Good morning, and welcome to the Ormat Technologies Second Quarter 2021 Earnings Conference Call. Please note this event is being recorded. I would now like to turn the conference over to Rob Fink of FNK IR. Please go ahead.

Thank you, operator. Hosting the call today are Doron Blachar, Chief Executive Officer; Assi Ginzburg, Chief Financial Officer; Smadar Lavi, Vice President of Corporate Finance and Investor Relations. Before we begin, we would like to remind you that the information provided during this call may contain forward-looking statements relating to current expectations, estimates, forecasts and projections about future events that are forward-looking as defined in the Private Securities Litigation Reform Act of 1995. These forward-looking statements generally relate to the Company's plans, objectives and expectations for future operations 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 risks 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 reports on Form 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. Reconciliations to the most directly comparable GAAP measures and management's reasons for presenting such information are set forth in the press release that was issued last night as well as in the slides posted on the website. Because these measures are not calculated in accordance with 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 would like to remind everyone that a slide presentation accompanying this call may be accessed on the Company's website at ormat.com under the Presentation link that's found on the Investor Relations tab. With all that said, I'd now like to turn the call over to Doron Blachar. Doron, the call is yours.

Thank you, Rob, and good morning, everyone. Thank you for joining us today. This was a productive quarter for Ormat, as we are progressing with our plans to grow our Electricity and Energy Storage segments. The quarter was highlighted by execution of our organic and M&A growth strategies. We completed the expansion of the McGinness complex in Nevada, with higher generating capacity than originally planned, and made significant progress ramping up generation of the Puna plant in Hawaii. Simultaneously, we closed a significant acquisition of two operating power plants and two other assets that should contribute to our future growth. In the Energy Storage segment, we continue with our efforts to secure new interconnection and land positions to support our pipeline, and we recently released two storage assets for construction. The progress in our growth reinforces our belief that we can achieve our stated goals of increasing Ormat's combined geothermal, energy storage, and solar generating portfolio to more than 1.5 gigawatts by 2023. While we continue to view 2021 as a buildup year in which we lay additional groundwork to accelerate our growth, the increased backlog and sales pipeline, along with the regulatory tailwinds and significant portfolio growth coming from our Electricity and Energy Storage segments, support our target of an annual run rate of more than $500 million in adjusted EBITDA towards the end of 2022. I will turn the call over to Assi to review the financial results before I provide further update on our operations and future plans. Assi?

