Ormat Technologies Inc (ORA) 2011 Q3 法說會逐字稿

Good morning. My name is Julianne and I will be your conference operator today. At this time I would like to welcome everyone to the Ormat Technologies third quarter 2011 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). Thank you. I would now like to turn the conference over to Mr. Rob Fink of KCSA Strategic Communications. Please go ahead, sir.

Thank you, Julianne. Hosting the call today are Dita Bronicki, CEO, Yoram Bronicki, President and COO, Joseph Tenne, CFO, and Smadar Lavi, Vice President of Corporate Finance and Investor Relations.

Before beginning, we would like to remind you that the 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 these 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 SEC on February 28, 2011.

In addition, during this call, statements may include financial measures as defined as non-GAAP financial measures by the SEC, such as EBITDA and adjusted EBITDA. The presentation of financial information is not intended to be considered in isolation or as a substitute for 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 the slide presentation accompanying this call may be accessed on the Company's website at www.ormat.com under the IR Events and Presentations link that is found in the Investor Relations tab. With that all said, I would now like to turn the call over to Dita. Dita, the call is yours.

Thank you, Rob. And good morning, everybody. Thank you for joining us today for the presentation of our third quarter 2011 results and outlook for the near future. It was a very strong quarter and we increased revenues, improved our gross margins in both the electricity and product segments, and maintained a very strong backlog.

The quarterly EBITDA was $46.7 million. In addition, we successfully enhanced our access to cash with new financing from a 20-year, 80% DOE guaranteed loan under the program designed for commercially proven projects that provides appropriate funding for our multi-phase approach to development. The nominal interest on the part of the loan that was funded earlier this week is an exceptionally low 4.687% and this will reduce our interest rate over the long term.

This quarter we had a loss from interest rate lock transactions we have entered in anticipation of the DOE loan to mitigate the interest volatility in the 10-year treasury rates. The interest rate would have been 6.22% had we treated the loss on the interest lock as a hedge. Still, it's a very attractive interest rate for a project under construction.

With that said, I would like now to turn the call to Joseph who will provide a financial review followed by Yoram that will provide an update on our operational progress, and as usual, following my remarks, we will open the call up for Q&A. Joseph, please.

Thank you, Dita, and good morning everyone. Beginning at Slide 5, total revenues for the quarter ended September 30, 2011 were $110.8 million, a 9.2% increase over revenues of $101.5 million in the third quarter of 2010. In our electricity segment on Slide 6, revenues for the quarter were $86.8 million, a 4.1% increase over revenues of $83.4 million in the same quarter last year. The increase in electricity revenues is due to higher energy rates at the Puna and Amatitlan plants. Such increase was partially offset by 3% decrease in electricity generation due to major maintenance activity in some of our power plants.

In the product segment on the next slide, revenues for the quarter were $24.0 million, an increase over revenues of $18.1 million in the same quarter of 2010. The increase in product revenues reflects the new customer orders that we secured in the second quarter of 2011.

Moving to Slide 8, the Company's combined gross margin for this quarter was 32.3% compared to 24.8% for the third quarter of 2010. The Electricity Segment's gross margin was 33.3% this quarter, compared to 26.2% in the third quarter last year. Excluding North Brawley, the Electricity Segment's gross margin would have been 39.1%.

In the product segment, gross margin was 28.7%, compared to 18.5% in the third quarter last year. This increase is due to higher revenues, the mix of products sold, and margins associated with customer orders.

Moving to Slide 9, interest expense net for the quarter was $23.9 million, compared to $11.0 million in the third quarter of 2010. The increase was principally due to an $11.6 million loss from interest rate lock transactions related to our DOE loan guarantee, which was not accounted for as a hedge transaction. As Dita mentioned, these interest lock transactions resulted in a loss in the current quarter rather than over the 20-year term of the loan.

Now, moving onto Slide 10, net income for the quarter was $1.0 million or $0.02 per share basic and diluted, compared to a net income of $32.4 million or $0.71 per share basic and diluted, for the same period in 2010. In addition to the loss from the interest rate transactions I previously mentioned, 2010 third quarter net income included a $36.9 million gain from the acquisition of a controlling interest of the Mammoth Complex.

As shown in the following slide, Slide 11, adjusted EBITDA for the third quarter of 2011 was $46.7 million, compared to $78.8 million in the same quarter of 2010 and net cash provided by operating activity was $59.0 million compared to $20.7 million last year. Adjusted EBITDA in the third quarter of 2010 included the Company's share in the interest and taxes, depreciation and amortization related to its unconsolidated interest in the Mammoth Complex in California in the third quarter of 2010.

