Ormat Technologies, Inc. (ORA) Q3 2012 Earnings Report, Transcript and Summary

Ladies and Gentlemen, thank you for standing by, and welcome to the Ormat Technologies Third Quarter 2012 Earnings Call. [Operator Instructions] Thank you. I would now like to turn the conference over to Mr. Rob Fink of KCSA Strategic Communications. Sir, you may begin your conference.

Thank you, Maria, and thank you, everyone, for joining us today. Hosting the call 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'd 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 by 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 company's annual report on Form 10-K filed with the SEC on February 29, 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 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 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 Events & Presentations link found in the Investor Relations tab. With that all said, I would now like to turn the call over to Dita. Dita, the call is yours.

Thank you, Rob, and good morning to everybody. Thank you for joining us today for the presentation of our third quarter 2012 results and outlook for the near future. This quarter, we continue to see major progress in our generation, which increased by 12%. Total revenue grew 23%. Cost per megawatt-hour were reduced, and operating income, excluding impairment charge and loss from hedging deal, increased over 4%. These improvements come from the fundamental of both the Electricity and the Product Segment. However, as we have explained, this year was marked by the impact of the low natural gas prices in multiple Californian contracts, and this quarter was the first one to reflect the full effect of the lower natural gas prices. And other indirect results of the weaker natural gas market is the noncash impairment charge related to the OREG 4 project. Going forward, we look for -- we took proactive steps to reduce our revenue exposure to oil and natural gas prices through hedge deals. In addition, we signed 2 new fixed-price PPAs for our Mammoth complex in California to replace 2 Standard Offer #4 PPAs and further reduce our exposure to natural gas prices. Joseph and Yoram will elaborate on these activities later on the call. I will now turn the call to Yoram to review our operation and then to Joseph to review the financial. Following my remarks, we will open the call for Q&A. Yoram?

Thank you, Dita, and good morning, everyone. Starting with Slide 5, total generation for the third quarter of 2012 was approximately 991,000 megawatt-hours, which is an increase of 11.7% from the same quarter last year. The growth in generation this quarter is mainly due to the successful completion of the Tuscarora power plant and the McGinness Hills power plant that has been in commercial operation since July. Control of operating costs remained a key priority, and our specific cost in dollars per megawatt-hour this quarter were 10% lower than in the third quarter of 2011. The reduction is both the result of targeted action in high maintenance-cost areas of the plants and the addition of higher-efficiency plants to our generation basis. Moving to Slide 6. At the macro level, the results from the North Brawley -- from North Brawley this quarter remained similar to those of the third quarter of 2011. We were not successful in reaching a breakeven EBITDA due to increased cost and lower-than-budgeted generation caused by a strong earthquake and work on 2 of our better production wells. However, at a detailed level, we continued to see substantial improvement in most of the cost drivers for Brawley, with production lines more than doubling compared to 2011 and expectation to see total operating expenses for 2012 at about 67% of 2011, and this is excluding depreciation. I will now turn to Slide 7. As Dita mentioned in her opening remarks, we believe that the impact of the low natural gas prices will subdue over time. However we have been proactive in dealing with the effects of the variable rates in our company. In the short term, we have secured a floor for the SO#4 contracts and secured the revenue from Puna using a swap hedge for 2012. For 2013, we have secured an energy rate of over $40 per megawatt-hour for the Standard Offer #4 contracts in a swap transaction and acquired a hedge for Puna's rates. These hedging deals require us to perform a mark-to-market adjustment but provide a stable revenue stream. As for the long term, we have signed 2 PPAs outside of the SO#4 structure for 2 of the Mammoth plants, and we will continue to look for opportunities to convert the remaining contracts to fixed-rate contracts that are not tied to natural gas pricing. For an update on the project pipeline, please turn to Slide 8. In the table, you can see the status and expected completion schedule for each of the projects that we plan to bring online by the end of 2013. The Olkaria III extension is progressing in both field development and plant construction, and we expect to have the project online by mid-2013. At Heber Solar, construction began in the fourth quarter of 2011, and we expect commercial operation in 2013. At Wild Rose, we are close to completing the drilling [indiscernible] phase for the power plant equipment. We currently estimate the generating capacity to be 60 megawatts. Successful completion of these 3 projects will bring our total generating capacity to 648 megawatts by the end of 2013. In Mammoth, we are in the process of modernizing the complex by replacing old units with Ormat-manufactured equipment. While the project will maintain the current name plate capacity, we expect higher availability and lower equipment-related costs. On Slide 9, you can see the list of projects under various stages of development. As you can see, we plan to develop a fourth phase in Olkaria III complex that will bring the complex's capacity to approximately 100 megawatts. Due to changes in the fee and tariff under the current regulation and the long permitting process, the solar-photovoltaic projects in Israel are currently excluded from our plan. Turning to Slide 10. In addition to the projects under construction and development, we now have 42 prospects in early exploration or where activity has yet to begin. Slide 11 provides an update on the Product Segment. As of November 6, 2012, our product backlog is approximately $192 million, which ensures high levels of revenue through 2013. Let me now turn the call to Joe.