Thank you, Doron. Let me start my review of the financial results on Slide 5. Total revenue for the second quarter was $146.4 million, down 16% from the prior year. The driver for the decrease was the product segment, which was impacted by low product backlog. Second quarter 2021 consolidated gross profit was $52 million, resulting in a gross margin of 35.4%, which is 200 basis points lower than in the second quarter of 2020, mainly driven by the reduction in the Electricity segment. This quarter, we experienced mostly temporary issues related to the Olkaria, Steamboat, and Brawley complexes. These issues reduced our Electricity gross profit by approximately $8 million. For the six months, gross margin was 40.1%, similar to the same period last year. We delivered net income attributable to company stockholders of $13 million, or $0.23 in the quarter, compared to $23 million, or $0.45 per share for the same quarter last year. Our effective tax rate for the second quarter of 2021 was 22.6%, which is lower than the 33% effective tax rate from the second quarter of 2020, mainly due to the movement in the valuation allowances for each quarter. We now expect the annual effective tax rate to stand at approximately 33% for the full year 2021, assuming no material onetime impacts. Adjusted EBITDA decreased 13.6% to $84.5 million in the second quarter, impacted mainly by gross profit reduction and higher G&A expenses driven by increased legal costs. Moving to Slide 6, breaking the revenue down. Electricity segment revenues increased 4% to $134 million, supported by contributions from new added capacity at our Steamboat and McGinness Hill complexes as well as Puna resuming operation. As Doron mentioned in the opening remarks, this new added generation was offset by lower generation in Olkaria due to a combination of lower resource performance that caused the capacity reduction and continuing curtailment by our local customer, KPLC. In addition, our Steamboat complex had a mechanical issue that was resolved a few days later. And in Brawley, we experienced a surface leak in one of the injection wells, which reduced generation. In the Products segment, revenue declined 83% to $7.4 million, representing 5% of total revenue in the second quarter. The decline year-over-year is expected to continue throughout '21 due to the lower backlog from the beginning of the year. Energy storage segment revenues increased nearly 124% year-over-year to $5.6 million in the second quarter, representing 4% of our total revenue for the quarter. The growth was mainly driven by revenues from the acquired Pomona energy storage assets and the contribution of our Valecito facility in California, which started commercial operation in April of 2021. Let's move to Slide 7. Gross margin for the Electricity segment for the quarter decreased year-over-year to 37.4%. This was a result of a higher cost related to the repair of the recovery of the Olkaria, Steamboat, and Brawley complexes. In addition, in the second quarter last year, we did record a business interruption insurance recovery of $2.7 million related to Puna complex, compared to zero this year. In the Products segment, gross margin was 20.1% in the second quarter compared to 20.6% in the same time last year. The Energy Storage segment reported again a positive gross margin compared to a negative gross margin in the second quarter last year. The improvement was primarily driven by the acquisition of the Pomona Energy Storage assets. Turning to Slide 8. Adjusted EBITDA decreased 14% to $84.5 million in the second quarter, impacted mainly by gross profit reduction and higher G&A expenses driven by increased legal costs. The Electricity segment generated 94% of the total adjusted EBITDA in the second quarter, and the Products segment generated 4%. The storage segment reported adjusted EBITDA of $2 million, which represents 2% of the total adjusted EBITDA. Reconciliation of EBITDA and adjusted EBITDA are provided in the appendix slide. On Slide 9, our net debt as of June 30, 2021, was $1.040 billion. Cash and cash equivalents and restricted cash and cash equivalents as of June 30 were approximately $330 million compared to $537 million as of year-end. In addition, we had $46 million of marketable securities. Slide 9 breaks down the use of cash for the six months and illustrates our ability to reinvest in the business, service debt, and return capital to our shareholders in the form of cash dividends, all from cash generated by our operations and our strong liquidity position. Our long-term debt as of June 30, 2021, was $1.4 billion, net of deferred financing costs. And its payment schedule is presented on Slide 30 in the appendix. The average cost of debt was 4.9%. During July, we closed two new corporate loans, raising approximately $175 million, out of which $50 million are green bonds provided by HSBC Bank. Funds were used to finance the Terra-Gen acquisition. On August 4, 2021, the Company Board of Directors declared approved and authorized payment of a quarterly dividend of $0.12 per share, pursuant to the Company's dividend policy. The dividend will be paid on September 1, 2021, to shareholders of record as of the close of business on August 18, 2021. In addition, we expect to pay a dividend of $0.12 per share in the next quarter. That concludes my financial overview. I would like to turn the call over to Doron to discuss some of the recent developments and our growth plan for the next three years. Doron?

