Brad Nelson Yehudit Bronicki - Chief Executive Officer, Director, Chairman of Compensation Committee, Chief Executive Officer of Ormat Industries, President of Ormat Systems, General Manager of Ormat Industries and Director of Ormat Industries Yoram Bronicki - President, Chief Operating Officer, Director and Director of Ormat Industries Joseph Tenne - Chief Financial Officer, Principal Accounting Officer and Chief Financial Officer of Ormat Industries Ltd Smadar Lavi

Michael Klein - Sidoti & Company, LLC Daniel J. Mannes - Avondale Partners, LLC, Research Division Scott Reynolds - Jefferies & Company, Inc., Research Division JinMing Liu - Ardour Capital Investments, LLC, Research Division Mark Barnett - Morningstar Inc., Research Division Carter W.

Driscoll - Ascendiant Capital Markets LLC, Research Division

Thank you. 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 the information provided during this call may contain forward-looking statements relating to current expectations, estimates, forecasts and projections about future events that are forward-looking as defined in the Private Securities Litigation Reform Act of 1995. These forward-looking statements generally relate to the company's plans, objectives and expectations for future operation and are based on management's current estimate and projection of future needs -- 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 Ormat Technologies, Inc.

annual report on Form 10-K filed with the Securities and Exchange Commission on February 29, 2012. And quarterly report on Form 10-Q filed with the Securities and Exchange Commission on November 8, 2012.

In addition, during this call, statements may include financial measures as defined as non-GAAP financial measures by the SEC, such as 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 the 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 comparison 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 & Presentation link that's found in the Investor Relations tab. With all that said, I would now like to turn the call over to Dita.

Dita, the call is yours.

Thank you, Brad, and good morning everyone. Thank you for joining us today for the presentation of our fourth quarter and full year 2012 results and outlook for the near future.

2012 was highlighted by increased revenue, consistent growth in the total generation and exceptionally strong performance in the product segment. Starting with Slide 4.

In 2012, we made significant operational improvements to our existing power plants, while also bringing new capacity online. The performance of the new power plants, together with the cost reduction in our operating portfolio, specifically North Brawley, enabled us to maintain margin in our electricity segment, despite the impact of the low natural gas prices.

We continue to move forward with our activities to drive organic growth. In parallel, the demand for new geothermal power plants and other power generating units continue to drive significant growth in our product segment.

2012 was a great year for the product segment, and we expect the sales order in 2013 to remain strong. While net income was substantially impacted by the noncash impairment charges of $236.4 million related to the North Brawley and OREG 4 power plants, adjusted EBITDA increased 11.5% to $185.8 million, and we generated operating cash flow of $93.2 million.

As we discussed on our special conference call a month ago, the impairment is noncash and will not impact our operations or put us in violation of any financial covenant with banks or other lenders. Our business and balance sheet remains sound and our growth prospects strong.

I will now turn the call to Yoram to review our operations and to Joseph to review the financials. And following my remarks, we will open the call for question and answer.

Yoram?

Thank you, Dita, and good morning, everyone. Starting with Slide 6.

The total generation for 2012 was approximately 4.1 million megawatt hours, which is an increase of 7.3% from 2011. The growth in generation this year is mainly to the successful completion of the Tuscarora power plant at the beginning of 2012 and the McGinness Hills power plant that has been in commercial operation since July.

We had notable reduction in cash O&M per megawatt hour, mainly due to the improvements in North Brawley, but also as a result of continued operational improvements implemented throughout our fleet. Operating costs in 2012 were similar to 2011, however, considering reduction in revenues that resulted from the SRAC pricing and the added expense of bringing new plants online, the impact of the improved efficiency on margin going forward is significant.

In Slide 7, you can see we have made substantial progress in reducing operating cost at North Brawley. And as we reached breakeven EBITDA in the fourth quarter, we expect this trend to continue.

Moving to the next slide. As we previously disclosed, the switch to SRAC on our Standard Offer #4 contracts caused a substantial reduction in our 2012 revenues.

However, we expect that once the PPAs are replaced or expired, we will be able to secure higher rates that reflect long-term pricing, as we are doing in the case of Mammoth. We believe that our exposure to SRAC pricing will reduce overtime in April.

Subject to the approval of SCE, we expect to start selling electricity from our Mammoth G3 power plant under a new PPA with long-term pricing. As for Mammoth G1, we expect to start selling electricity under the new PPA toward the end of 2013.

