Good morning, and welcome to the Ormat Technologies Second Quarter Earnings Conference Call. (Operator instructions) Thank you. I’ll now turn the conference over to Robert Fink of KCSA Strategic Communications. Please go ahead, sir.

Thank you, Carrie. Hosting the call today are Dita Bronicki, Chief Executive Officer; Yoram Bronicki, President and Chief Operating Officer; and Joseph Tenne, Chief Financial Officer. 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 company’s Annual Report on Form 10-K filed with the Securities and Exchange Commission on March 8, 2010. In addition, during this call statements that may be made that include financial measures defined as non-GAAP financial measures by the Securities and Exchange Commission such as EBITDA. These measure maybe difference 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 other 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 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 at www.ormat.com under the webcast and presentation link as found in the Investor Relations tab. With that said, I would now like to turn over the call to Dita for her opening remarks.

Thank you, Rob. Good morning to everyone and thank you for joining us. As we review the results of the second quarter, let me emphasis a few points. The results of the quarter are primarily impacted by North Brawley, which is operating a partial load. This has lead to low revenue of $2.5 million and high operating cost of $11.9 million. Second element of the exploration expenses to Gabbs Valley, and third R&D cost related to a rig project at an LNG terminal in Spain, which when completed will be recognized as revenue. We will discuss later on these call achievements of the important business goals, which will further advance our work claims. I will turn the call over to Joseph for the review of the quarter financials. Yoram will then update the status of operations and following my remarks, we will open the call to questions. Joseph, the floor is yours.

Thank you, Dita and good morning, everybody. We’ve included certain financial highlights from our company’s statements of operations and balance sheets in our earnings release and in accompanying slides. I would like now to review the main issues that affected our financial results this quarter, starting with slide four. For the second quarter of 2010, total revenues were $96.3 million compared to a $99.5 million in the second quarter of 2009. As you can see on slide five, this quarter the Electricity segment had revenues of $68.8 million, a $9 million increased from the second quarter of 2009. The 15% increase is the result of some additional capacity with North Brawley contributing $3.5 million in this quarter along with increase generation from most of plants in particular the Puna power plant, which is back in full capacity. Electricity segment revenue increase resulted in slight increase in the average revenue rate of our electricity portfolio from $75 per megawatt hour in the second of 2009 to $78 per megawatt hour in the second quarter of 2010. In the Product segment on next slide, this quarter, revenues were $27.5 million compared to $39.7 million in the same quarter last year. Revenues and corresponding margins are down from record high in 2009 and we expect that this will continue throughout the year due to a decline in the product backlog from last year’s high levels. Moving to slide seven, the company’s total gross margin was 19.4% compared to 27.7% in the same period last year. Gross margin for the Electricity segment was 17.7% compared to 25.3% in the same quarter last year. As Dita mentioned, the main contributor to the decrease in the gross margin is related to the North Brawley power plant. In the Product segment, gross margin was 48.6%, compared to…

Thank you, Joseph and good morning everyone. I would like to begin with slide 17 for an update on our operational activity. Total generation from our US and international plants increased 11% to about 880,000 megawatt hours. Noteworthy events this quarter were Puna’s return to full capacity following the completion of the well field word and important progress in Brawley, which we will expand on. We were also impacted by and recovered from three natural disasters. The magnitude 7.2 El Mayor earthquake in April that affected our plants in the Imperial Valley and the volcanic eruption and the tropical storm Agatha that affected our Amatitlan plant. Through the expeditious work of our teams, these events had only a minor impact on generation and all of the plants had been brought back to normal conditions with Amatitlan returning to full par yesterday. However, repair work did cost higher operating cost during the quarter, but some cost it will be carried to the following quarters. Moving to slide 18, for a detailed update on North Brawley. As Dita mentioned, the loss from Brawley has been affecting the gross margin of the company as a whole. Besides the depreciation, the losses, the result of the low output and high operating cost, element that we have been working to address. There are three cost areas that are disproportionate compared to other facilities. Brine processing, manpower and Well field work. On the Brine processing, we continue to work on a sustainable solution for the injection problems, and by the end of the second quarter almost eliminated the use of disposable filters. This reduced the operating cost in this area by almost 75% and we expect the continued reduction as we install additional ancillary equipment. The difficult Brine processing carried with it additional labor cost, which…