Thank you, Assi. Turning to Slide 12 for a look at our operating portfolio. Power generation in our power plants increased by approximately 2.4% compared to last year. In the second quarter, we see the continued contribution of Steamboat Hills that started operation in mid-2020, the incremental contribution of McGinness Hills for approximately one month, and the generation from Puna, that is operating still in partial capacity. These were partially offset by continuous curtailment and lower performance of the field at our Olkaria power plant and other operational issues in the U.S. that I will elaborate shortly. We recently completed the expansion of our McGinness Hills facility and are now providing electricity for approximately 6,000 homes, while offsetting approximately 63,000 tons of CO2 emissions, delivering the highest level of efficiency and safety in the geothermal industry. With the addition of the acquired operating assets, we are running a 1 gigawatt electricity portfolio, an increase of 83 megawatts in the second quarter. As noted on Slide 13, Puna resumed operation in November 2020. We have ramped Puna generation to approximately 28 megawatts following the repair of a turbine, up from 20 megawatts in our last quarterly report. We expect to reach 30 megawatts by year-end. We have continued discussions with HELCO and the PUC about our new PPA and continue selling electricity under our existing PPA, which is in effect until the end of 2027. Turning to Slide 14. Let me discuss some of the challenges we experienced this quarter in a few of our operating assets, and I will start with the known one in Kenya. Our revenue in Olkaria complex was down year-over-year as a result of continued curtailment and a reduction in the performance of the results. The combination of which has resulted in approximately a reduction of generating capacity of 25 megawatts. This reduction in capacity reduced our quarterly gross margin by approximately $2.7 million. We are operating to restore the complex generating capacity throughout the continuous drilling campaign in Kenya and are optimistic we will see an increase in production through and by the end of the year. We expect a similar quarterly reduction in revenues until capacity is fully restored. We also experienced a mechanical failure at our Steamboat complex, resulting in revenue loss and increased expenses that reduced gross margin by approximately $2 million. The Steamboat complex is now back to full operation. In the Brawley complex, we had a leak in one of the injection wells and a pump failure in one of the production wells that caused the reduction of the generating capacity to 3 megawatts. We are working to restore full production at Brawley. The second half of 2021 will be impacted by the lower performance of the Olkaria and Brawley power plant, and we have updated our annual guidance accordingly. Turning to Slide 15. In July, we closed the accretive acquisition of the Terra-Gen asset. This acquisition added a total net generating capacity of approximately 67.5 megawatts to our portfolio. In addition, we bought the greenfield development asset adjacent to Dixie Valley with high resource potential and an underutilized transmission line, capable of handling between 300 to 400 megawatts on the 230 kilowatt electricity, connecting Dixie Valley to California. With this acquisition, we now own 10 operating plants in Nevada, generating a total of 443 megawatts. The proximity of these plants to population centers in both Nevada and California is important. California remains at the forefront of driving the adoption of renewable energy with supportive mandates and requirements already in place and more being considered. Utility companies in California are increasingly looking for affordable and reliable renewable energy. This dynamic makes the acquired transmission line increasingly important. Turning to Slide 16 for an update on our backlog. While the result of our products segment continued to be impacted by the lower backlog at the beginning of the year, we are starting to see encouraging signs of recovery. We have seen clear signs of improvement in this business, including an expansion of our backlog, reinforcing our confidence that this is a short-term phenomenon. As of August 4, 2021, our products segment backlog increased 59% by $22 million to reach $59 million, compared to $37 million in early May this year. We signed a few contracts during the quarter, including a new contract with Star Energy Geothermal to supply products to a new 14 megawatt Salak geothermal power plant in Indonesia and another contract to supply equipment in Japan. Despite the recent improvements in this segment, we anticipate continued weakness in our products revenue during 2021 and have adjusted our annual guidance accordingly. Partially offsetting the weakness of the product segment has been a consistent improvement in our Energy Storage segment. As I mentioned earlier and as discussed at Slide 17, this business continues to become a more important part of our consolidated results. This quarter, our projects in both the East Coast and Texas enjoyed higher revenues due to higher market prices. The storage segment again generated positive EBITDA, and we released two new projects for construction in Ohio and California. Moving to Slide 18. I previously mentioned the supportive mandates being implemented in California and the increasing demand for affordable and reliable renewable energy in this state. One example is the recent ruling by CPUC requiring electric load service entities, LSEs, to procure 11.5 gigawatts of new clean electricity by 2026. 1 gigawatt of this procurement must deliver firm power with an 80% capacity factor, produce zero on-site emissions, and be weather independent. No form of renewable energy generation is more poised to fill this need than geothermal, with a 95% capacity factor and a firm and flexible generation. Geothermal energy is not only an excellent complement to intermittent resources, but the natural replacement for baseload fossil fuels and nuclear generation. California efforts to achieve its goal of 100% carbon-free electricity by 2045 through massive deployment of renewable energy and energy storage resources enable us to sign new contracts for geothermal, as we did this quarter with CPA for our 14-megawatt Heber geothermal power plant in the Imperial Valley, California. We also issued our first-ever request for bids for the 26-megawatt Heber 2 and actively look for opportunities for our storage partners. Moving to Slide 20 and 21. As we have communicated, 2021 will be a significant buildup year comprised mainly of geothermal projects. This buildup supports our robust growth plans, which is expected to increase our total portfolio by almost 50% by the end of 2023. Our medium-term goal in the Electricity segment is to add an additional 240 to 260 megawatts by year-end 2023, above the 80 megawatts added since the beginning of 2021. And in our rapidly growing Energy Storage portfolio, we plan to enhance our growth and increase our portfolio by 200 to 300 megawatts by year-end 2022. Achieving this growth target is expected to help us reach an annual run rate of more than $500 million in adjusted EBITDA towards the end of 2022 that we expect to continue to grow as we move forward with our plans in 2023 and onwards. Slide 22 displays 13 projects underway that comprise the majority of our 2023 growth goals. While we are experiencing some delays in the permitting process, we are still on track to meet our growth targets for the end of 2023. Moving to Slide 23 and 24. The second layer of our growth now comes from the Energy Storage segment. Slide 23 demonstrates the energy storage facilities we have announced or started construction. We released two new projects for construction, Bowling Green and Pomona 2. The other projects included in our growth plans are in different stages of development, and the release will require site control and execution of an interconnection agreement, all obviously subject to economic justification. As you can see on Slide 24, our energy storage pipeline stands at 2 gigawatts and currently includes 36 named potential projects, mainly in Texas, New Jersey and California. Moving to Slide 25. The significant growth in both our Electricity and storage segment will require robust capital investment over the next couple of years. To fund this growth, we have over $750 million of cash and available lines of credit. Our total expected capital spend for the remainder of 2021 includes approximately $280 million for capital expenditures, as detailed on Slide 31 in the appendix. Overall, Ormat is well positioned with excellent liquidity and ample access to additional capital to fund future initiatives. Please turn to Slide 26 for a discussion of our 2021 guidance, which has been revised to account for our recent acquisition and other development previously discussed. We expect total revenues between $650 million and $685 million, with Electricity segment revenues between $585 million and $595 million. We expect products segment revenues between $400 million and $60 million. Guidance for Energy Storage revenue is expected to be between $25 million and $30 million. We expect adjusted EBITDA to be between $400 million and $410 million. We expect annual adjusted EBITDA attributable to minority interest to be approximately $31 million. As noted in previous quarters, adjusted EBITDA guidance for 2021 includes insurance proceeds of approximately $10 million. This concludes our prepared remarks. Now I'd like to open the call for questions. Operator, if you please?