In both PPAs, the pricing is higher by more than 50% of the current pricing. As part of the early termination of G1 and G3's SO4 contracts, we expect to make a termination payment to the current off taker of approximately $10 million that will be expensed in the first quarter of 2013.

For an update on our current generating capacity, please turn to Slide 9. We made a few changes, as you can see in the table.

North Brawley has been updated to reflect our decision to operate at 27 megawatt. The generated capacity of Brady and Steamboat complexes have been reduced to reflect the changes in the resource condition.

The performance of McGinness Hills has been very strong, and we updated its capacity to 33 megawatt to reflect that. For an update on our project pipeline, please turn to Slide 10.

We're in varying stages of construction or enhancement. Some of the projects are fully released for construction.

While Carson Lake and CD4, where we have started construction in the past, remain on hold this year. The Olkaria III Plant 2 construction is progressing.

Field development and plant construction remain on schedule, and we expect to have the project online by mid-2013. The 16 megawatt Olkaria Plant 3 is in an early stage of field development and is expected to come online in 2014.

For both plants, the PPA is in place and the financing was secured through the OPIC loan. We completed the field development for Wild Rose and manufacturing of the power plant equipment is at an advanced stage.

In Mammoth, we have shut down the G1 plant and are performing a total modernization of the equipment in preparation for a new PPA. At Heber Solar, we have all permits in place to continue with construction.

In both Heber Solar and Wild Rose, we expect to complete construction toward the end of 2013. Successful completion of these 4 projects will bring our total generating capacity by the end of 2013 to 637 megawatt, with an additional 16 megawatts in 2014.

On Slide 11, you can see a list of projects under various stages of development. The combined generating capacity of these projects is approximately 117 megawatt.

However, each of the project's readiness for continued construction and expected economics will determine its actual release date and therefore, we are not planning to invest in all of them this year. While we have been active in the international markets since the mid-90s, the U.S.

market is where we have invested most of our efforts in the recent years. Going forward, we have decided to dedicate equal business development efforts to the international and the U.S.

markets, taking advantage of the increased interest in renewables in general and geothermal in particular in markets like New Zealand, Southeast Asia and East Africa. In November, we announced the acquisition of a late-stage development geothermal project in Honduras.

The Platanares project comprises of the right to a field where exploration work has been conducted in the past and a power purchase agreement for up to 35 megawatt that is already in place. Upon fulfillment of certain conditions and the closing of the transaction, we will become the owner of the project's asset.

Once the well field is fully appraised and the power plant is constructed, we will hold the assets under a BOT structure for approximately 15 years. In Sarulla, substantial progress has been made, even though we have not reached our goal of full signature of the energy sales contract and the joint operating contract.

The current status is the energy sales contract has been initialed, which is great progress, but full signature still requires full resolution of tax exposure associated with the transfer of the assets. In addition, as you can see in Slide 12, we now have 41 prospects in early exploration where activity has yet to begin.

Slide 13 provides for an update on the product segment. As of February 15, 2013, our product backlog is approximately $262 million.

Let me turn the call now to Joseph.

Thank you, Yoram, and good morning, everyone. Before I go through the results, I have to emphasize that although we have completed substantially all of our work on the tax provision, certain review procedures are still to be completed prior to the filing for our annual report on Form 10-K.

As a result, while we believe the results are materially correct, certain amounts could be revised when we will file our annual report on Form 10-K. Beginning on Slide 15, with the results of the year ended December 31, 2012.

Total revenues for 2012 were $514.4 million, a 17.7% increase over revenues of $437 million in 2011. In our electricity segment, as you can see on Slide 16, revenues increased 1.1% from $323.8 million in 2011 to $327.5 million in 2012.

This increase was primarily due to $23.5 million in revenues from our Tuscarora and McGinness Hills power plants, which began commercial operations in January and July 2012, combined with the $3.2 million net increase in revenues from other power plants. In addition, we also booked a net gain of $2.2 million on derivative contracts on oil and natural gas prices.

This increase was offset by a $25.2 million decrease, resulting from the impact of low natural gas prices on energy rates in our Standard Offer #4 PPAs in California, which in the beginning of May 2012 changed from fixed rate to a variable rate that is subject to the impact of fluctuations in natural gas prices. In the product segment, on Slide 17, revenues for 2012 increased 64 -- 65.1% from $113.2 million in 2011 to $186.9 million in 2012.