Thank you, Yoram. Starting with slide 25, let me elaborate on a few business developments and financing points that I mentioned earlier. In June, we submitted an application for an ITC cash grant for the North Brawley power plant. We expect to receive approximately $100 million shortly, a substantial contribution to our liquidity for funding capital expenditures in the months to come. Additionally, as recently announced we have signed the term sheet with John Hancock Life Insurance Company to provide debt for a senior secured construction in term loan of up to $350 million. The credit facilities will be used to finance the construction of the McGinness Hills, Jersey Valley and Tuscarora projects. As Yoram discussed earlier, the construction of the first phase of all three projects has already commenced and represent a total of approximately 60 megawatts. After completion of phase I of each project, and in line with our revised approach to development, we will assess the feasibility of the second phase of each project, which if successful could increase the size of these projects up to total 520 megawatts. As you know, the DOE section 17 of five long guarantee programs is that from the RIA of 2009 and allows the DOE to provide a long guarantee of up to 80% of project cost. We have submitted Part I of the total guarantee application to the DOE. After it is approved for eligibility, Part II of the application will be submitted subject to due diligence by both the DOE and the lender applicant, a conditional commitment for the financing will be issued followed by financial close. The experience of others tells us that it is a long process and might take six to 12 months. Yesterday, we announced the issuance of seven-year senior unsecured bonds with another…

(Operator Instructions) Your first question comes from Steve Milunovich with Merrill Lynch. Steve Milunovich – Merrill Lynch: To the recovery you’re expecting in North Brawley, how long that’s going to take and roughly when you think that’ll get back to more normalized margins?

We think that North Brawley will reach a breakeven point sometimes in 2011, second half of 2011. And then as of 2012, normalized margins with one caveat and this are the depreciation cost of North Brawley are going to be higher than normal. The total cost of Brawley are still the reduction of the ITC cash grant going to be in the order of $270 million, which is a very high cost for a 50 megawatt project or above $4 million in megawatt. So, depreciation costs are going to remain higher on Brawley. Steve Milunovich – Merrill Lynch: And you said you think you can get to that 50 megawatt rate by yearend? And if that’s true, why is not breakeven until sometime in maybe the second half of next year?

Yoram mentioned that the operating cost in the early yield of the projects because of the heightened content in the project are going to be higher with one major item is upon replacement, which are going to be more frequent in the early yields until the whale are clean themselves from heightened content and then it will reach the – we hope it will reach the normal level of the Imperial Valley project, which are all higher operating cost than these other projects. Steve Milunovich – Merrill Lynch: I see. Okay. And then finally, any update of comment on permitting which you’ve mentioned in the past has been slower than you’d like?

Something is slower than we like, but we just build into our program and just include it in our program. If you can’t be then slower, then I hope that we are now just taking it into account. There is a major effort of the industry and the BLM to accelerate the permitting forces. I cannot say that we are seeing it, good results, but I can say that the effort is going on and hopefully we will see and improvement.

You’re welcome. Steve Milunovich – Merrill Lynch: Great. Thank you.

Your next question comes from Elaine Kwei with Jaffray. Elaine Kwei – Piper Jaffray and Company: Hi. Thank you so much for taking my question. Just a little clarification. If North Brawley was placed in service in January, could you help us understand why the gross margin was down so much more in 2Q? Was that due to extra repair expenses, or was there a decrease in production from 1Q to 2Q?

There wasn’t a huge difference in operating cost of Brawley is actually – I think that operating cost in the second quarter were slightly better but I think that the impact given all the rest of the mix that was happening in the company, the impact is just different. Brawley by itself is not, first quarter was a full quarter last two weeks. So, it was about the same. Elaine Kwei – Piper Jaffray and Company: Okay, but the 2Q margin decline was attributed primarily to North Brawley?

Yes, but it wasn’t – it’s just not – I should have say I mean it’s the margin in Q2 is not good with Brawley being the first, the biggest impacting factor, but Brawley was the same in the first quarter as well. It’s just that there were other good banks happening. Elaine Kwei – Piper Jaffray and Company: Okay. Got it.

So, overall margin was better. But the plant itself is not much different. Elaine Kwei – Piper Jaffray and Company: Okay, understood. And then the increase in guidance for the electricity segment is that purely from Mammoth or is there also some strength from pricing that you’re seeing?

