Ormat Technologies, Inc. (ORA) Q4 2010 Earnings Report, Transcript and Summary

Good morning. My name is Wes, and I will be your conference operator today. At this time, I would like to welcome everyone to the Ormat Technologies Fourth Quarter and Year End Earnings Conference Call. [Operator Instructions] I'll now turn the conference over to Marybeth Csaby. Please go ahead, ma'am.

Thank you, Wes. Hosting the call today are Dita Bornicki, Chief Executive Officer; Yoram Bornicki, 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 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 related to the company's plans, objectives and expectations for future operations and are based on management's current estimates and projections of future results or trends. Actual future results may differ materially from those projected as a result of certain risks and uncertainties. For a discussion of such risks and uncertainties, please see risk factors as described in the annual report on Form 10-K filed with the Securities and Exchange Commission on March 8, 2010. In addition, during this call, statements may include financial measures defined as non-GAAP financial measures by the Securities and Exchange Commission, such as EBITDA and adjusted EBITDA. The presentation of this financial information is not intended to be considered in isolation or as a substitute for the financial information prepared and presented in accordance with GAAP. Management of Ormat Technologies believes that adjusted EBITDA may provide meaningful supplemental information regarding liquidity measurement that both management and investors benefit from referring to this 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 comparison to the company's historical liquidity. Before I turn the call over to management, I would like to remind everyone that a slide presentation accompanies this call, and can be accessed on Ormat's website at www.ormat.com under the IR and Presentations link, as found on the Investor Relations tab. With that said, I would like to turn the call over to Dita. Dita, the floor is yours.

Thanks, Marybeth. Good morning, everyone, and thank you for joining us today for the presentation of the summary of 2010 and the outlook for the near future. 2010 was highlighted by strong production in the Electricity segment. Year-over-year output increased by more than half a million megawatt hour and segment revenue grew by over 15%. Despite the number of unique challenges at North Brawley electricities [ph] in plants for long-term growth continue unimpeded. As Yoram will explain for later in the call, we have made considerable progress in our construction, development and exploration activities. In parallel, we raised the capital required to support such activities. Let me turn the call over to Joseph for a review of the financial. Yoram will review our operations and as usual, following my remarks, we will open the call up for Q&A. Joseph?