Operator Instructions. And our first question will come from Noah Kaye of Oppenheimer.

I guess to start, it looks like you raised your 2023 geothermal portfolio target size for the Terra-Gen acquisitions you just completed. And please correct me if I'm wrong. So your organic growth targets kind of remain the same there. Should we think about that roughly 250 megawatts of further additions as just being an organic target? In other words, is M&A in any part of that? Or would further M&A be upside?

Thank you for the question. The growth targets are organic. So Terra-Gen was on top of that. And similarly, if we have additional acquisitions, they will be on top of that.

Okay. Can you talk a little bit about plans for using that underutilized transmission line? What in the initial planning stages seems most likely, a geothermal expansion and new solar facility? What would make the most sense? And when might that transpire?

This is Assi. So basically, we have two options. The first option is to continue and develop more assets in Nevada, like we are planning to, and to add them and move more electricity to California with this line. Although, as we mentioned during our calls before, there is a bottleneck in control in California that will need to be taken into consideration. The second option is to allow third parties to use this line while keeping our capacity to ourselves. And that's something we're also looking into, either doing it by offering capacity to others or by joint venturing the access to third parties. I will say this is a very good asset, especially knowing the fact that the PUC now is requiring the utilities in California to increase the amount of renewable and baseload renewable in California. And that's why we think there will be a lot of demand over time. All of it, of course, is subject to permits and the ability to either increase the capacity, the bottleneck in the control area or to bypass it by using third-party lines.

