Ormat Technologies Inc (ORA) 2011 Q4 法說會逐字稿

Ladies and gentlemen, thank you for standing by, and welcome to the Ormat Technologies fourth-quarter and year-end 2011 earnings call. (Operator Instructions). 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 and 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 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 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 Technologies believes that adjusted EBITDA may provide meaningful supplemental information regarding liquidity measurements that both management and investors benefit from referring to this non-GAAP financial measure in assessing Ormat Technologies' liquidity and when planning and forecasting future periods. This non-GAAP financial measure may also facilitate management's internal comparisons to the Company's historical liquidity.

Before I turn the call over to management, I would like to remind everyone that the slide presentation accompanying this call may be accessed on the Company's website at Ormat.com under IR events 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, 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, an increase in operating cash flows, steady growth in total generation, and an exceptionally strong performance in the product segment.

The 2011 net income was negatively impacted by a non-cash tax-related valuation allowance of $61.5 million, which was 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 credits. For those valuation allowances recorded against these deferred tax assets, no economic loss has occurred, and the underlying net operating loss carryforward and other tax credits remain available to reduce future U.S. taxes to the extent income is generated.

We made operational improvements and enhancements at several plants, 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 view of the financials. 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 at slide five, total revenues for the full year of 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 six, revenues for the full year were $323.8 million, an 11% increase over revenues of $291.8 million in 2010. The increase in electricity revenues is due to higher variable energy rates of our Amatitlan and Puna PPAs, and increased electricity generation of some of our partners.

In the product segment, on the next slide, (multiple speakers) for the full year were $113.2 million, an increase of 39% over revenues of $81.4 million in the second quarter -- in 2010. The increase in product revenues reflects the new customer orders that were secured in the first half of 2011.

Moving to slide eight, the Company's combined gross margin 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 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 of 2011 increased 172% from $23.6 million in 2010 to $64 million this year.

Moving to slide nine, interest expense for the 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 in August 2010 and February 2011.

Moving to slide 10, in the fourth quarter and full-year 2011, we recorded a valuation allowance in the amount of approximately $61.5 million against our U.S. deferred tax assets, which includes net operating tax loss carryforwards, which are called NOLs, and unutilized tax credits, mainly PTC, but also ITC.

As of December 31, 2011, we had U.S. NOLs in the amount of approximately $350 million and unutilized tax credits, which can be used over 20 years, of approximately $60 million. The related deferred tax assets total approximately $193 million. Realization of this operating loss in tax credits is dependent on generating sufficient taxable income in the U.S. prior to expiration of the NOLs and the tax credit, which is between 2021 and 2032.

After performing a routine year-end analysis to confirm our ability to realize deferred tax assets, it was determined that non-cash tax-related valuation allowance of $61.5 million against the U.S. deferred tax assets as of December 31, 2011, is required. We can use the deferred tax asset in the future if we can establish sufficient evidence of our ability to generate taxable income in future years, which may reduce the valuation allowance, resulting in income tax benefit or reduction in income tax provision that will appear in our consolidated statements of operations.

Now moving to slide 11, the net loss for the full year of 2011 was $42.7 million, or $0.95 per share, basic and diluted, mainly due to the $61.5 million valuation allowance. Excluding the impact of the valuation allowance, the Company would have recorded full-year net income of $18.8 million, compared to a net income of $37.2 million, or $0.82 per share, basic and diluted, for 2010. Please note that 2010 net income included a $22.4 million after-tax gain from 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 12. For the fourth quarter of 2011, total revenues were $123.7 million, compared to $92.8 million in the fourth quarter of 2010. Revenues in the electricity segment increased 5.5% to $77.6 million, up from $73.6 million in the fourth quarter of 2010. Revenues in the product segment were $46.2 million, an increase of 139.4% compared to $19.3 million in the fourth quarter of 2010.

Now on slide 13, operating income in the fourth quarter 2011 was $17.3 million, compared to $4.2 million last year. Net loss for the quarter was $43 million, or $0.95 per share, basic and diluted, compared to net income of $4.5 million, or $0.10 per share, basic and diluted, in the fourth quarter of 2010.

As shown in the following slide, slide 14, adjusted EBITDA for full-year 2011 was $166.7 million, compared to $164.3 million in 2010. The 2010 number includes a $36.9 million gain from the acquisition of the controlling interest in the Mammoth complex in California. 2011 EBITDA does not have any special or nonoperational items.

