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. [Operator Instructions] 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, Chief Executive Officer; Yoram Bronicki, President and Chief Operating Officer; Joseph Tenne, Chief Financial Officer; and Smadar Lavi, Vice President of Corporate Finance and Investor Relations. Before beginning, we would like to remind you that information provided during this call may contain forward-looking statements relating to current expectations, estimates, forecasts and projections about future events that are forward-looking as defined in the Private Securities Litigation Reform Act of 1995. These forward-looking statements generally relate to the company's plans, objective and expectations for future operations are based on management's current estimates and projections of future results or trends. Actual future results may differ material 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 ormat.com under the IR Event 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, and 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 Electricity and Product segment and maintained a very strong backlog. The quarterly adjusted EBITDA was $46.7 million. In addition, we successfully enhanced our access to cash with new financing from a 20-year, 80% BOE guaranteed loan under the program designed for commercially proven projects that provides appropriate funding for our multiphase 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 low interest rate lock transactions we have entered into in anticipation of the BOE loan to mitigate the interest volatility in the 10-year treasury rate. The interest rate would have been 6.22% had we created the loss on the interest lock as a hedge. Still, it's very attractive interest rates for the projects 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 rate at the Puna and Amatitlan plants, such increase was partially offset by a 3% decrease in generation due to major maintenance activity in some of our power plants. In the Product segment, on next slide, revenues for the quarter were $24 million, an increase over revenues of $18.1 million in the same quarter of 2010. The increase in product revenues reflects the new customer order that we secured in the second quarter of 2011. Moving to Slide 8. The company combined gross margin for this quarter was 32.3% compared to 24.8% for the first 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 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 all customer orders. Moving to Slide 9. Interest expense net for the quarter was $23.9 million compared to $11 million in the third quarter of 2010. The increase was principally due to an $11.6 million loss from an interest rate lock transaction related to the BOE loan guarantee debt, and which was not accounted for as a hedge transaction. As Dita mentioned, this interest…

Thank you, Joseph, and good morning, everyone. Starting with Slide 15. You have seen earlier we had good results from our Electricity segment. Generation was lower this quarter mostly due to short-term maintenance events, but the revenues 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 continue the practice of selective operation of production well. While this resulted in lower revenues, it also reduced cash operating costs by $2.5 million resulting in a better EBITDA. In parallel, we continue 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're monitoring the progress of the Global Settlement of the SO4 contracts of Heber or main side Mammoth, which is expected to become effective later this month. The Global Settlement requires us to amend the SO4 contracts to reflect the pricing option based on a short run of what it cost methodology, with certain applied modifiers until December 2014, and thereafter converts to a mandatory short run of what it cost methodology pricing. This makes both our revenues from these PPAs to greater fluctuation 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 by approximately $9.5 million, and in 2013 by approximately $6.5 million. It's not possible at this point to estimate…

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. And I'll start with Slide 21. As mentioned in my opening remarks, we've finalized the loan agreements for up to $350 million under the U.S Department of Energy's 1705 Loan Guarantee Program to finance 3 projects in Nevada, and we received a $310 million commitment form OPIC to refinance and expand the Olkaria complex in Kenya. The BOE guarantee of the 20-year loan for up to $350 million of financing from John Hancock Life insurance, provides us several refinancings to support the development of Jersey Valley, Tuscarora and McGinness Hills. It is the portfolio's 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 3 power plants in 2 phases each. The expected generating capacity of all 3 power plants in both phases is up 213 megawatts. The capacity of the first phase is expected to be approximately 60 megawatts and capacity of the second phase will be determined following the feasibility assessment of the geothermal resource which will be performed following completion of the first phase of each facility. This 2-phased approach allows us to manage risks, and by including the second phase in [indiscernible] financing to better control long-term interest rates. 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 refinancing tranche of up to $85 million to repay the existing loan…

[Operator Instructions] Your first question is from the line of Paul Clegg with Mizuho.

On the SO4 contracts, your warning of a headwind there... [Technical Difficulty]

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

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, et cetera. I mean, the number is -- I guess I'm just wondering, 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.

Is that something that's under discussion? Is that a possibility? And given the rates that are embedded 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 that 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 cost formula 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 the loan -- 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 and monitor the forecast if you'd lock a 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 3 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 a benchmark to show that this is -- it's not nice, but it's not dramatic, and certainly, as a company we can live with it.

But you are pursuing other alternatives because you do believe these are below market? And worst-case scenario, if 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 just assuming you could square that. And does it relate just to the specific facilities that were down, or if you could just explain that a little bit?

