Ladies and gentlemen, thank you for standing by, and welcome to the Ormat Technologies Fourth Quarter and Year End 2011 Earnings Call. [Operator Instructions] Thank you. I would now like to turn the conference over to Mr. Rob Fink of KCSA Investor Relations. Sir, you may begin your conference.

Thank you, and thank you everybody for joining us today. Hosting the call today are Dita Bronicki, Chief Executive Officer; Yoram Bronicki, President, Chief Operating Officer; Joseph Tenne, Chief Financial Officer; and Smadar Lavi, VP 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 related to current expectations, estimates, forecasts and projections about future events that are forward-looking as defined in the Private Securities Litigation Reform Act of 1995. These forward-looking statements generally relate to the company's plans, objectives and expectations for future operations, and are based on management's current estimates and projection 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 Securities and Exchange Commission 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 Technology believes that adjusted EBITDA may provide meaningful supplemental information regarding liquidity measurements for both management and investors' benefit from referring to these non-GAAP financial measures 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's found in the Investor Relations tab. With that said, I would now like to turn the call over to Dita. Dita, the call is yours.

Thank you, Rob, and good morning to everyone. Thank you for joining us today for the presentation of our fourth quarter and full year 2011 results and outlook for the near future. 2011 was highlighted by increased revenue and increase in operating cash flow, steady growth in total generation and an exceptionally strong performance in the product segment. Our 2011 net income was negatively impacted by a noncash, tax-related valuation allowance of $61.5 million, which were recorded against the company's U.S. deferred tax assets. Realization of these deferred tax assets is dependent on generating sufficient taxable income in the U.S. prior to the expiration of the tax losses and credit. Although valuation allowances recorded against these deferred tax assets, no economic losses appeared in the underlying net operating loss carryforwards and other tax credits remain available to reduce future U.S. taxes to the extent income is generated. We made operational improvements and enhancements in several plans, and we are continuing to move forward with our activities related to our organic growth. Let me turn the call over to Joseph for a review of the financial. Yoram will review our operations and following my remarks, we will open the call up for Q&A. Joseph, please.

Thank you, Dita and good morning, everyone. Beginning in Slide 5, total revenues for the full year 2011 were $437 million, a 17.1% increase over revenues of $373.2 million in 2010. Total cost of revenue increased by 8.3% compared to last year. In our electricity segment on Slide 6, revenues for the full year were $323.8 million, an 11% increase over revenues of $291.8 million in 2010. The increase in electricity revenue is due to higher variable energy rate of our Amatitlan and Puna PPA, and increased in electricity generation of some of our parks. In the product segment on the next slide, revenues for the full year were $113.2 million, an increase of 39% over revenues of $81.4 million in 2010. The increase in product revenues reflects the new customer orders that were secured in the first half of 2011. Moving to Slide 8. The company's combined gross margins for the full year was 26.8% versus 20.8% in 2010. The electricity segment gross margin was 24.6% for the full year versus just 17% in 2010. Excluding North Brawley, the electricity gross margin would have been 34.4% compared to 26.8% in 2010. In the product segment, gross margin for the full year was 32.8% versus 34.6% last year. The decrease is due to the mix of products sold and margins associated with our customer orders. Operating income for the full year 2011 increased 172% from $23.6 million in 2010 to $64 million this year. Moving to Slide 9, interest expense full year was $69.5 million compared to $40.5 million in 2010. The increase was principally due to $16.4 million loss from an interest rate lock transaction related to our DOE loan guarantee that were consummated in September of 2011, and the issuance of senior unsecured loans in August 2010 and…

