Ormat Technologies Inc (ORA) 2018 Q3 法說會逐字稿

Good morning, and welcome to the Ormat Third Quarter Earnings Conference Call. (Operator Instructions) Please note that this event is being recorded.

I would now like to turn the conference over to Rob Fink of Hayden IR. Please go ahead, sir.

Thank you, operator. Hosting the call today are Isaac Angel, Chief Executive Officer; Doron Blachar, 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 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 estimates and projections, future results or trends. Actual future results may differ materially from those projected as a result of certain risk factors and uncertainties.

For a discussion of such risks and uncertainties, please see risk factors as described in Ormat Technologies' annual report on Form 10-K and quarterly report on 10-Q that are filed with the SEC.

In addition, during the call, the company will present non-GAAP financial measures such as adjusted EBITDA and adjusted net income attributable to the company's stockholders. Reconciliations to the most directly comparable GAAP measures and management's reasons for presenting such information is set forth in the press release that was issued early this morning as well as in the slides posted on the website. Because these measures are not calculated in accordance with U.S. GAAP, they should not be considered in isolation from the financial statements prepared in accordance with GAAP.

Before I turn the call over to management, I'd like to remind everyone that a slide presentation accompanying this call may be accessed on the company's website at ormat.com under the presentations link that is found on the Investor Relations tab.

With all that said, I'd now like to turn the call over to Isaac Angel. Isaac, the call is yours.

Thank you very much, Rob, and good morning, everyone. Thank you for joining us today. Starting with Slide 5. For the third quarter, total revenues grew 5.9% and electricity revenues grew 5.4% as new power plant, including Platanares, Tungsten Mountain, Olkaria and the 3 power plants we acquired with the U.S. Geothermal acquisition mitigated the continuous impact of the shutdown in the Puna power plant in Hawaii.

While we continue to grow our revenue, we faced some challenges on the profitability side. The Puna shutdown that resulted in no revenues but with expenses in the P&L, coupled with a larger-than-average number of production pump failures that we had to replace in the quarter and 9 months compared to the last year impacted our overall margin. Nevertheless, we delivered $75.6 million in adjusted EBITDA this quarter. Our solid continued profitability despite significant unforeseen events further demonstrates the strength and the resilience of our business model.

As a vertically integrated company, we have the unique advantage of controlling the entire value chain of geothermal development. And during the past month, we have made significant effort to expedite the commencement of the 48-megawatt McGinness Hills 3 power plant now planned for early December 2018. We expect that the contribution of McGinness Hills 3 as well as high generation and margins expected in the fourth quarter should result in strong financial performance of the electricity segment that will support our full year 2018 guidance.

Our product segment -- in our product segment, we secured new contracts during the quarter, now our backlog stands at $236.4 million, supporting our outlook for 2019.

I will turn the call over to Doron for a review of the financial results before I provide an update on our operations. Doron, please.

Thank you, Isaac, and good morning, everyone. Starting with revenues on Slide 7. For the third quarter of 2018, total revenues were $166.5 million, an increase of 5.9% from $157.2 million for the third quarter of last year. The increase was attributable to a 5.4% year-over-year increase in the electricity segment revenue and a 7.9% increase in revenue from our product segment, which were partly offset by slight decline in revenues from our other segments.

Moving to Slide 8. Electricity segment revenues increased 5.4% to $116.9 million for the third quarter of 2018, up from $110.9 million in the third quarter of 2017. The increase was due to the commencement of Platanares in September of 2017; the commencement of Tungsten Mountain in December of 2017; the consolidation of U.S. Geothermal, which was acquisition was closed on April 24, 2018; and the commencement of Plant 1 expansion project in Olkaria III complex in Kenya in June of 2018.

The increase was partially offset by a decrease in revenue at our Puna plant following the volcanic eruption on May 3, 2018. Since then, the power plant was shut down; and by decrease in generation at some of our power plants that were taken off-line for maintenance issues and enhancement as well as a decrease in generation due to the high ambient temperature and grid operators' curtailment that was required mainly due to maintenance work performed by the grid operator.