No, it’s purely for Mammoth. Elaine Kwei – Piper Jaffray and Company: Purely from Mammoth. Okay, great. Okay. And just lastly on the purchase price for Mammoth. I was wondering if you could give us a little color into your thinking and how you arrived there and if you had an IRR target in mind, just to get a little bit of an understanding and what you think the potential would be for growth and expansion.

I can tell you two things. Number one, we arrived at the price by the mixing of the mind of the seller and the buyer, so that’s the negotiated price. Elaine Kwei – Piper Jaffray and Company: Right.

The way we look at it is we allocate some portion of the project site to the existing operating assets and the certain portion of the purchase buy so the potential in this site is a big potential and that these are the two components. We don’t have yet a number for the purchase price allocation. We have 90 days to agree on it, so we can’t share with you something that we don’t have. Elaine Kwei – Piper Jaffray and Company: Okay. Well thank you so much.

Your next question comes from Lasan Johong with RBC Capital Markets. Lasan Johong – RBC Capital Markets: Thank you. I’m a little puzzled. The backlog on the product segment is down something like $26 million from the end of March, but obviously there’s acceleration in geothermal projects. What’s driving that? And then related to that, the margin popped dramatically versus last year on the product segment. What’s driving that?

Let me start with the margin. There is a project that we successfully completed this quarter and there were some contingencies on these projects, which were clear in this quarter when we successfully completed and we were able to include those revenues in Q1 and that’s the reason for the high margin. You should not expect such a margin in the next few quarters. As to the backlog, that’s the current situation. As we said in the past, we expect towards the end of the year maybe beginning of 2011 to get more orders for new geothermal projects especially in the U.S. Lasan Johong – RBC Capital Markets: So you expect the backlog to improve over the next couple of quarters?

Yes. Lasan Johong – RBC Capital Markets: Okay.

We hope so. Lasan Johong – RBC Capital Markets: The timing of the Spanish LNG recovered energy generation project revenue; you just mentioned something like $13 million. When would that be coming and are there similar projects coming down the pipe?

Again, the contract there is a little unique. So, for us to recognize this as revenue, the plant itself would have to be operating. It’s not enough for it to be complete and on that there is a component of course that we’re responsible for, which is building the plant. But then our host there needs to do its own interconnections and allow us to run the plant or do what is required for us to run the plant and therefore, although we expect to probably complete the plant by the end of the year or very early in 2011 when exactly would our host would be ready, we don’t – we can’t control this. I mean we expect this to be later in 2011. My guess is towards the end of the first half of 2011. And I’m sorry, what was your other question? Lasan Johong – RBC Capital Markets: Do you expect other similar projects to follow?

This is truly – I believe it will be the first of its kind in the world. So, it’s a very important demonstration project. And there is a substantial potential in the world, it’s a few hundred megawatts in that area. However, it’s an add-on to the not only to the gas industry, but specifically to the LNG industry that has its own cycles. And so I think that on our part, it’s very important that we demonstrate the viability, the technology and show some substantial record there. But if I would have to guess, it’s a few years before this can be adopted in a larger scale and it would require recovery in the LNG industry, which during low natural gas prices is generally not doing that, not doing too well. Lasan Johong – RBC Capital Markets: Understood. What is the impact of the natural disasters in the second quarter?

I think it was the biggest impact was at Amatitlan, which was operating at – I think at the top of my head, I think that we generated about 70% of what we plan to generate. So, that was the biggest impact. Lasan Johong – RBC Capital Markets: What was it in terms of earnings per share or EBITDA or revenue?

I don’t know. It’s not material, under –

It’s under $1 million. Lasan Johong – RBC Capital Markets: Perfect. Last question, Dita, did you say that Jersey Valley, McGinness Hill and Tuscarora could be 120 megawatts? The slide shows 61.

Phase I is 61. Now, the way we are approaching the development now and I think we shared it with most of you during the analyst day and they thought we are doing now is developing each project in phases, not building a large project and then finding out that the resource maybe a little different that’s one with what we predicted it to be. So, take McGinness, for example, there are good chances that it’s a 60 megawatt resource. We are developing 30 megawatts as phase I. We will run this phase I for a period and once we get the comfort that it can support an additional capacity, we will increase it, exactly as we have done at Steamboat and as we are doing now in Kenya with the Olkaria additional plants that is currently under development. So, these three projects have all been selected to be implemented using the same philosophy. Phase I first, test it, and then add add-ons as the resource can support. Lasan Johong – RBC Capital Markets: Understood. Thank you.