Thank you, Yoram, and good morning, everyone. Beginning on Slide 13, total revenues for the third quarter were $136.1 million, a 22.8% increase over the revenues of $110.8 million in the third quarter of 2011. In our Electricity segment, as you can see on Slide 14, revenues decreased 6.2% from $86.8 million in the third quarter of 2011 to $81.5 million in the third quarter of 2012. The decrease in Electricity revenues resulted from a $9.3 million decrease resulting from the lower natural gas prices, impact on the energy rates under our SO4 PPA in California and a net loss of $3.8 million on swap contracts and put transactions on oil prices and natural gas prices. As previously explained, these transactions are mark-to-market at each balance sheet date, so actually, the loss this quarter eliminates the gain we had recorded from these transactions in the previous quarter. On an annual basis, these fluctuations are eliminated. As I mentioned in previous calls, we are not using hedge accounting for those contracts. The decrease in revenues was partially offset by $7.8 million in revenues from our Tuscarora and McGinness Hills power plants, which commenced commercial operations in January 2012 and July 2012, respectively. In the Product Segment on Slide 15, revenues for the third quarter more than doubled from $24 million in the third quarter of 2011 to $54.7 million this quarter. The increase in Product revenue is largely attributed to the progress we made in execution of the Ngatamariki geothermal project in New Zealand that we secured in 2011 and the new contract for the Cove Fort project in Utah we signed in 2012 with Enel. Moving to Slide 16. The company's combined gross margin for the third quarter was 23.9% compared to 32.3% in the same quarter last year. The Electricity Segment's gross margin was 24.5% for the quarter compared to 33.3% in the third quarter of 2011. The decrease is mainly attributable to the lower revenues from our Standard Offer #4 PPAs. In the Product Segment, gross margin for the third quarter was 23% compared to 28.7% in the same quarter last year. The decrease in Product's gross margin is mainly attributable to a different product mix and different margins in the various sales contracts. Moving now to Slide 17. Operating income for the third quarter was $14.2 million, a decrease of $10 million from $24.2 million in the same quarter last year due to the OREG 4 impairment charge and lower gross margin in the Electricity Segment. Since commissioning the OREG 4 recovered-energy generation power plant -- in the OREG 4 recovered-energy generation power plant, the compressor station has operated at lower than historical levels. As a result the current and projected output for OREG 4 is low, and therefore we have to test for recoverability by estimating its future cash flows. The carrying value of $10.9 million exceeded the estimated undiscounted cash flows, and therefore we recognized a noncash pretax impairment charge of $7.3 million. Underlying operating income, which is operating income excluding the impairment charge and excluding the loss on the put and swap transactions, amounted to $25.3 million. Moving to Slide 18. Interest expense net of capitalized interest for the second quarter was $15.4 million compared to $23.9 million in the same quarter in 2011. The decrease was primarily due to the $11.6 million loss in the third quarter of 2011 on interest rate-lock transactions relating to the OFC senior secured notes. The decrease was partially offset by additional interest expense mainly as a result of the issuance of the OFC 2 senior secured notes in October 2011 and higher interest capitalized to projects under construction in 2011. Moving to Slide 19. The net loss for the quarter was $0.5 million or $0.01 per share, basic and diluted, compared to net income of $1 million or $0.02 per share, basic and diluted, for the same quarter of 2011. As shown in Slide 20, adjusted EBITDA for the third quarter of 2012 was $48.2 million compared to $46.7 million in the same quarter of 2011. Adjusted EBITDA excludes the impairment loss in respect of the OREG 4 power plant and includes the loss on the put and swap transactions. For the 9 months, adjusted EBITDA grew by approximately 24%. It was more than $150 million. 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 27. Moving to Slide 21. Cash, cash equivalents, marketable securities and short-term bank deposits as of September 30, 2012 were $40.5 million, down from $118.4 million as of December 31, 2011. The accompanying slide breaks down the use of cash during the 3 months. Our long-term debt at the end of the third quarter of 2012 and the payment schedules are presented in Slide 22 of the presentation. That concludes my financial overview. I would like now to turn the call back to Dita for closing remarks.