Okay. That's helpful. The next question is really around operational focus. What we're trying to understand is whether there are any common threats related to the issues you mentioned, such as the surface leak at Brawley and the transformer issue at Steamboat. You've previously discussed Olkaria, and you've mentioned permitting delays for some of the new projects, which seem to have pushed the timing out a bit for a couple of them. Is there a common factor among these challenges? We've observed that many companies are facing difficulties with everything from labor availability to logistics issues. I want to understand if there is a shared challenge for you currently, what your pain points are, and how you are addressing these issues.

No. The simple answer is no. We don't see any similar trend between all of these. And you look at different states, different countries, different technologies somewhat. So I think each one has its own unique situation. Geothermal asset is an asset that we've been operating for many years and needs to be maintained and operated. This quarter, some of the items happened together. But usually, they don't happen in one, but there's no common thread to all of them. Different items in different locations. The only one that maybe does have some relation is the last one of the permitting that you said that is causing delays in projects. That's related to COVID, the fact that the BLM and the other regulators, not all of them are working from their office, so not working too much. So that's the only, I think, common denominator across projects is the permitting issue.

Okay. And I think, last quarter, you touched briefly on the independent board committee review and some of the dialogue that you're having with some of the regulators. Can you just give us an update there?

The only thing you know I can update, and I think that's quite common is that we continue to cooperate with the regulators. We don't have any time frame for this investigation. As its customer, and we can't elaborate on it until they finish what they're doing.

You mean what they, you mean the committee or what the regulators are doing? I apologize.

Both of them. The one other thing I would say is that, as you probably know, this is quite common, the fact that you cannot comment until they finish. But you should not infer anything from this anyway, okay?

And our next question will come from Julien Dumoulin-Smith with Bank of America Securities.

I wanted to start first off on California here and just talk about, one, the repricing opportunity. Admittedly, some of your peers have pointed to some of the sharpest revisions upwards in pricing in your geographies in, frankly, a couple of decades. So I'm curious, perhaps not necessarily what the status of those negotiations are, on the extent to which you have some repricing opportunities. But maybe speak to some of the near-dated contract expirations and/or any ability to blend and extend, if you will, to preemptively address some of these contract expirations in the future as well as, if you don't mind, some of the opportunities derived out of the latest transmission line acquisition in Nevada and associated geothermal expansion opportunities therein?

Thank you. I can certainly confirm what you mentioned. We are experiencing an increase in pricing and a significantly higher demand for renewable energy in California, which is also impacting surrounding states. This trend has intensified recently due to the CPUC decision and requirements I previously discussed. We are engaged in multiple discussions regarding various Power Purchase Agreements and feel much more confident in these talks now. I also noted during the call that we issued a request for bids, offering our Heber 2 complex to other utilities and MCCAs to consider. The market is shifting in our favor after a long period. Regarding the transmission line, as Assi pointed out, it is a unique asset linking Nevada to California. Currently, it leads to a control substation that is congested. We are in discussions with various transmission companies to explore ways to collaborate and make better use of this line for transferring electricity from Nevada to where it's needed.

Got it. As you evaluate the pricing across your portfolio, including the Heber complex, Steamboat, and Brady, do you perceive a net increase in pricing based on the current market conditions over time? I understand this may be somewhat short-lived, and you can't confirm it until the contracts are signed. However, I'm interested in your thoughts on repricing as you consider the future. Clearly, this won't happen immediately, but do you have any comments on that?

Okay. It's very hard because it's site-specific. I'd say some sites might enjoy higher pricing, others lower. Pressure is still not as high as in 2010 and 2012 when we signed Don Campbell for $99. That track is not coming back, I think, but it's very, very much site-specific. And also, it depends on the time that we start the negotiation and agree on the terms of the PPA as well.

Got it. Excellent. Can you update us on the situation in Kenya regarding their cost-cutting efforts? Are you having direct discussions with them about potential relief measures? Additionally, do you have any updates on the broader investigation, specifically related to the cost-cutting initiatives in Kenya?

