Ormat Technologies Inc (ORA) 2010 Q2 法說會逐字稿

Good morning and welcome to the Ormat Technologies second quarter earnings conference call. (Operator Instructions.) Mr. Fink, you may begin your conference.

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 the information provided during this call may contain forward-looking statements related 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 may be made that include financial measures defined as non-GAAP financial measures by the Securities and Exchange Commissions such as 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 an 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 period. This non-GAAP financial measurement 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 ormat.com under the webcast and presentation link as found in the investor relations tab.

With that said, I would like to now turn the call over to Dita for her opening remarks.

Thank you, Rob. Good morning everyone. And thank you for joining us. As we review the results of the second quarter, let me emphasize a few points. The results of the quarter are primarily impacted by North Brawley, which is operating at partial load. This has led to low revenues of $3.5 million and high operating costs of $11.9 million.

Second element of the exploration expenses related to Gabbs Valley, and third R&D costs related to a REG project at an LNG terminal in Spain, which, when completed, will be recognized as revenue. We will discuss later on this call achievements of important business goals, which will further advance our growth claims.

I will turn the call over to Joseph for a 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 statement of operations and balance sheets in our earnings release and in the 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 $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 increase 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 increased generation from most other plants, in particular the Puna power plant, which is at full capacity.

Electricity segment revenue increase resulted in a slight increase in the average revenue rate of our electricity portfolio from $75 per MWh in the second quarter of 2009 to $78 per MWh in the second quarter of 2010.

In the product segment, on the 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 this will continue throughout the year due to decline in the product or the backlog from last year 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 7.7% 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 31.3% for the same quarter last year. The increase is attributable to removal of a contingency thereby enabling us to record revenues for a project that was substantially completed in the second quarter of 2010.

On slide eight you can see the impact of the other two factors Dita mentioned. R&D costs which increased as a result of $2.4 million cost related to a REG project in an LNG terminal and the write-off of exploration costs of $3.1 million.

Moving to slide nine, interest expense net for the second quarter of 2010 was $9.4 million compared to $4.4 million in the same quarter last year. The $5 million increase was principally attributable to a $4.2 million decrease in interest capitalized to projects under construction, primarily due to the commencement of operations of North Brawley, substantially reducing the amount of projects under construction during 2010 and increasing interest expense due to new long-term projects finals incorporate debts.

Moving now to slide ten, loss from continuing operation for the second quarter of 2010 was $2.1 million compared to income from continuing operations of $4.6 million in the same quarter last year. The decrease in income from continuing operation was principally attributable to the reasons I mentioned before.

And on slide eleven, net loss for the second quarter of 2010 was $1.5 million or $0.03 per share compared to net income of $14.6 million or $0.35 per share, basic and diluted, for the second quarter of 2009. The after-tax impact of North Brawley on the net income in the second quarter of 2010 was approximately $7.6 million or $0.16 per share.

It's shown on slide twelve adjusted EBITDA for the second quarter of 2010 was $24 million compared to $39.8 million for the same quarter last year. Adjusted EBITDA includes consolidated EBITDA and the Company's share in the interest, taxes, depreciation, and amortization related to the Company's equity investment interest in its 50% interest in the Mammoth complex in California.

Cash flows from operating activities for the second quarter of 2010 was $10.7 million compared to $12.8 million in the same quarter last year.

Turning now to slide 13. As of June 30, 2010, the Company has cash and cash equivalents of $54.2 million compared to $46.3 million as of December 31, 2009. The accompanying slide breaks down the use of cash during the quarter. Liquidity claim from the utilization of revolving credit lines with commissioned banks as well as cash derived from operating activities that were used to fund capital expenditure and to repay long-term debts.

Taking into account the proceeds of approximately $142 million from the senior unsecured bonds offering that we announced yesterday while considering the funding needed for the Mammoth acquisition, our liquidity position will increase by approximately $70 million.