Thank you, Joseph. In my remarks, I would like to comment on third quarter financing activities, our capital position and conclude with revenue guidance for 2012 before opening the call up for questions. In the third quarter, we received a $47 million ITC cash grant relating to the investment in the McGinness Hills power plant. This has added to the $72.2 million received earlier in the year. In addition, we signed a $310 million limited-recourse OPIC loan agreement for the Olkaria III complex. Out of the first draw under the loan that is expected shortly, approximately $150 million will be used to [indiscernible] finance corporate loans and therefore replace corporate debt by project financing. Please turn to Slide 24, where you will see the CapEx requirements for the remainder of 2012. We plan to invest a total of $70 million. $48 million is expected to be invested in construction of new projects, which will be completed in 2013, and an additional $22 million for development of new projects, exploration, maintenance CapEx and enhancements for operating power plants and enhancements 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 25, which presents our revenue forecast for 2012. We increase our 2012 Product revenue guidance to between $175 million and $180 million. We expect Electricity Segment revenue to be approximately $325 million. And in total, approximately $0.5 billion of revenue. In closing, we are pleased with the steady improvement in revenues and operating costs. While federal support in the renewables sector in the U.S. is unclear, we are confident that the strong fundamentals and successful track record in both segments will enable us to continue with our plans in the global geothermal arena. I would like to thank you for your support and open the call for questions. Operator?

[Operator Instructions] Your first question comes from the line of Carter Driscoll of Capstone Investments.

I guess I was hoping you could elaborate a little bit about the incident that occurred at North Brawley and potentially any impact on the generation equipment, whether anything had to be specifically replaced because of that? And then maybe comment on the outlook of reaching EBITDA breakeven? Maybe you could project when you think you may or may not do so? Whether you potentially might have to take an impairment charge similar to the evaluation you did at OREG? And I have a follow-up.

Yes, it's Yoram. It was a fairly strong earthquake in the Brawley area, and it just tipped the plants off-line and affected the performance of some of the wells. It was actually the second of relative strength this year, and it is -- all our geothermal plants or all the geothermal power plants don't like to be taken off-line abruptly. So there's cleanup and repair that needs to happen after that, and the recovery takes a few days. When it happens during the peak season, this is damaging, and it carries with it more costs. So nothing dramatic but certainly an upset when it comes to generation and some costs. In terms of breakeven, we think that we are very close. We're really expecting to be at that point in the third quarter. There's a good chance for the fourth quarter, but fourth quarter has substantially lower rates because of the time of delivery structure of the PPA. So a hiccup can move us in one way or the other, but we're very close. And if we continue with our -- with, really, the very good progress that we've made on increasing run life of pumps and the rest of the equipment, we think that the project will turn the corner soon.

Okay. Got it. I was just going to say -- so you think -- absent the earthquake, you would have approached breakeven this quarter, you believe? Is that correct, if I heard you correctly?

Yes. But to me, to be perfect or not -- maybe not perfect, but to be more precise, it's really 3 issues -- or 2 issues. The one is that we had the earthquake. The other is that we had to shut down 2 of our better producers during the quarter to do some work on them. They're back online, and they're performing well, but we lost substantial generation temporarily from those. And in a quarter, in a high-revenue quarter like the third quarter, that was very painful. So anyway, both events are behind us now, and we hope that we won't have to repeat neither.

And then just my follow-up, and I'll get back in the queue. The Israeli solar projects, those no longer are being counted as part of your future potential. Can you talk about just the permitting becoming too onerous? If you could help us understand why you don't see them contributing to revenue anytime soon, that would be helpful.