The reconciliation of GAAP net cash provided by operating activities to adjusted EBITDA as well as additional cash flow information is set forth in Slide 25.

Moving to the next slide, cash, cash equivalents, and marketable securities as of September 30, 2011 were $80.3 million, down from $82.8 million as of December 31, 2010. The accompanying slide breaks down the use of cash during the nine months. Our liquidity came from the issuance of senior unsecured bonds, proceeds from the sale of Class B membership units of OPC to JP Morgan, and cash derived from operating activities.

Our long term debt at the end of the third quarter of 2011 and the payment schedule are presented in Slide 13 of the presentation.

In accordance with the Company's debt covenants, on November 2, 2011, Ormat's Board of Directors decided not to declare a quarterly dividend in the third quarter of 2011 because it has incurred a loss of $16.4 million from the interest rate lock transactions, and as a result, net income for the nine months ended September 30, 2011 was approximately $0.3 million. The Board of Directors will continue to track the Company's cumulative net income to determine on a quarterly basis whether the Company may distribute a dividend and remain in compliance with debt covenants.

That concludes my financial overview. I would like now to turn the call to Yoram for an operational update.

Thank you, Joseph, and good morning, everyone. Starting with Slide 15. As you have seen earlier, we had good results from our Electricity Segment. Generation was a little lower this quarter, mostly due to short term maintenance events, but the revenue from the higher rate contracts increased and the overall cost to operate was reduced resulting in a substantially higher gross margin.

There were no major events in North Brawley during this quarter and we continued the practice of selective operation of production wells. While this resulted in lower revenues, it also reduced cash operating costs by $2.5 million resulting in a better EBITDA. In parallel, we continued to work on improvement programs to the major cost areas of this project, production pump life, chemical usage, and production/injection balancing.

In Jersey Valley we received the permit to drill an additional injection well, which has been recently completed. We will wait for the long term results to assess the contribution from this well and determine targets for additional wells.

We are monitoring the progress of the global settlement of the SO4 contracts of Heber, Ormesa and Mammoth, which is expected to become effective later this month.

The Global Settlement requires us to amend the SO4 contracts to reflect a pricing option based on a short-run avoided cost (SRAC) methodology with certain applied modifiers until December 2014, and thereafter convert to a mandatory SRAC methodology pricing.

This may expose our revenues from these PPAs to greater fluctuations and may adversely affect our revenues under these PPAs. Our expectation is that the new pricing, which will be based in large part on future natural gas prices, will reduce our revenues in 2012 and 2013 by approximately $9.5 and $6.5 million, respectively. It is not possible at this point to estimate the impact on revenues beyond 2013.

For an update on our future growth, please turn to Slide 16. In the table you can see the status and expected completion schedule for each project under construction. The Puna enhancement has been completed and we are ready to deliver power to the grid as soon as the PPA is approved by the PUC in Hawaii.

Construction is in its final stage in Tuscarora and we are in the commissioning phase of the plant.

In McGinness Hills, we are progressing with the power plant construction and with field development. Field development also continues in CD4 and in Wild Rose.

In the Olkaria III expansion, we successfully drilled one production well and are completing a second.

The Carson Lake project in Nevada received the approval of the BLM for the required Environmental Impact Study. We're developing a new project schedule to determine if the project will still meet the ITC deadline.

On Slide 17 you can see the detailed list of projects under development.

In Sarulla, the consortium proceeds with the discussions on the contractual amendments required for project bankability.

We are in various stages of construction of seven projects that are expected to be completed by the end of 2013 and will contribute approximately 145 megawatts to our portfolio.

Turning to Slide 18, in addition to the projects under construction and in development, we now have 35 prospects in early exploration or where activity is yet to begin. As was recently announced, the Chilean Committee of Geothermal Energy Analysis announced it has recommended to the Chilean Ministry of Energy to award five exploration concessions to Ormat. When this process is completed, our total number of prospects in Chili will be six.

Let us now turn to Slide 19 for an update on the product segment. Since the beginning of the year, we signed new international contracts for the supply of geothermal power plants and other power generating units. As of the end of this quarter, we have a backlog of approximately $200 million that will support strong product segment revenues through 2012.

I would now like to turn the call back over to Dita.

Thank you, Yoram. In my remarks I would like to review recent financing, comment on our capital position, and then conclude with revenue guidance for 2011 before opening the call for questions. I'll start with Slide 21.

