Ormat Technologies, Inc. Q3 FY2021 Earnings Call

Hello, and welcome to the Ormat Technologies Q3 2021 Earnings Call. My name is Robyn, and I'll be coordinating your call today. I will now hand you over to your host, Jeff Stanlis from FNK IR. Jeff, please go ahead.

Thank you, Robyn. Hosting the call today are Doron Blachar, Chief Executive Officer; Assaf Ginzburg, Chief Financial Officer; and Smadar Lavi, Vice President of Corporate Finance and Investor Relations. Before beginning, we would like to remind you that the information provided during this call may contain forward-looking statements relating to current expectations, estimates, forecasts and projections about future events that are forward-looking as defined in the Private Securities Litigation Reform Act of 1995. These forward-looking statements generally relate to the company's plans, objectives and expectations for future operations and are based on management's current estimates and projections, future results or trends. Actual 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 reasoning for presenting such information is 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 is 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, Jeff, and good morning everyone. Thank you for joining us today. During the third quarter, we completed several strategic initiatives that support our long-term position, including a sizable geothermal acquisition in Nevada, a new resource adequacy contract for our Energy Storage segment, a joint venture for exploration in Indonesia and several new product wins, providing further evidence that the COVID-related disruption in our product segment is abating. This development supports our long-term goals and furthers our efforts to expand our generation capabilities towards our goal to achieve a run rate of $500 million in annual EBITDA towards the end of 2022. Looking at the third quarter, our results were negatively impacted by operational challenges at three plants. We are making progress to resolve these challenges and expect them to gradually recover by the first half of 2022. Even with these challenges and the ongoing slowness in our product segment, we reported continued growth of more than 15.4% in the electricity segment, leading to revenue that was essentially flat year-over-year. This enabled us to deliver over $100 million in adjusted EBITDA for the quarter. We continue to view 2021 as a buildup year. The strategic acquisition of two operating plants and an underutilized transmission line in Nevada is an example of this buildup. The new long-term resource adequacy agreement with PG&E for our Pomona-2 project is another example, along with other product segment wins in Nicaragua and Indonesia, which boosted our product segment backlog. With a portfolio of over 1.1 GW of generation, a rebounding product segment, and a growing energy storage offering, we are well positioned to maintain our industry leadership and deliver consistent profitable growth. As we look into 2022, we anticipate increased growth as we put the short-term challenges behind us and reap the benefits of the hard work of the last year. I will turn the call over to Assaf to review the financial results, before I provide further updates on our operations and future plans. Assaf?