Our total outstanding debt as of the end of the second quarter of 2010 is approximately $700 million, and it will be repaid as presented in slide number 14. Although we present in the table the revolving lines of credit we will be repaying in 2011, we expect to extend those lines of credit and have them available for general corporate use so there will not be an actual repayment in 2011.

Moving on to slide 15, Ormat's Board of Directors approved the payment of a quarterly dividend of $0.05 per share pursuant to the Company 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 August 26, 2010 to shareholders of record as of the close of business on August 17, 2010. The Company expects to pay a dividend of $0.05 per share for the third quarter of 2010.

And now let me turn the call over to Yoram. Yoram, please?

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 MWh. Noteworthy events this quarter were Puna's return to full capacity following the completion of the well field work 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 Tropical Storm Agatha that affected our plant in Amatitlan.

Through the expeditious work of our teams, these events had only a minor impact on generation and all of the plants have been brought back to normal conditions with the Amatitlan returning to full power yesterday. However, repair work did cause higher operating costs during the quarter with some costs that 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 loss as the results of the low output and high operating costs, 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 costs in this area by almost 75%, and we expect a continued reduction as we install additional ancillary equipment. The difficult brine processing carried with it additional labor costs which are also being reduced as the solid disposal process becomes more automated and less frequent.

On the well field we do not expect a significant reduction this year, but from experience we expect the frequency of pump replacement to drop sharply over the first two years of operation. Our near-term solution to increase generation lies in connecting four additional wells that have been drilled for the East Brawley project, and during the past months we have acquired permits and materials that would allow us to connect those wells by the end of the fourth quarter. The success in these three areas should bring the plant to a profitable status.

Let's move to slide 19 for an update on our projects under construction. We have completed the construction and commissioning of the 5.5 MW recovered energy generation project for Great River Energy, which is located along the northern border pipeline in Minnesota, and we expect it to begin commercial operation in the next few weeks.

On the Puna enhancement in Hawaii, we believe that we have resolved the final PPA details with Hawaii Electric Light Company and are expecting the plant's lenders to approve the signing of the PPA.

We are continuing with construction of the first phase of the Jersey Valley project. Construction permits have been obtained and civil work has started at the site. We expect to complete the construction of the first phase by the end of 2010 with commercial operation in 2011.

In McGinness Hills, we are continuing with the development of the first 30 MW. We have four production wells and one successful injection well, and we are continuing with the rest of the field development. On the power plant side we are progressing with equipment fabrication and with the permitting process that we hope will allow us to begin commercial operation in 2012.

Good progress was also made in the field development of Tuscarora where we believe that we have already secured all the production for the first phase of the plant, and we are now working on developing the injection scheme as well as the release of the power plant itself.

Last week the PUCN approved the 20-hear PPAs of McGinness Hills and Tuscarora that we have signed with Nevada Power Company.

There are no new updates on East Brawley and Carson Lake.

On slide 20 you can see the detailed status of projects under construction -- under development. As we announced earlier this week, we acquired Constellation Energy's 50% stake in the partnership that owns the Mammoth complex. As a sole owner, we will immediately release the projects to modernize the equipment and add new facilities to the complex to maximize its revenues.

The modernization of the complex and the expected field development could increase generation from the area to about 70 MW and is expected to be completed in time to benefit from the ITC cash grant. We will also record a capital gain as a result of the acquisition.

In Wister we conducted a 3D seismic survey as part of our joint exploration program with the DOE. The survey is the first step in our on-site exploration activity, and based on its result we expect to begin drilling in the third quarter of this year, which will make this prospect eligible for existing incentive programs.

With respect to the solar activity in Israel, we have the rights for the development of eight solar portable tank projects. All eight sites have been submitted to the Israeli Electrical Corp for a system impact study. We received approval for four sites and expect to get answers on the remaining sites by the end of the year. Next step in the process of obtaining the production license and other statutory approval, which can take up to two years.