Your next question comes from Dilip Warrier with Stifel Nicolaus. Dilip Warrier – Stifel Nicolaus: Good morning. Thank you. I was wondering if you could address perhaps what you’re seeing on the competitive landscape on the EPC side. It looks like a couple of projects here in the US were awarded – are being constructed using some form of lender financing. Is that something of a trend you are beginning to see here?

I think that it’s really a reflection of the situation of some of the developers in the U.S. geothermal industry that have potentially have prospects or sides, but are very limited in terms of their financial means. In that sense, if a vendor could provide the financing, it’s certainly good for the developer and maybe good for the vendor. So, I think that more than anything else it’s a reflection of a state of the developers, but that would be my guess. Dilip Warrier – Stifel Nicolaus: Okay. Is that something that you would be willing to consider, vendor financing?

I think that it’s – it has to be something. It has to be to make sense on a case by case basis. We basically share with you fairly openly what are their challenges in developing geothermal projects and sometimes they could be quite substantial. So, if you provide vendor financing you need to make sure that you’re comfortable with the resource risk that now is not for you to resolve but for the developer that you’re offering the vendor financing to. If you look at our North Brawley example, which is certainly it has been a challenge. It requires a company like Ormat to resolve situations like these and not everybody is – not every company is either willing or able to overcome issues like this and if you’re the vendor that provided the financing that’s something that you seriously need to consider. So, I think that it has to be done on a case by case basis and like any company that provides a construction loan; the vendor has to be comfortable with the site. Dilip Warrier – Stifel Nicolaus: That makes a lot of sense. The $140 million bond issuance, is the thinking here to kind of accelerate the construction here in the US to maximize the number of projects that can qualify for an ITC grant? Was that the thinking behind this?

This was the part of the thinking. It goes into a bigger picture, of course, which states that as our balance sheet was not very leverage and actually is not very leverage about 45% to total capitalization, which is a low leverage. This means that the next funding shouldn’t come from equity, but should come from that in the high yield bond. It’s just one step towards achieving that. Dilip Warrier – Stifel Nicolaus: Got it. One last question. Given this experimental rate project you’re working on, are you expecting R&D expenses to continue at similar levels for the foreseeable future?

I think that is unique. We generally have R&D activity, but are generally not a full size project that is being built. So, I would say that the LNG plant is really a high water mark, if you’d like, at least for the foreseeable future. Dilip Warrier – Stifel Nicolaus: Okay, so does it make sense that the R&D expense could potentially sequentially decrease?

Yes, that’s our – at least based on our plan for now. Yes. Dilip Warrier – Stifel Nicolaus: Thank you.

Your next question comes from Brian Shore with Avondale Partners. Brian Shore – Avondale Partners: Hey, everyone. Thanks for taking my questions here. Just a quick question, again, following up on North Brawley. It looks like with the cost issue identified going up from I think $9.5 million to $11.9 million from first quarter to second quarter, I know that the project wasn’t on line fully in first quarter. I just wanted to make sure, so you haven’t seen acceleration in cost there on the operating side?

It’s actually on the contrary. We are seeing and I was a little too detailed, but in some areas we have reduced throughout the quarter, we have reduced our cost by as much as 75% not on everything, of course, but we see a reverse trend. Most of it was happening towards the end of the quarter. We started the installation of the new equipment very late in the first quarter, but most of it was installed through the second quarter towards the end of that. So, in the second quarter, we don’t see this. We should see cost reduce further in the third quarter. But the real issue in Brawley is, of course, getting more production and getting more generation out that this is what it’s going to change the picture dramatically and this is something that we know we can’t accomplish before the fourth quarter just because of construction timing. Brian Shore – Avondale Partners: Okay.

But I hope that this is clear. Brian Shore – Avondale Partners: Okay. Is there – I guess can you talk a little bit about when you think it may be – you may be able to get the project financing on it and has that changed at all over the last – I guess since your last quarter?

No, it has not changed. It’s towards the end of the year. Brian Shore – Avondale Partners: Okay. I guess then separately on I guess maybe on the loan guarantee, Dita, can you kind of talk about sort of your confidence in moving forward? How confident are you that the steps you’ve taken with the term sheet with John Hancock – if you’ll be able to sort of get the loan guarantee? I guess in general how confident are you in the program as a whole?