Look we can start with the basic. The basic that we have a signed contract with the Kenyan KPLC, which is the government-owned utility company. The project is financed by DFC previously, OPIC, a U.S. government bank. And that's the basic. We have seen, in the press and in other places, discussion about trying to reduce prices. There has been a commitment set in Kenya to look at this. I think, as you mentioned, Ormat is very well looking for always to win-win situation with its customers. We're in Kenya for the long term. We've been operating in Kenya for more than 20 years, and we expect to operate there longer. We have been discussing with some of these committees that were set. Whatever we will find will be a win-win situation for Ormat and for Kenya because we do see us as a long-term player there, supporting renewable energy and, in general, the energy in Kenya. And there's always room to make agreement for both parties. Although at this stage, some discussions are over there, but it's very, very early discussions.

Could you clarify the timeline? I understand that the situation in Kenya was anticipated to take about six months. However, as you mentioned, it's still early, and the process has been ongoing for a while. Do you have a general idea of the timeline? Do you think a resolution could occur this year?

No. We don't have any sense of any timeline from them. Obviously, we are in no rush. So there's no sense of timeline. As I said, we are in very, very early general discussions that they started with us as well as with other IPPs, not targeted at Ormat, but a general discussion last month.

Got it. And sorry, just the last one here. I apologize. With respect to your storage efforts here, there's just been availability questions as people have been scaling their efforts, pricing impacts, et cetera. Any comments therein on your specific efforts underway in terms of just being able to execute on time and on budget and any material deviation?

No. Our plans that are on the presentation are on time. We have all required, spec-level required batteries. We have a long-term agreement with battery suppliers with commitments on delivery and pricing. So as long as they stand with the contract, we should be on time with all the projects as we announced them.

Operator Instructions. Our next question comes from Jeff Osborne with Cowen & Company.

Just a couple on my end. I was wondering if you could give us a walk on the old guidance to the new guidance and some of the moving parts. So you've obviously had the acquisition, and then you have the underperformance at the three sites. I was wondering if you could sort of bridge the gap of what the acquisition is adding relative to the deficiencies of the three locations?

There are two key items to consider regarding the guidance. First, the addition of Terra-Gen, which we expect to contribute $35 million of EBITDA in 2022, although we don't have the complete six months, and we will need to make some system upgrades. On the downside, we are facing challenges in Kenya, particularly in Brawley, along with significantly higher legal expenses this quarter.

So is it a safe assumption, without the acquisition, but with the legal expenses and the Brawley and Olkaria facility, the guidance would have been down or no?

If we disregard the changes in Brawley, Olkaria, and Steamboat, the projection would not have decreased, aside from the $10 million reduction in the guidance for the product segment. However, in the Electricity segment, the issues we faced were what impacted Terra-Gen. As mentioned earlier, Steamboat has already returned to full capacity, and we anticipate that Olkaria will also normalize by the end of the year.

Got it. And just a couple of follow-ups on Julien's question. So on Kenya, can you touch on the payment capability or the terms? Or are they becoming current on their past due payments?

As I said in the last few quarters, KPLC has been very good at making ongoing payments. They are actually making all the ongoing payments, but they are not making a lot of progress in paying the due payments as of the end of the year. But I will say, in general, since July of 2020, they've been making all the payments.

That's good to hear. And then can you touch on what the M&A pipeline looks like? Do you anticipate any other sizable acquisition similar to Terra-Gen in the coming quarter or two or not?

Honestly, we cannot comment on any specific M&A. I can say that we are looking at various M&A opportunities, mainly in the energy storage and storage for solar acquisition. That's, I think, the most we can say at this time.

Got it. And the last question was just following up again on Julien's question around pricing. Is there any contracts that are up for renewal in 2022 of existing facilities other than the Heber 2 RFP that you have outstanding for the September response?

I think the first one is in '23, not in '22.

And our next question comes from David Lowish with Atlas.

David here from Atlas Impact Partners. Just a quick question, if I may? Just on Hawaii and your comment about the new PPA being suspended. Can you just sort of talk me through what does that mean in terms of specific financial implications for you now and in 2022?

The new PPA that the PUC suspended included refurbishment of the existing facility that would have taken us about two years. Following that, we would have had an increase of the PPA and the generation to about 46 megawatts. We have a PPA today for 38 megawatts until the end of '27. So specifically, for 2022 and 2023, this doesn't have any impact. The suspension of the PPA might delay a year or something once it is approved. But again, the real impact is about 8 megawatts of additional PPAs.