As mentioned in my opening remarks, we finalized the loan agreement of up to $350 million under the US Department of Energy's 1705 Loan Guarantee Program to finance three projects in Nevada and we received a $310 million commitment from OPIC to refinance and expand the Olkaria complex in Kenya.

The DOE guarantee of the 20-year loan for up to $350 million of financing from John Hancock Life Insurance provides us stable financing to support the development of Jersey Valley, Tuscarora and McGinness Hills. It is a portfolio financing like we have done in several locations in the past, but this time it is both a construction and a term loan. The innovative part of this development and construction financing is the ability to finance three power plants in two phases each.

The expected generating capacity of all three power plants in both phases is up to 113 megawatts. The capacity of the first phase is expected to be approximately 60 megawatts and capacity of the second phase will be determined following a feasibility assessment of the geothermal resource, which will be performed following completion of the first phase of each facility. This two-phased approach allows us to manage risk, and by including the second phase in the OFC 2 financing, to better control long term financing costs.

We also signed a commitment letter with OPIC for up to $310 million, to refinance and expand the Olkaria III complex located in Kenya. Under the terms of the commitment the loan will be comprised of a refinancing tranche of up to $85 million to repay the existing loan and fund transaction costs, a construction loan tranche of up to $165 million to finance the construction of an additional 36 megawatt expansion currently underway, and a $60 million stand-by facility to finance an additional optional 16 megawatt capacity expansion that, if exercised by us, could bring the total capacity of the complex to approximately 100 megawatts.

These financings, together with the expected ITC cash grants will provide us with sufficient cash to support our capital expenditure program through the end of 2012.

We can see this in sources and uses of our CapEx requirements for 2011 on Slide 22. For the remainder of 2011, we plan to invest approximately $83 million in projects currently under construction as well as an additional $25 million for development, exploration, and other uses as seen on the slide. The funding of these programs will come from cash on hand at the end of the third quarter, cash from operations, unused corporate lines of credit, project debt under the DOE loan guarantee program, and cash grants.

Turning to Slide 23, you can see our revenue forecast for 2011. We continue to expect the Electricity Segment revenue to be between $315 million and $325 million. However, we are updating our forecast for the Product Segment to be at the higher end of the previously announced range with revenues of approximately $100 million in 2011.

In closing, we made significant progress in the third quarter of 2011. Our existing portfolio benefited from improved operating efficiency, new orders are increasing product segment revenues and new financing strength in our balance sheet and access to cash.

We thank you for your support and at this time I would like to open the call for questions. Operator?

(Operator Instructions). Paul Clegg, Mizuho.

Hi, thanks for taking my questions, and congratulations on the strong performance this quarter. On the SO4 contracts, you're warning of a headwind there [audio technical difficulty].

Paul's line has disconnected. Your next question is from the line of Dan Mannes, Avondale Partners.

Hi, good morning. I think I'll probably follow up where Paul's question left off. On the SO4 contracts, the potential step down, the one thing you didn't address there is, what are you doing to mitigate that, particularly as it relates to any negotiations on contract extensions, etc? I mean the numbers -- I guess I'm just wondering, is that -- that's based on -- the numbers you put out is based on the assumption that you don't renegotiate or extend the contracts I assume?

That's correct, yes.

So is that something that's under discussion? Is that a possibility? And given the rates that are imbedded in the decline you put out there, how does that compare to the type of rates that could be acquired in a negotiation?

So I think the way to look at this, Dan, is that this is really -- that's the low case in any analysis. Obviously this is what is currently in the short-run of what it costs formula with the capacity, with the capacity payment and the other options in that recipe that is part of the global settlement. What is in there is below market in our opinion for renewable power. And so I think that -- now there is -- always there's a downside and there's an upside to a somewhat volatile contract. And I think that what we would do is continue to monitor the forecast, if you like, the forward strip on gas, and decide whether these are contracts that we want to keep, or which contracts we would like to keep. They are -- it is three facilities, but actually it's a multitude of contracts. And each of them behave differently depending on the type of facility, the age of the facility, and we're certainly looking at this. But since nothing was signed at this point, then we're providing this just as I guess a benchmark to show that this is not nice but it's not dramatic. And certainly as a Company we can live with it.

And you are -- but you are pursuing other alternatives because you do believe these are below market, and worse case scenario is you're stuck with this until the expiration and then they would move to hopefully a more market based price? Or more of what you believe it's worth?

Yes, that's correct. Our duty is to maximize value. So we're certainly looking at this.