The increase in our product segment revenues reflects the increase in new customer orders that we secured in 2011 and 2012, largely attributable to the $130 million order we received from Mighty River Power Limited for the Ngatamariki geothermal field in New Zealand, which is expected to be completed in 2013. Moving to Slide 18.

The company's combined gross margin for the full year was 26.1%, compared to 26.8% in 2011. The electricity segment gross margin was 25.3% for the full year, compared to 24.6% in 2011.

In the product segment, gross margin for the full year was 27.6%, compared to 32.8% in 2011. The decrease in the product segment -- in the product gross margin is mainly attributable to the exclusion of revenues in the amount of $12.1 million in 2011, compared to only $3 million in 2012, relating to an experimental REG plant and LNG regasification terminals in Spain, with virtually no associated cost of revenues, since the related cost were included in research and development cost in previous years.

A different -- also, a different product mix and different margins in the various sales contracts. Excluding the impact of the revenues relating to the LNG project, the product segment gross margin would have been 26.4% in 2012, compared to 24.7% in 2011.

Moving to Slide 19, operating loss for the full year was $155.1 million, compared to operating income of $64 million in 2011. The operating loss was primarily impacted by the impairment charges taken at the North Brawley and OREG 4 power plants.

Moving to Slide 20. Interest expense net of capitalized interest for the full year was $64.1 million, compared to $69.5 million in 2011.

The decrease was primarily due to $16.4 million loss in 2011 on interest lock transactions relating to the OFC 2 senior secured notes, the increase was partially offset by additional interest expense, mainly as a result of the full year impact of the OFC 2 senior secured notes and senior unsecured bonds and $1.8 million of cost associated with the early repayment of part of the DEG loan in November 2012. As you can see in the next slide, in 2012, the adjusted interest expense, excluding the loss on the interest rate lock transaction in 2011 increased.

This increase reflects the shifting in our debt structure from a revolving corporate debt structure to long term project finance debt, with virtually no increase in the debt level. Moving to Slide 22.

Net loss for the full year was $206.7 million or $4.56 per share, compared to $42.7 million or $0.95 per share for 2011. Now I would like to go over a few quarterly financial highlights, beginning with Slide 23.

For the fourth quarter of 2012, total revenues were $116.1 million, compared to $123.7 million in the fourth quarter of 2011. Revenues in the electricity segment increased 1.6% to $78.8 million, up from $77.6 million in the fourth quarter of 2011.

Revenues in the product segment were $37.3 million, a decrease of 19.3%, compared to $46.2 million in the fourth quarter of 2011. Now on Slide 24.

Operating loss for the fourth quarter of 2012 was $221 million, compared to operating income of $17.3 million in the fourth quarter last year. Net loss for the fourth quarter was $222.9 million or $4.91 per share, compared to $43 million or $0.95 per share in the fourth quarter of 2011.

As shown in the following slide, Slide 25, adjusted EBITDA for the full year 2012 was $185.8 million, compared to $166.7 million in 2011. Adjusted EBITDA for the electricity segment was $153.7 million, and for the product segment, $32.1 million.

Adjusted EBITDA for the fourth quarter of 2012 was $35.3 million, compared to $45.1 million in the same quarter of 2011. The adjusted EBITDA was impacted by various factors, including timing of recognition of product segment revenues, reduction in electricity revenues associated with the Standard Offer #4 PPAs and mining tax in the amount of $3.3 million in respect of the years 2008, '09 and '10 that we have appealed.

Adjusted EBITDA excludes the impairment charges in respect of the North Brawley and OREG 4 power plants in the full year and the North Brawley power plant in the quarter. Net cash provided by operating activities was $30.8 million, compared to $34.2 million, respectively in the quarter, and $93.2 million in the full year 2011 (sic) [2012], compared to $132.7 million in 2011.

Moving to Slide 26. Cash, cash equivalents, marketable securities and short term bank deposit at December 31, 2012 was $69.6 million, down from $118.4 million as of December 31, 2011.

The accompanying slide breaks down the use of cash during the full year of 2012. Our long-term debt at the end of 2012 and the payment schedules are presented in Slide 27 of the presentation.

