brawley aren’t necessarily, I mean you don’t expect those to impact the timing I guess or more so, the operation of the East Brawley project.

I’ll start with the second question. The issue that we had is mostly removing sand from water, it’s something that doesn’t require breakthrough in technology. The problem that we have is that the type of water, the temperatures and the pressure that we work in on the geothermal side is not what you’d typically have in commercially available water treatment systems, we’re just too hot for that. So the problem that we have is that as we’re experimenting or trying to fine tune different control devices. We can’t enjoy anything that is off the shelf and everything is special orders, so it’s really a development project in an ideal case should be done before you build your full fledged facility. This is very unfortunate in the case of North Brawley, but whatever is done there would be applicable for East Brawley and on East Brawley, we have the time. Looking at the completion at the end of 2010, we would have the time to special order almost anything to deal with it and this is why we don’t think that. Let me put it this way, we think that we understand that the issue is the sand. We know that sand can be removed and therefore we don’t see this as being on a critical path for East Brawley. As for the permitting side, as we described in our last call, what was keeping us from moving ahead and getting our permit were some of the water issues in the Imperial Valley and based on everything else that we know, this problem seems to have been solved.

Okay great. That’s very helpful. Thanks a bunch guys.

Your next question is from the line of Brian Yerger [ph] with Erica Advisors.

Thanks for taking my call. I just had a question revolving around the new technology and competition that’s emerging out there. What is your outlook and kind of your approach on the recovered energy market in the U.S.? Are you seeing projects that are just too small for you guys to focus on, and that would I guess apply both for the products and the electricity side.

The first answer is, we don’t see any project as being too small for us to focus on or almost, but I think I would say that the factor that would change recovered energy generation in North America is having more states that would accept this for what it is, which is really the nearest thing to renewable energy, because energy efficiency is as important and may be as a much lower hanging fruit. The reality is that recovered energy generation is not viewed by many of the states that actually have it, if you’d like to resource. The ones that have waste heating being or heat being wasted, these states don’t recognize that as an RPS type technology and therefore it doesn’t necessarily get the right treatment. In that sense, a four megawatt or five megawatt project would always be at a disadvantage, compared to a 100 megawatt base load project of our projects. So if you treat to the same, it’s hard to get them to expand quickly. What we think is that they should not be treated the same and that REG projects should enjoy better rates comparable to the other renewable technologies and we also think that in the foreseeable future this would happen, because CO2 is an issue.

Okay so let’s move away from the RPSs just for a second, just look let’s say an enterprise, a corporation that has some waste heat that may or may not and I guess this is a question for your guys; that may or may not be suitable for your technology because we’re seeing some lower temperature technologies coming out. Are those the type of opportunities that you would go after or are you just kind of letting that portion of let’s say, the emerging business be left to the competition right now?

If an enterprise has available waste heat, that’s certainly interesting for us.

Okay, on the products side obviously.

Either product or electricity side, we’re very flexible in our business model. By the way, waste heat is generally not low temperature. It’s generally higher temperature than geothermal.

Okay, so you wouldn’t have any problems obviously on the technology side. Okay, that’s all I had, thank you.

Ladies and gentlemen we have time for one or two more questions, and your next question is from the line of Jessie Pichel with Piper Jaffray.

Hi, this is Ming Chu for Jesse Pichel. Thanks for taking my questions. Can you give us some color on whether the gross margin is sustainable? Do you anticipate any impact from the recent trend of commodity prices?

I think we have said from the beginning of the year that the gross margins which we are seeing in the product segment we not plan to continue or not intended to continue in the years to come. They are a consequence of changes in commodity prices, but they are not expected to continue in the years to come.

Great, that’s very helpful, thanks.

Your final question is from the line of Patrick McGlinchey with Sidoti & Co. Patrick McGlinchey - Sidoti & Co.: Good morning, just a couple of follow ups on that product segment. With regards to the guidance increase, was that strictly a result of accelerated timeframes instead of construction and deliveries?

Sorry, can you say it again? Patrick McGlinchey - Sidoti & Co.: I’m sorry, with regards to the guidance increase on the products side of the business, was that strictly a result of accelerated timeframes of construction of the projects and accelerated delivery times of turbines and whatnot?

Yes, but not necessarily turbines. Turbines we control, but other components. Certainly delivery times have been shortened this year, because of some lower economic activity and we have benefited. Patrick McGlinchey - Sidoti & Co.: Okay, and then just with the backlog now at $117 million with the guidance, I guess we’re implying back half of somewhere between $53 million and $63 million. If we were to assume that the backlog would be realized over the next 12 months, are we looking at something similar in the first half of 2010 as the second half of 2009, somewhere in the $55 million to $65 million range?

We don’t have yet a guidance for 2010 and I would refer it to our next or the following call, please. Patrick McGlinchey - Sidoti & Co.: Is it safe to assume though that the backlog should be realized over 12 months?

Not more than that, because it’s all to say 2010 and probably it will be realized, this backlog, before 2010. Patrick McGlinchey - Sidoti & Co.: Okay great, thank you.

Ladies and gentlemen this concludes the Q-and-A portion of today’s conference call. I’ll now turn the call back over to management for any closing remarks.

My only remark is thank you for the lively and interesting conversation. I hope it clarified things for you as it did for us. Thank you.

Thank you all for participating in today’s conference call. You may now disconnect.