Adjusted EBITDA for the fourth quarter of 2011 was $45.1 million, compared to $29.4 million in the same quarter of 2010. Adjusted EBITDA includes consolidated EBITDA and the Company's share in the interest, taxes, depreciation, and amortization related to the Company's unconsolidated 50% interest in the Mammoth complex for the period from January 1, 2010, to August 1, 2010, the date we acquired the remaining 50% interest in such complex.

Net cash provided by operating activities was $32.3 million, compared to $21.8 million, respectively, in the quarter, and $132.7 million in the full-year 2011, compared to $101.4 million in 2010. The reconciliation of GAAP net cash provided by operating activities to adjusted EBITDA, as well as additional cash flow information, is set forth in slide 35.

Moving on to the next slide, cash, cash equivalents, and marketable securities as of December 31, 2011, was $118.4 million, up from $82.8 million as of December 31, 2010. The accompanying slide breaks down the use of cash during the 12-month period. Our liquidity came from the issuance of senior unsecured bonds; proceeds from the sale of Class B membership units of OPC to JPMorgan; issuance of the OFC two senior secured notes, 80% guaranteed by the DOE; and cash derived from operating activities. Our long-term debt at the end of 2011 and the payment schedule are presented in slide 16 of the presentation.

In accordance with the Company's debt covenants, on February 22, 2012, Ormat's Board of Directors decided not to declare a quarterly dividend for the fourth quarter of 2011. However, the Company expects to pay a dividend of $0.04 per share in the next three quarters.

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

Thank you, Joseph, and good morning, everyone.

Starting with slide 18, total generation for 2011 was 3.9 million MW hours. This represents an increase of 4.1% from 2010 and approximately 57% increase in total generation over the past five years.

Steady growth in total generation and the decrease in 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 MW. We plan to continue work on the injection and hope to increase generation further during this year.

In North Brawley, we continued to work on the geological interpretation of the field and on improvements to the production pump assembly. Based on the geological interpretation, we successfully completed one production well in the fourth quarter and successfully tested the 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. 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 by at least 90%. This, together with successful solid control measures, will allow -- will provide substantial reduction in the operating expenses in the future.

The 10-K that will be filed next week will have updates to the total generating capacity figures, as you can see on slide 20. The main changes are the new Tuscarora power plant and the adjustments of the North Brawley and Jersey Valley to our short-term expectations. We have also made minor changes where recent well fieldwork resulted in increased capacity, such as in Olkaria and Brady, or the resource cooling requires a downward adjustment.

Moving to slide 21, as we discussed last month -- disclosed last month, the continued decrease in forecast for natural gas prices in 2012 and 2013 and the delay of California's greenhouse gas cap-and-trade program have increased the impact of the transition from a fixed to a variable rate for the energy component of our standard number for contract. The Global Settlement requires us to amend the contracts to reflect the pricing option based on a short-run avoided cost methodology with certain applied modifiers until December 2014, and thereafter convert to a mandatory short-run avoided cost methodology pricing.

We believe that the green power from the existing plants is valuable and are focused on finding a solution that will reflect that. A benchmark for a fixed price under new long-term contracts is the market price reference approved in December by the California Public Utilities Commission, and reflects the long-term avoided costs of the investor-owned utilities in California.

Looking at the slide, you can see the approved pricing for contracts to be signed in 2012 for power plants that will start operation in the years 2012 to 2015.

Turning to slide 22, offsetting the impact of the current natural gas prices on our 2012 revenues are additional generation from new projects and our strong product segment pipeline. I'd like to review some of the recent developments impacting production and new projects.

Our 18 MW Tuscarora project was put online in late November and has been selling pre-commercial power since. In January, we performed the tests that are required to demonstrate commercial operation and are waiting for the offtaker to accept them.

In Hawaii, the PUC approved the PPA for the additional plant and the amendments to the existing PPA, and the plant has been generating power since late December.

For an update on our projects under construction, please turn to slide 23.

In our Olkaria expansion, two production wells were completed last year and a third was recently completed. We believe that the wells are capable of delivering 75% of the required production flow for the expansion, and we are already benefiting from the increased capacity using the operating plan. We are continuing to drill additional wells and are manufacturing and purchasing equipment for the new power plant.

In McGinness Hills, we recently completed the drilling of the last production well and are in very advanced stages of construction. We expect completion in the third quarter of 2012.

In Wild Rose, three wells have been drilled, and we are continuing with drilling activity.

Late last year, we signed a PPA for a 10 MW solar photovoltaic power plant in Heber. We began construction in the fourth quarter and expect commercial operation within 18 months.

There hasn't been much progress in Carson Lake and in CD4, where permitting has been slowing down resource development and is putting a 2013 completion at risk. In December 2011, we terminated the Carson Lake PPA and joint operating agreement with NV Energy, which will give us the flexibility to adjust the commercial terms to the new project configuration and a new project timeline.