One of the reasons that we decided to go with John Hancock is the track record that John Hancock has with the DOE. They have been able to move one project past conditional commitment and this is the Nevada Geothermal. In fact, that we are going with John Hancock in its experience and the fact that it is the one-stop shop. We are not dependent, not on capital market and other structures without available in the market. They do give us the confidence of the closing. But is also important to note that we are not waiting for it one day, I mean we are sure that Jersey Valley will be complete before we gave the deal with loan guarantee and if it’s going to be a refinancing and not a standing of construction loan. And the other two projects, Tuscarora and McGinness are going to be well advance in construction before we receive the DOE money. But it is still a source of locals money and I think that we shouldn’t give up on this opportunity and that’s our approach to it. Brian Shore – Avondale Partners: That certainly makes sense. In the first quarter I think you guys hinted at or you at least discussed being in early stages of discussions on a potential acquisition. I was just going to see if you had an update there?

Yes. We have it earlier this week, the 50% of Mammoth. Brian Shore – Avondale Partners: Okay. Okay. I just wanted to confirm that. And then the last thing, there’s been quite a bit of press in Israel about your relationship with one of the large shareholders over there, and we’re just going to see if maybe you could provide an update and some thoughts on kind of the status and how things are progressing in that situation?

All right, with pleasure. The press was much stronger than the reality, but probably the nature of this place. They are taking some agitation and there was some agitation and blowing this up to totally out of proportion. But there was an attempt by a large shareholder of the parent company to a change in decisional recommendation of the Board for two outside directors that their term came up for renewal, in the Board so that they are Board Directors and that at the general meeting should approve their renewal for a second term. Because of the request of the other shareholders, we have proposed or the Board has proposed to other outside director and then this shareholder got upset with all his request to appoint two different outside directors. And all expectations are and there is no reason for anybody to think that it’s once said in – that in the annual meeting that is scheduled for either the last day of August, the two proposed outside directors will be approved and they are as good, if not better, than the incumbent outside director. And we have certainly interested shareholders and we think that if the dialogue is going to benefit the company. Brian Shore – Avondale Partners: Thank you very much. That’s very helpful. Thanks, Dita.

Your next question comes from Angie Storozynski with Macquarie. Angie Storozynski – Macquarie Research Equities: Thank you very much. Two questions. First on the Mammoth acquisition. It seems like it was relatively expensive, about $5,000 per kilowatt. Is that simply a price of existing assets that you see in the market place, or is this somehow related to expansion abilities or existing PPAs or future PPAs for this capacity?

Yes. The answer is that there’s a certain portion there that is for existing plant and if you’d like to existing PPA. But a lot of the justification is really the fact that this is one of the best known reservoirs in the United States. The only other similar reservoir that we know is Steamboat, which we already own. And once you recall the story of Steamboat, we were able to more than double capacity in Steamboat and we believe that Mammoth is similar or even has a greater potential – not everything can be done immediately. It has some of its own constraints, but it’s in our opinion, it’s a gem and therefore, it’s worth the money, and not only the acquisition cost, but also additional investments and projects that we will build there. So, in short, I wouldn’t divide the acquisition projects by the existing capacity and come up with a new yardstick for the cost of geothermal power plants. Angie Storozynski – Macquarie Research Equities: Okay. Second question is we’ve heard some recent comment from Nevada utility regulators about the performance of at least some of your plants in the state. Could you comment on that issue?

Not really. But I think this is a – it’s a debate that we are not really part of. So, it’s really a debate between the regulators and the utility. I think that it was an early comment that had been stricken, so that comment doesn’t even stay or got some amplification or it was picked up by a certain newspaper. Angie Storozynski – Macquarie Research Equities: So, you don’t think it’s going to have any impact on your future PPAs in the states or your ability to actually expand your sites?

No, not at all. Actually, I mean that comment is non-issue anymore, it has been. It’s not part of the order. There’s always – if you analyze the relationship between the PUCNs and the regulated utilities, there is always a complicated relationship between the two and independent power producers are somewhat of a step child in that relationship. So, sometimes the step child is well-loved and well-liked and sometimes it gets a little of the blame. Angie Storozynski – Macquarie Research Equities: Okay. Thank you.

Your next question comes from Brian Yerger with Aerca Advisors. Brian Yerger – Aerca Advisors: Thanks for taking my questions. I just had two things related to North Brawley. The first one would be when we’re looking at East Brawley, I just was wondering if you could give us maybe a little more color on that resource and if you had more information, would there be a point where you would look to maybe discontinue exploration of that project due to similar financing that’s going on with North Brawley?