Thank you, Dita, and good morning, everyone. Beginning Slide 5, our Electricity segment revenues for the year were $291.8 million, a 15.5% increase compared to $252.6 million in the previous year. The increase in revenue is due to 14% increase in total electricity generation as a result of additional generation and capacity with Puna, North Brawley and Mammoth being the major contributors. The increase also positively reflected by a slight increase in the average revenue rate of our electricity portfolio. In our Product segment on Slide 6, revenue for the year were $81.4 million, a 48.9% decrease from $159.4 million in the previous year. This decrease in our product revenues is a result of a decline in our Product segment customers' orders which we have discussed in previous calls. For the year ended December 31, 2010, total revenues were $373.2 million, compared to $412 million in the previous year as shown in Slide 7. Moving to the next slide, the total gross margin was 20.8%, compared to 29.2% last year. Gross margin of the Electricity segment was 17%, compared to 29.1% last year. As anticipated, the decrease in gross margin derived mainly from gross margin loss of $24.6 million in North Brawley and an increase in the depreciation amount related to the acquisition of the Mammoth complex. A $25 million out of deferred revenue of the Mammoth complex and the acquisition date of the additional 50% ownership, which was allocated to the existing plant is being depreciated until the complex is repowered in 2013. However, in the mean time, this cost will continue to negatively affect our gross margin. The North Brawley power plant was tested under U.S. GAAP guidance for impairment in the current year due to the low output and the higher-than-expected operating costs. Based on these indicators, we tested North Brawley for recoverability by estimating its future cash flows. The cash flow recoverability concluded that no impairment existed at December 31, 2010. However, if we will not be able to bring the project capacity to approximately 45 megawatts and the operating costs to the level of our current projections, we will have to recall the material impairment of the investment in the power plant. We are continuously assessing our progress in achieving these objectives. Now to Slide 9. Interest expense net for 2010 was $40.5 million, compared to $16.2 million in 2009. The $24.3 million increase was principally due to a $17.9 million decrease in interest, capitalized to projects under construction due to a lower accumulated level of investments in projects under construction during 2010 and an increase in the total amount of interest due to increased level of debt and the higher cost of funds. Moving now the next slide. Net income for the year was $37.2 million or $0.82 per share diluted, compared to $68.6 million or $1.51 per share diluted for the year ended December 31, 2009. The decrease in net income is principally due to a decrease in the gross margin due to the reduction in the Product segment revenue, and the increased Electricity segment cost of revenues relating mainly to North Brawley and to an increasing interest expense net as I previously mentioned. This was partially offset by an after-tax capital gain of $22.4 million related to the acquisition of the controlling interest in the Mammoth complex in California. Now, I would like to go over a few quarterly financial highlights beginning with Slide 11. For the fourth quarter of 2010, total revenues were $92.8 million compared to $94.2 million in the first quarter of 2009. Revenues in the Electricity segment increased 17.1% to $73.6 million, up from $62.8 million in the fourth quarter of 2009. This increase in revenues represent a 22% increase in electricity generation. Revenues in the Product segment were $19.3 million, a decrease of 38.5%, compared to $31.4 million in the fourth quarters of 2009. Now on Slide 12. Net income for the fourth quarter was $4.5 million or $0.10 per share diluted, compared to $16.1 million or $0.35 per share diluted in the fourth quarter of 2009. Net income in the fourth quarter of 2009 included an after-tax gain of $13.3 million resulting from our acquisition from Lehman Brothers of the Class B membership units in OPC. As shown in the following slide, Slide 13, adjusted EBITDA for the year ended December 31, 2010, was $164.3 million compared to $167 million in the year ended December 31, 2009. For the fourth quarter of 2010, adjusted EBITDA was $29.4 million compared to $41.8 million for the same quarter in 2009. Reconciliation of GAAP cash flows from operating activities to EBITDA is set forth in Slide 33. Moving to the next slide. As of December 31, 2010, the company had cash and cash equivalents of $82.8 million, compared to $46.3 million as of December 31, 2009. The accompanying slide breaks down the use of cash during the year. Liquidity came from utilization of revolving credit lines with commercial banks, the proceeds from the issuing of senior unsecured bonds to institutional investors in August 2010 and from the North Brawley ITC cash grant, as well as cash derived from operating activities that we used to fund capital expenditure and to repay long-term debts. Our long-term debt as of the end of the year and the payments schedule are presented in Slide 16 in the presentation. We successfully extended $130 million of our lines of credit in these commercial banks and increased them by additional $40 million. Slide 16 reflects our dividend policy and recent dividend declaration. On February 22, 2011, Ormat's Board of Directors approved the payment of a quarterly cash dividend of fixed $0.05 per share as sent through the company's dividend policy, which started an annual payout ratio of at least 20% of the company's net income subject to Board approval. The dividend will be paid on March 24, 2011, to shareholders of record at the close of business on March 15, 2011. The company expects to pay a dividend of $0.04 per share in the next three quarters in 2011. That concludes my financial overview, and I would like now to turn the call to Yoram.