Yes. Our output is just slightly down, I think. In terms of total capacity, it's about 3% below what it was in 2010. So within -- not a huge difference. But really, what we have is in our mix theres's such a multitude of PPA prices that sometimes you can get ahead 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 the high-value contracts. And some of the hit that we took was not over maintenance or other issues was really in contracts that are not as significant. And of course, we were able to reduce costs, which is always a 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.

Okay. 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 spot, so the top purchase agreement is the flow, but we have no right to fail in the market as well. So we sold a little bit in the market, and this is what created the higher rate with Amatitlan. Puna is clearly a floating rate, again with the flow, but the flow is so far off, we don't even mention it anymore.

Is that something you'll be able to take advantage of on Amatitlan in the future? 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 price are higher than our flow, 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.

Your next question is from the line of Paul Clegg with Mizuho.

On the revenue guidance, you had a pretty strong quarter on the Electricity side. And you've actually, I think each quarter this year, been up in that segment versus last year, and 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, 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 put you incrementally behind or flat with last year?

No. But when we look at our -- I mean, what we have changed during the year, from the beginning of the year is really the way we operated Brawley. And we operated Brawley at a lower revenue rate but a substantially lower cost rate. Yoram is probably the 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 on the cost structure there. It looks like you're getting pretty close to cash flow breakeven. But when can you 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?

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 when we described it in our last earning call, what we did is operate the wells that are what we call the high-grade wells, the one that produced a relatively higher portion of power from them because the wells are not identical. And while operating these wells to the pump lines, because the pump costs the same whether it's in a highly productive well or in 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 a progress there. And we will see the ramp up of generation will be gradual as we get more comfortable in the pump lines. I'll just use illustrated figures, but once we're confident that we have the 9-month average life for a pump, there's a group of wells that's 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 -- it can bring us to the demonstrated capacity of 33, 35 megawatt. 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 -- hope for our target would 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?

No, out of the $200 million backlog that we have at the end of the third quarter and between the fourth quarter next year, we recognize most of it.

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 contradictability in the timing of the queue in new orders. In the same way as the difference between 2009 and 2010, we have 2009 was a very good year in the Product Segment, 2010 was lower. And now we are -- we see a pickup, we may see such a phenomena in the future and we may not. Very hard to predict.

Your next question is from the line of Ben Kallo with Robert W. Baird. Benjamin J. Kallo - Robert W. Baird & Co. Incorporated, Research Division: My first question's on Brawley, on the EBITDA. There's the discussion of moving towards EBITDA positive for Brawley. And I just kind of wanted to get a timeframe around that, Yoram, or at least breakeven maybe?

So we promised 2 quarters ago not to give forward looking statements on Brawley. I don't know how, I'm trying to figure how to [indiscernible]. But I think, I mean, 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 a guess, and I hope that I can beat your guess in terms of timing. But beyond that, there's not a lot that I can say. Benjamin J. Kallo - Robert W. Baird & Co. Incorporated, Research Division: Okay. And 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 2 years since Q3 '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 this strip [ph] is coming from?

I think, Dan, 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 that 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 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 2 plants that have enjoyed higher rates and that's great. But beyond that operational cost are -- were down, almost across the board. Benjamin J. Kallo - Robert W. Baird & Co. Incorporated, Research Division: 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 it to climb down or do we see strength continuing on for the next couple of quarters in Puna?

The Hawaiian electricity -- Hawaii PUC has slightly modified the formula to which they are determining the [indiscernible] cost in the last 2 years. So the relationship with oil prices is a little weaker than it was 2 years ago and before. But I think that we might see a reduction in the current level prices, but we don't expect it to be big. Benjamin J. Kallo - Robert W. Baird & Co. Incorporated, Research Division: Okay. And then just 2 more. On the revenue side, again, at someone's earlier question, to get to even 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 sales quarter is enjoying from the higher rates in December for a number of full contracts, which is the California contract. Those California contracts that have a time of use elements, and these are the standard SO4 at standard Brawley. So the third quarter revenues are higher than the entire year. And at the same level of activity, the fourth quarter revenues are lower. Benjamin J. Kallo - Robert W. Baird & Co. Incorporated, Research Division: And then on the product gross margin, it's 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 the years where we're seeing high product margin, we've seen gross margins much higher than that. So is that how we should think about it?

This year we're seeing higher amounts in the Product Segment because of the LNG project that we recognized revenues in the second quarter, I believe, with no cost associated because it was part of R&D before. So this is one of the reasons for year-over-year higher margins. The third quarter margin is more volume and mix related. So the higher... Benjamin J. Kallo - Robert W. Baird & Co. Incorporated, Research Division: Okay. Then so looking forward to 2012...