It's just that, I guess, the fact between an IPP and the regulators or the state. The fact is that the state provides very transparent permitting process with a clear start and a clear end and a clear pricing. The IPP can factor this into his plans. And unfortunately, this has not been the case. And this happens. This is not specific to Israel. It happens in many places. But this has not been the case. And so this doesn't mean that the projects will not get built, but it means that we cannot say at this time what the timing will be. And this was really coupled with the fact that there were changes in the feed-in tariff. And again, as a developer, we need to know -- we know what the risks -- what are the risks that we're taking, but some risks have to be taken off the table to determine that we push ahead with the project, and we just can't do this at this time. So in order not to cloud our reporting, we don't want to keep projects that, at this point, we don't know when we'll build them. And as soon as we'll have -- hopefully, we'll have better predictions at some point, we can put some of them or all of them back on our list.

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

A couple of quick follow-ups. First, on North Brawley, Yoram, I didn't catch this. Have you guys restarted the drilling program there to add producers, or is that still awaiting permitting?

So there are 2 elements. There's -- in the original North Brawley field, we have the ability to drill. It's not -- we need administrative permits but nothing major. Drilling in what we used to call the East Brawley project, we cannot yet do. There's still some permitting work or clarification that needs to be done. But in terms of actual targets, we have identified a good target about this time last year, so we drilled that well just around -- just somewhere between -- starting in 2011 and completed in 2012. And this is based on our seismic interpretation of the field. And we have been going slow in drilling additional wells based on this interpretation because we wanted to monitor the results. So far, we're very happy with the result of the well. The question that we need to answer to ourselves is whether the well is good in isolation from the rest of the wells or whether the well is actually a net contributor when all the other wells are operating. And in that sense, we're very happy. Part of the work that we did in the third quarter on that well was just to confirm that it's not competing with other wells. And based on more -- and as we gather more data, we will target additional wells. As soon as the East Brawley portion opens up for us, it certainly will allow us to step up some of the activity, again, most of it based on geophysical and other geological work that we have done in the last years.

So as you talked about breakeven, that was really based on the existing wells, or was that based on -- including some of these new prospects?

The breakeven that we are hoping for is with the plant as it is, just improving the cost basis.

Okay. In your commentary, I think you said you're expecting to see almost -- it sounded like a 30% decrease in costs year-over-year from '12 to '13. Did I catch that?

Yes, correct, 33%.

And that was inclusive of D&A or exclusive?

Excluding.

Excluding, yes. You meant depreciation?

Yes. Okay, great. Okay. So that should get you a long way there. And then if you get the production as well, we could get back on -- hopefully, we can get back on track to this being a valuable project over time.

That's our hope.

Got it. And then real quick on the power purchase agreements, first of all, the $0.04 that you talked about for the 2013 lock on, I guess, on Heber or Ormesa, I'm trying to understand. Was that inclusive of the GHG benefit, or would you get the GHG benefit incremental?

Yes, it's a little over -- I like to count in dollars, but it's a little over $40, and it is inclusive of the GHG benefit with an assumption of $16 a ton. [indiscernible]

But just keep in mind that it excludes the capacity rate, so we have additional $20, $21 per megawatt-hour of capacity, so that comes to over $60.

So that will be a nice step up from what you've been receiving this year -- or somewhat of a step-up from what you've been getting this year.

Yes.

Okay. And then lastly, can you give us any color on the pricing on the Mammoth contract? Is that at all tied into -- I know you had at one point looked at doing sort of a contract swap with North Brawley, or is this a different structure? And can you maybe give us a little more color there?

So it's a different structure, and they're nicely priced above the average for the company. So they are modern contracts in terms of structure and pricing.

[Operator Instructions] Your next question comes from the line of Mark Barnett of Morningstar.

Could you update us as to whether you've submitted yet the application for a grant from that additional Brawley investment that you've made and maybe some of the timing around that, as well as potential timing for the Wild Rose grant application?

We had submitted an application for additional grants on additional investment in Brawley. We have not heard back yet from the Treasury, so we don't know. Wild Rose, we have submitted the pre-application that was required by September, I believe, but the actual application will only be submitted once the construction is complete.

Okay. And that's still TBD for next year?

Wild Rose is expected to be completed by the end of 2013, and only then we would submit the ITC cash grant application.

Okay. Just one quick further question. On the Nevada PPAs with the PUC and then you have 2 of them kind of outstanding, are you still negotiating with the utility, or are those at the stage where now you're -- those are back in front of regulators?