Good morning, everybody. I'd like to start with operational highlights on Slide 18. The total generation for 2010 was 3.76 million megawatt hour. This represents an increase of 14% from 2009 and approximate 60% increase in total generation over the past five years. Steady growth and total generation each year is a result of completing new projects and enhancement to the existing plants. In 2010, we had a 35 megawatt of capacity to our portfolio including 14.5 megawatt that were added in August once completed acquisition of the Mammoth complex. 5.5 megawatt were added through the commercial operation of the OREG 3 REG Power Plant near Martin County, Minnesota. 15 megawatts were added from the Jersey Valley Power Plant. The plant construction was completed and it was placed in service in the end of 2010, while some oil field work remains to be completed. Our Jersey Valley project was the only utility scale geothermal plant completed in the United States during 2010. The plant is currently operating at about 7 megawatt, and we expect commercial operation in the second quarter of 2011. As you were able to see in Joseph's presentation, the overall good performance of the electricity sector has been heavily affected by the North Brawley power plant and I will summarize the progress at the plant in the following slides. During 2010, we made substantial progress, both in the ability to generate power and in the reduction of the costs associated with operating the facility. Most of our attention was given to the stabilization and increase of injection capacity and we were able to more than double it over the course of the year. In terms of injection capacity, we were able to increase injection flow from a level that support approximately 17 megawatt in the beginning of the year, to what we believe can support at least 40 megawatt. We believe that the measures that we have taken in terms of sand removal and chemical treatment have been effective in stopping the rapid deterioration of injectivity that we have seen in 2009, and that the addition of the East Brawley injection area and better spacing of injection and production in the western field will provide all or most of the injection capacity that is required to reach full power. However, the actual performance of the production wells, as well as the actions that we have taken to improve injection, cause us to be short of production capacity, which at the moment is limiting the outputs to about 30 megawatt. During this quarter, we expect to commission additional production wells that are available, and as we gather more experience from the operation of the field at the higher flow rate, we will determine if and how many additional production or injection wells are required. On Slide 20, you can see the impact of the improvement that were made to the brine processing and the reduction in operating expenses between the two halves of the year. The chart on the right hand of the slide also shows the well field cost and better distribution of manpower cost are the biggest remaining issues. Manpower cost distribution is expected to improve as power generation ramps up. The well field costs are mostly driven by production pump replacement, which is adversely affected by sand production and by the corrosiveness of the brine. Our improvement in this area are expected later this year. We do not expect to see significant reduction in the well field cost in 2009. As you can see on Slide 21, we have seen significant reduction in sand production on the mature production wells. And although we expect some production wells to continue to produce sand during this year, we expect the amount to drop over time. We're also dealing with the problems that are caused by the corrosiveness of the brine through local upgrades and materials of construction and installation methods of the downhaul assembly, and we expect to reach run times that are in-line with what we experienced in other facilities in the Imperial Valley. Moving to Slide 22. As you can see, we made substantial progress this year but didn't reach the desired generation for the plant. We still believe that the North Brawley reservoir is sufficient to support 50 megawatt but this field is less homogeneous than what we initially believed, and a large portion of it is not yet accessible due to the lack of permits. Installation of the hydro clones (sic) [hydro-cyclones] on production wells is expected to further reduce operating costs on the plant side, as it will allow us to keep the sand out of our system. Slide 23 is an update on projects under construction and in it you can see the status and expected completion schedule for each project. During the year, we made significant progress in both early and late stage development. The note-worthy progress on the late stage development were the acquisition of the HSS [Hot Sulfur Springs] project and the balance of the Mammoth complex. The acquisition has allowed us to make progress with Tuscarora construction, the Mammoth repowering and CD-4 development. On the early phase development, we continued to perform geophysical work in a number of sites and have been diligently working on drilling permits that will allow to move some of the prospects into the next stage of development. We will provide updates as we gather more information on the quality of the resource in those ptojects. We're in various stages of construction and development of 10 projects that could add as much as 220 megawatt or 40% to our portfolio by the end of 2013. In addition, there is our 42 megawatt share in the Sarulla project in Indonesia, and our share of approximately 36 megawatt in solar-photovoltaic projects under development in [ph]. In Puna, the construction of the expansion is substantially complete. HELCO still needs to complete the needed modification to the grid, but power can be sold using the existing infrastructure as soon as the PUC approves the new [ph]. Drilling in McGinness Hills continues and we're in the advanced stages of equipment manufacturing. Commercial operation is expected in 2012. Field development at Tuscarora has been completed and equipment is on its way to the site. In Mammoth, we plan to repower the plant by replacing part of the old units with new Ormat-manufactured equipment. The replacement of the equipment will optimize generation and add approximately 3 megawatts. In addition, we have completed one production well and began drilling a second well for the CD-4 expansion. We have no new updates on Carson Lake as EIS process wasn't completed yet. Now let me continue with our projects under development from Slide 24. As part of the joint venture we announced in October 2010, we will develop, construct, own and operate one or more geothermal power plant in the Crump Geyser area located in Lake County, Oregon. At the current time, we have drilled one well and we'll continue drilling throughout 2011. Phase 3 of the Olkaria III complex is progressing. We initialed an amendment to the existing PPA to expand the complex, and we expect to sign this PPA upon receipt of regulatory approval and the consent of the lenders that provided financing. In Sarulla, the consortium executed an agreement amendment to the energy sales contract. The revised power price has been formally approved by the State Audit Agency for Development and declared legally binding by the State Attorney General. Project sponsors have shortlisted the candidates and are currently in the process of selecting mandidately [ph] arrangers out of the shortlisted candidates. Moving to Slide 25 where an update on exploration activities. The key to growth of the geothermal industry's successful exploration of large blocks of land. Ormat remains committed to this process and we continued to search for new prospects in and outside of the U.S. We continued to expand our land position through a total of over 343,000 acres and added seven new sites for future development. We have 24 sites in eight states in the U.S. and an additional three sites in Guatemala and in Chile. We're conducting exploration studies in eight sites of the U.S. and in six other sites, we have completed studies and are waiting for the [indiscernible] to start drilling. Given the prospective nature of exploration, cost control is key. We feel that we have made additional progress this year and the implementation of geophysical tools and in cost reduction and drilling, for [ph] permitting remains the bottleneck for large-scale exploration activity. So let's now turn to Slide 26 for an update on the Product segment. 2010 was a typical year in terms of revenue from this segment. As of the end of 2010, we have approximately $50 million in the product backlog, of which $30 million will be effective upon receipt of letters of credit. This backlog excludes $15 million in revenue related to the REG LNG project in Spain that we expect to recognize in the first half of 2011. We believe that the near-term development in this segment is mostly outside of the U.S. Let me turn the call over to Dita.