We are currently working on coming to terms on a new PPA for the Haber complex, which may allow us to generate an additional 6 MW there. The additional output is not included in the table, but is part of our CapEx plan.

All in all, we are in the construction phase of seven projects. Most of these are expected to be completed by the end of 2013 and will add between 144 MW and 149 MW to our portfolio.

On slide 24, you can see the detailed list of projects under development. In Sarulla, we made progress on the amendments to the joint operating contract and the energy sales contracts, which reflect the agreed adjusted tariff and other financial conditions.

We also have an agreement in principle with the Indonesian Ministry of Energy and Mineral Resources and the Ministry of Finance. The execution of these amended contracts is expected to occur during the first half of 2012. The consortium has [mended] its certain lenders, and the selection and the engagement of due diligence consulting is currently underway.

We have reduced our estimate on the size of the Crump Geyser project based on the resource work that was done to date.

We may generate an additional 6 MW from the Menengai BOT project, which the GDC, owned by the government of Kenya, awarded to us. The additional output is not included in the table.

We are currently working on the development of as much as 18 ground-mounted and rooftop projects in Israel. Due to the competitive nature of the solar market, we expect that only a portion of them will come to fruition and have not included any of them in our current pro forma.

Turning to slide 25, in addition to projects under construction and development, we now have 42 prospects in early exploration or where activity has yet to begin. We significantly increased our land position in 2011 and now have approximately 675,000 acres. We continue to work on identifying new prospects while focusing on cost control in this highly prospective phase.

In 2011, we continued to expand our in-house capability to perform well fieldwork and added three new rigs, which increased our operating fleet to one fixed and eight mobile rigs. Our fleet is now capable of performing most of the steps from exploration through well field development and O&M, with good schedule and cost control.

Turning now to slide 26 and 27 for an update on the product segment, 2011 was a strong year for the product segment. We signed new international and domestic contracts for the supply of geothermal power plants and other power generating units.

As of February 15, 2012, our product backlog is approximately $240 million. It includes revenue for the period between January 1 and February 15. This number includes a geothermal supply project, which is subject to the customer finalizing its financing arrangement for the project, and an EPC contract with Cyrq for which the revenue will only be recognized upon reasonable assurance of payment by the customer.

On a second project with Cyrq, we haven't included it yet as the conditions precedents have not been met. We also signed with Cyrq a credit agreement under which Ormat will provide financing in an aggregate principal amount of up to $22.7 million that will be used to finance the project construction costs under the EPC contract.

I'd now like to turn the call back to Dita.

Thank you, Yoram.

In my own remark, I would like to review regulation and financing activity of 2011, comment on our capital position, and then conclude with revenue guidance for 2012 before turning the call for the questions.

Starting on slide 29, federal legislation and government-sponsored programs that were available to renewable energy development 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 IPC 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 encourage California's RPS to 33% by 2020 was signed in 2011, and it represents one of the most aggressive renewable energy goals in the United States. The IOUs have [entered one thousand] 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 sales from renewable energy resources by 2020, opening up a significant new market of potential offtakers in the years ahead. These utilities do not have incurring targets. 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 serve as a strong example of others to follow.

Turning to slide 30, in 2011 we were active on several fronts to obtain the necessary financing to secure our goals. In September, we finalized the loan agreement of up to $350 million under the U.S. Department of Energy's 1705 loan guarantee program to finance three projects in Nevada. We also received a $310 million commitment from OPIC to refinance and expand the Olkaria project in Kenya.

We raised in August of 2010 and February 2011 $250 million in total for the sale of seven-year senior unsecured bonds. Also in February, we financed a $25 million [with] tax equity transaction for OPC Power Plants and extended lines of credit both internationally and in the United States.

The DOE guarantee of a 20-year loan provides us federal refinancing to support the development of [veld Israeli], [daccord], and McGinness Hills. The innovative part of this development and construction financing is the ability to finance three power plants in two phases each. The two-phased approach allows us to manage risk by including the second phase in the OFC financing to better control long-term financing costs.

The commitment letter with OPIC for up to $310 million toward financing and expand Olkaria III complex, located in Kenya, is currently in documentation phase.

Please turn to slide 31, and you will see the CapEx requirement for 2012. In 2012, we plan to invest $192 million for the construction of new projects and an additional $70 million for development of new projects. We expect to invest $31 million in exploration in 2012.

In addition, our capital expenditure budget for maintenance CapEx and enhancements for operating power plants is approximately $65 million. Approximately $7 million to invest in our production facility, and the funding of this program will come from cash on hand at the end of 2011, cash from operations, unused corporate lines of credit, ITC cash grants, and project finance debt. Another capital need is to find the Cyrq thermal contract until payment by the customer.