Thank you, Doron. Let me start my review of our financial highlights on slide five. Total revenues for the third quarter were $158.8 million, essentially flat year-over-year, reflecting the contribution of the Terra-Gen acquisition offset by lower year-over-year product sales. Third quarter 2021 consolidated gross profit was $63.1 million, resulting in a gross margin of 39.8%, up from the gross margin of 34% in the third quarter of 2020. Gross margin including $15.5 million of business interruption income compared to $2.6 million in the third quarter last year. We delivered net income attributed to the company's stockholders of $14.9 million or $0.26 per diluted share in the quarter compared to $15.7 million or $0.31 per share in the same quarter last year, representing a decrease of 5% and 16.1% respectively, mainly as a result of a lower operating income driven mainly by a $9 million increase in G&A expenses. Adjusted net income attributed to the company stockholders was $17.8 million or $0.32 per diluted share in the quarter compared to $0.31 per share in the same quarter last year. Net income attributed to the company stockholders was adjusted to exclude the transaction cost of $3.7 million pretax and $2.9 million after-tax related to the Terra-Gen Geothermal acquisition. Our effective tax rate for the third quarter was 9.2%, which is lower than the 38.8% effective tax rate from the third quarter of 2020, mainly due to the movement in the valuation allowances for each quarter. We still expect the annual effective tax rate to stand approximately between 30% to 34% for the full year 2021. Assuming no material one-time impact or no impact from changes in laws. This will result in an overall higher tax rate in the fourth quarter of 2021. Adjusted EBITDA decreased 5.1% to $101.6 million in the third quarter compared to $107.1 million in the third quarter last year. I'd note that compared to the second quarter of 2021, adjusted EBITDA increased 20.2%. The lower year-over-year adjusted EBITDA was due to a combination of approximately $4.6 million lower business interruption income and approximately $4.7 million of higher G&A costs, mainly related to the special committee legal costs. I would like to note that we do not expect to incur significant costs on these issues in the remainder of 2021. Moving to slide 6. Breaking the revenues down, electricity segment revenues increased 15.4% to $142.7 million supported by contributions from new added capacity to our McGinness Hills Complex, Puna's resumed operation and the contribution of the recently acquired plants in Nevada. This new added generation was partially offset by lower generation in Olkaria and Bouillante power plants due to a lower resource performance that caused a capacity reduction and surface leak in one of the broader injection wells, which also reduced generation. We made progress in resolving these challenges and expect to gradually recover from them by the first half of 2022. In the product segment, revenue declined 64.5% to $10.5 million, representing 6.6% of total revenues in the third quarter. The decline year-over-year is expected to continue throughout 2021 due to the lower backlog at the beginning of the year. Energy Storage segment revenues remained flat year-over-year at $5.7 million in the third quarter. This quarter, we had an increase in revenue from our storage operating facility of 26%. That was offset by approximately 67% reduction in demand response revenue as we expect to diminish over the next few quarters. Let's move to slide 7. Gross margin for the Electricity segment for the quarter increased year-over-year to 42.8%. This was the result of $15.8 million in business interruption insurance, of which $15.5 million was included in the cost of revenues for the Electricity segment, partially offset by higher costs related to the repair and recovery of Olkaria, Brawley and Bouillante power plants. Excluding the impact of the business interruption in Q3 2021 and Q3 2020, gross profit increased 2.8% compared to the same time last year. In the product segment, gross margin was 12.8% in the quarter, compared to 18.9% in the same quarter last year. The Energy Storage segment reported gross margin of 12.2%, compared to gross margin of 25.6% in the third quarter last year. The decrease was primarily due to the reduction in demand response and associated profit. Turning to slide 8. Electricity segment generated 96% of Ormat's total adjusted EBITDA in the third quarter. The product segment generated 2%, and 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 September 30 was $1.5 billion. Cash, cash equivalents, marketable security at fair value and restricted cash and cash equivalents as of September 30, 2021 was approximately $402 million, compared to $537 million as of December 31, 2020. Marketable securities were at fair value of $46 million. Slide 9 breaks down the use of cash for the nine months and illustrates our ability to reinvest in the business, service debts and return capital to our shareholders, all from cash generated by our operations and our strong liquidity profile. Our total debt as of September 30th was $1.9 billion net of deferred financing costs and its payment schedule is presented on slide 32 in the appendix. The average cost of debt for the company reduced to 4.4%, compared to 4.9% last quarter. During the third quarter, we raised $275 million of new corporate debt to support the Terra-Gen asset acquisition and CapEx needs. On November 3, 2021, the company Board of Directors declared approved and authorized payment of quarterly dividends of $0.12 per share pursuant to the company's dividend policy. The dividend will be paid on December 3, 2021 to shareholders of record as of close of business day on November 17, 2021. That concludes my financial overview.