Moving to slide 21, we continue with exploration of 14 sites with actual drilling in our Dead Horse and Gabbs prospects in Nevada. At this point we decided not to pursue Gabbs due to low temperature.

Another important development that I would like to discuss is related to the Mount Spurr site in Alaska, on slide 22. In June, Alaskan governor, Sean Parnell, and the Alaska State Senate signed senate bill 243. This bill significantly reduces the annual royalty rate paid from geothermal production on state lands to the same levels paid on federal lands. Additionally, the Alaska Energy Authority recently approved a $2 million grant to support our exploration drilling work there in the next year.

Both the passage of state bill 243 and the grant provide us with the confidence that supports the development of the geothermal industry in a manner that is financially viable and are an important step towards developing Alaska's renewal geothermal resource into utility scale power plants.

Slide 23 is a recap on our product segment. As of the end of the second quarter our backlog is approximately $51 million. I would now like to turn the call back to Dita.

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 bond -- excuse me. 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 years to come -- in the months to come.

Additionally, as recently announced, we have signed a term sheet with John Hancock Life Insurance Company to provide debt for senior secured construction and term loan of up to $350 million. The credit facilities will be used to finance the construction of the McGinness Hill, Jersey Valley, and Tuscarora projects.

As Yoram discussed earlier, the construction of the first phase of all three projects has already commenced and represents a total of approximately 60 MW. After completion of phase one of each project and in line with our revised approach to development, we will access the feasibility of the second phase of each project, which, if successful, could increase the size of these projects up to a total of 120 MW.

As you know, the DOE section 1705 loan guarantee program results from the IRA of 1879 and allows the DOE to provide the loan guarantee of up to 80% of project costs. We have submitted part one of the total guarantee application to the DOE. After it is approved for eligibility, part two of the application will be submitted. Subject to due diligence by both the DOE and the lender applicant, a condition of commitment for the financing will be issued followed by financial close. The experience of others tells us that this is a long process and may take six to twelve months.

Yesterday we announced the issuance of seven-year senior unsecured bonds with an amount of $142 million that bear an interest rate at a fixed rate of 7% per annum. Interest is paid semi-annually while the principle is due at maturity. The notes can be prepaid with a premium in years five and six and expire in year seven. Deposits from the issuance will be used for general corporate purpose and will enable us to accelerate the commencement of development and construction of additional geothermal projects in the US before the end of 2010, allowing ten projects to qualify for the ITC cash bonds.

Please turn to slide 26. We are updating our guidance to reflect the consolidation of the Mammoth project's revenue starting in August 2010 and expect 2010 electricity segment revenues to be between $285 million and $295 million.

It should be noted that this number does not include revenues of approximately $6 million representing our share in Mammoth related to the first seven months of 2010 until the acquisition of the remaining 50% stake at Mammoth.

As for the product segment revenues, we stay with our previous guidance of between $75 million and $85 million.

In slide 27 you can see the CapEx requirements for the remaining of 2010 show our growth activity. Our estimated capital needs for the rest of 2010 include approximately $174 million for capital expenditures on new projects and development and construction, exploration activities, operating projects, and machinery and equipment.

If we include the funding of the recently-announced acquisition, our CapEx requirement totals approximately $246 million. The funding of this program will come from cash from operations, our new corporate lines of credit, proceeds from the $142 million unsecured bond issuance announced yesterday, and from refinancing of the cash bonds of North Brawley that will sum up to approximately $466 million.

We are satisfied with the progress that we have made on the operational level. When placed alongside the positive development we made in financing and acquisition, we are able to reaffirm that our long time growth claims continue to move forward as planned with approximately 200 MW expected to come on line by 2013 with more than 100 MW eligible for PTC -- for ITC cash bonds.

I want to thank you for your support, and we'll now open the call for questions. Operator?