Okay, real briefly, just on your discussion of output, I guess I'm a little bit confused because it sounds like you were talking about your output being down year over year in the third quarter, but at the same time your costs were also lower. And I guess I was hoping you could square that. And does it relate just to the specific facilities that were down? If you could just explain that a little bit.

Yes, there was -- our output was just slightly down, I think, in terms of total capacity. It's about 3% below what it was in 2010. So not a huge difference, but really what we have is, in our mix there is such a multitude of PPA prices that sometimes you can get a hit in one PPA but it's almost meaningless compared to the improvement elsewhere. And I think that that's -- the story on revenue is really around this. We had good performance out of high value contracts and some of the hit that we took was not, over maintenance and other issues, was really in contracts that are not as significant. And of course we were able to reduce costs which is always a different, completely different battle. So we reduced operating costs and so the total provides a nice picture both on the revenue side and on the cost side to give a good EBITDA, a better EBITDA. A substantially better EBITDA.

And lastly on the revenue line, you noted year over year revenue per megawatt hour was up. Was that a mix shift or was that also related to higher contract pricing? It sounded like Puna and Amatitlan which I didn't realize had a floating rate component.

Amatitlan doesn't really have a floating rate component, it's a different structure. The purchasing agreement is a floor that we have the right to sell in the market as well. So we sold a little bit in the market and this is what created the higher rate at Amatitlan. Puna is clearly a floating rate. Again, with a floor, but the floor is so far off, that we don't even mention it anymore.

Is that something you'll be able to take advantage of on Amatitlan in the future or was that just due to better output? Or is that sort of a seasonal issue?

No, no, no. We will be -- as long as the market rates are higher than our floor, we will be able to take advantage of it.

Okay. And then the last question, I guess I missed it, it sounded like you had a brief comment on Sarulla. Is there anything new to report there or is it still you're in the same position of negotiating the security part of the debt agreement?

We are still in the same position. Of course there is the dynamic of the negotiations, but nothing new to report.

Paul Clegg, Mizuho.

Hi, thanks for putting me back in. I'm not sure what happened there. On the revenue guidance, you had a pretty strong quarter on the electricity side and you've actually, I think, each quarter this year have been up in that segment versus last year. So it looks like you're tracking towards the upper end of guidance. So why not raise guidance for the year?

We don't think we'll exceed the guidance.

Okay, I guess when I look at it though, and sort of tracking towards the upper end, in the past you've kind of tightened up at the bottom. Is there something that we should expect in the fourth quarter that would be, that would put you incrementally behind or flat with last year?

No, but when we look at our -- what we have changed during the year from the beginning of the year is really the we operated Brawley and we operated Brawley at the lower revenue rate, but a substantially lower profit rate. Yoram is probably a better person to explain it than I am. And this is why on the revenue side we don't expect any improvement over the guidance.

Okay. And then actually on that issue of North Brawley, when could we expect to start -- congratulations first of all on the very good improvements in the cost structure there. It looks like you're getting pretty close to cash flow breakeven. But when can we start to see the revenues step up again? And then is the run rate for the cost side this quarter a good run rate or do you see the need to do pump replacements and other items short term that could step up expenses there over the next few quarters?

So it's a little hard -- I think I'll answer first with the second part and then I'll move to the first question. What we did is, and I think we described it in our last earnings call, what we did is operate the wells that are what we call the high grade wells, the ones that produce a relatively higher portion of power from them. Because the wells are not identical. And while operating these wells [audio interruption] to the pump lines because the pump costs the same whether it's in a highly productive well or on a less productive well. So this allows to generate more power with less cost, if you would like.

Also, it's important to remember that the rates for the third quarter are better than the fourth quarter and any other quarter of the year so this also makes the margin a little better. But really what we have done is not an isolated activity. It is part of the program to get to a reasonable pump life and we feel that we're making progress there. And we will see ramp up of generation as soon -- ramp up of generation will be gradual. As we get more comfortable on the pump life, and I'll just use illustrative figures, but once we're confident that we have a 9-month average life for a pump, there's a group of wells that now become accretive and we will restart them. And as soon as we move to 12 months there's another group that will become accretive and we'll start producing from. And then there's the wells that we will produce only once we get to say 15 months. And prior to drilling, this is the ramp up that is expected and this will bring us to the demonstrated capacity of 33, 35 megawatts.

Beyond that, more than that would require drilling and this is part of the well field studies that we're doing. As soon as we have good conclusions, we will target new wells and drill them and hopefully produce from them and they will be -- our target will be to have better wells, so wells that follow more of the ones that are currently operated rather than ones that we are not operating at this stage.