Turning to Slide 9. Product segment revenues were $48.4 million for the third quarter of 2018 compared to $44.9 million for the third quarter last year. On Slide 10, you can see that the new segment we added in third quarter of 2018 contributed $1.2 million of revenue from our storage activity compared to $1.4 million in the third quarter of 2017.

Moving to Slide 11 for a look at our total gross profit and margin. Gross margin in the quarter was 29.3% of total revenue compared to 37.7% in the third quarter of 2017. The decrease was mainly attributable to a decrease in the electricity segment gross margin.

Moving to Slide 12 for electricity segment gross margin. Electricity segment gross margin was 31.7% compared to 41.9% last year. The decrease was primarily due to a higher cost of revenue primarily attributable to the Puna power plant in Hawaii under which we recorded cost of revenue with no associated revenues due to the shutdown of the plant following the volcanic eruption. Excluding the impact of the shutdown in Puna, electricity segment gross margin was 35.3%.

The gross margin was also impacted this quarter by $3.8 million higher cost compared to the same period in 2017 related to pumps, which failed and needed to be replaced in some of our power plants. The impact -- this impact represents 3.2% decrease in gross margin. Gross margin was also impacted by revenue losses as a result of a decrease in generation mainly because of high ambient temperature and grid operator curtailments. This impact represents an additional 1.6% decrease in gross margin.

While pump failures and replacement of part of our plant and ongoing maintenance activities in the third quarter, we had higher number of pump failures, and therefore, we had higher risk-related expenses. Due to the fact that many of the pumps were replaced in the first 9 months of 2018, we project to have lower expenses related to pump replacement in the fourth quarter, and therefore, we expect that the gross margin of the electricity segment, excluding Puna, to be approximately 43% for the entire year.

Moving to Slide 13. In our product segment, gross margin was 26.4% compared to 28.3% in the third quarter of 2017, reflecting higher cost of revenue primarily attributable to the different scope and different margins in the various sales contracts we entered for the product segment as well as increased competition and reduction in margins in our contracts. The gross margin for the entire year is expected to be between 25% and 30%. Our other segments related to our storage activity reported a negative gross margin.

Turning to Slide 14. Selling and marketing expenses for the third quarter of 2018 were $8.6 million compared to $3.6 million for the third quarter last year. This increase was primarily due to a $5 million termination fee paid to NV Energy related to the termination of the Galena 2 PPA.

General and administrative expenses for the third quarter of 2018 were $13.6 million compared to $10.9 million for the third quarter last year. The increase was primarily attributable to increase in stock-based compensation cost associated with grants made in May and June 2018. The increase was also due to additional legal and auditing expenses associated with the remediation plan for the material weakness related to taxes in the fourth quarter.

Turning to Slide 15. Operating income for the third quarter of 2018 was $25.9 million compared to $44 million for the third quarter last year, a decrease of 41.1%. The decrease in operating income was attributable to the decrease in our electricity segment gross margin, the $5 million termination fee of Galena 2 PPA and the increase in general and administrative expenses.

Turning to Slide 16. Operating income attributable to our electricity segment for the third quarter of 2018 was $20.2 million compared to $37.3 million for the third quarter last year. Operating income attributable to our product segment was $7.3 million for the third quarter of 2018 compared to $7.8 million for the third quarter last year. Operating loss attributable to other segment for the third quarter of 2018 were $1.5 million compared to $1.1 million for the third quarter last year.

Turning to Slide 17. Interest expense net for the third quarter of 2018 was $18.7 million compared to $11.7 million last year. This increase was primarily attributable to the acquisition of U.S. Geothermal and the associated net interest that USG that amounted to approximately $100 million; $1.3 million of interest expense related to the sale of tax benefit, which includes the new Tungsten Mountain partnership transaction we entered on May 2018; higher interest expense as a result of the $100 million of proceeds from senior unsecured loan received on March 22, 2018, higher interest related to net proceeds from revolving credit lines with commercial banks to support our capital expenditure; and a decrease of $2.4 million in interest capitalized to projects.