(Operator Instructions.). Your first question comes from Steve Milunovich with 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 sometime in 2011, second half of 2011. And then as of 2012, normalized margins will run caveat, and this is the operational cost of North Brawley are going to be higher than normal. The total cost of Brawley after the reduction of the ITC cash grant, it's going to be in the order of $260 million to $270 million, which is a very high cost for a 50 MW project, so about $4 million MW. So the operational costs are going to remain higher on Brawley.

And you said you think you can get to that 50 MW rate by yearend? And if that's true, why is not breakeven until sometime in maybe the second half of next year?

Yoram mentioned it that the operating cost in the early years of the project, because of the high salt content in the project are going to be higher with one major item is pump replacement which are going to be more frequent in the early years until the wells are going to clean themselves from the high salt content, and then it will reach the -- or we hope it will reach the normal level of the Imperial Valley projects which are all higher operating costs than our other projects.

I see. Okay. And then finally, any updated comment on permitting which you've mentioned in the past has been slower than you'd like?

Permitting is slower than we'd like, but we've just been adding it into our programs and just include this in our program. If it's going to be even slower than I hope that we are now just taking this into account.

There is a major effort of the industry and the BLM to accelerate the permitting sources. I cannot say that we are seeing yet the good results, but I can say that the effort is going on and hopefully we'll be seeing improvement.

Great. Thank you.

You're welcome.

You're next question comes from Elaine Kwei with Jaffray's.

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 Q2? Was that due to extra repair expenses, or was there a decrease in production from Q1 to Q2?

There wasn't a huge difference in the operating cost of Brawley actually. I think operating costs 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 -- it was a full -- the first quarter was a full quarter less two weeks, so it was about the same.

Okay, but the Q2 margin decline was attributed primarily to North Brawley?

Yes, the margin in Q2 is not good with Brawley being the first -- the biggest impacting factor. But Brawley was the same the first quarter as well, it's just that there were other good things happening.

Okay. Got it.

Overall margin was better, but the plant itself is not that much different.

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 from Mammoth.

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. The way we look at it is we allocate a certain portion of the purchase price to the existing operating asset and a certain portion of the purchase price for the potential, and this site has a big potential. And 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.

Okay. Well thank you so much.

You're next question comes from Lasan Johong with 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 an 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 completed -- successfully completed this quarter, and there were some contingencies on this project which were cleared 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've said in the past, we expect towards the end of the year, maybe the beginning of 2011 to get more orders for new geothermal projects, especially in the US.

So you expect the backlog to improve over the next couple of quarters?

Yes.

Okay.

We hope so.

The timing of the Spanish LNG recovered energy generation project revenue, you mentioned something like $13 million. When would that be coming and are there similar projects coming down the pipe?

It's -- I guess the contact 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 be ready we don't -- we can't control this. 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?

Do you expect other similar projects to follow?

It's -- this is truly -- I believe that 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 is a -- 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 of 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 on a larger scale, and it would require recovering the LNG industry, which during low gas -- low natural gas prices is generally not doing too well.

Understood. What is the impact of the natural disasters in the second quarter?

I think the biggest impact was Amatitlan which was operating at I think -- you know, off the top of my head I think that we generated about 70% of what we planned to generate, so that was the biggest impact.

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 a million dollar.

Perfect. Last question. Dita, did you say that Jersey Valley, McGinness Hill, and Tuscarora could be 120 MW, because the slides show 61?

The first one is 60, 61. Now the way we are approaching the development now, and I think we share this with most of you doing the analysis and that's what we are doing now is developing in each project in phases, not building a large project and then finding out that the resource may be a little different than what we predicted it to be.

So take McGinness for example. There are good chances that it's a 60 MW resource. We are developing 30 MW in phase one. We will run the phase one for a period, and once we get the comfort that it can support additional capacity, we will increase it, exactly as we have done at Steamboat and as we are doing now in Kenya with Olkaria additional plant that is currently under development.