Okay, that's helpful color. And if I may, just one final one. Can you give any sense on how much of your product backlog is recognizable over the next year? And if you could just talk generally about the level of activity that you're seeing in the product segment to rebuild that pipeline?

Out of the $200 million backlog that we had at the end of the third quarter, between the fourth quarter and next year we (inaudible).

And then the level of activity in the product segment that you're seeing in the market generally?

That's a much more difficult question because as you know, there is a lot of (inaudible) flexibility in the timing of the curing of new orders. In the same way as the difference between 2009 and 2010 where 2009 was a very good year in the product segment and was lower and now we see a pickup. We may see such a phenomenon in the future and we may not. It's very hard to predict.

Okay, thanks very much.

Ben Kallo, Robert W. Baird.

Good morning. My first question is on Brawley and on EBITDA. There's a discussion of moving towards EBITDA positive for Brawley and I just kind of wanted to get a timeframe around that, Yoram. Or at least break even.

So we promised two quarters ago not to give forward-looking statements on Brawley. I don't know how -- I'm trying to figure out how to dance. But I think -- all that I can say is that we're moving closer all the time and I think that you can see this in our cost structure. We're not very far off and I wish that you put in a guess and I hope I can beat your guess in terms of timing. But beyond that, there's not a lot that I can say.

Okay. Then if I look at your gross margin first on the electricity side, to me it looks like, looking at my model here, it's the best that we've seen in two years, so since Q3 of '09. And that's really even with the drag of Brawley. I'm just trying to understand, is it all the Puna and Amatitlan strength causing that or is there some other factor? How do I break down that strength coming from Puna and Amatitlan? Could you give me a percentage of where the strength is coming from?

I think, Ben, that actually we went quickly through the list of our plants and all of our plants performed well. And it really goes to show what a strong company we are operationally and we really know this part of the business and we do it well. Sometimes things happen that are outside of our control, sometimes there are things that we don't know. But operational efficiency is what such a big part of what our team is about. And it's adding new wells, it's modifying wells, it starts with the resource and goes through O&M. And we had good performance really overall. Now there are two plants that have, that enjoyed higher rates and that's great, but beyond that, operational costs were down almost across the board.

Okay, great. And then if I remember correctly, there's a lag between oil prices or diesel prices and electricity prices at Puna. So are we seeing the peak of oil prices over the last 12 months really hitting this quarter? And should we expect a decline now or do we see strength continuing on for the next couple quarters in Puna?

How I see it, you'll see a slightly modified formula for which they are determining the devoted costs in the last two years, so the relationship with oil prices is a little weaker than it was two years ago and before. But I think that we might see a reduction in the current electric prices, but we don't expect it to be big.

Okay, then just two more. On the revenue side, Dita, to someone's earlier question, to get to even the top end of your guidance, I have to have about a $7 million step down in electricity revenue quarter over quarter. And I'm just wondering why the revenue would be stepping down.

Because the third quarter is enjoying from the higher rates in the standard SO4 contracts which is the California contracts, those California contracts that have a kind of fuel element. And these are the standard SO4 in Brawley. So the third quarter revenues are higher than (inaudible) at the same level of activity the fourth quarter revenues are essentially, not essentially, but they're lower.

Okay, perfect. And then on the product gross margin, it was pretty strong this quarter, and then obviously with the strength in sales next quarter, how do I think about margin? I know you guide to 20%, 22% typically as a historic rate, but in years where we see high product margin we've seen gross margins much higher than that. So is that how we should think about it?

This year we are seeing higher amounts in the product segment because of the electric projects that recognized revenue in the second quarter I believe with no costs associated because this was part of R&D before. So this is one of the reasons for year over year higher margin. The third quarter margin is more a volume and mix related.

And so looking forward to 2012 --

With higher volume we can expect slightly higher gross margin, but then when the volume goes back to say $100 million a year, then it will go down again.

Okay. My final question on the dividend front, were you actually up against hitting a covenant if you issued a dividend? Is that what caused you not to issue the dividend?

Yes, the covenant is not (inaudible). The covenant of the dividend, related to the dividend is 35% of net income. And if we were to distribute a dividend, we would have saved 35% of net income. Our policy, our dividend policy is 30% of net income, our covenant is 35% of net income. And with the treasury rate loss, we would save, not make the debt covenant of 35%.

Great. Thank you. And sorry for all the questions. Thank you.