Turning to Slide 18. The income tax provision for the third quarter of 2018 was $1.2 million compared to $6.2 million for the third quarter of 2017. Our annual effective tax rate excluding mainly the impact of the valuation allowance released for the 3 months ended September 30, 2018 is approximately 44%.

Turning to Slide 19. Net income attributable to the company's stockholders was $10.6 million or $0.21 per diluted share compared to $24 million or $0.47 per diluted share in the third quarter of 2017. Adjusted net income attributable to the company's stockholders, excluding the termination fee, which represented $5 million or $0.10 per diluted share, was $15.6 million or $0.31 per diluted share compared to adjusted net income of $25.9 million or $0.51 per diluted share in the third quarter of 2017, which excludes a $1.9 million or $0.04 per diluted share attributable to a onetime make whole premium paid in connection with the prepayment of OFC senior secured notes and the DEG loan.

Turning to Slide 20. Adjusted EBITDA of $75.6 million compared to $76.4 million in the third quarter of 2017. The electricity segment portion of our total adjusted EBITDA in the third quarter was 89% compared to 87% in the third quarter of 2017, which reflects our strategic focus to enhance the electricity segment portion in our portfolio. Reconciliation of EBITDA and adjusted EBITDA are provided in the appendix slide.

Turning to Slide 21. Cash and cash equivalents and restricted cash as of September 30, 2018, increased to $155.1 million, up from $96.6 million as of December 31, 2017. The accompanying slide breaks down the use of cash for the 9 months. Our long-term debt as of September 30, 2018, was $1.2 billion, net of deferred financing cost, and its payment schedule is presented on Slide 22. The average cost of debt for the company is 4.9%. Our net debt as of September 30, 2018, was just under $1.1 billion.

Turning to Slide 23 for an update on new financing. We announced last week that we completed the closing of Tranche I under the finance agreement totaling up to $124.7 million with OPIC for the financing of the 35-megawatt Platanares geothermal power plant in Honduras. Following the closing, we received a disbursement of $114.7 million, representing the full amount of Tranche I of the OPIC nonrecourse project finance loan that carries a fixed interest rate of 7.02% per annum with a maturity of approximately 14 years. The closing of the second tranche of up to $10 million is expected during the first half of 2019. The proceeds of the loan will be used to repay revolving bank credit debt.

And finally, on November 6, 2018, Ormat's Board of Directors approved payment of a quarterly dividend of $0.10 per share for the third quarter of 2018. The dividend will be paid on December 4, 2018, to stockholders of record as of close of business on November 20, 2018.

That concludes my financial overview. I would now like to turn the call to Isaac for an operational and business update. Isaac?

Thank you very much, Doron. Starting with Slide 25 for an update on operation. Starting with an update on Puna. The lava flow now appears to have stopped and the volcano level was officially lowered on September 5, enabling us to initiate key steps that will ultimately bring Puna back online. This is expected to be a long process but we are moving rapidly.

As a priority, our team has begun to process of building a new access road to the plant. We are working with HELCO, the local utility, to build a new electrical substation as the prior one was consumed by the lava. Additionally, efforts to remove the plugs from the production wells and to open the monitoring wells have begun. In part to this work, we are in negotiations with the insurance companies regarding the reimbursement for loss of profit and damage to the property.

Turning to Slide 26. Power generation increased in the third quarter by 7.1%, primarily to the commencement of our Platanares and Tungsten Mountain power plant and Olkaria III Plant 1 expansion. Additionally, the consolidation of Neal Hot Springs, San Emidio and Raft River power plant contributed to the increase in generation.

The increase was partially offset by the impact of the Puna shutdown, as Doron mentioned, by decrease in generation that some of our power plant that were taken offline to address maintenance issues and enhancements as well as a decrease in generation due to high ambient temperature and grid operators' curtailment.

Turning to Slide 27. As of November 1, 2018, our product segment backlog was approximately $226.4 million. We secured 2 new contracts in Turkey, and we expect that our solid backlog will support revenue for 2019 and beyond. We are closely monitoring the developments related to the economic situation in Turkey. And while we are continuing to progress as planned with the signed contracts under the backlog, the economic situation might impact our backlog and future pipeline. We are encouraged by the opportunities in pipeline for the product segment from regions such as New Zealand, Central and South America and Asia Pacific that will diversify our client base for the product segment.