So these three projects have all been selected to be implemented using the same philosophy. Phase one first, test it, and then add add-ons as the resource can support.

Understood. Thank you.

You're next question comes from Dilip Warrier with 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 US geothermal and energy industry that have -- potentially have prospects or sites but are very limited in terms of their financial means. In that sense, if a vendor could provide financing, it's certainly good for the developer and maybe good for the vendor.

I think that more than anything else it's a reflection of a state of the developers. But that would be my guess.

Okay. Is that something that you would be willing to consider, vendor financing?

I think that it's -- it's something that has to make sense on a case-by-case basis. We basically share with you fairly openly what are the 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 are comfortable with the resource risk that now is not for you to resolve but for the developer that you are offering the vendor financing to.

And if you look at our North Brawley example, which certainly has been a challenge, it requires a Company like Ormat to resolve situations like this 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.

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 a part of the thinking. It goes into a bigger picture of course which says that as our balance sheet is not -- was not very leveraged and actually is not very leveraged, 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 debt. And the high bond is just one step towards achieving debt.

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 hardly -- we generally have R&D activity, but it is generally not a full-size project that is being built. So I would say that the LNG plant is really a high watermark if you'd like at least for the foreseeable future.

Okay, so does it make sense that the R&D expense could potentially sequentially decrease?

Yes. That's our expect -- at least based on our plan for now, yes.

Thank you.

You're next question comes from Brian Shore with 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 an acceleration in cost there on the operating side?

No, 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 in everything, of course, but we see a reversed trend.

Most of it was happening towards the end of the quarter. We started our 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 -- and Brawley is of course getting more production and getting more generation out, that this is what is 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.

Okay.

But I hope that this is clear.

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 still the end of the year.

Okay. I guess then separately on I guess maybe on the loan guarantee, 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. As you know, they have been able to move one project past conditional commitment, and this is in Nevada geothermal. And the segment we are going with, John Hancock in its experience and the fact that it's a one-stop-shop. We are not dependent on capital market and other structures that are available in the market do give us the confidence of the closing.

But it 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 get the DOE loan guarantee, and it's going to be a refinancing and not a funding of construction loan. In the other two projects, Tuscarora and McGinness are going to be well advanced in construction before we receive the DOE money, but it is purely a source of low-cost money and I think that we shouldn't give up on this opportunity, and that's our approach to it.

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 had it earlier this week, the 50% of Mammoth.

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 were 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?

With pleasure. The press was much stronger than the reality, which is probably the nature of the press. They are taking some agitation, and there was some agitation, and blowing it up to totally out of proportion.

But there was an attempt by a large shareholder of the parent company to change a decision or 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 their request of the other shareholders, we have proposed, or the Board has proposed to other outside directors, 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 won't happen, that in the annual meeting that is scheduled for 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 directors.

And we have certainly an interested shareholders, and we think that this dialogue is going to benefit the Company.

Thank you very much. That's very helpful. Thanks, Dita.

Your next question comes from Angie Storozynski with Macquarie.

Thank you very much. Two questions. First on the Mammoth acquisition. It seems like it was relatively expensive, about $5,000 per kilowatt. How -- 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 the existing plant, and if you'd like the 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 if 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 it's own constraints, but it's, in our opinion, a gem. And therefore it's worth the money. And not only the acquisition cost but also additional investment in projects that we will build there.

So in short, I wouldn't divide the acquisition price by the existing capacity and come up with a new yardstick for the cost of geothermal power plants.

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 that this is 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, got some amplification, or was picked up by a certain newspaper.

So you don't think it's going to have any impact on your future PPAs in the state or your ability to actually expand your sites?

No, not at all. And actually that comment is a non-issue anymore. It has been -- it's not part of the order. So, there's always -- if you analyze the relationship between the PUC and the regulated utilities, there is always a complicated relationship between the two, and independent power producers are somewhat of a stepchild in that relationship. So sometimes the stepchild is well loved and well liked and sometimes gets a little bit of the blame.