Thank you, Assaf. Turning to slide 12 for a look at our operating portfolio. During Q3 of 2021, our power generation in our power plants increased by approximately 13.8% compared to last year. We benefited from the incremental contribution of the recently expanded McGinness Hills and the generation from Puna that is operating now at a stable level of 26 megawatts. In addition, we had the contribution of the Dixie Valley and Beowawe plants acquired from Terra-Gen with a total net annual generating capacity of approximately 67.5 megawatts. These contributions were partially offset by the lower performance of our Olkaria and Bouillante power plants. As noted on slide 13, Puna resumed operation in November 2020. We stabilized Puna generation to approximately 26 megawatts as we continue reservoir study and improvement of existing wells to maximize the long-term performance of the power plant. We have continued discussions with HELCO and PUC about our new PPA and continue selling electricity under our existing PPA, which is in effect until 2027. Turning to slide 14. Let me discuss some of the challenges we experienced this quarter in a few of our property assets and I will start with a known one in Kenya. Our revenue in the Olkaria complex was down year-over-year as a result of a reduction in the performance of the resource, which has resulted in an approximate reduction of 25 megawatts. This reduction in capacity and associated repair costs reduced our quarterly gross margin by approximately $3.6 million compared to last year. We are taking a few actions to restore the complex generating capacity. We reduced one of the wells that we plan to connect to the power plant by the end of the quarter. We are upgrading the equipment that will enable us to generate more capacity utilizing the same resource. And we continue with our planned drilling campaign which includes drilling and re-drilling of wells. We are very optimistic that following these actions we will see an increase in the production through the first half of 2022. In the Bouillante power plant in Guadeloupe, we experienced limited injection availability due to scaling that we expect to resolve by cleaning the well. We finished cleaning the well and we are waiting to get the permit to restore capacity in the coming days. 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 three megawatts since the second quarter. We are working to restore production and expect a full recovery by year-end. The lower performance of the Olkaria, Bouillante, and Brawley power plants are reflected in our annual guidance. We continue to monitor the recommendations of the task force created by the President of Kenya related to the review of all independent power producers' PPAs. Based on a review done by the task force and the report issued by the task force of the President in September 29, Ormat's rates in Kenya are significantly lower than many IPPs as you can see in the chart that shows energy rates of other IPPs compared to Ormat's rates. In the task force report, they indicate that Ken-Gen geothermal average tariff including steam cost is $8.05 per kilowatt hour which is not significantly lower than our rate. Having said that we believe that Ormat's rate cannot be compared to Canadian tariffs as it is a government-owned company that receives financial benefits, grants, and preferred financing terms that we are not qualified for. We remain committed to providing clean renewable base load energy to Kenya and continue to work with KPLC for many years to come. Turning to slide 16. In July, we closed the accretive acquisition of the Terra-Gen assets. As a reminder, this acquisition added a total net generating capacity of approximately 67.5 megawatts to our portfolio along with the greenfield development asset adjacent to Dixie Valley and an underutilized transmission line capable of handling between 300 megawatts to 400 megawatts on a 230 KV electricity connecting Dixie Valley in Nevada to California. With this acquisition, we now own 10 operating plants in Nevada generating a total of 443 megawatts which is roughly equivalent to approximately 7% of Nevada's overall generated energy. We are currently working to increase the capacity of the acquired Dixie Valley in 2022 by adding Ormat's acquisition. Turning to slide 17 for an update on our backlog. Our results for the product segment continued to be impacted by the lower backlog at the beginning of the year. We continue 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. We signed a few new contracts during the quarter including a new contract with Salak Energy geothermal to supply products to a new 14 megawatt Salak geothermal power plant in Indonesia and another contract to supply equipment to a project in Nicaragua. As of November 3, 2021, our product segment backlog increased for the third quarter in a row to approximately $67 million compared to $56 million in early August, giving us a good start for this segment in 2022. Moving to slide 18. The Energy Storage segment continues to become a more important part of our consolidated results. This quarter we see an increase in our storage facilities contribution. As Assaf indicated, they were up 26%. The increase was offset by diminished contribution of the demand response activity inherited from the Viridity acquisition. Moving to slide 19 for an update on legislation. The global support for renewable energy by government continues as can be seen in the Glasgow Climate Change Conference. In the US, the negotiations between the White House and Congress have made substantial progress over the past weeks. Last Thursday the House released a draft bill that will serve as the basis for the final negotiation. Although not final, the new bill suggests extending the PTC and ITC until the end of 2026 for geothermal and includes storage to be eligible for ITC. The bill draft also allows taxpayers to elect the option to receive the tax credits in cash. The commitment of the government to renewable energy is also reflected in the inclusion of credit plans beyond 2026. We believe that assuming the bill will pass, this enhanced flexibility and long-term clarity will encourage and accelerate the use of renewable energy and we expect to be in the forefront of this growth in geothermal and in energy storage as well as in solar. Moving to slide 21 and 22. As we have communicated, 2021 will be a significant buildup year comprised mainly of geothermal projects. The buildup supports our robust growth plan which is expected to increase our total portfolio by almost 50% by the end of 2023. One of the main challenges in our efforts to achieve our growth is obtaining permits on the timeframe we were used to before COVID. The delays we experienced in obtaining the permits result in delays in the commissioning of our future projects. Although we have delays within 2021 to 2023, we are still aiming to add an additional 240 megawatts to 260 megawatts by year-end 2023 in addition to the 83 megawatts we added since the beginning of 2021. In our rapidly expanding energy storage portfolio, we plan to enhance our growth and to increase our portfolio by 200 megawatts 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 beyond. Slide 23 displays 14 projects underway that comprise the majority of our 2023 growth goals. While we are experiencing significant delays in the permitting process, we still expect to be on track to meet our growth targets for the end of 2023. Moving to Slide 24 and 25. The second layer of our growth plan comes from the Energy Storage segment. Slide 24 demonstrates the energy storage facilities that have started construction. The other projects included in our growth plans are in different stages of development and their release will require site control and execution of an interconnection agreement, obviously all subject to economic justification. The storage facilities listed in this slide are expected to generate in today's pricing approximately $15 million annually with EBITDA margins of 50% to 60% approximately. Since the majority of the revenues are merchant based, we may see volatility in revenues once they are in operation. As you can see on Slide 25, our energy storage pipeline stands at 2.1 gigawatts and currently includes 30 named potential projects mainly in California, Texas, and New Jersey. Moving to Slide 26. The significant growth in both our electricity and storage segments will require robust capital investment over the next couple of years. To fund this growth, we have over $780 million of cash and available lines of credit. Our total expected capital for the remainder of 2021 includes approximately $177 million for capital expenditures as detailed in Slide 33 in the appendixes. Overall, Ormat is well positioned with excellent liquidity and ample access to additional capital to fund future initiatives. Before I move to the guidance, I would like to update you on some ESG initiatives. On Slide 27, we are moving to strengthen our ESG commitment. We build our approach and policy on four significant valuable issues: water management, taxation, suppliers and procurement policies, and political communication. The purpose of the move was to reflect in the most up-to-date and accurate way our approach, vision, and courses of action on these issues. I'm also happy to update that we are planning to publish our corporate sustainability report in the next few weeks. Please turn to Slide 28 for a discussion of our 2021 guidance. We expect total revenues between $652 million and $675 million with electricity segment revenues between $585 million and $595 million. We expect product segment revenues between $40 million and $50 million. Guidance for energy storage revenues are expected to be between $27 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. Adjusted EBITDA guidance for 2021 includes the $15.8 million insurance proceeds received in the third quarter. This concludes our prepared remarks. Now I would like to open the call for questions. Operator, please?