Thank you, Yoram. Let me start with Slide 28 to review some of the financing activities in 2010. During the year, we continued to secure our goal by providing the required financing. Relayed in August and February this year, $250 million for the sale of seven-year senior unsecured bonds. The profit from the offering are utilized to fund goals and has temporarily reduced our corporate goal decline. We closed earlier this month the OPC refinancing transaction in which we sold to JPMorgan our Class B membership increasing OPC for $24.9 million. JPM will be able to benefit from the production tax credit that the OPC projects are eligible for, stock depreciation and operating cash flow generated by the project. We continue to benefit from the federal legislation as later [ph] we are now the developer ending September 2010, a portion of the equity invested in North Brawley we've refinanced is the $108 million cash grant we received under section 1603 of the ARRA. Our application for $350 million loan grant with the Department of Energy to finance three projects in Nevada; McGinness, Jersey Valley and Tuscarora is currently in due diligence stage, and we hope to be able to complete the process before the sunset of the program in September 2011. Please turn to Slide 29 where you will see the CapEx requirement for 2011. In 2011, we plan to invest $232 million for the construction of new projects, and an additional $150 million for development of new projects. We expect also to invest $46 million in exploration drillings at 2011. In addition, our capital expenditure budget for operating power plants is approximately $19 million. Approximately $10 million were budgeted for land acquisition and $10 million to invest in our production facilities. We expect a similar level of CapEx requirement also in 2012. The funding of this program will come from cash on hand at the end of 2010; cash from operations and used corporate lines of credit; cash received from the second tranche of the bond offering and obviously, transaction with JPMorgan; project base for Jersey Valley, McGinness and Tuscarora; and cash grant from Jersey Valley and Puna. Going forward, we intend to finance our projects under construction with long-term project finance debts and ITC cash grants. As we look for 2011, please turn to Slide 30. We expect our 2011 Electricity segment revenues to be between $315 million and $325 million. We move out to our Product segment. We currently expect our 2011 revenue to be between $75 million and $85 million. The first half of the year is going to be impacted by several factors which will impact the expected results in this period. Volumes now [ph] are expected to be at the level of the fourth quarter of 2010. Jersey Valley, which we'll place in service at the end of 2010 but still nothing commercial operation, is going to incur full operating costs but lower revenue. If the buyer takes [ph] the kilowatt hour of the full commercial operation cost is less than the 50%, than the rate under the PPA after commercial operations, the energy rate for Jersey Valley reflects all pricing, which are much lower than the current -- new PPA policy. Additionally, we also expect the lower level of revenue recognition in the Product segment in the first half of 2011, other than the revenue recognition of major product of the regular need at the LNG plant in Spain. This is currently expected in the first quarter. As a result of all these factors, we expect the result losses in the first two quarters of 2011. We do, however, expect to be positive in the remainder of 2011 and in the full year. Let me conclude with a few comments on the general business environment for renewable energy in general and geothermal in particular. 2011 has seen record investments in renewable worldwide. Numbers quoted are in excess of $240 billion. The share of geothermal is, of course, a small fraction of this number, in line with the share of geothermal in the global potential for renewable energy. On the regulatory side, the modest results of Copenhagen at the end of 2009 have not created a breakthrough in global regulation. In the U.S. as well, there was no additional major climate or energy legislation other than the extension by one year of the start of construction deadline for eligibility of ITC cash grant and other than 33% RPS target in California. Going forward, internationally, we will have to wait and see the results of the finds [ph] that we succeed Cancun. Domestically, it is a question. The environmental aspects of the State of the Union of the office of President Obama will call [ph], other statements coming from the house are more conservative. But as long as the RPS from the legislation at the state level is in place, the market in the U.S. for additional renewable power remains substantial. We see a real opportunity of growth in the years to come in the international market and specifically in some emerging markets. Even though in certain parts of the U.S. the competition with low-cost coal and the reduction in demand created some difficulty to some of the renewable energy technology, in the States, though, we are operating geothermal, we have not noticed any resistance to our prices. We were able to sign one PPA and finalize discussions on another one. The concern of the review of nature of gas prices turned to be of a lesser importance to us, as the driver for renewable energy prices is not only the cost of alternative fuel. New PPA prices are still in the $90 to $100 per megawatt hour range. The most notable change in our view is the drastic reduction in the cost of solar PV and the agreement of sales in solar PV developers to affect our prices similar to geothermal would [ph], even though the advantage of geothermal would and remain the fate that we are very close. It remains to be seen if these developers will also be able to build a power plant at these rates. It probably depends not only on the cost of the module, but also on the appetite for the tax benefit created by these investments and availability of reasonably-priced debt. Both the tax equity and the debt market have come back. The fact that we have been able to resell the Lehman positioning OPC to JPMorgan by the weighted price, which is much higher than what we paid when acquired the positioning the fall of 2009 is just one small example. Our ability to waive cohort is reasonably waived [ph] suggest that even though the deal with longer in the program [ph] is only available for projects that can close financing by September of this year that will be available for further development, at the course which is not going to be prohibitive to the development. As far as we are concerned, the fact that our balance sheet is still not level to the full blown capacity of the company at comfortable debt levels means that we will be able to fund our goal with debt to the extent necessary after using a cash grant as long as they are available. Ormat had its share of difficulties in 2010, but our technical and financial strength will enable us to come out of it stronger than before. We remain committed to our whole strategy, which we based on our technical strengths, executions skills, strong land provision and financial stability. With these unique fundamentals, we have and will continue to successfully manage some of development including the 300 megawatts currently under construction and development. So to summarize. The market is there, the capital is accessible and we have the resources to build on the foundation of the strong company we are in order to continue the development and grow within the growing renewable energy market. Before I open the call to questions, I would like to thank you for your support and look forward to what should amount to a better year in many regards. Operator, at this time, I would like to open the call for questions.