If I may add, on the other side, David, the current prices in Puna are actually higher than the new PPA. Oil prices are somewhere between $68 to $70 right now, and therefore, what we're actually getting is revenue is more than what we would have made otherwise in 2021 and 2022. So at this point, it has a positive impact on us. And that's why we think that there is a very good reason for our customer over there to try and push this decision because it will lower the average price of the PPA. What we will get in return is more capacity on one hand and many, many more years of extension of the PPA.

Could you please clarify why the PUC has an issue with that PPA?

The PUC doesn't have a problem with the PPA. They've actually reached out to the DLNR and the local county, asking them or requiring them to see if we need to do an environmental impact study or not. The power plant is opening for many years. The PUC raised the question. We have been discussing with the DLNR and the county, and we do not think there is a need for such a study. But we also don't think this study will change the decision of the PUC because there is a geothermal power plant operating over there. The new power plant will be a newer power plant, a smaller site facility, less emission and more efficient. So actually, from the environmental perspective, it's a positive. But still, the PUC suspended that. You can ask them whether or not we need to do an environmental impact study.

Okay. I understand. Can I return to the technical issues at Steamboat and Brawley? Would you say that it is just bad luck that these issues have occurred simultaneously, or is this something that might happen regularly? How should we approach this as investors? The $8 million is significant, and while you’re offsetting that with an acquisition, it still feels like a setback. I'm trying to grasp how you view these events and what the likelihood of them recurring might be.

No, the fact that they occurred in the same quarter is unfortunate. In my eight years here, I believe we only had one other quarter, possibly in 2017, with similar mechanical issues. It is very unfortunate that both incidents happened simultaneously and at all, considering we do strive to maintain our power plants to prevent such occurrences. Having them both happen in the same quarter is just unlucky.

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

Well, I have a couple of questions left. The first one is a broader question or request to discuss, if you could, the broader look at the geothermal energy and the commercial aspect of the product segment. As the return on assets in the mainstream sectors like wind and solar has decreased in many countries, do you see the return of the product sector to the pre-corona levels like a few years ago? Or do you think it will be a very slow increase to the levels that are closer to the current levels? Or do you see the demand coming actually for the energy in general and for your product sector specifically?

Thank you, Ella. So we see a move to more renewable everywhere. We see a move to more geothermal everywhere. Over the last few months, we've seen actually a recovery in the product segment, with more projects being tendered and more developers globally trying to develop new geothermal power plants. Our backlog went up this last quarter, but also this quarter. We hope that this trend will continue when we look at the pipeline that we have and the contracts that we are tendering and negotiating today. Regarding geothermal in general, I think we see this as an outcome of the basic demand for geothermal. Any country outside of the U.S. that has geothermal potential wants to develop geothermal. This is the only baseload renewable energy. And in the U.S. we see increased demand with the CPUC requirements of 11.5 gigawatts of renewable energy. Out of that, 1 gigawatt must be 80% available, which basically is geothermal.

Only?

Yes. We see demand for geothermal increasing. After the CPUC ruling, we've been contacted by some CPAs interested in signing PPAs. This indicates a greater demand for geothermal energy. There hasn't been a change in returns for geothermal globally or in the U.S., and we are looking forward to the support from the new Biden administration act for renewable energy, which includes geothermal and the energy storage market.

So if we look at the levels of over $100 million, $120 million a year, is it feasibly possible in the next, let's say, two, three years? Or do you think it will be slower demand?

Okay. I think you need to follow the backlog. As the backlog grows, I would expect the revenue of the product segment to grow. I don't know to say now that it will reach $200 million or anything like that. We give guidance one year ahead. But the backlog increase, I think, is a good sign that will support revenue as we go into future years.

Okay. And the next question is regarding Japan. If I'm not mistaken, that's the first time actually you mentioned Japan. And I remember that you had a historical agreement with ORIX about, I don't know if it's still existent, about having priority actually in the Japanese territory. So if you could say a few words about this Japanese project that you mentioned?