So, the answer is that from a very high level point there is no difference between the East Brawley resource and the North Brawley. That’s from a very high level point. Specifically within the field and we know this on North Brawley and we think that we understand this. For East Brawley, there is huge variance in both quality and temperature of production from certain areas and also the injectivity or the ability to inject into certain areas. Currently, the area that we’re targeting for injection in East Brawley looks very promising and looks like it will provide – has a very good chance of providing the relief that we need for North Brawley. So, a lot of these is generally the same, but each acre is somewhat or each plant is somewhat different from the other. For us, obviously, finding a solution for the North Brawley injection issues takes precedent over building a second project over there because we need to make sure that we can get the generators that are currently installed running and making electricity. If I had to guess, as time goes by, we’re learning more about the resource. We’ll learn more about areas within the existing plots that are better for injection and where better injection wells can be drilled. And as time goes by, we will be able to use more of the vast resource that is in this are that we estimate that in terms of production there is between 80 and 100 megawatt that can be produced from here. Yes and the question is how do we find the injection? Since we’ve been – we’re still working on the permitting and the permitting issues for East Brawley. It hasn’t been resolved. We’re making progress, but it’s a slow regulatory process. At this point, we’re not even faced by hard decisions because permitting doesn’t allow us to build the second plants but our priorities are very clear. Brian Yerger – Aerca Advisors: Okay, great. So, I guess just asking it in a little bit different way, if the financials looked similar on East Brawley that you have in North Brawley right now, even with your experience that you’re going to gain obviously, would you still green light the project even if the financials look kind of the same?

Yes. I would say that the problem of North Brawley more than anything else is the fact that we can’t get – we built a plant. The plant was ready by the end of 2008 and we can get productions there specifically its injection, but anyway we couldn’t get production to where it needs to be and it becomes such an expensive issue. The second problem was that a lot of the challenges were only apparent once we were producing fluids at large scale and therefore, we had to find the solutions to those problems on the fly, which is almost utmost – I mean there’s hardly any more expensive way of solving a problem and then we you have – when you’re under pressure with the partially operating project. If we had to rebuild North Brawley with the equipment that we have in place, it will not be a substantially more expensive power plant than our original plans. And so the circumstance is made it so expensive – the looking – the continuous search for problem and solution, this has what is predominantly expensive about his project. The rest of the cost drivers are fairly routine for the Imperial Valley. And so yes, we could once we understand the reservoir well enough, we could build an East Brawley project and it could be a very successful project. Brian Yerger – Aerca Advisors: Okay. And just one quick one on North Brawley. You’d mentioned that you’re looking at breakeven in the second half of 2011. Could you give us any color at all on what electricity gross margins are going to be in 2011 as a result of this extension of North Brawley’s issues?

Not at this time. No. Brian Yerger – Aerca Advisors: Okay. All right. Thanks a lot.

Your next question comes from Carter Driscoll with CapStone Investments. Carter, your line is open. Carter Driscoll – CapStone Investments: Sorry, I had my mute on. Apologies. Thanks for taking my call. Following up on a question just asked, obviously, good explanation of East Brawley, but is Carson Lake facing similar permitting issues, or has there been in a change that we’re not aware of, or is it really still constrained by just the permitting issues?

Carson Lake is – our site in Carson Lake is highly complicated by conservation issues and native American issues or crossroad issues, and by the fact that this whole area is one that is affected by – or I should say that the cumulative impacts that are greater than just our projects, but other projects that are planned for the area forced the BLM into an environmental impact study, which is the long process and not a process that we control. It’s a four-party process over there. It started very late and we’re very far from getting the permits to substantial work over there. And since time is really of the essence with the ITC cash grant and the importance of started construction and actually completing construction by the end of 2013 that we need to put our resources, where we think that we can get the most benefit from and – with the permitting situation there, it’s probably not the place where we should focus our attention on. Carter Driscoll – CapStone Investments: All right. Just on the back burner a little bit. Just switching gears a little bit, you discussed have 10 projects subject to some type of DOE, whether its loan guarantee or production credits or the cash grant. Could you qualify just a number, not necessarily the amount of projects into each bucket, like what you may get or apply for the loan guarantee versus the cash grant versus the production tax credit?