[Operator Instructions] Our first question comes from Paul Clegg of Mizuho.

Dita, I thought your comments on Solar just now were very interesting. I am not sure if this is what you are saying, but is solar PV having any crowding out effect on investment in geothermal due to the lower risk of development? Are you seeing any evidence of that?

No, not all. I think that the fact that geothermal is based low is still a substantial benefit of geothermal compared to solar PV, but I might need to adjust the facts of life. The prices of solar PV are coming down.

Are you reconsidering any more opportunities in the Solar business to take advantage of the fact that module prices are coming down?

No, in my view of it, I said it still remains to be seen. The projects can really be based at these prices. What we have seen so far in the PPA side that these prices, we didn't see projects built in these prices. Having said that, we are implementing our solar PV program at a low pace, not at a very aggressive pace, both in Israel were we are in the process of securing the PPA. And in the U.S., the permitting process is of course much longer, but in several site in the U.S., we are permitting PV installations to support or to complement our geothermal generation in these sites.

And then a question on backlog. Backlog was up a bit this quarter, do you think we've already passed the low point on backlog. Is there any downside in the coming quarters as you work off some of those orders? And then just the $50 million, if you could comment on how much of that is recognizable in 2011. And then I noticed that you pointed out that $30 million is subject to a receipt of an LC, and I didn't know if you were clue us in that there might be some risks to that or if you're just giving full disclosure.

We are giving full disclosure. I mean, the content of the backlog, we are confident that we will receive the LC, but we expect to recognize the full $50 million and the $15 million from the LNG plant in 2011, and we are expecting additional orders that will still be recognized during the year.

Your next question comes from Gregg Orrill of Barclays.