Turning to Slide 28. We are continuing with our growth plans and pleased with the growth we achieved from the beginning of the year, bringing our total portfolio to 862 megawatts, and we are on track with our near-term growth target and plan between 115 and 125 megawatt by the end of 2020.

During the past month, we made significant efforts to expedite the commencement of the 48-megawatt McGinness Hills 3 power plant now planned for early December 2018. We are also planning to enhance the upper Steamboat complex in Nevada, which will include Steamboat Hills and Galena 2 power plant. At Steamboat Hills, we expect to add over 16 megawatt to the existing power plant before the end of 2020 by adding new equipment and optimizing the geothermal field. The additional capacity from Steamboat Hills will also be sold to SCAPPA under the existing portfolio PPA. In Galena 2, we opted out the PPA with NV Energy, and beginning in March 2019, we will start selling power to SCAPPA under the portfolio PPA at $75.5 per megawatt hour, replacing lower pricing under the Nevada Energy PPA.

Having the same offtaker for both Steamboat Hills and Galena 2 will enable us to optimize the resource and improve future generation for the upper Steamboat complex as a whole. In addition to McGinness Hills and Steamboat Hills, we are continuing our work on Tungsten Solar, which we plan to complete in Q1 2019 and additional prospects to support our near- and long-term target.

Turning to Slide 29. We also continue to make progress in energy storage activity. As a reminder, during the second quarter, we broke ground on 2 20-megawatt-hour utility scale in front of the major energy storage system in New Jersey. Construction is ongoing, and the first system is expected to be operational in the fourth quarter of 2018 and the second system in the first quarter of 2019. These systems will be utilized to provide ancillary services to assist PJM, a regional transmission organization, in balancing the electric grid and will also be available as a capacity asset.

As a reminder, this new initiative for us, we expect that revenues and expenses will fluctuate over the next few quarters, and it is likely to take several quarters to reach a point where this business will be profitable and stable.

Turning to Slide 30. Our estimated capital need for the remainder of 2018 include approximately $22 million for construction of new project and enhancement of our existing power plant; in addition, we estimate approximately $27 million to be invested in maintenance CapEx, storage activity and in our production facility.

In the aggregate, we estimate total capital expenditure of approximately $49 million for the remainder of 2018. We also expect $19 million for long-term debt repayment and $50 million for revolving bank credit repayment.

Please turn to Slide 31 for a discussion for our 2018 guidance. We are reaffirming the full year 2018 guidance and expect electricity segment revenues to be between $500 million and $510 million. We expect product segment revenues to be between $190 million and $200 million, and revenues from energy storage and demand response activity to be between $8 million and $12 million. As such, our guidance for total revenue is between $698 million and $722 million.

Our 2018 adjusted EBITDA guidance is expected to be between $370 million and $380 million for the full year, assuming successful resolution for our insurance claim related to the losses of Puna by the end of 2018. In the event that we don't reach a resolution of our insurance claim by the end of 2018, the 2018 adjusted EBITDA might be negatively impacted by approximately $20 million. We expect annual adjusted EBITDA attributable to the minority interest to be approximately $30 million. This amount includes our partner shares in the EBITDA related to the insurance claim for the Puna power plant.

As we move past the exceptional situation in Puna, I'm confident in our unique business model and our diversified global portfolio that positions us to continue and deliver profitable growth.

And this concludes our prepared remarks. Now I would like to open the call for questions. Operator, please.

(Operator Instructions) And our first question comes from Jon Windham from UBS.

I want to ask about -- obviously the gross margins were lower than typical. Based on the release, I would estimate 1/3 of that is related to Puna. I was wondering if you could -- wonder if that's about right is the first question. And then two, how would we roughly approximate the incremental gross margin as between maintenance and the curtailment? And then I'll have a follow-up after that.