In 2012, we distributed interim dividend in aggregate amount of $3.6 million or $0.08 per share. Although we reported a net loss for the year, under the credit agreements, the loan agreements and the trust instruments governing the senior unsecured bonds, we can distribute interim dividends on the basis of our estimates of our net income for the full year.

Since we incurred a loss for the year 2012, an adjustment of $3.6 million will be made in the next fiscal year in which we will distribute the dividend. We do not anticipate that the dividend will be paid in the first half of 2013.

We will evaluate resuming dividend distributions based on our dividend policy in the third quarter of 2012 -- 2013, sorry. That concludes my financial overview.

I would like -- before I transfer the call to Dita, I would like to refer to the accounting of the ORTP transactions that we closed last month. In the statement of operations, we will recognize income from the sale of the tax benefits based on their utilization by our partner.

The amount of $35.7 million will be allocated between noncontrolling interest and long-term liability in the balance sheet. The noncontrolling interest component will present the fair value of the 5% interest of our partner on the fleet date.

We will record an interest expense on the liability that will reflect the partner's yield during the period. We expect that the net amount on the statement of operations will have a positive impact on the bottom line.

And now let me return back the call to Dita. Dita?

Thank you, Joseph. In my remark, I will review the general business and regulatory environment, financing activity in 2012, comment on our capital position and then conclude with revenue guidance for 2013, before opening the call for questions.

Starting on Slide 29. Several event that occurred in 2012 are important for the understanding of the business environment of the clean energy industry, being drivers pushing the world to a cleaner energy system, to mitigate the clear tendency of long term average temperature increase of 3.6 degrees centigrade by 2035.

These drivers include in no special order; the Rio+20 conference covering topics like energy access, energy efficiency and renewable energy. The Doha climate conference, in which countries have adopted amendment to the Kyoto Protocol to establish its second commitment period.

The reelection of President Obama that removes uncertainty over the U.S. commitment to a cleaner energy future, and the expectation that if the legislature process will encounter difficulties, the EPA will regulate carbon emissions.

The signature on January 2, 2013 by President Obama of the American Taxpayer Relief Act of 2012 into law. The act contains an extension and modification of the production tax credit and investment tax credit for projects that start construction prior to January 1, 2014.

These projects will be eligible for ITC or PTC when they are placed in service. The act changes the requirement that must be made to qualify for the PTC or ITC in lieu of PTC.

To qualify for the PTC or ITC, including ITC cash grant, which was not extended under this law, renewable energy facilities must have been placed in service prior to January 1, 2014. The current act modifies this rule, so that these facilities will be eligible for the PTC or ITC without regard to when the projects are placed in service so long as construction begins before the end of 2013.

This month, the White House issued a call to make the renewable energy regulatory support permanent. If this happens, an element of uncertainty will be removed from plans for future development.

To summarize, clean energy is becoming a significant part of the energy mix in many countries, and its share is expected to double in the global energy mix in the next decade or 2. Geothermal energy, where available, will continue to be the renewable energy of choice due to its baseload capabilities.

Turning now to Slide 30. In 2012, we were active on several fronts to obtain the necessary financing to fund our continued growth.

We closed on a $310 million loan from OPIC to finance the expansion of our Olkaria III geothermal complex in Kenya. In November, we received disbursement on the first two tranches of those loan, amounting to $220 million.

We are in the process of drawing additional $45 million for Plant 2 and have an additional capacity for the construction of the 16-megawatt Plant 3. We used part of the proceeds drawn in November to pay down corporate lines of credit and part of it will be used to partially prepay DEG loan.

The remaining outstanding DEG loan has been subordinated to the OPIC loan. The OPIC loan enables us to strengthen our balance sheet by replacing corporate debt with cost-effective long term project finance debt.

Last month, we announced that we entered into a tax equity partnership transaction with JPMorgan to monetize tax benefits. Under the transaction, existing power plants under OFC and Orcal were transferred into a new limited liability company, ORTP, and an interest in it was sold to JPMorgan.

JPMorgan paid approximately $35.7 million and will make additional payments based on the value of PTC generated by the portfolio over time that are expected to be made with until December 31, 2016, and sum up to approximately $8.7 million. This transaction enables us to maximize the use of our available production tax credit and accelerated depreciation, that we would not have otherwise been able to utilize either at all or for a long time, due to the fact that as a growth company, we generate more deductions for tax purposes than we are currently able to utilize.