Our first question comes from Noah Kaye from Oppenheimer. Noah, please go ahead.

Good morning and thank you for taking the questions. Maybe I could start with the portfolio growth plans. I think you mentioned some challenges in getting permits creating some delays in commissioning future projects. But looking at the timetables for project CODs, it appears like it stayed fairly stable. So just wondering if you could put a finer point on your comments. Are you seeing permitting delays pushing projects out a quarter or two, or can you help clarify that a little bit because, again, the tables don't really seem to have changed from last quarter to this quarter?

Hi Noah, thanks. There are two types of delays. Some delays occur between years. For example, we initially expected the Heber complex to be completed by the end of 2021 or early 2022, but that has now shifted to the end of 2022. Similarly, Dixie Meadows, which was planned for 2022, has been updated to 2023 in the table. So while some delays fall between years, others, like Dixie, have experienced significant shifts.

Okay. And I guess if you could comment on expectations on the IRRs for these projects? And certainly, we've seen rising commodity costs, steel inflation, etc., labor availability issues and just higher logistics costs. On the other hand, I know you did a lot of your manufacturing last year for some of these projects. So, can you just kind of comment on whether an increased cost environment affects your expectations for profitability of these projects?

Obviously raw material and labor costs are increasing, transportation. I wouldn't use the word increasing but exploding basically on the cost side. But we have manufactured, as you mentioned, a big part of it already last year with raw materials that were acquired even before the large increases. But obviously going forward, the new projects will have to endure the higher cost. And what we see in parallel to that is increasing demand for geothermal and increasing pricing. So, the coming projects will enjoy the lower cost that we have but also the PPA environment of the past. And now we see an increased demand for geothermal and we do expect to see in the coming in the short term increased pricing as well that will compensate us. The fact that PTC and ITC will be extended, obviously will also support the profitability. So all in all, we don't see a significant or hardly any change in the IRR when we expected IRR when we release the projects.

Okay. Doron, it's great to hear that you're actually seeing pricing new PPAs increasing. That's a big change from the trend in the past couple of years. Can you elaborate on that a little bit more? What sort of upward pricing at are you seeing in the US?

The negotiations that are beginning today follow previous discussions that helped lower pricing. Recently, the CPUC mandated the addition of 1,000 megawatts of new renewable energy with an availability exceeding 80%. This has led to a rise in demand for geothermal energy, which is practically the only renewable source that fulfills this requirement. This must be accomplished by 2026. As a result, we have been approached and have initiated negotiations with several CCAs and utilities. We are optimistic that this will lead to new power purchase agreements in the upcoming months that will feature higher pricing or prices returning to normal levels.