Jon, it's Doron. First, we did add that the 9 months -- the 3 months revenue gross margin electricity revenue, excluding Puna was 35.3%. That's about 3.6% higher than what we had so this is excluding Puna because accounting wise, although we're not recording any revenues, we are still required to record a big part of the expenses. Actually it has not only now the positive effect but the negative effect on the gross margin. In addition, Q4 is a winter, is a cold quarter compared to Q3, which is summer. And we estimate the annual gross margin for the electricity to be about 43%.

Okay. I guess, the other question I would have was, did I hear you correctly when you seem to be implying or saying that the increased maintenance expense on pumps would be offset by lower maintenance expense in the fourth quarter? Did I hear that correctly?

Yes, in the first -- in this quarter, we had 3 -- compared to Q3 of last year, $3.8 million higher maintenance cost. And we see the quarter progressing, we are already one month and a week into it, we expect a lower, a significantly lower maintenance cost in Q4.

Okay. And just last question. Any comments around what drove the curtailment? And what specific markets those were in?

The main curtailment was done because of our request from NV Energy to connect McGinness Hills faster than planned next year. And the actual works that they were done actually curtailed McGinness 1 and 2 for quite a significant time, which costed us about $3 million -- sorry, $600,000.

And our next question comes from Noah Kaye with Oppenheimer.

So just to follow up on that question around curtailment. I want to make sure I heard you right that it's related to some ongoing construction work and upgrades around those plants. There's no other reason for curtailments like too much of renewable energy or anything like that on the grid. This is purely kind of a construction issue? Is that correct?

Noah, the 2 major curtailments which happened one in Nevada and the other one in the Imperial Valley, were connected with the direct Ormat power plant interconnection to the grid. And one of them, as I mentioned, was -- the interconnection that was built because of McGinnis 3 and the other ones, a specific issue with an interconnection point in Imperial Valley. And those were the major things that made a huge difference comparing to other third quarters. We have curtailment but they're not usually significant on yearly basis. Unfortunately, in this particular quarter, we had some kind of a 3 or 4 curtailments that happened in one single quarter, which affected negatively. But as usual, we have curtailment because, as you probably know, because of maintenance issues of transmission lines and so forth.

Okay, that's helpful. And then, Isaac, you talked about working to diversify the product backlog. If we could just sort of level where things are at right now. Of that $226 million backlog, roughly how much is for Turkey and what's for other geographies? You can, sort of, ballpark it for us.

I'm not sure that we are actually breaking down the backlog quarter-after-quarter. But in order to give you some more color in this particular quarter, we still have the significant part of this sector coming from Turkey. I would say, more than 50%. But the bright side is, we also have backlogs coming from the Philippines, potential -- no, it's not a potential to the ones that we have already. We have New Zealand and we have other countries. But as I mentioned during the conference call, we are worried on the financial development in Turkey even though somehow, the currency exchange rate that blew up a few weeks ago is going back to normal. Our main concern is if our customers that are obviously financing their power plants will be able to finance with the same rates that they were financing before. So that's what the reason for the remarks saying that for the future, we are increasing for -- trying to diversify faster our markets around the world, so we will be able to compensate if and when there will be some kind of a slowdown.

Okay, great. And then maybe last one for me. First of all, congratulations on closing the OPIC loan. Great to see. At your Investor Day, you talked about all the opportunities in emerging markets, Ethiopia, Egypt, many other areas where there's resource and clearly a need for power. That -- those geographies, if I look at what you're thinking about adding between now and 2020, that doesn't really seem to be contributing. It seems like most of the projects that come online are North America. Has anything changed in terms of how you're thinking about development, prospects or financing or cadence? How should we think about some of those geographies and the project pipeline there working its way into the portfolio?