Elaine Kwei, Jefferies.

Hi, everyone. Thanks so much. Could you just remind us where we're at in terms of the current level of production at Jersey Valley and what the criteria would be for commercial operation? And if there are any pending deadlines under the PPA there?

Jersey is operating at around 5 megawatts at this time. And theoretically yes, there are pending deadlines on the PPA, but we believe that the reason that Jersey is not producing at the higher rate is the force majeure because of the damage that was done by previous drilling, not geothermal drilling as it was is unreclaimed, is really something that we did not know of and was not in our control. And I think that there is interest on both, certainly on our side but also on the side of the utility, to be patient and let us work through this area or this problem by developing other areas that were not affected by mining activity. And hopefully this will not be an issue.

Okay. Is there any kind of -- is that something that you anticipate would take six months or two years or even longer? Or any kind of timeframe on that?

So we have drilled -- we have drilled one new injection well in the new area. We did a short turn test and we will move into a long term test. If the results of the long term test are in line with what we expected and what we saw in the short term test, this would certainly bring our generation up substantially. And we will continue and develop in that area additional wells. The delay was because of the time that it took us to permit this area. This is an area that was not previously permitted. We have now caught up with that activity and so based on results we could move fairly quickly and I would say it's not two years. Now if the results are negative, we'll have to see what we do, but if they are positive, it will not take two years.

Okay, but you still intend to eventually get to the original stated production capacity there?

Of course. Yes.

Okay, then do you have any view on the timing of the PC approval for the Puna enhancement? Is that something that's before the end of the year or is it a more extended process there?

We hope that it's not that extended process, but it's not something that we -- we are not participants in the process itself so we can't tell.

Okay. Just earlier, Yoram, just to make sure I understood your comments on North Brawley, it sounds like with your current activities there you can get to a 33 to 35 megawatt level. But getting beyond that will require new well drilling. Is that -- did I understand that correctly?

Yes, we had demonstrated last March, or this March, I'm sorry, we have demonstrated in a test capacity of a little over 33 megawatts. It was a fairly warm day, so prior to that we were actually running at about 35 megawatts. So if you look at the existing wells, both injection and production, what can they do? They can do about 35 megawatts.

Anything beyond that would require some work-over of the wells or some modification of the wells or drilling additional wells. There's nothing magic about 33 megawatts, it's just that this is a number that we've already demonstrated, so that part is less questionable. Our intent would be to of course move beyond that on that facility.

Okay. Is there ever a point that would be reached where it would make more sense not to drill additional wells? Or would you just continue drilling until you got to that 50 megawatt level?

Yes, there is a scenario where it's not worth continuing to work on that facility. We don't intend to reach that position and hope that we don't. But forgive me if I'm becoming a little too technical, but the point that we were, that I was trying to make is that not all wells are the same. There's this very big diversity among the wells we currently service, call it 33 megawatts. Each of them makes sense -- if they were operating for three years between pump replacements, all of them would make a lot of sense. Until we reach that point, then some of them do make sense, some of them don't make sense. And that's actually, that's also the trigger for drilling new wells.

Just to give a rough number and not a precise number, but a 380 degree well is, could be justified typically, even if the pump only lasted a month in it. A 300 degree well would require two year lifetime in order to be justified. And so as we understand, further our understanding of the well fields and our expectation to find one temperature, one form of fluid at a certain area, or a different form of fluid at a certain area, this would also indicate whether it's reasonable at the current operating cost and especially chemical costs and pump life expectancy whether we should drill in that location of the field or not.

And so there is a dynamic process that is based on -- any decision is really based on the current state of the equipment. And based on this, that would be one of the reasons to continue and spend money or wait with the additional expenditures until we have resultive pumps.

And there is, at the risk of saying something that we already said, we view the pump issue as something that is a short to medium term problem and ultimately will be solved because it has been solved in other areas. And it's just a matter of coming up with the right solution. In the meantime we don't want to spend money too soon or lose money on frequent pump replacement and this lies our strategy.

Right. Just last one -- so between North Brawley and Jersey Valley it sounds like if there is additional drilling or additional wells that would make sense, then would there be -- would that require additional financing on your part? Or is that something that could be financed out of existing funds for either project?

The level of the investment of such is we can finance it from our own resources. We don't need additional financing. Don't forget that Brawley is not financed. Brawley is carried on our balance sheet (inaudible) and certainly once we bring it to a certain level of performance it will be part of the (inaudible) financing in the future. But those improvements are a development of normal operating capital.