We're not aware of PPAs that are in front of the PUC. Which ones are you referring to?

At your 2 projects in Nevada that don't currently have approved PPAs.

Oh. So I think that on one of them, we are negotiating. We don't have a PPA yet. This is true. This is Wild Rose. And if the other one that you referred to is Carson Lake, then we're not in negotiation at this time.

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

A question. First I have a question about the Thermo 1 project in the backlog of your Equipment segment. What's the status there? Can you give us an update?

The question is how do we record the Thermo 1 project? Since we did not receive any upfront down payment and we are financing this project, we do not recognize any revenues until, call it, stability is reasonably assured. So it's kind of an inventory. It's not recorded as revenues yet.

But did you finish the project itself, or is it still ongoing?

No, it's still under construction.

Oh, okay. Got that. And next is just about your solar projects. Do you have any other potentials for solar project in the U.S?

Not currently, no. I mean, there is the Heber Solar project, the 10-megawatt Heber Solar project, but no pending projects beyond that.

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

Back for a few more questions. First, I noted that you actually gave some forward look at 2013 CapEx for the projects under construction, so I guess that's Heber Solar, Wild Rose and Olkaria III. When you think about 2013 -- and I know it's a little bit early -- it looks from the outside like you'll see a pretty significant reduction in your overall capital spend. Is that your current expectation as well?

The number that appears on the slide is just the CapEx for the projects that are currently under construction, and this is the amount of CapEx that will be required in order to complete them. But you are right that our expectation for 2013 is lower CapEx budget than we have seen in the last few years. But it's too early to say how much it is.

Okay. So I guess the follow-on question is to the extent that you are generating free cash flow next year rather than investing more than you produce, how do you think through what you might start doing in terms of cash flow generation? Whether that would be used for debt reduction or potentially increasing the dividend or something like that, or are we a little early in thinking about that?

Yes, this is probably a little early in thinking, but definitely, debt reduction. And you have to understand that our level of dividend is quite -- dividend distribution is quite limited. We have covenants that limit the level of dividends that we can distribute. So debt reduction is probably a better use for excess operating cash flow than dividend.

No problem. Real quick on the Product side. Obviously, we saw a bit of a tick-down in margins from what we've seen in the past. And we know margins are lumpy, but I was just wondering, were there any specific projects of different margins that flowed through this quarter? And this may be indicative of a little bit of a different margin structure looking forward?

Dan, you're talking about the Product Segment, right?

Yes, I'm talking about Product, correct.

I think we have said probably on more than one call that a normal level of gross margin is between 20% and 25%. It is true that from time to time, we have a bump and we are able to exceed a higher margin. But I think that the normal level is what one should assume on a go-forward basis.

Okay. Real quick on OREG, the rationale for the impairment -- was this one of the ones where, perhaps, the pipe that it's connected to just isn't being utilized that much and there's not sufficient waste gas? Or is this one where it was an issue with the plant? Or is there some other issue that we should be thinking about?

No. It's just that the load through pipeline has been low, and without heat, we just can't make the power.

Got it. And then last thing, because no call should go on without it being asked, anything worth discussing on Sarulla this quarter?

I was waiting for it.

I couldn't let a call go without asking.

There's no news on Sarulla to report. If my memory serves me right, I said on the Analyst Day that I expect Sarulla to get to the signing of the various agreements that will enable us to move to the next phase before the end of the year. We are still expecting it, but as time goes by, the end of the year is behind the corner, but we are still expecting it.

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

Just a question on the regulatory front. Now that President Obama has been reelected, domestically, which of the programs you think has been most helpful? I mean, it doesn't seem like 1603 has any chance of being revived. But maybe you could talk about the PTC or your expectations or hopes of which of those programs domestically might aid in continued financing of some of the projects.

Not to sound like a broken record, I will repeat my belief that the long-term program, the one that was the most effective for the renewable energy industry is the RPS. It is not a federal program. It is a state program. But this was the most effective program and the one which had a long-term visibility. And the one thing which is very important is the predictability of the long-term feasibility. Not to say that the 1603 was not beneficial for the industry, but we knew from the beginning that it has a limited life that the budget cannot support this incentive for a long period of time, and I think it's done a lot for the renewable energy industry.

At this time, there are no further questions. I would like to thank everyone for joining us for today's call. You may now disconnect.