The transaction has a lot of similarity to our OPC transaction, but unlike in the case of OPC, no cash is transferred to the partner and flip will occur after 4 to 5 years, a much shorter period than in the case of OPC. Earlier in the year, we also received $119 million amount in ITC cash grants relating to McGinness, Puna, Jersey Valley and Tuscarora geothermal power plants.

While those using solar may be impacted by the expected sequestration of approximately 9% of the ITC cash grant payable after March 2013. If you could please turn to Slide 31, you will see the CapEx requirement for 2013.

We plan to invest a total of $237 million. $179 million is expected to be invested in construction of new projects and enhancements, and an additional $58 million for development of new projects, exploration, maintenance CapEx and enhancement to the production facility.

As you can see, on the right side of the slide, we have sufficient capital resources to support our plan. Turning to Slide 32, which presents our revenue forecast for 2013.

Our 2013 product revenues are expected to be between $180 million and $190 million. We expect electricity segment revenues to be between $335 million and $345 million.

This guidance takes into consideration lower revenue in 2013 compared to 2012 in certain projects. In Puna, we assume low revenue of approximately $7 million as a result of lower energy rate for the 25 megawatt contract as the actual energy rate in 2012 was materially higher than the hedged rate under the put contract.

If the actual rate of the 25 megawatt in Puna will be higher, we will have an upside in that project. For Brady and in the Steamboat complex, we updated the generating capacity, as Yoram explained, resulting in lower revenue by approximately $2 million.

Due to the enhancements we are currently conducting in Mammoth and Heber complexes, we may have lower generation during the enhancement work and revenues can reduce by approximately $3.5 million. Our Imperial Valley plants have been subject to grid curtailment due to maintenance work performed by the grid operator.

We expect this to continue into Q2 and have estimated this impact at $2 million. In closing, please turn to Slide 33, which summarizes the main achievements this year, in both segments from the increase in product segment revenue and the record backlog in the product segment.

And from the addition of 51 megawatt of new plant, to reduction in operating expenses in the electricity segment. We remain confident that as support for renewable energy continues across the globe, Ormat is poised to take advantage of this trend and maintain its leadership position in the geothermal energy.

Before I'll open the call for questions, I would like to take a minute and express my or our appreciation to Joseph, who is leaving us at the end of next month. Over the last 8 years, Joseph has done a tremendous job as CFO and has been instrumental in Ormat's success.

Thank you, Joseph. And I would like also to welcome Doron Blachar, who will officially be joining our team on April 2.

Operator?

What drove the gross margin at the electricity segment in the fourth quarter? It was substantially lower than the previous quarters of the year and Q4 of 2011.

So I'm just curious what impacted that.

So I think that basically Q4s are weaker than the rest of the quarters. But specifically, we had a few adjustments that were not really related to generation and were made -- and captured and made in the fourth quarter, such as the tax audit that was performed.

And although we do not accept the results of the audit, we had to capture the cost in the fourth quarter.

Okay. So it's mostly some miscellaneous onetime charges that weighed on it in addition to being a weaker quarter.

Correct. Beyond the seasonality of fourth quarter, yes.

Okay. And I want to make sure I'm interpreting Slide 7 correctly.

Just to make sure, of course, you have to recognize that when you look at the fourth quarter in 2011, you still see our Standard Offer #4 plants with their fixed rates rather than the SRAC rates. And this is, if you compared Q4 '12 to Q4 '11, my guess is that this would be a very substantial impact on margin.

Right. Okay.

So going forward, the expectation in the fourth quarter would be somewhere in between this quarter and the fourth quarter of 2011? Is that the way to look at it?

Going forward for fourth quarters, yes. Over time, we expect this to get better because we will have new facilities come online.

Really our expectation for Olkaria, for instance, which are both very good performers -- or expect to be very good performers, and also are not affected by varying rates. So really, the -- if you like, historically, fourth quarters have been -- fourth and first quarters have been weak because of Standard Offer #4 contracts that are mostly -- and so as their impact wanes, the variability will change and actually most of our plants benefit from winter month generation because we're able to make more power and therefore have higher rate.

So this, over time, this will go away, but yes with the addition of Olkaria, the replacement of the G1 and G3 contracts for Mammoth. And hopefully, elimination of onetime charges, then yes, we should have a stronger fourth quarter in '13.

Okay, and on Slide 7, where you talk about North Brawley. I just want to make sure I'm interpreting it correctly.