The project in Japan is separate from ORIX and involves a different company. It is not a large endeavor, as most projects in Japan tend to be smaller. We have completed a few similar projects in the past. The agreement with ORIX remains active, so we maintain priority. However, at this point, we do not have any upcoming projects. If a project arises, we will have priority, and we are hopeful that we can proceed with it.

I understand. So it's essentially isolated at this stage. Now, regarding financial matters, it's a broad question, but could you discuss the development of net debt? You mentioned the resources the Company has. Can we anticipate an increase of around 15% over the next two years in this regard? Based on my calculations, it looks like there could be a rise of at least $200, if I’m not mistaken.

So Ella, this is Assi. I will answer. As of the end of the quarter, it was roughly $1 billion. We closed the transaction in July for the Terra-Gen assets for a total of $380 million. This will immediately increase our net debt to roughly $1.4 billion. Looking from now until the end of the year, we provided guidance of about $275 million in CapEx. After accounting for our free cash flow, this should lead to an additional increase in net debt of around $70 million to $100 million. Considering all this, our net debt by the end of the year will be closer to $1.5 billion. However, by that time, we will have already invested the majority of amounts. Most of the projects we are developing will commence in 2022, but significant investments for CD4, Dixie Meadow, and North Valley have already been made. Therefore, when evaluating the net debt to EBITDA, our EBITDA at that time will be about $500 million, bringing us to roughly 3x debt-to-EBITDA.

And our next question is a follow-up from Julien Dumoulin-Smith of Bank of America Securities.

Sorry guys. I have so many today, but I just want to go back to this because, at the top of the call, perhaps, you all talked about your organic targets here at the year-end '22 run rate. And you talked about Terra-Gen being incremental to that target. I just want to make sure we're crystal clear about that, right? Because you've had a number of puts and pulls, whether it's Hawaii PPA, the product segment, et cetera. I just want to be very clear that, despite the use of your balance sheet, that Terra-Gen transaction is indeed incremental to that year-end target you all approved or that run rate target you all put out there recently?

Look, the number that we said last quarter was a little bit approximately $500 million. Today, we believe it will be more than $500 million. We see more than $500 million, including Terra-Gen. Some of the delays in the permitting have impacted 2022 potential EBITDA, full planned EBITDA. So we do expect to be above $500 million. But at this time, we cannot say that the full impact of Terra-Gen will be on top of the $500 million.

Okay. I just wanted to confirm that I understood you correctly. To clarify, regarding the transmission investment you mentioned earlier, do you already own the transmission interconnect? You referred to increased interconnect costs, but you already possess this transmission line as part of the transaction. That's the key aspect here, right? I want to ensure I understand this in relation to how it will be utilized and the timeline involved.

Yes, that's correct. We own the transmission line. What we said is that this is an underutilized asset because of the control substation. Today, the only generation that can be wheeled over the transmission line is the Dixie output of a 60-megawatt PPA. We are working with other transmission companies that have approached us to see how we can fully utilize this line and either upgrade the control substation or bypassing it to other substations and connecting Nevada to California with an additional line and additional capacity. So this is an additional asset that is not utilized and the next few years will be utilized.

Got it. Just to clarify that, if the transmission interconnect into the CAISO, that's the incremental cost because you already have the transition line itself?

Yes, yes.

The added capacity is above the 60 megawatts that we have already connected to CAISO.

Julien? Hello?

Sorry. Could you hear me there?

We didn't hear you, Julien.

I apologize. It was just with respect that once you resolve the transmission interconnect upgrade cost into California, not the fact that you own a transmission line, then that will unlock your ability to scale up the capacity on site. And I suppose just to summarize that, the expectation that you will be participating in this upcoming California RFP?

I would say that there is also a way to bypass control by utilizing third-party lines. And that's why I will not say that, for sure, we will go in to try and increase the capacity of the control system. So I think this is to be discussed in future calls.

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

Thank you. So thank you, everyone. This was, as you've seen, a very productive quarter. We are continually focusing on increasing and investing in our portfolio in the geothermal and the energy storage in order to grow the business and to meet the enhanced demand that we see today in California and outside of the U.S. Thank you.

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