Great. The loan guarantee is now it’s like for threefold and we currently don’t have plans to apply for additional, so we might. We still have these projects, if these forces works and if its attrition, we discuss this earlier on the call. The 10 projects that we expect to be eligible on ITC cash grant, which means projects that will reach the status of south of construction is defined under the 1603 program. I don’t know how familiar you are with the definition, but it has to be either a project-based substantial physical work, exercise has commenced or the Safe Harbor definition of 5% of total cost incurred. So, we plan to have enough projects so that a total of 10 projects we’ll reach that point and we’ll be eligible to an ITC cash grant, which is the 30% cash grant. Carter Driscoll – CapStone Investments: Yes. If I understand it, you got three eligible for the loan guarantee and potentially seven eligible for the 1603 program?

And there might be more eligible for a loan guarantee, but we are not in the process of applying it. Loan guarantee application can be submitted until September 2011. So, we are not against the deadline yet. Carter Driscoll – CapStone Investments: All right. Thank you for that clarification. Is there any update on getting closer reaching PPA for the Sarulla project?

Sorry? Carter Driscoll – CapStone Investments: Is there an update on maybe potentially getting closer to a signed PPA for Sarulla?

The negotiations are progressing. Whether it will be done in the next couple of weeks or not, is always an Indonesia question. Carter Driscoll – CapStone Investments: Fair enough. And just lastly, a clarification of the comment I thought I heard earlier about not making a debt payment in 2011. Just clarification about what the actual statement was. I may have misheard that.

The revolving lines of credit have the term – have original years of three years, which expires in 2011. We are in the process of expanding the revolving line of credit. With some banks, we already got the extension. With others, we are in discussion to get the extension. So, even though formally, 2011 is the maturity date of the revolving line of credit, practically we expect it to be extended. Carter Driscoll – CapStone Investments: Okay. So, essentially you don’t have any bullet payments for several years?

Right. Carter Driscoll – CapStone Investments: Okay. Thank you very much. Appreciate it.

Thank you.

Your next question comes from Adam Weitzman with Luminus. Adam Weitzman – Luminus: Hey, guys. Thanks for taking my question. First on North Brawley, the breakeven that you speak of. Is that net income or EBITDA breakeven?

Net income. Adam Weitzman – Luminus: When do you get EBITDA breakeven?

Sooner, but I’m not sure I have the number in my head. Adam Weitzman – Luminus: Okay. Do you think it’s a 2010 event?

Probably early 2011, but I don’t have that exact number. Adam Weitzman – Luminus: Okay.

And it also may change. Even if I had it, it may change. Adam Weitzman – Luminus: Understood. And then on the acquisition, I know you mentioned don’t think of $5,000 a kilowatt as the price you paid for the existing asset. Just curious, for the land that you purchased and the land under development, how much money has already been spent there? So, if I’m trying to think about allocating money between the existing asset and then land and development, how would I think about that?

I don’t think that we have answer because the land has been acquired a long time ago. It’s not a recent acquisition and it’s all folded into the basis that we have in that project. So, it’s not something that we can answer. But what I can tell you that we have allocated a low number for the existing assets and an important number for the potential. Adam Weitzman – Luminus: Okay. Maybe to ask the question in a different way, if the metric we typically have is about $4,000 a kilowatt to develop new geothermal?

Yes. Adam Weitzman – Luminus: How much do you think it’s going to cost to develop incremental megawatts on that land?

On that land, development costs are lower than $4,000 megawatt because it is a premier resource. Adam Weitzman – Luminus: Excuse me? Because why?

Because the resource there is so good, the development cost – is it’s high temperature and good chemistry, the development costs are lower than the average industry numbers – Adam Weitzman – Luminus: Okay. But is it cheaper than it would have otherwise been on that resource because money has already been spent or is it just what it would normally be if you were doing normal starting of development?

I think that the advantage in a place like these is that you have 20 years of history on the reservoir and therefore, a lot of certainty on your ability to increase that reservoir. And that’s worth – it’s an interesting question, but how do you quantify that risk? And when you buy land, even if somebody drilled and discovery well on that land, you just don’t have that type of information. Adam Weitzman – Luminus: All right. Thanks guys.

And we did drill a few wells already for the expansion.

At this time, I would like to turn the call over to management for closing remarks.

Thank you all for listening and for being so interested in what we have. We think that the state of readiness for the next set of goals is there and we are confident that we will deliver. Thank you all.

Thank you. That concludes today’s teleconference. You may now disconnect.

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