So you're expecting about an $8.8 million reduction in D&A due to the impairment charge. So really holding all else equal, that's how we get to EBITDA positive in 2013.

Am I thinking about that correctly? It's as simple as just removing?

No, I think that the EBITDA positive is prior to depreciation. And this is -- we were positive in the fourth quarter of 2012 based on the work that we have done.

And so our assumption is that this positive trend will continue into '13 and would provide a positive EBITDA out of the plant. And Joseph?

And you'll see, yes, also the D&A does not impact EBITDA. It will impact the gross margins, but not EBITDA.

Okay, and what was the EBITDA generated in the fourth quarter in North Brawley?

It was about, it was a slight positive, so you can call it a breakeven EBITDA for the fourth quarter. And we expect -- again, expect this improvement to continue.

So if you couple the fact that we expect to be away from the negative EBITDA, and the fact that depreciation will be much lower, then we can expect a positive margin out of that project.

Okay. And then just sticking with improvement at North Brawley for a second.

The overall improvement to cash O&M and gross margin at the electricity segment going forward, I guess, realistically, what kind of improvement can we expect? Can we expect maybe O&M cost at a $30 per megawatt hour rate, gross margin near 30% or is that pretty lofty expectations?

For Brawley?

Consolidated company, but being driven by improvement at Brawley. Trying to just really figure out how much of a drag Brawley was, and going forward, how much improvement to expect at the overall company.

Yes, we think that up to 30% or the 30% range is realistic.

And just a couple of follow-up questions. First, looking at power guidance for '13, Dita, at the end, you laid out a couple things that you were sort of running into that maybe we haven't thought about before, particularly the -- it sounded like the takedown or the enhancements at Mammoth and Heber, as well as -- it sounded like you mentioned some grid issues at your Imperial Valley plant.

Can you give us a little bit more color on those 2 issues? And did those crop up at all in the fourth quarter as well?

So let's start with the grid. Yes, the grid curtailment has been -- work on Path 42 actually is something that has been around for a while, but really affected us in the fourth quarter, will affect us or already affected us in the first quarter, and we expect this to continue into the second quarter as well and what this really results in is that the grid operator tells us, no, you can only put so many megawatts on the line at this moment.

So despite the ability of the plans to make more power, we cannot generate that power, and we cannot get -- we cannot be paid for that power. And on top of this, in the structure of the agreement is actually sometimes grid issues actually cost us money on top of this.

So this is the estimate. Dita is correcting me that the right term to use is a location adjustment and -- which effects our -- in a way effects our rate.

Our expectation is, I mean, there is work that is being done on the system. So this should cure itself, but we cannot ignore it for this year.

As for Mammoth and Heber, I believe that we have shared with you in the past our plan to modernize both facilities. Unfortunately, the more you modernize the facility, the bigger the change it is to the existing facility.

In the case of Mammoth G1, we are taking the facility completely apart and putting it back together with better equipment on the same area. And so the facility is effectively shut down, I think, since just before Christmas, and we hope to be back online in time for the new PPA.

In the case of Heber, we're looking at -- the extent of the modernization is not as high but still substantial. The modernization is to Heber 1 and so we do -- we did factor in some downtime on the big steam turbine there to get ready for the upgrade, which will happen in 2014.

Okay. And then real quick, as we look at your guidance for '13.

The next question I had. Do you include the potential uplift in rates from the 2 Mammoth contracts?

Is that baked into your guidance? Or since you haven't finalized the arrangements with SCE, you're leaving that out at this point.

At this point, it is in our guidance yes.

Okay. And then, secondly, as it relates to guidance on Puna, can you remind us real quick of where your hedges are for '13 and how that compares to, I guess, realized pricing or whatever the marker was for '12?

So within a certain allowance for error, I think that the -- if our formula is correct, and this is a little difficult or it's not -- there is not a 100% fit between the format that we use and the protection on this gives us a protection at a Brent -- I'm sorry, I'll just translate this to what we think it means on rates and this means, this gives us a protection at an average rate of $165 a megawatt hour, which is lower than the average rate that we had in 2012. Again, if oil goes beyond what we currently have in our protection, and the avoided cost will be increased, then we can benefit from that.

But if not, this is where our protection is. And this is what we used in our guidance.