With higher volume, we can expect slightly higher gross margin. And then when the volume goes back to $100 million a year, then it will go down again. Benjamin J. Kallo - Robert W. Baird & Co. Incorporated, Research Division: Okay. And 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 a secret. The covenant of the dividend -- elected to the dividend is 35% of net income. And if we were to distribute the dividend, we would exceed 35% of net income. Our dividend policy is 20% of net income, our covenant is 35% of net income and with the treasury rate low, we would have not made the debt covenant of 35%.

Our next question is from the line of Elaine Kwei with Jefferies. Elaine Kwei - Jefferies & Company, Inc., Research Division: 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 is there 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 the damage that was done by previous drilling, not geothermal drilling as it was unreclaimed, is really something that we did not know of and was not in our control. And I think that there's 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. Elaine Kwei - Jefferies & Company, Inc., Research Division: Okay. Is there any kind of -- is that something that you anticipate will take 6 months or 2 years or even longer? Or any kind of timeframe on that?

So we have drilled one new injection well in the new area. We did a short-term test and we will move into a long-term test. If the results of the long-term tests 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 2 years. Now if the results are negative, I want to see what we do. But if they are positive, it will not take 2 years. Elaine Kwei - Jefferies & Company, Inc., Research Division: Okay. But you still intend to eventually get to the original stated production capacity there?

Yes. Elaine Kwei - Jefferies & Company, Inc., Research Division: Okay. Great. And then do you have any view on the timing of the PUC approval for the Puna Enhancement? Is that something that's before the end of year or is that a more extended process there?

We hope that it's not that extended process, but it's not something that -- we are not participants in the process itself, so we can't tell. Elaine Kwei - Jefferies & Company, Inc., Research Division: Okay. And just earlier Yoram, I just want to make sure I understood your comments on North Brawley, it sounds like with your current activity there you can get to a 33-megawatt to 35-megawatt level, but getting beyond that will require new well drilling, was that -- did I understand that correctly?

Yes. We have demonstrated this March, we have demonstrated in the test capacity of a little over 33-megawatt. It was a fairly warm day, so prior to that we're 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-megawatt. 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 megawatt, 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. Elaine Kwei - Jefferies & Company, Inc., Research Division: 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 doomsday scenario where it's not worth continuing to work on that facility. We don't intend to reach that position, we hope that we don't. But forgive me if I'm becoming a little too technical, but the point that we were trying -- I was trying to make is that not all wells are the same. There's a very big diversity among the wells currently serviced, call it 33 megawatt. Each of them makes sense if they were operating for 3 years between pump replacements, all of them will 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 could be justified typically, even if the pump only lasted a month in it. A 300-degree well would require a 3-year lifetime in order to be justified. And so if as we further our understanding of the well field 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 cost and pump life expectancy, whether we should drill in that location of the field or not. And so it 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 resolved the 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 drives our strategy. Elaine Kwei - Jefferies & Company, Inc., Research Division: Right. And 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 that require additional financing on your part? Or is that something that could be financed out of existing funds at [ph] free project?

No. The level of the investment of such that we can finance this from our own resources, we don't need additional financing. Don't forget that Brawley is not financed. Brawley is current on our balance sheet and signal [ph], and certainly once we point it to a certain level of performance, it will be bolted between [ph] financed in the future. But those improvements are delevering of normal operating profit. They may be higher.

Your next question is from the line of JinMing Liu with Ardour Capital.

Most of my questions have been answered, just one for me. The $130 million supply in the EPC contract in New Zealand, can you give us 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 think received the contract in June, and the typical delivery, 22 to 24 months. So the majority of the revenues will be recognized until the end of 2012 with some carryover to 2014. [indiscernible]

How about the EPC part of that contract?

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

So you will not take, say, in terms of revenue rec how initially you will not take a percentage of completion out there, you go out at true self--what's the term? All the revenue altogether?

No. No. Based on completion, we recognize revenue on most of our EPC contracts and most of our supply contracts. We recognize the revenue based on progress.

Your next question is from the line of Tom Daniels with Stifel, Nicolaus. Thomas Daniels - Stifel, Nicolaus & Co., Inc., Research Division: Just looking at your Product segment backlog. If I think about you guys executing on that over the next 5 quarters, it would imply about $165 million in revenue in 2012. Last time you did that it was at a gross margin of around 29.5%. Is there any reason we shouldn't think you'll be able to achieve a similar gross margin on the products 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. Thomas Daniels - Stifel, Nicolaus & Co., Inc., Research Division: Okay. So it may be slightly lower. And then as you guys execute on that product backlog, is there any upfront or back-end loaded? Should we think of it as kind of a pretty even execution over the next 5 quarters?