Okay, Noah. as I mentioned before, first of all, as you know, you very well know that the geothermal development takes time. And as a matter of fact, we have a prospect, as we speak, in Indonesia and which we are developing. And we are continuing with our effort in Ethiopia. The reasons for the delay was mainly financial issues dealing with how to repatriate the funds that we will get in the country. And this was the main thing that was delaying the final signature of the PPA, which I hope will be solved soon. So if we are talking about the geographies that we discussed then which are mainly Indonesia and Ethiopia. I want to believe that we are on track on those projects. On the other hand, I also discussed about projects in Central and South America. And as you very well know, we come online with the project in Honduras. And I already -- and I also said during one of our last calls that we have additional prospects in Honduras. So this is also one of the countries that we are focusing and we will continue to focus. But there's nothing wrong also in the domestic development that we are building. I am optimistic that we will come up with new announcement also in the U.S. And don't forget that we still have to develop and deliver the 185 megawatts to SCAPPA, which we are on track as we speak. And another focus that we are putting a lot of emphasis on is the enhancements of the existing power plants. If I remark that Steamboat Hills is being -- as we speak, actually being, I don't know if you know the complex, it's the complex with 4 power plants. And we are trying to build them as -- we are trying to enhance them and operate more efficiently with the resource. We have more power plants in the same situation, which are complexes, and also in Imperial Valley and we are planning to do the same. And so development in the company is continuing as planned, and as I said, we will be hitting our numbers both on this particular year and also in the upcoming years by means of megawatts and so on. So unfortunately, we had this Puna issue and we had few other issues that concentrated in this particular quarter. But as the management, we are optimistic and we are on track on what we discussed during the Analyst Day and beyond. Sorry, it was a quite long for a short one.

No, I really appreciate the color. I think my takeaway here is, there is more announcements potentially from both international and domestic. So thank you for that. Appreciate it.

And our next question comes from Paul Coster from JPMorgan.

This is Mark Strouse on for Paul. So understand there's still a lot to be learned about the Puna facility. But now that the lava has stopped flowing, can you just kind of give your latest thoughts of how long it might take to get that plant back up and running?

Okay. Paul (sic) [Mark] As we all know that the lava stopped the situation, the emergency situation was lowered. And as we speak now, we are building -- the bulldozers are basically building the access roads to the power plant. Our operators are already in the [conference] in the last few weeks and trying to fix things. The next steps are building the substations together with HELCO. And then we believe that we'll be in a situation to unplug the wells within the next few weeks. Our expectation today is -- but again, we will not know for sure until we unplug that the resource is untapped, and we are not expecting problems with the resource, but as I said, I have to be very careful on this thing. If everything will be okay, we will expedite. And as I said before, the first estimation was 18 months from beginning of operation, which was -- which started actually now, but we will do our best to expedite this and do it before.

Right. Okay. And then you've made now the decision to transition the Galena 2 PPA. Paid a $5 million termination fee this quarter. Can you just talk about the payback period for that under the new PPA? How long will it take to recoup that expense?

It's a very -- look, it's a very fast payback between 2 to 3 years. So for us, it actually has more than 1 bonus on it because one thing is straightforward, it's much better paying PPA, very much lower. But the second thing is, there will be -- in the current situation it -- selling electricity to 2 different utilities using and utilizing the same resource. And now, after March 2019 basically, we will be selling -- consolidate upper Steamboat into one power plant and we'll be selling to one utility. And by that also, we will utilize much better and much more efficiently the resource. So it's a very, very good resource.

And our next question comes from Gerry Sweeney with Roth Capital.

Doron, I think you mentioned gross margins in the electricity segment hitting 43% for the full year ex Puna. I think Puna was about a drag of $7.5 million in the first -- in Q2, $4.2 million in Q3. What's the run rate on the Puna drag in fourth quarter and then into next year? Are we going to see this, sort of, trend down or will that stabilize?

On the revenue side, until the power plant doesn't come online, we will not see any revenue.

But I mean that on the expense side? Sorry, go ahead.

Yes, all the expense side, we obviously continue to see the depreciation, accounting wise we cannot stop the depreciation as well as additional expenses in the range of $1 million to $2 million that we still have. Once we finalize the discussions with insurers, the expenses of the gross margin -- on the cost of goods will be only the depreciation, and all the revenue that we will get basically the business interruption part will be recorded as part of the operating but other income, not as part of the gross margin.