Right. And if -- but at current levels then I guess, would we ballpark $110 million on Brent, give or take, is that above or below where you're currently hedged at?

We are very close. I don't have the numbers in front of me.

But we're very -- our hedge is, I think, as of today, is giving us a protection. But starting from the beginning of the year, I think that we're very close to being right there.

Got it. And then real quick on your product guidance.

I think you said explicitly, you're not including the potential revenue from Thermo in your guidance for '13. Is that correct?

Correct.

Okay, and then real quick, just on Thermo, can you give me -- give us an update on where that stands, since the revenue is kind of contingent on plant completion and refinancing.

Well, what I can say is that, like always when we build plants to others, we're on schedule and provide a quality product. But specifically on an update on the project, you have to ask the owner.

So for us, this job is going well.

Okay, just one last one. We were a little bit surprised, it looked like both G&A or R&D were up a little bit sequentially in the fourth quarter.

Can you maybe think -- can you maybe give us a little bit of thoughts on how that should play out or was that at all impacted maybe by sales bonuses or anything like that, given the strong product performance?

Look it's a quarterly number, Dan, and sometimes the changes in quarter, there's nothing material in Q4 that we should report on.

Okay, great.

I think you should look at the annual number, I think, and you can see that on an annual basis we are okay.

I wanted to ask about products. So in the quarter, products were stronger than expected.

What were the moving pieces of that versus what your guidance was?

It is more timing than anything else. When -- because we recognize revenues in the product segment based on progress, if certain work was moved from one quarter to another, there are more revenues recognized.

And this is what happened this quarter. It can in the same way happen in the other direction and for the same reason, just timing.

All right, that's fair. And then when we look out to -- for product sector margins in 2013, I think we had talked around previously that margins would settle around the mid-20s range, is that still a reasonable expectation?

Or something closer to fourth quarter numbers?

No, we've -- the 25% range is still what we are looking in our margin in the product segment.

Okay, and then on the electricity margin, back to Michael's question, can you quantify the onetime charges, and also when we look out to the next couple of quarters as far as margins go, when you talk about that 30% gross margin number, is that an annual number? Or should we in 2Q, 3Q start to look on average to get more towards that 30% level?

The 30% is an annual average. It's lower in the first and fourth quarter, maybe slightly higher in the summer quarter as long as we have the Standard Offer #4 contract, but it's an annual average.

And then the quantification of the onetime charges in the quarter?

I don't have it in front of me. I don't know if Smadar Lavi?

The $3.3 million of mining tax is about 1% in gross margin, so that's the real amount.

First, can you share with us how much of your total capacity that is currently under tax equity financing, including your January financing. And also the original OPC contract?

Most of our generating capacity is under tax equity transaction, other than OFC 2. The big asset that are not under a tax equity transaction is OFC 2 and of course Brawley.

Okay got that.

Now this is the U.S. of course.

None of our international projects are under...

Also Puna Dita.

Okay got that.

Puna and REG plant.

No, no, Puna has a lease.

But it's not under...

It's not tax equity, but it's related to tax dollars.

But also the REG plants, but it's not much.

Okay, got that. And also I think I missed that.

How big is the interest expense impact of the January financing will have in this year?

Sorry, can you restate your question, please.

It's just, I may have missed that part. How big the interest impact will the January tax equity financing have on the interest expense for 2013?

You're now talking about the ORTP transaction?

Yes.

It will have a negative impact, but on the other hand we will have, of course, because of the yield of the investors -- but on the other side, we will have a benefit from utilizing the tax benefit and that will be a line in the income statement of income from sale of tax benefit. And since we are not utilizing those benefits, and since we are in a situation of valuation allowance, that we believe that the impact will be positive.

That's what I said in my words. So you need to look at the whole picture, not only on the interest expense.

The interest expense will increase, but on the other hand, we paid part of our debt because of that. So of course, the interest rate is much higher on the ORTP transaction than on regular debt, corporate or project finance.

But still, the total impact, as I said, will be positive.

I've been booted from the call a few times, so I'm sorry if you already went over, and I know it's a small item. But can you discuss some of the higher revenues at your other existing plants that were outside of the SRAC impact and outside of Brawley, what was driving that modest positive improvement?

Are you asking, which plants are the good contributor? Is that...

Yes, and sort of what's driving that with those plants?