Thank you, Joseph, and good morning, everyone. Starting with Slide 18. The total generation for 2011 was 3.9 million megawatt hour. This represents an increase of 4.1% from 2010, an approximately 57% increase in total generation over the past 5 years. Steady growth in total generation and the decrease in the O&M expenses, excluding depreciation, are a result of improved operational performance, enhancement of existing plants and completion of new projects. Moving to Slide 20. During the quarter, we have made improvement to the injection capacity of the Jersey Valley plant and it is currently operating at about 9 megawatts. We plan to continue work on the injection and hope to increase generation further during this year. In North Brawley, we continue to work on the geological interpretation of this field and on improvement to the production pump assembly. Based on the geological interpretation, we successfully completed one production well in the fourth quarter and successfully tested a second production well, which was completed early this year. We believe that once connected to the plant, the second well will allow the plant to become EBITDA positive on an annual basis. And based on how successful it will be, we will use our new tools to target the third well. As for the production pumps, we have made substantial progress in the second half of the year and increased the average pump life at least 90%. This, together with successful solid control measures, will allow the -- will provide substantial reduction in the operating expenses in the future. The 10-K that will be filed next week will have updates of the total generated capacity figures, as you can see on Slide 20. The main changes are the new Tuscarora power plant and the adjustments of the North Brawly and Jersey Valley…

Thank you, Yoram. In my remarks, I would like to review regulation and financing activity of 2011, comment on our capital provision and then conclude with revenue guidance for 2012 before opening the call for questions. Starting on Slide 29, federal legislation and government-sponsored programs that were available for renewable energy developers positively impacted our business and the terms under which we were able to obtain financing. While it is unclear if the renewable energy industry's effort to extend the ITC or the PPC will succeed, the regulation at the state level, in particular the RPS target, will continue to create a demand for renewable energy. In California, Senate Bill 2X, SB 2X, to increase California's RPS to 33% by 2020 was signed in 2011, and it represents one of the most aggressive renewable energy growth in the United States. The IOUs have been doing targets each year with a requirement of 25% by 2016. Due to the new 33% target, publicly-owned utilities in California must also procure 33% of retail electricity sale from eligible renewable energy resources by 2020, opening up a significant new market of potential offtakers in years ahead. New facilities do not have interim target, we therefore expect the current pressure on PPA prices and availability to be temporary. Separately, California's greenhouse gas cap-and-trade, GHG program, which was scheduled to become effective on January 1 of this year, has been delayed. It is now anticipated that this program will commence in 2013. And while disappointed in the delay, we believe it represents the nation's most comprehensive GHG program and could sell as a strong example of others to follow. Turning to Slide 30. In 2011, we will exit on several reforms to obtain the necessary financing to secure our goal. In September, we finalized the loan…

[Operator Instructions] Your first question comes from the line of Steve Milunovich of Bank of America-Merrill Lynch.

Do you have of a thought on what your product margin is likely to be next year? I think previously, you've indicated that it's likely to be down from this year but any specific thoughts there?

Yes, this field, the margin moves slightly higher, mainly because of the income recognition from the LNG projects, or what we call the north projects and the expectation for next year is to go back to our normal margin which is between 20% and 25%.

20% and 25% next year -- or this year. And where are you seeing...

It's not a guidance for the year, it's our normal for this margin.

And where are you seeing demand coming from? For products outside kind of New Zealand and looking at other companies' geothermal projects, what sort of ramp do you see over the next few years?

Unfortunately, it is very difficult to predict and we have -- we are continuously struggling with an ability to predict new projects in the product segment. It's a come-and-go. It is the life of a project which is, finally saying yes or no. Nevertheless, definitely New Zealand, we expect to continue to be a market. Chelsea is a market. Indonesia may open up. Didn't open up yet, but may open up. Central and South America is a market. And to a certain extent, maybe also the United States.

And then finally, any guidance in terms of what North Brawley revenue and gross margin might trend toward this year?

We made a promise to ourselves not to give guidance on Brawley. Yoram just mentioned that we think we are currently EBITDA positive. Currently, meaning from now on we could firm up with guidance on Brawley.

Your next question comes from the line of Dan Mannes of Avondale.

A couple of file questions, first of North Brawley, rather than giving us guidance, can you tell us maybe what the EBITDA contribution was in the fourth quarter, so at least we understand how it's trending?

Let's just look for the numbers, if you have additional questions we'll give you the right number.

Absolutely. I certainly have a few more. Real quick on the California, on the SRAC contracts, I appreciate the slide, but maybe if you could go into a little bit more detail here and maybe try to help us sketch out the price volume metrics, i.e., could you sort of walk us through how much you see at risk on a megawatt-hour basis and what the sensitivity is to changes in gas prices? Just so we understand that as gas prices move to kind of leverage in your model.