On slide 32, we have provided a snapshot of our debt portfolio. As you can see, we have a good balance between corporate and project finance debt. The debt to EBITDA, as well as debt to capital, ratio indicated our debt capacity can support our growth plans.

As we look forward to 2012, please turn to slide 33. Based on current expectation of [effort] prices, we anticipate that our 2012 electricity segment revenues to be between $315 million and $330 million. From our product segment, we currently expect our 2012 revenues to be between $150 million and $165 million.

In closing, as we look at the years ahead, there is a lot to drive our commitment for the sector in general and for us within the [normal] subsector in particular. California, 33% RPAs; new investors entering the renewable space, like Mid-American or [simply]; a projected rebound in actual gas prices, which are at their lowest since 2001 due to the pressure from the [shale mass], light winter, and the weak economy; and Rio+20 driving the international -- or expected to drive the international supporting the move towards geothermal.

And for us, the progress in construction and development, the improvement in Brawley and other operating plants, the strong land position of the future development, and the record backlog for the product segment.

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

(Operator Instructions). Steve Milunovich, Bank of America Merrill Lynch.

Do you have 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 year, the margin was slightly higher mainly because of the income recognition from the LNG project, what we call the [north] project. 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 (multiple speakers)

It's not the guidance for the year. It's our normal product margin.

Okay. Where are you seeing demand coming from for products outside New Zealand? 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 are continuously struggling with an ability to predict new projects in the product segment. It's a come and go; it's the life of a project, which is a binary thing, yes or no.

Nevertheless, definitely [relanding] we expect to continue to be a market, [tel keys] 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 prefer not to give guidance on Brawley.

Okay, thank you.

Dan Mannes, Avondale.

A couple follow-up questions. First, on 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 us just look for the numbers, so if you have additional questions, we will give you the right number.

Absolutely. I certainly have a few more. Real quick, on the California, on the SRAC contracts, I appreciated the slide. But maybe could you 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 volume you see at risk on a megawatt hour basis and what the sensitivity is to changes in gas prices, just so we can understand, as gas prices move, the kind of leverage in your model?

So, what is the sensitivity to gas prices? I think that on a very rough order of magnitude, every $1.00 a million BTU is about $0.01 a KW hour, and we have about -- currently about 140 MW that are affected by that.

Okay (multiple speakers)

Go ahead.

And then, can you walk us through the greenhouse gas piece, because I know you've excluded that from 2012 and I believe from 2013. Can you walk us through how that bakes into the number? You gave us the $25 million, but it would really help us to get a little bit more granular in terms of this since it's such a big sensitivity in your earnings power.

So, a 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 kilowatt hour, unless there are additional details -- 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, re-contract them under the current terms, which move into energy-only calculations, move away from the legacy structure. And basically, use what the California PUC views as long-term fair or reasonable long-term prices as a guideline for our re-contracting 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, yes.

Okay, we may have to double-check that off-line because that sounds like it got substantially worse, because I thought it was only about a $1 million EBITDA loss in 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 two.

But beyond that, we have done some work on our well field, which reduced generation increase, 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 pumps, and we are now at the higher generation level and at the lower cost. So we expect the forward to be better.

And what generation level is that?

We are currently generating about 25 megawatts. And this is (multiple speakers)

Sorry, 20 -- 2-5?

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

Okay, and then two 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 you're -- sorry, keep going.

No.

And the $192 million of construction new projects includes 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. And 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 an 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?

Sarulla is my [road] to answer. We're definitely today more optimistic about solar than we were, now, let's call, in November.

On the last call, in November, if you'll recall, I was very 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 issues.

From this to put a date, it is still very difficult. We cannot say -- 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 of financing. This will probably be next year. But what we think will happen this year is finalize the contracts, again with all the caution that we have to have for solar. The product segment revenues for solar are in the order of between $250 million and $300 million.

And obviously none of that is in the backlog that you guys are disclosing?

Of course, of course.

Great. Thank you very much.

Carter Driscoll, Capstone Investments.

The first question is, you had mentioned, I think it was on the last call, about the opportunity to potentially co-locate some small solar facilities or realize that the opportunities in this field don't seem to be progressing at the rate you had previously forecast. 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 incremental contribution and help us try to plan out how that might impact your results going forward?

The easy answer to your question is at this point, our first step was the 10 MW 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 Ormesa area, though it's a little more difficult, and the plants could be at that size. So, 10 MW to 20 MW is certainly a reasonable size for such a photovoltaic plant.