Okay, thank you so much.

JinMing Liu, Ardour Capital.

Good morning. Thanks for taking my question. Most of my questions have been answered. Just one for me. The $130 million supply in the [EPC] account in New Zealand, can you give us some, in terms of timing of that contract, and also whether the EPC part of that contract will have some negative impact on your product margin?

The timing is I think we assumed the contract in June and a typical delivery is 22 to 24 months. So the majority of the revenue won't be recognized until the end of 2012 with some carryover to 2013.

How about the EPC part of that contract?

It's all together. It's supply and construction.

So you will not take -- in terms of revenue recognition, you will not take a percentage of completion (inaudible) -- what's the term, just whatever the whole project, all the revenue together?

No, no. We recognize revenues on most of our EPC contracts and most of our supply contracts. We recognize the revenues based on the progress.

Tom Daniels, Stifel Nicolaus.

Good morning. Thanks for taking my question. Just looking at your product segment backlog, if I think about you guys executing on that over the next five quarters, it would imply about $165 million in revenue in 2012. Last time you did that it was at a gross margin around 29.5%. Is there any reason we shouldn't think you'll be able to achieve a similar gross margin on the product side in 2012?

Some reason. And the reason is that in 2009, in addition to the volume, we also had the benefit of declining commodity prices. I don't know if we are today in the same economic situation.

Okay, so maybe slightly lower. And then as you guys execute on that product backlog, is there any upfront or backend loaded? Should we think of it as kind of a pretty even execution over the next five quarters?

No, typically it could be a combination of projects -- how do you call it -- an S curve.

I missed that, what was it?

A typical (inaudible) of income recognition in a project is an S curve and not a straight line.

Okay. On your electricity gross margins, do you guys feel with the operational improvements you've kind of reached a higher run rate here moving forward? And then maybe comment on how the SO4 contract reduction will impact gross margin on electricity?

I'm sorry, I didn't get your question.

The electricity gross margin, 33.3%, adjusted for North Brawley, 39.1%. Operational improvements, is this a new run rate for electricity gross margin? And then can you comment on the gross margin considering the SO4 contracts and how there's a $9.4 million reduction in revenues. Will that have a negative impact on gross margin as you go forward?

It will clearly have a negative impact on gross margin because it's a reduction in revenue for a similar level of costs. So unless there are some operational efficiencies, it will have an impact on gross margin, yes.

But our intent is not to stay in this situation for long and so I think -- I mean all of this will happen in 2012, second quarter of 2012, and this is not our intent to be in this situation.

Okay. On the operating expense line, you guys, it went down sequentially. Are we -- is there anything in there specifically that happened this quarter or is this kind of a newer run rate for you?

I think that it's -- in principal this is, part of this is really the fruits of our labor. And a lot of this is work in Brawley and other locations. Whenever this is done by design and by design and by effort, then it's a lasting effect. But some of it is circumstances. There was a big outage, not related to us of course, in southern California in the beginning of September that took the whole southern California grid down. Such an outage can cause damage to equipment. And then it's certainly not expected, not controlled, and this has a temporary impact. But a lot of this is really effort that was done and real savings.

Okay, then one last question. Can you guys talk a little bit about your income taxes and how you expect those maybe on a dollar amount to kind of move going forward? It's kind of been all over the map.

That's a very complicated question and actually it's more than that. There are several factors that impact our tax calculation, especially on a quarterly basis when you use the average tax rate for the year. And what is happening is that we have a big ITC amount which impacts substantially our income tax expense benefit when you have a relatively low pretax income. And as always, the fourth quarter will be a kind of catch up. But because that's the way you calculate the taxes on the cap. So we expect, for the whole year we expect a tax benefit and not tax expense because of the (inaudible). So it's difficult to tell you how we will look at yearend, but we will have a catch up in Q4.

Okay, then going into 2012, you guys don't expect to be paying taxes, you should still expect a credit, correct?

We are not expecting to pay taxes in the States, but we will pay taxes in some of the other locations. In Guatemala we don't pay taxes. In other locations, in Kenya, we have accelerated depreciation, but we have tax expense. And in the States we would probably (inaudible).

Okay, understood. When it washes all out at the corporate level, do you guys expect to be paying taxes or getting a tax credit?

In 2012?

Yes.

We are expecting to pay taxes in some locations and have credit in others and not paying it out, have a tax benefit.

Right, at a corporate level overall --

Overall, 2012, I don't think we give guidance on taxes for 2012. I can talk about 2011.

Okay. Thank you.