So what is the sensitivity to gas prices? I think on a very rough order of magnitude, every dollar and million BTU is about $0.01 a 1 kW hour, and we have about -- currently, about 140 megawatts that are affected by that.

Okay.

Go ahead.

No -- and then can you walk us through the greenhouse gas piece, because I know you've excluded that from '12 and I believe, from '13. Can you walk us through how that bakes into the number? You give us some $25 million, but it would really help us to get a little bit more granular in terms of this. It's such a big sensitivity to your earnings power.

So very rough response to this is that the greenhouse component, I think, is an estimate at that point. And so our current estimate is that in 2013, it could add under some formulations it could add another, about $0.007 per kW hour, unless there are additional details -- I'm sorry, additional delays in putting this in place. But these are really -- for us, these are really estimates, and we really don't know at this time. Our preferred course of action is really to move away from these contracts, recontract them in -- under the current terms, which move into energy-only calculations, move away from the legacy structure. And basically, use what California PUC views as a long-term fare or reasonable long-term prices as a guideline for our recontracting negotiation. So how much of this can be accomplished, still in 2012, is hard to say. These are typically long processes. But we would like to move away from this position and have modern contracts at reasonable and certainly, fixed energy rates.

Absolutely understood.

To answer your question, the impact of Brawley in the fourth quarter was a negative EBITDA of about $4 million.

For the year or for the fourth quarter?

For the fourth quarter.

Wait $4 million in EBITDA?

Negative $4 million.

Okay, we may have to double-check that offline because that sounds like it got substantially worse, because I thought it was only about $1 million EBITDA loss from the third quarter.

The difference is that -- the biggest difference is really that the rates for the fourth quarter -- fourth and first quarter are substantially lower than the rates in the third quarter, so there is -- everything else being equal, there is a difference between the 2, but beyond that we have done some work on our wealth that which reduced -- generation increased some of the cost during the fourth quarter, so somewhat different. But as we said, we are now -- we have completed that work. We've completed some of the upgrades to the pump and we're now at the higher-generation level and at the lower cost, so we expect that forward to be better.

And what generation level is that?

We're currently generating about 25 megawatts, and this is -- sorry, because I mentioned before...

2-5?

25, yes. And as I mentioned this is before connecting the well that was -- we believe was very successful that we expect to connect shortly. So we think that we are at the -- we'll move to a next level in terms of sustainable generation at Brawley.

Okay. And then 2 real quick ones, first, you mentioned the drilling at Wild Rose, any indication on the results from the drilling of the wells?

Yes, I mean, there is certainly a well field there, and this is why we keep the project as a project-under-construction. We are planning long-term tests to quantify the size of the reservoir and move to the next stages of field development and ultimately, power plant development.

And your pump -- sorry, you go.

No.

And the $192 million of construction new projects include some amount for both Wild Rose and for the Mammoth expansion or no?

Mammoth is certainly included. A portion of the well field work in Wild Rose is certainly included as well. So the next steps that we contemplate in quantifying the size of the field is certainly included, yes.

Okay. But one last one, and thanks for giving me all this time, Sarulla, this is the first time we've seen you guys put a date on paper as to when you expect that execution. Can you walk us through the process of what's changed there? And then, can you remind us again what the potential revenue impact is on the product side, should that move forward?

Dan, Sarulla, is mine all to answer. We are definitely today, more optimistic about Sarulla, then we were in our last call in November. On the last call in November, if you recall, I was really iffy about the chances of this project to move forward. We are way more optimistic today because we have been able to solve one of the stumbling blocks that was related to one of the bankability issue. From this supposed date, it is still very difficult. We cannot put a date, even though our expectation is that it will happen this year. "Will happen" means -- what I mean by "will happen" is not closing the financings, this will probably be next year, but what we think will happen this year is finalized the contract. Again, with all the caution that we have to have so and so in Sarulla, the products segment revenue for Sarulla are in the order of $250 million and $300 million.

And obviously none of that's in the backlog that you guys disclosed.

Of course.

Your next question comes from the line of Carter Driscoll of Capstone Investments.

First question is you had mentioned, I think in the last call, about the opportunity to potentially co-locate some small resource facilities to realize that the opportunities in this field -- the opportunity to be progressing at the rate you had previously forecasted. Could you maybe address magnitude and potential scale of doing so and what potential ROIs you might receive from those? Or maybe help us see what the incremental of contribution and help us try to plan how it might impact your results going forward.