I was wondering if the assumption for the average price per megawatt hour in 2011 for the Electricity segment is still around that $78 level, or should we be thinking about a different number?

I would stay with the $78 until we get the actual prices of the new mix.

And then in the event that you would have to take an impairment on North Brawley, is there any cash impact to that?

No, it's only accounting impact, no cash.

And then the third question is just around -- the intra-segment revenue for products is $70 million there. Just if you could provide some color on what opportunities you're seeing there, and how we should think about that going forward.

I'm glad you're asking this question because it's something that I wanted to convey. I do hear or we did hear throughout the year concern about the low level of product backlog. And the truth is, with the manufacturing capacity of the company is used for two customers. One customer is third party customers, and this is what people reflected in our product segment sale. But the most important customer is ourself, and the sale to ourself in 2010 exceeded the level of sale to third-party. And this is what will enable us to add those hundreds of megawatts in the years to come with power plants built by ourselves for ourselves. And that's the importance of this inter-company segment.

Your next question comes from Michael Lapides from Goldman Sachs.

Dita, structurally, when you think about the project development process because from a physical standpoint you've had some issues over the last two years in terms of getting new projects online ramped up to the megawatts you originally discussed with investors. What are you doing differently or what are you planning on doing differently to avoid some of those issues going forward?

I'm not sure we are doing differently. It's just the effect of time, which we changed. What we have definitely underestimated were the time that it takes to bring the project from -- we underestimated this a few years ago. I think, for the last two years we know it, but a few years before, we underestimated the time it takes, from the time we start to work on a grade fuel project until you can bring it out, let's say, online. And there are two elements which are delaying this. One is the time that it takes technically to prove the results, to study the results before this, and the time that is an idle time in between. And this is the time to get the permit for each stage. And when we said a few years ago that the development process from a greenfield to a complete power plant is five years. With the current delays in permitting, it may be even a little longer than five years. And this is when we are the EPC contractor for our sales and we do not depend on deliveries of third-party supplier. I think for a company that is not vertically integrated as we are, it may be even longer. Now what are we doing different? We are exploring in parallel a large number of projects. So we have in the pipeline towards completion in much larger number of projects that are going to mature some of them, not all of them. And it's another thing that we all need to remember, not all of them are going to mature to a successful project. But when you have a number of projects in exploration as we have, we will be able to shorten the time from the time we declared them a project under construction than before.

Do you worry about being spread too thin, trying to do too many projects in too short of a timeframe? Which means maybe from just a labor and a human resources or human capital perspective makes it more challenging to bring in individual projects online, on time, on budget, at the right scale.

Michael, this is Yoram. I think the early part in your question, why is it that we don't get to the capacity that was originally declared on projects, and to couple this with your next question, I would say no, we're not spread too thin. I think that the issue that we had and we shared with our investors is that we underestimated the GAAP between successful discovery, and successful or being able to say that a certain plot is a geothermal field. And the initial estimate of what the size of the field actually is to what actually is the outcome later, at least the initial outcome when the field is -- the development drilling is completed. And I think that the -- and this has been our main issue. In a way, though Brawley is a little different, but in a way Brawley is one case where we underestimated the challenges of producing 50 megawatt. And on a smaller scale, Jersey Valley has been a field that initially we thought could just support 30 megawatt and the more we've drilled there and tested, the more difficult it seemed and we had to choose to start with a 15 megawatt facility. And I think that the solution to this is not so much about being spread thin, the solution to this is just we have to do much more front-end work on the fields that requires more wells to quantify the size and the quality. And there are the disadvantages. If we share information and assessments with the world early on, they're almost bound to become smaller or different as time goes by and what we have to do now is work on more fields and parallel, and actually not share the information until we have better certitude on what the size is.

Your next question comes from Ben Kallo of Baird.

Could you guys give us an update on any disability you have in Sarulla and if any of that is included in your guidance for this year?

The Sarulla is not included in the guidance. I think we said in the prepared remarks that there is progress, but much lower than we had initially expected. And not only initially, initially and subsequently in the middle, it's a very slow process. One, we will reach the final ESC and JOC, the two projects agreement, I think things are going to move much faster. But until now it's not included in the numbers.

And then could you just clarify for Jersey Valley. Is there additional drilling that has to be done to get to 15 megawatts? Or, what has to be done to fully ramp that project?