Mark Barnett, Morningstar.

Good morning. A couple of quick questions. I think I may have heard something incorrectly. But with Carson Lake, even in your prior calls you had already anticipated you wouldn't be qualifying for the ITC, and it still says that in the presentation deck. I was wondering if there was any acceleration in the timing that led that to be again kind of a possibility?

At this point we keep it out of the 2013 bracket because it is late. It's financially possible, but we're not convinced that it is and therefore we keep it out. If we change our minds we will share this with you and everybody else.

Okay, so your expectations haven't changed then, okay. And then just a couple of quick questions on the PPAs. Is there anything specifically holding up the Puna PPA for the enhancement or is that just another timing issue?

We are not aware of a reason why the PPA should not be approved by the PUC, but it hasn't been approved yet. Nothing has been shared with us, so we can't give an intelligent answer.

Okay, then I saw you had received the permit to continue drilling for Jersey Valley. Have you dealt with the PPA extension issue at that plant yet or is that still in progress?

We are in contact with the utility and we're keeping them appraised of the situation and there's frequent communication with them of course.

Okay, so is the force majeure issue going to need to be resolved before you modify the PPA?

No, the PPA does not need to be modified. The issue that we have with the utility is that both we and them expected to get commercial power by now. And because of the force majeure impact, we cannot provide the amount of commercial power that we expected. And this is where we need to work hard and they need to understand us and hopefully when there is will on both sides we will work towards the resolution.

Okay, thanks for the comments.

Tim Arcuri, Citi.

Hi, guys. Just wondering to what extent any of the exchanges or talk of change in ownership at Ormat's parent level have any implications for Ormat Technologies?

It has no implications for Ormat Technologies.

Stephen Malonovich, Bank of America, Merrill Lynch.

Good morning, thanks for taking my questions. This is Peter in for Steve. Most of my questions have been answered. A quick one, with the outage in California, I mean utilization was pretty low for the quarter compared to other previous 3Qs. Where there any other unscheduled maintenance work during the quarter? And could there be some that could creep into the fourth quarter?

I'm sorry, what do you mean about the outage in California? Or the utilization, what do you mean by that?

Well utilization on the aggregate level was pretty low and comparative to Q3 last year and I think you talked about some maintenance behind that. I think a previous caller mentioned some outage in California. Was there any unscheduled maintenance during the quarter and is there a potential for some that could be in Q4?

No, I think what I meant was there was a big blackout in the southern California grid that took everybody down. It was just an example of how something that is outside of the plant could actually result in damage. Fortunately for us, a hard shutdown of a power plant is oftentimes, not only in the geothermal power plants, oftentimes results in some damages because it is a shock and this is what happens when the grid disappears. For us, it was for most of the southern California facilities, it was just a few hours and they were back online without big damages. We had a little more damage in Heber but nothing dramatic.

I think that if you look at generation is lower by 3%, 3% is not a huge number. It's timing of major maintenance, so there was nothing really dramatic in the third quarter and we don't know of anything dramatic in the fourth quarter. It's not so much of a trend, that 3% change, it is just, if you like, it's sort of a ripple or a wave on a general sideline. Since we didn't put any substantial amount of capacity online between the last, the Q3 2010 and Q3 2011, and that's about the number.

That's good color, thank you. And I want to follow up a little bit on some of Elaine's questions earlier regarding the ultimate output of Brawley. As it relates to the DOE funding that you've received, are there any mandates under that or terms that require you to reach a certain output?

So we did not get DOE funding for Brawley. All that we got for Brawley was the ITC cash grant. And the ITC cash grant is driven by investment, not by performance. Of course the owner has to continue and operate at the plant for a certain period of time, that's certainly our intent. So generation is not an issue when it comes to any recapture from Brawley. But certainly it's an issue for us and we are working to get generation and especially revenues, or especially EBITDA, higher.

Very good. Thank you.

There are no further questions at this time. I'll turn the conference back over to Dita for any further remarks.

Thank you all for the good questions. Maybe one clarification that I'm not sure I answered totally and I take this opportunity to emphasize, our dividend policy is a modest dividend policy. The salt behind it is to provide some equilibrium between need of shareholder for some return, some cash return on their investment. But the major benefit of the investor is in the improvement of the Company in the sale price in particular. So I think that even though we had to discontinue dividend distributions this quarter, maybe next quarter, I don't think it makes a major change in the value of the investment in Ormat. And we would like to thank you all for your continued interest and hopefully joint success of Ormat. Thank you.

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