Okay. And if it's been business interruption. I mean, I think you -- let me take a half a step back. You mentioned or in the presentation that potentially up to $20 million of insurance proceeds in the fourth quarter, if you finish negotiations with the insurance company. Is that $20 million all you could get for business interruption? Because I'm under the impression business interruption would have been for a full year or there's certain limits. Maybe can you discuss those potential limits on the insurance, and if $20 million is the max you can get on that?

No, $20 million is the amount that we expect to get this year for 2018. And once we pass 2018, we'll still continue to collect the business interruption for 2019 until the power plant comes online.

Is there a max amount of insurance that -- is there an insurance limit on that business interruption?

There is an insurance limit on the business interruption plus the property damage, combining the 2 of $100 million. So the substation and the monitoring wells, this is part of this insurance today based on the damage that we know today to the substation, the monitoring well, this is maybe gets close to $10 million. So I don't think that when you look on the BI, instead of 18 months from when we started working, we don't see that the BI would run out -- the BI insurance would run out as long as there's no additional damage to the property.

Okay, great. That's helpful. And then just switching gears a little bit. I know you've closed the U.S. Geothermal acquisition a couple of quarters ago. I know one of their assets, I think, San Emidio II was an undeveloped field, and the HTM or U.S. geothermal have talked about there being some potential in that field. Have you dug further into the assets? And what are your thoughts on just the overall acquisition? And is there some upside to it in terms of expanding fields, et cetera?

I will start and Isaac can follow on. Just one thing, in our call on the insurance, we said, we're negotiating with the insurance company, so this is obviously until we finalize with them. This is our expectation. San Emidio Phase 2 is a prospect that Geothermal has the very high hopes to. We're also seeing that it is a viable prospect with our -- the reading there. And the rest of the power plant geothermal is coming online, generally speaking, as we expected, maybe a little bit behind is what we expected. We thought that the power plants would be in a bit better shape, and we're doing a little a bit more maintenance today to them, to get them to the run rate that we expect. And we said in the past that in 2019, we expect them to be a regular part of our power plant suite.

And our next question comes from Jeff Osborne with Cowen and Company.

Just had 2 quick ones here. On Nevada, just with the valid measure today, possibly going to 50% renewables, can you just touch on beyond San Emidio II, which you just addressed? What other sites you have without PPAs that could be developed?

First of all, it's a very good news, of course, if this will happen, and there would be -- with California going to 100% in 45% and Nevada going into 50%, obviously, there will be serious room for geothermal in both states. And obviously, we already have a couple of ones so it's not an issue. But we are -- as I said before, we are expecting and hoping and we are optimistic that we will have more PPAs in both states. And obviously, there's not something that a sign that I can talk about it right now. But again, the fact that this RPSs are as they are now, it will add value to our business in the future.

I guess, what I was getting at, do you feel comfortable with your land position given most of your sites were signed with SCAPPA? My impression was that you didn't have that many undeveloped sites in Nevada to leverage the developments in California and Nevada, but maybe I'm wrong.

Yes, Jeff. I don't know exactly how many acres we have, but I already mentioned in one of the earlier calls that we are pretty much a real estate company. And we have lots of land bought in Nevada and California. And we are expediting, as we speak, our greenfield exploration.

Good to hear. And is there any risk just with the NV Energy $5 million fee for the breakup of the contract? Is there any animosity between the 2 parties if they're forced to buy more power from you in the future?

No, not at all. It was done on mutual understanding. They are very clever and smart guys that they exactly understood. And today as it stands for them the remaining of the contract represented a certain amount of money. There was a negotiation and it was obviously closed in a very good space between both companies. We are in a very good position with them.

Excellent. The last one I had is just can you touch upon the strategy on storage? So you've got these 2 20-megawatt projects, one in the fourth quarter and one in the first quarter. Obviously, the largest of that size that you've done. Do you want to execute on those before adding to the development pipeline? Or maybe just touch on the plan for the second half of '19 or mid-'19. Is there anything that you've won? You don't have to be specific, but I just want to get a sense of do you need to validate your EPC capabilities first before adding to the pipeline? And maybe that comes along in a few quarters from now or is there already a very robust pipeline behind these 2 projects ready to go?