Yes, we're currently drilling one more well and we hope that, that would be all that is needed in the field. It was very important for us to complete the plant and place it in service in 2010, given the ITC criteria. We were fortunate that it was extended but we didn't rely on that. So we started it with the available well field and we think that will be done very soon.

Your next question comes from Steven Milunovich of Bank of America Merrill Lynch.

This is Peter Christiansen, in for Steve Milunovich. I have a quick question. Do you expect to pay taxes in 2011?

Not in this stage. We're going to pay taxes in other jurisdictions but not in this stage, mainly in Israel in [ph].

So we should expect the effective tax rate to be not what it was in 2009 or 2008?

Look, the effective tax rate is not effective only by cash payments but also by deferred taxes. So the main impact on the taxes in 2010 and in, in probably in 2011 is the production tax credit that is impacting the effective tax rate mainly. Also, I should mention maybe that Product segment in Israel, tax rates are going to decrease substantially from 25% in 2010 to 15% in 2011, which is important to say.

And it seems like you have a lot of construction activity going on. How should we expect to capitalize interest to trend over the year?

I believe it will be in similar level to what we had in 2010.

And then finally, can you just give us a sense of some of the benchmark for the potential impairment of North Brawley in terms of timing? Is this something that's going to be evaluated on a quarterly basis? Have you set deadlines for yourselves, so on and so forth?

Yes, the evaluation is going to be done on a quarterly basis based on the progress, but we don't have a deadline when we need to reach the 50 megawatt. As long as the -- but we will evaluate it on a quarterly basis.

Your next question comes from Dan Mannes of Avondale.

A couple of questions and I apologize in advance, I missed a lilt bit on the early part of the call. As it relates to North Brawley, you had historically said you would hope to get to EPS or earnings breakeven by the middle of '11, given the new timeframe on the injection. What would be -- how should we think about the potential ramp there? I mean, can we get to breakeven EPS or even breakeven EBITDA under the current scenario?

We think that it may happen in the fourth quarter. We're really at an interesting phase because production is going to ramp up to the next phase very shortly, and typically this is the stage where no information comes up, the new bottlenecks are identified. So we may have better news or slightly worse news. And we'll know much better in the next few months, but we think that -- and the fourth quarter is realistic, given everything that we know today.

But based on, I think, the chart you had, you were showing that at 50 megawatts, given the current cost structure but on a full 50, it was about $0.107 per kilowatt hour. Is that sort of the break even EPS number in your heads or do you need to get costs below even that?

I'm sorry, we didn't spend enough explaining the chart. The chart is not the expected cost at 50 megawatt, it was just taking the cost that we actually had in the second half of 2010. That we're still high in some areas or very high in some areas and just reconstructing it to, let's say, what are the items that are kept in the same proportion like brine processing which at this point, think that we got very close to where want to be and is now completely in there with the amount of brine versus depreciation or manpower that are pretty much a fixed cost that is either distributed on a 25 megawatt facility like in the second half of the year or in a 50 megawatt facility. I don't know if you can see the slide but the gray area, the gray block, the biggest one which is the well field, is the one that was very high in the second half, and had we operated all the wells or enough wells, it would have remained high even at the 50 megawatt level. And this is really our main focus for improvement and cost reduction. We’re working through the issues and we're confident that we'll see improvement partially due to the reservoir and partially due to the pump improvement that we're doing. And so this will not -- in our understanding of what the project will look like when it's operating at 50 megawatt or 45 megawatt, whatever the number is, this block is not expected to be as expensive as it is now. And we also had costs that were identified as other costs that again are shakedown costs that are associated with increasing the capacity over time with the impact of sand that we are now working on removing at the production wellhead rather than at the injection wellhead. And all these things are expected to go away. So the plant is 50 megawatt or even at 45 megawatt, should have substantially different cost structure. It's the things that we've learned in 2010.

Real briefly and just one quick follow-up on North Brawley, and I apologize if I missed this, did you mention how much of a drag it was in the fourth quarter?

How much, I'm sorry?

How much of an earnings drag it was?

Oh, what was the impact on earnings?

Yes.

We did not specifically mention that, did we?

We did. Marybeth?

In the fourth quarter, it was a loss of $4.5 million.

And that's a fully loaded including G&A?

Including G&A, correct.