No. It's typically income recognition of the project is, how do you call it?

[indiscernible]

An S-scale [ph]. Thomas Daniels - Stifel, Nicolaus & Co., Inc., Research Division: Sorry, I missed that. What was it?

A typical profile of income recognition in the project is an S-scale [ph] and not a straight line. Thomas Daniels - Stifel, Nicolaus & Co., Inc., Research Division: 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. Thomas Daniels - Stifel, Nicolaus & Co., Inc., Research Division: The Electricity grew its margin 33.3%, adjusted from 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 does the $9.4 million reduction in revenues will that have a negative impact on gross margin as you move forward?

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

But it's not -- our intent is not to stay in this situation for long. And so I think -- I mean, all of this will happen in 2012 or at the second quarter of 2012, and this is not our intent to be in this situation. Thomas Daniels - Stifel, Nicolaus & Co., Inc., Research Division: Okay. On the operating expense side, you guys went down sequentially. 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 principle, part of this is really the fruit of our labor. And a lot of this is work in Brawley and other locations. Whenever this is done 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 could 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 saving. Thomas Daniels - Stifel, Nicolaus & Co., Inc., Research Division: Okay. And then just one last question, can you talk about 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.

It's a very complicated question, and the answer is even 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 IPC amount which impacts substantially our income tax expense benefit when you have a relatively low pretax income. And as always, it also will be a kind of catch up, but because that's the way that you calculate the taxes under cap. So we expect for the whole year -- we expect a tax benefit and not a tax expense, because of [indiscernible] tell you how it will look by year end. Thomas Daniels - Stifel, Nicolaus & Co., Inc., Research Division: Okay. And then going into 2012, you guys don't expect to be paying taxes, you still expect a credit, correct?

We are not expecting to pay taxes in the States, but we would pay taxes in some of the other locations, because in some others [indiscernible] we don't pay taxes. In other locations we have, in Kenya we have auxiliary depreciation, but we have tax exempts. And in the States, we would probably have the pretaxes because we have provision on [ph] basis. Thomas Daniels - Stifel, Nicolaus & Co., Inc., Research Division: Okay, I 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? Thomas Daniels - Stifel, Nicolaus & Co., Inc., Research Division: Yes.

We are expecting to pay taxes in some locations and have credit in others, and not paying in others and have tax benefits. Thomas Daniels - Stifel, Nicolaus & Co., Inc., Research Division: Right. At a corporate level overall when it washes out?

It depends on where are you. Overall? In 2012? Thomas Daniels - Stifel, Nicolaus & Co., Inc., Research Division: Yes.

I don't think we give guidance on taxes for 2012. Not at this stage. I can talk about 2011.

Your next question is from the line of Mark Barnett with MorningStar.

A couple of quick questions, I think I may have heard something incorrectly. But with Carson Lake, even on 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, 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 potentially possible, but we're not convinced that it is, and therefore we keep it out. If we change our mind, we will share this with you and everybody else.

Okay. So your expectations hadn'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. And 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 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 par that we expected. And this is where we need to work hard and they need to understand us, and hopefully when there's will on both sides, we will work towards a resolution.

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

I was 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?

Sure. It has no implication for Ormat Technologies.

Your next question is from the line of Steven Milunovich with Bank of America Merrill Lynch.

This is Peter in for Steve. Most of my questions have been answered. Quick one with the outage in California, I mean, utilization was pretty low for the quarter compared to other previous 3Qs, were 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 3Q last year, and I think you talked about some maintenance behind that. And 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 mentioned was that there was a big blackout in the Southern California grid that took everybody down. And that actually 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 often times not only the geothermal part, but it often times 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, it's a little -- it's lower by 3%. 3% is not a huge number, it's timing of major maintenance. So there was nothing really dramatically 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'd like it, sort of a ripple or a wave on a general sideline. And since we didn't put any substantial amount of capacity online between the Q3 2010 and Q3 2011, then that's about the number.

That's good color. 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. Although we got for Brawley was the ITC cash grant. The ITC cash grant is driven by investment not by performance. Of course, the owner has to continue and operate 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 I should say, especially EBITDA higher.

And 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 properly and I'll take this opportunity to emphasize. Our dividend policy, the modest dividend policy, the thought behind this is to provide some equilibrium between need of shareholder for some return of sale -- some cash return on their investment. But the major benefit of the investor is in the improvement of the company in the share price, et cetera. So I think that even though we had to discontinue dividend distributions this quarter or 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 a joint successful for all of us. Thank you.

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