Okay. Great. And one last question. I think you mentioned in the prepared remarks that you don't expect those elevated legal expenses to continue into 4Q. Could you please help us understand why that might be the case?

We mentioned on the call that we do not anticipate these costs to remain at the same level. The Independent Counsel that the company engaged has reported its findings, and we do not expect to incur additional costs or lower costs going forward than what we experienced in the last two quarters.

And so you said that the Independent Counsel has reported its findings already?

Yeah. Yes. As there is custom, we cannot relate to any of these comments until everything is finished.

Okay. Thank you very much.

Thank you.

Thank you, Noah. Our next question comes from Julien Dumoulin-Smith from Bank of America Securities. Julien, please go ahead.

Thank you, good morning. This is Alok on behalf of Julien. Thank you so much for taking the question. Just wanted to understand a bit more based on the comments that you made on the Kenya PPA negotiation and how Ormat's PPA prices are among the lowest.

Regarding Kenya...

Sorry just. Yeah, go on.

Yes. No, no.

The question I had was a couple of recent media reports indicated that the Energy Capital secretary had indicated lower energy prices after some renegotiation by unnamed IPPs by December. And I was curious whether any of those discussions pertain to or matter that was just a broader statement?

I'll mention two points. First, this was a general statement primarily concerning KPLC and necessitated that KPLC initiate negotiations. As of today, we have not been approached regarding any new negotiations on our PPAs. The President's task force released its report at the end of September or early October. In that report, there is an analysis of PPA rates, comparing ours with KenGen's. It indicates that KenGen has about 10% to 12% lower PPA fees. However, we must consider that KenGen is a state-owned entity and is not subject to the same obligations as a public company in the US. They have access to funding that Ormat, as a public company, cannot obtain. They also benefit from government support and additional concessions. While we are not privy to all details of KenGen's operations, it is well-known that government-owned entities receive various forms of support from their governments. Therefore, we do not believe the comparison is fair. Nevertheless, even with this analysis, the difference remains around 10%.

Got it. That's very helpful. Regarding Kenya, could you provide insights on the trend of receivables related to KPLC? Specifically, are there any patterns in the payment of South-related receivables or any outstanding older receivables?

We're actually seeing a big improvement from payments fees from our customers KPLC. They actually reduced the overdue to $33 million at the end of the quarter. And since then they paid an additional $14.2 million. So if you think about it right now they are delayed roughly two months which is something that we work with them and we appreciate their support.

Got it. Thank you. And then lastly on Kenya, with respect to Olkaria resource underperformance, if you could just provide a bit more color on the delay that we observed from the end of year 2021 ramp-up to now the first half of 2022, what exactly is causing that delay and the certainty around the newer timeline?

In Kenya, every time that you deal with drilling and resource there are potential complications. So we had a few delays in the drilling, we have now a very detailed plan going forward. We expect generation to increase gradually over time. It's not one solution, one-hit to solve to go back to the normal generation that we have. So we do expect to see it in stages going up. Part of the issues that we encounter is the global transportation issues. Kenya, like most countries, don't have in the country all the requirements, all the materials that are required to do the drilling and we need to bring it from outside of Kenya. And as you know, shipment costs today or shipment time frames are very much delayed today. So we were impacted by these delays. But we do have a plan exactly what to do and when to do it, and we see that going over the next few months and it will be gradual. It's not that one day we will get back to the full capacity. We have a few parts that we want to – a few elements to this project to bring it back to full capacity by the middle of next year.

Got it. Thank you. And one last question from me and then I'll pass it on. With respect to your 2023 target of 1.5 to 1.6 gigawatt capacity. I'm just curious, given that some of the projects that you have in the development pipeline now are expected COD 2023, so how much of a buffer or leeway do you have with respect to that target now? Thank you.

This is the target that we believe we can achieve. Obviously, from the geothermal part it relates a lot to permitting and the delay that we've seen. But this is the target that we think is achievable that we plan to be there.

Thank you. Our next question comes from Jeff Osborne from Cowen and Co. Jeff, please go ahead.