Yes, so we have, certainly, for this year, it's the addition of Tuscarora and McGinness that are very good performers, with a very nice -- and this is driven by technology, I would say, the combination of technology and well field, where you have a very good ratio of revenue to operating cost. So certainly, good performance out of there.

Strong performance out of Puna, but in the case of Puna, it's of course given the fact that we had a good strategy on hedging on oil and strong oil prices, this drove the variable rate to be a very positive one for us. So I think that big difference from previous years, I would say that these are the 3 that had a big change.

Beyond that, we have other good performers in our fleet. So -- but for them, there was nothing new in 2012 compared to previous years.

Okay, and obviously, the motivation for -- you discussed kind of moving towards a more equal split between U.S. and international development, the motivation there is clear.

Is there any chance you can give any detail or color on what that might mean, maybe with personnel or potential M&A opportunities similar to the one at the end of last year?

I think that in terms of personnel, there are -- this is -- we don't see any effect. Our workforce is very flexible in terms of geography.

It really doesn't matter if you work in Hawaii, you work in Kenya for the development side. Rarely do we actually get to do development work from our home office anyway.

And then I think that the value in our statement is really to tell you what is to come in future years. Project development is always a lengthy process, and there is a long process of screening prospects.

Our growth is typically driven by identifying either very early or greenfield development projects or a late-stage development project, not a fully constructed power plant. So M&A although it is possible, is typically less relevant for what we are looking at.

We are looking for fields that are ripe to be turned into power plants, and we believe that there are quite a few of them in the world. It takes time to find the right field and to make sure that this is done in the right market environment.

So again, it's a somewhat lengthy process, but this is what we are looking at doing in 2013 and going forward.

Okay, and if you don't mind, just one more quick question on the Honduras project. Obviously, the closure of the deal is subject to some conditions.

Is that just going to be confirmation on your end of the resource? Or are there some other kind of major conditions there?

No, the closing of the transaction is subject to more legal and administrative conditions. They're not resource conditions.

We needed some local Honduran confirmation, some publication and especially the rates and things of that kind. We are optimistic about the resource.

Of course, we will do our own exploration, but this is after the closing, not before the closing.

Real quick, on your CapEx needs for '13. Under the $180 million of construction of new projects and enhancements, does that include anything in it for Carson or for Mammoth?

And if not, sort of what are the gating items for you to either move forward with those or not?

You asked Carson and McGinness?

No, Carson and Mammoth or CD4.

Mammoth, CD4, the answer is no for both. Carson is just not a priority.

And CD4, we don't expect the permit to be obtained in time.

Okay. So that also would likely mean neither will end up qualifying for the PTC, or at least under the current deadline?

Not sure because the law this passed just -- this was signed just in early January, enables a PTC for a project whose construction has started prior to 2013 -- when it is placed in service, without a time limit of when it has to be placed in service. Regulations have not been issued yet.

And we are operating under the assumption that start of construction will be defined in the same way as it is defined in the ITC cash grant. If this is going to be the case, and of course, we don't know if this is going to be the case, but if this is going to be case, then both of them are eligible to PTC when they are placed in service.

Okay. And the last question I have is, we can't have a conference call going without it.

It looked like there was some progress on Sarulla in terms of the initials on the joint operating contract and the energy sale agreement. I know last year at this time, you were pretty optimistic that maybe the contracts would be completed in '12, now we're in sort of early '13.

Are you willing to sort of maybe give us an update in terms of expected timing? Or just given the uncertainty, it's maybe better not to.

I will admit that we didn't make the end of '12 for it. And I will be cautiously optimistic to say that I see it in a matter of weeks and not in a matter of months.

So conceivably, you could have financial close on this during this year?

Oh no, it's not, no financial close, no. This is the signing of the contract and financial close will be a year later.

So financial close is 2014 not 2013.

My question was mostly answered about the PTC effect in Carson Lake and the definition of whether it gets applied to the previous definition in terms of the threshold for CapEx, but maybe just unrelatedly, is the tear down at Mammoth, and rebuild, is that possibly subject to the PTC since I guess it's technical coming offline and being rebuilt or no expectation there?

We have not finished that analysis. It's a possibility, but we have to do the analysis.

There is a tax rule which describes what a new plant and what's not a new plant. We have not completed that analysis.

There are good chances that it will.

Just a big thank you to all of you. And hopefully, we'll continue to show progress as we expect this year to be an excellent year.

Thank you.