Jeff, we only have actually 3 projects that are going to be online very soon. We have the fourth one, I think, we already talked about also. And on top of it, if you recall, we had a Rabbit Hill project that was on our 10-K 2 years ago with advisory company, Alevo which has an issue. And eventually, we are continuing the project and it will be also online sometime during 2019. And beyond that, we have additional pipeline both in California and in other states. And -- but as I said in my -- in the call, we are relating -- we restructured the whole storage thing, and we are relating to it as a startup running and building itself, which means that we are investing into it, but from the P&L point of view, it's not going to be stable. I mean, this is being built so it will take a few quarters until -- no doubt that it's not going to happen in '19 by means of, okay, we are making lots of money on that. It's not the case. We all realize, the management and the board that this thing needs nurturing and investing, and it will take time until those investments will return profitable. So we put it aside as a third statement just to show you that we are serious about it. The numbers are very insignificant at this time, but we will altogether see that they are picking up and will be significant within the upcoming few years.

And our next question comes from Ella Fried with Leumi Bank.

Firstly, I would like to check due to the quality of the line. Did you say that you expect the gross margin for the year to be around 43% or I didn't hear you well?

Yes, our estimation is that the gross margin for the whole year of 2018 will be electricity, of course, will be around 43%.

Okay. So I have another follow-up question. What would you say -- what do you expect to be the existing portfolio's gross margin in steady-state, let's say, in the next 4 or 6 quarters without the addition of McGinness? Just the existing portfolio and USG integrated into it.

The electricity segment gross margin, if we put aside this quarter and put it aside as a single quarter, is going up. And if you'll recall in our Analyst Day, we said that we are striving to go into 45% -- to over 45% gross margin within the next 5 years. This was 2 years ago. So we are pretty much close to this number. And by introducing, as you rightly said, new power plants such as McGinness 3 and Olkaria -- last Olkaria power plant and more, I'd say, brownfield enhancement, which are helping to increase the gross profit, though I should say that we are on our track to be between 45% to 50% by 2023.

Okay. And then you don't expect the existing situation to slow down significantly this progress, like 2 quarters, 3 quarters? You actually expect, in the next 2 quarters, a pretty steady recovery of the existing portfolio or gross margin, if I understand you right.

Yes, you're right. If we put aside the Puna thing, which as Doron explained to Jay a few minutes ago, that it is a particular situation that we don't have revenue but we have the expenses, which is changing the number itself. Then on a normal -- yes, yes, you're right, we are expecting the electricity gross margins to be stable. The differences between summer and winter, of course, don't forget that the summer, the very warm summer months obviously, the generation goes down. But in the yearly calculation, we expect that it should hit the numbers if we expect.

Okay. And another question concerning -- also a follow-up question concerning the emerging markets mainly Ethiopia but not only. How would you define, for instance, for Ethiopia or this kind of risk profile, the net yields that you are looking at in order to invest in a significant project there, net of finance, because the [auditor] and the question is, of course, coming from yields going up and emerging markets' yields going up. So what would you find lucrative net yield in this kind of profile risk project?

Ella, as we already discussed before, and I will repeat it. As you know, in development in the U.S., looking on high teens, equity IRR and almost on the -- I said low or high?

High.

Sorry, in the U.S., looking into low teens IRRs and elsewhere with the different risk, like in Ethiopia, Kenya and Central American countries, you're looking to high teens IRRs. Obviously, the risk profiles are not necessarily the same but don't forget that we have loss of remediation on the risk side, which is obviously a financing through place like OPIC, OIG or others. We are playing political risk and [influential] risk and so on, which means that it's not only the IRR, but we also trying to mitigate the risk by additional things that we're doing, as I said before, through financing and others.

And this concludes our question-and-answer session. I would like to turn the conference back over to Isaac for any closing remarks.

Guys, thank you very much. It was a challenging quarter for us, but as I said before, we are -- our numbers are robust and we reiterate our guidance for the whole year of 2019. And thank you very much for your ongoing support.

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.