The easy answer to your question is, at this point, our first step was the 10-megawatt photovoltaic plant, which is really in the area or in the geothermal area of the Heber project. And if you'd like, there is certainly the possibility, both in terms of room and other supporting infrastructure, there is a possibility of doing the same in our other geothermal power plants in the Imperial Valley. So certainly in the Brawley area and potentially in the -- or mixed area though it's a little more difficult. And the plants could be at that size, so 10 to 20 megawatts is certainly a reasonable size for such a photovoltaic plant. However, it does require the PPA markets to be open for such additional power. And return on investment is really, in that sense, it has -- we have some advantage in some areas over a greenfield solar facility, but it is generally in line with what you can expect from a solar facility. And really like, I think, most of the other developers, we start with our threshold for return from the projects with our estimates on cost and market the power at a rate that would support that or be a little better. Because the solar projects are relatively low risk, the pricing can be somewhat more aggressive. You don't have the exploration risk and other long-term unknown that you have in geothermal, so the pricing can be more aggressive.

Helpful. Of the forecast CapEx requirements, can you kind of breakdown, maybe this year or next year, about what you have to pull through, not necessarily construction, development and exploration, but kind of bracket; what you expect to do in the next 12 versus 24 months?

I'm not sure that I'm following the question, could you...

You forecast your CapEx requirements at $367 million going forward, could you kind of break it between 2012 and 2013?

$367 million is 2012, it does not include 2013 CapEx...

All 2012, okay. I just wanted to clarify. And then my last question is the -- if you could just clarify with the SRAC issue, the projects that are currently in place versus what you expect to bring online in 2013, all the projects that are coming online will be subject to the same type of changes to the PPAs whether existing versus new, that's correct?

No. The rate of the SRAC impact is only on legacy PPAs. PPAs that were signed, I think that the last of them was or -- they're all PPAs from either the mid-80s or very, very early in the 90's. So these are all PPAs that we inherited, that were developed under an old regulatory framework. So nothing of the new capacity is really affected by SRAC other than just a little bit of modifications that we have been contemplating. So a few megawatts, 3 megawatts in Mammoth and -- which I think is really the only ones that were on the list and are affected by that, the rest is not affected.

Okay. And just -- the last question is Jersey Valley, I know you don't really want to still break out project by project, but Jersey Valley, at current run rate, is that positive contribution EBITDA currently?

Yes, it is.

Okay.

And it has been throughout the year, actually.

Your next person comes from the line of JinMing Liu of Ardour Capital.

Most of my questions have been answered, just one left in there. It looks like -- a little bit early, but it just looks like you need to refinance, actually, about $440 million of -- from your line of credit will come to you in 2013, are you -- I mean, what's your plan there?

The way the table is presented is that if you have a revolving line of credit, which is a limited time and those are typically for 2 years, when the 2 years is expected to arrive, we show it to the repayment. But our working assumption and our past experience has been that those are renewals, and they will just be rolled over for another 2-year period. So don't take the 2 years of 2013, 2014, too seriously with respect with revolving lines of credit.

You're next question comes from the line of Mark Barnett at Morningstar.

Just a couple of shorter questions. I know you've already talked a little bit about the SRAC pricing, I know that you're trying to move away from those contracts, where -- can you talk maybe some of the obstacles in addition to when existing contracts roll off, what might some of the obstacles be to realizing higher price contracts?

I think that the biggest obstacle is the fact that the California PUC allows the 3 large investor-owned utilities to stop part of their contracting or buy very little in the current and in the next compliance period. And therefore -- and clearly, when you compare it -- when you combine this with the fact that there is an economic downturn, so there is a reduction in load or in consumption of power in most of the Western United States markets, and the fact that natural gas is very low, this puts, I guess, a denting effect on recontracting new power when the current contracts allow them to buy the power under a very short term or very favorable cost. So I think that, in many ways, for the near term, the IOUs are not the best customer. And we need to either find ways that allow both parties to enjoy from the longer-term prospects of the power, because the power is not only available for the duration of the old contracts. The power will be available for another 20 years and more than that. So either we can find a way for both the utility and Ormat can enjoy the fact that the power is stable and competitive on a long-term basis or find customers that are not in the same position as our existing customers and do need the power at the moment. So that's really the balancing act that we need to go through. Everybody recognizes that our power is very valuable, but just like we would like to see higher revenues at the moment, some of our customers would like to see lower cost at the moment, and we need to find a comfortable common ground.