Real quick, just on your guidance. For the Power segment broadly, I guess we had assume a bigger step up year-over-year, certainly some of the reduction is North Brawley, but can you talk about sort of your what's in your guidance year-over-year ? I mean are you assuming any increase in North Brawley or is it mostly just better pricing at Puna, the impact of the Puna expansion, full year of Mammoth? I guess I'm just trying to figure out the year-over-year, because it was a little lighter than I would have thought.

It is maybe conservative, but we have been conservative and maybe we will be able to narrow the range or maybe even increase it as we continue through the year. But we have assumed a modest increase in Brawley. And Jersey Valley formed the second half of the year.

Your next question comes from Dilip Warrier of Stifel, Nicolaus. Dilip Warrier - Stifel, Nicolaus & Co., Inc.: I just wanted to confirm, A, if the $15 million LNG project is included in the product revenue guidance for this year of $75 million to $85 million. And then second part of the question was backlog. I think you mentioned about $13 million was subject to LCs. And I was wondering if in the past, on a quarterly basis, the backlog numbers you provided included or excluded any business subject to LCs?

The first question -- the answer to the first question is yes, our guidance includes the $15 million of the LNG plant. I'm not sure that we have transitioned like today, in the past where the order was received and the LC wasn't received yet. But it is quite typical if you receive an order and the LC is coming later. Dilip Warrier - Stifel, Nicolaus & Co., Inc.: One more question then. Operating expenses in 2010 swung pretty widely on a quarter-to-quarter basis. I was wondering if you could just provide us a sense of what we could expect in 2011 at least directionally?

On operating expenses, you mean G&A and net sale and marketing? Dilip Warrier - Stifel, Nicolaus & Co., Inc.: Yes.

We don't expect an increase in G&A. Sales and marketing is a function of the specific orders without being executed. Some have higher sales and marketing costs and some have lower, and it's not a function of volume.

Your next question comes from Matt Ravel [ph] of Imperial Capital.

With net leverage, I calculate net debt divided by LTM EBITDA of around 4.3x and you mentioned that you have not fully utilized the borrowing capacity of the company and slow on substantial CapEx needs going forward. Is there a target leverage multiple or another type of number that you used that you had not wished to exceed?

Yes, I think that we are definitely comps for computation with 6x EBITDA. We have the right to go under because of [ph] our various financing to go up to 7x EBITDA.

And then another question on North Brawley. Is there any risk of a treasury grant recapture? And what steps might you be doing to mitigate that sort of event?

There is no risk for recapture as long as you operate the plant and we are operating the plant. The treasury grant does not tax us for full power or partial power, only operations.

So in any case, you plan to operate the plant. At this point, is there any risk that the plant will ever be shut down?

No, I don't think so.

Your next question comes from JinMing Liu of Ardour Capital.

First is about your guidance regarding the Increment segment. Can you provide with us please, what percentage of your guidance is for inter-segment sales?

None. The inter-segment sales is not included in our guidance because this is not recorded as revenue. It's recorded as property plant and equipment.

Regarding the Spain REG project, that $50 million revenue. Have you recognized cost in R&D over the past few periods for that specific project?

Yes, we included all the cost of these projects in R&D. And those costs are even higher than the revenues that we're going to recognize.

Basically if, say, your recurrent revenue in your first quarter for this $50 million, we won't see a big bump to our EPS because of the costs.

Yes, it will be revenue, it's now -- cost of revenue say for additional cost that we will incur during 2011 which are not substantial. Most of the costs have been incurred in 2009, 2010 as R&D expenses.

And lastly, recently, the House of Representatives introduced the bill that, well, basically proposed to cut away DOE loan guarantee program. If that happens, I mean there is the chance -- what are you going to do to get your financing in place for your development?

We are planning only on one DOE guaranteed loan program and this is the -- for project Jersey Valley, McGinness and Tuscarora. I believe that they are advanced enough that the cut will not infect them. Yes it will. Looking at the work place, I don't think will happen. We will have to go to the capital now. And Brawley, a little higher rate than the DOE loan guarantee expected rate.

And ladies and gentlemen, we've reached our allotted time for Q&A for today's conference. I'll turn the conference back to management for any closing remarks.

Not really closing remarks, but just thank you for your attention and for your interest and we hope to deliver on what we said and maybe even better than that. Thank you.

And ladies and gentlemen, that concludes the Ormat Technologies Fourth Quarter and Year-End Earnings Conference Call. We appreciate your time. You may now disconnect.