Okay. Thank you.

Your next question comes from Brian Yerger with 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 and the North Brawley resource. 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 is 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 the -- generally the same, but each acre 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 generators that are currently installed running and making electricity.

If I had to guess as times goes by we'll learn more about resource, we'll learn more about areas within the existing plants 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 area. We estimate that in terms of production there is between 80 MW and 100 MW that can be produced from the area, 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 haven'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 a second plant. But our priorities are very clear.

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 build a plant, the plant was ready by the end of 2008, and we couldn't get production, there specifically it's injection. But anyways, 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 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 the most -- I mean, there's hardly any more expensive way of solving a problem than when you have -- when you're under pressure with a partially-operating project.

If we had to rebuild North Brawley today with the equipment that we have in place, it would not be a substantially more expensive power plant than our original plans, and so the circumstances made it so expensive.

The continuous search for problem and solution, this is what was predominantly expensive about this 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.

Okay. And just one quick one on North Brawley. You had 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? Okay. All right. Thanks a lot.

Your next question comes from Carter Driscoll of CapStone Investments. Carter, your line is open.

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 cultural issues and by the fact that this whole area is one that is affected by -- or I should say the cumulative impacts that are greater than just our projects or other projects that are planned for the area forced the BLM into an environmental impact study, which is a 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 do 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 -- with the permitting situation there, it's probably not the place we should focus our attention on.

All right. Just on the back burner a little bit. Just switching gears a little bit, you discussed have ten projects subject to some type of DOE, whether it's 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?

The loan guarantee is now applied for three projects, and we currently don't have plans to apply for additional. We might. We'll see how this process works, and if it is efficient, as we discussed it earlier on the call.

The ten projects that we expect to be eligible for ITC cash grants, which means projects that will reach the status of start of construction and defined under the 1603 401. I don't know how familiar you are with the definition, but it has to be either a project that substantial physical work at the site has commenced or if it falls under the definition of 5% of project cost incurred.

So we plan to have enough projects so that the total of ten projects will reach that point and will be eligible for an ITC cash grant, which is the 30% cash grant.

Okay. So if I understand it, you have three eligible for the loan guarantee and potentially seven eligible for the 1603 program?

And there might be more eligible for loan guarantee, but we are not in the process of applying yet. Loan guarantee applications can be submitted until September 2011, so we are not against a deadline yet.

Okay. Thank you for that clarification. Is there any update on getting closer to reaching PPA for the Sarulla project?

Sorry?

Just 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.

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 a term -- have an original term of three years, which expires in 2011. We are in the process of extending the revolving line of credit. With some banks we already got the extension. With others we are in discussions 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.

Okay. So essentially you don't have any bullet payments for several years?

Right.

Okay. Thank you very much. Appreciate it.

Thank you.

Your next question comes from Adam Weitzman with 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.

When do you get EBITDA breakeven?

Sooner, but I'm not sure I have the number in my head.

Okay. Do you think it's a 2010 event?

Probably early 2011, but I don't have that exact number.

Okay.

And it also may change. Even if I had it, it may change.

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 an 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 is that we have allocated a low number for the existing assets and an important number for the potential.

Okay. Maybe to ask the question a different way, is if the metric we typically have is about $4,000 a kilowatt to develop new geothermal?

Yes.

How much do you think it's going to cost to develop incremental megawatts on that land?

On that land the development costs are lower than $4,000 a megawatt because it is a good resource.

Excuse me? Because why?

Because the resource there is so good the development cost -- its high temperature and good chemistry, the development costs are lower than the average in the full number, so potentially lower.

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 this 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 which -- it's an interesting question but how do you quantify that risk? And when you buy land, even if somebody drilled in a discovery well on that land, you just don't have that type of information.

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. 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 growth is there, and we are confident that we will deliver. Thank you all.

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