However, it does require the PPA market 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 other developers, we start with our threshold for a return from the project with our estimate on cost, and market the power at the rate that would support that or be a little better. Because the solar projects are relatively lower risk, the pricing can be somewhat more aggressive. You don't have the exploration risk and other long-term unknown that you have in the geothermal, so the pricing can be more aggressive.

Helpful. Of your forecast CapEx requirements, can you kind of break down maybe this year or next year about what you hope to pull through, not necessarily construction, development, exploration, but kind of bracket what you expect to do over the next 12 versus 24 months?

I'm not sure I'm following the question. Can you (multiple speakers)

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 the 2013 CapEx (multiple speakers)

(Multiple speakers) 2012. Okay. Just wanted to clarify.

And then, my last question is if you could just clarify what the SRAC issue, the projects that are currently -- the PPAs 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. Really, the SRAC impact is only on legacy PPAs, PPAs that were signed -- I think the last of them was -- they're all PPAs from either the mid-1980s or very, very early in the 1990s. 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, 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 actually break out project by project, but Jersey Valley at current run rate, is that positive contribution to EBITDA currently?

Yes, it is (multiple speakers). It has been throughout the year, actually.

Thank you.

JinMing Liu, Ardour Capital.

Most of my questions have been answered. Just one lap in there. It looks like -- it's a little bit early, but it just looks like you will need to refinance actually about $414 million of (multiple speakers) credit comes due in 2013. What's your plan there?

The way the table is presented is that if you have the revolving line of credit, which has a limited time, and those are typically for two years, when the two years is expected to arrive, we show it as a repayment.

But our working assumption and our past experience has been that those are renewed, and they will just be rolled over for another two-year period. So, don't take the two years of 2013, 2014, too seriously with respect [to] revolving lines of credit.

Okay. Thanks a lot.

Mark Barnett, Morningstar.

I just had a couple of shorter questions. You've already talked a little bit about the SRAC pricing. And I know that you're trying to move away from those contracts. Can you talk maybe about 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 three 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 -- certainly 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 dampening effect on re-contracting new power when the current contracts allow them to buy the power under very short terms -- or very favorable costs.

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 prospect 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 where 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 you 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 costs at the moment, and we need to find a comfortable common ground.

Okay. And 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 was any other work included in this line that is going to be meaningful, or how we should think about that.

I think that the biggest part is Puna, where we expect to increase capacity, both have 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 plants.

Okay. And just one last quick question, I was wondering on Tikitere. I know it's only been about six months, but I was wondering what the timeline for 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 will start exploration in Tikitere.

Okay. Thanks for the detail.

Peter Christiansen, Bank of America Merrill Lynch.

Thanks for taking my question. Joseph, I was wondering, could you provide us any visibility on what book taxes could be this year and how that could -- would compare to cash taxes?

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 allowance. So it's very difficult to do so. We will need to do an analysis each quarter to see where we are with the valuation allowance because it's -- will be an ongoing process once you bid it. So it's very, very difficult to predict.

But probably, and I must be very careful about it, in the U.S. probably will be at a zero tax. The rest of the world, Guatemala is zero, Israel is 15%, Kenya is about 7%, and [Caraga], it is 25%. So you can imagine that we will be at relatively low tax rates from a book perspective. But I can't give you the number because (multiple speakers)

Okay, fair enough. And then, selling expenses increased in the quarter. Should we think of that as increasing with product revenues? Is that where the primary source of that growth is?

There are two common links there. If the product segment is better, it goes up. But in the last quarter and the last year, we had, if you recall, about $1.7 million that we pay NV Energy for the Carson Lake termination of PPA. That amount is also included there. So if you eliminate that, you can get a better picture of going forward a selling and marketing expense.

Okay. That's very good color. Thank you.

Dan Mannes, Avondale.

Hey, 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 maybe what you're baking it in terms of either the SRAC or the gas price that's implied by that range?

We basically -- this tracks what we have provided in our disclosure three or four weeks ago. So, I believe, not to be precise, but just assume a $24 million reduction in revenue compared -- from those projects compared to 2011.

So basically, as of gas prices three weeks ago, we have taken the whole impact of that. Gas did continue 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 use 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 improvement that could make the picture better.

So real quick, just two verifications there. So number one, so that does assume that for -- I guess it's the seven or eight months starting after May, you're going to have sort of a sub-$3 gas curve 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 time frame under which the Puna expansion and Tuscarora come up, and McGinness start up 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 McGinness starts up, yes.

But, I mean, Tuscarora and Puna have already started. So, are you assuming a full year, or --

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

Got it. Thanks.

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