Great. It's not a huge item relative to the total, but for 2012 CapEx, there is about $36 million or so in enhancements. And I know you had mentioned Heber, but I'm wondering if there is any other work included in this line that's going to be meaningful or how should we think about that?

I think that the biggest part is Puna where we expect to increase capacity, both at some standby capacity beyond what we currently have in the well field, and also increase the ability to generate power. But it's really outside of Puna, it's really made out of a few little things in each of the plant.

Okay. And just one last quick question. I was wondering, on Tikitere, I know it's not -- it's only been about 6 months, but I was wondering what the -- kind of timeline to a regulatory progress in New Zealand on that project might be?

Like every regulatory timeline, it is hard to predict, but we think that before the end of the year, we'll start exploration at Tikitere

Next question comes from the line of Peter Christiansen of Bank of America-Merrill Lynch.

Joseph, I was wondering, can you provide us any visibility on what book taxes could be this year and how that would compare to cash taxes?

What the meaning in book taxes? Usually, it's difficult to say because it's coming from different jurisdictions. For example, on the product segment which is going to be very good in 2012, most of it is 15% in Israel. In the U.S., it's as you know, around 38%. So it's difficult, but on the other hand, any profitability will enable us to reduce the valuation level. So it's a very difficult to do so, we'll need to do an analysis each quarter to see where we are with the valuation allowances because it's really an ongoing process once you did it. So it's very difficult to predict. But probably and I must be very careful about it -- in the U.S. probably we'll be at the 0% tax. The rest of the world, Guatemala is 0%, Israel is 15%, Kenya is about 7%, and Nicaragua is 25%, so you can imagine that we will be as relatively low tax rate from book perspective. But I can't give you the numbers because...

Okay. Fair enough. And then selling expenses increased in the quarter, should we think of that as increasing with product revenues, is that we're the primary source of that growth is?

There are 2 common incidents, if the product segment is better, it goes up, but in the last quarter and the last year, we had, if you recall, $1.7 million that we paid in the NV Energy for the Carson Lake termination of the PPA. That amount is also included there. So if you eliminate that, you can get better picture of going forward as selling and marketing expenses.

Your next question comes from the line of Dan Mannes of Avondale.

Sorry, one follow-up question, again, going back to the SRAC, when I look at the range of revenue guidance for the power segment for 2012, can you sort of walk us through of maybe what you're baking in, in terms of either the SRAC or the gas prices that's implied by that range?

We -- basically, this tracks what we have provided in our disclosure, 3 or 4 weeks ago. So I believe that, not to be precise, but this assumes a $24 million reduction in revenue compared -- from those projects compared to 2011. So basically, we -- as of gas prices 3 weeks ago, we have taken the whole impact of that. GAAP had continued to move but it is moving all the time so we did not recalculate this. But we haven't assumed an upside on that portion. So we just used that -- for those projects we have used just that as a fixed point in time. And then the balance is really other operational issues or potential improvements that could make the picture better.

And then, so real quick, just 2 verification there. So number one, so that does assume that for, I guess, it's the 7 or 8 months starting after May, you're going to have sort of a sub-$3 gas curves embedded in that $24 million. And number two, so the balance of the movement from top to bottom is going to also include things like the timeframe under which the Puna expansion and Tuscarora come up and McGinness startup late in the year, et cetera?

Yes. I think, I mean, it does include where we believe we are in Tuscarora and on Puna, and it does include an assumption on when we McGinness starts up, yes.

But I mean, Tuscarora and Puna have already started, so I mean, assuming a full year or...

Assuming it’s full year in operation, in terms of, as we mentioned earlier, this -- first, power is sold under pre-commercial rates, so there is -- we have an estimate of what would be the date for moving from pre-commercial to commercial power in each of the projects.

At this time, there are no further questions. Thank you for your participation in today's call. You may now disconnect.