Great. Thank you. Good morning. A couple of questions on my end on the increased activity or confidence of the demand in California. I was wondering if you could just update us on your land position in California, or would you be needing to use your Nevada sites that you've self-developed and I think acquired from US geothermal years ago? And then correlated to that, could you give us an update on the power line that you have between Nevada and California? And if there's a way of ballparking how many megawatts of capacity that could serve if you were to see set demand in California?

We have multiple land positions in California but also and also in Nevada that we are doing exploration in 2021 and in 2022 and that we expect them to mature into a project that we'll be able to supply both to NV Energy in Nevada and to the various CCAs and SCAPPA in California. So we're working in both places. As you said we did acquire from US geothermal a few land positions that we are going to explore this year. Also, on the Terra-Gen acquisition, we acquired Coyote Canyon, which is a very high potential land position. And in Beowawe and Dixie, we are planning to expand the generation over there due to a much better resource that we think can be utilized and generate more electricity. So on and on we see the demand and we see – and we are developing the assets to support this demand. We're actually very happy to see the demand coming from California but we also see demand in Nevada for geothermal projects.

That's great to hear. And then maybe just following up on the PPA pricing I think in response to Noah's question. What – how would you characterize returning to normal? I think the SCAPPA deal was done at 75 but that that was with some older assets. Do you think somewhere in the 80, 90 range is reasonable and more normalized to you? I'm just trying to get a sense of where you think the market is today.

I would like to say that 80 to 90 is the right pricing, but unfortunately, that is not the case. In the last couple of months, we have seen a continued reduction of PPA pricing into the 60s. Following the CPUC decision, this reduction has essentially stopped and reversed. We hope to negotiate new PPAs in the coming days at prices in the high-60s to low-70s, which is the range we expect. Thanks to significant improvements in our manufacturing and NEPC capabilities, we have managed to reduce our capital expenditures. While the increase in raw material costs has an impact, we have been able to enhance and maintain our desired returns. The proposed new bill that might extend the PTC could provide an additional $25, and if it is in cash payment, that amounts to another $25 per megawatt hour for a decade.

Got it. That's helpful. Just two quick ones here. I think on past calls, you've talked about the Heber two repowering process. Can you talk about where that RFP stands for that additional power? And then any comments on what you're seeing in Indonesia would be helpful just given the size of the resource there and some of the comments from the government.

We have issued a bid with substantial demand following that, and the pricing is similar to what I mentioned earlier. We are currently in negotiations for Power Purchase Agreements, and we hope to sign one in the coming weeks. Once we do sign, we will update the market accordingly.

Any quick thoughts on Indonesia?

Indonesia is very, very interesting. If you look at what we've been able to develop there, although it takes a bit longer, and COVID obviously delays things. But on top of the Sarulla 12.75% ownership that we have, we are drilling now with Ijen which is a joint venture with Medco where we own 49% and they own 51%. We are drilling and we expect this to become a project towards the end COD towards the end of 2023. The other one is the announcement we did where we have a joint venture with a large mining company in Indonesia where we own 75% and they own 25% of an asset in the area of Bitung. So we see quite a lot of prospects. We have additional sites that we have exploration rights in Indonesia. And from the product segment, what we expect is that in 2022, we will see a few tenders coming out in Indonesia that hopefully will be able to boost the product segment towards 2023 and onwards.

That’s great to hear. Appreciate the insight for this detail. Thanks.

Thank you.

Thank you. Our next question comes from Julien Dumoulin-Smith from Bank of America Securities. Thank you, Julien.

Hey, everyone. I just wanted to follow up and clarify something. Regarding the Ken-Gen aspect, I understand you prefer not to negotiate during this call, but I'm curious about the relationship between the Ken-Gen tariff level and what they refer to as capital structure refinance opportunities. Are these two separate opportunities for them, or are they interconnected in terms of potential cost savings? I want to ensure we're on the same page here, as it appears there may be two distinct paths being considered.

Julien, good morning. We appreciate the question. It's Assaf. So the task force report is actually a public report and you can look at it online. And it shows very specifically that the tariff of format is basically 10% higher than the tariff of Ken-Gen, when you look at Ken-Gen cost including the steam costs. I will also say that based on that report, Ormat is the lowest IPP in Kenya when you exclude some very small plants that are barely operating. So when you talk about negotiation, we are providing the cheapest electricity in Kenya and we are quite large IPP over there. So, just those are the facts. With respect to the report, as you said that they are using maybe potentially structuring of our debt as a way for us to reduce the tariff. But they are saying specifically that's the reason to reduce the tariff. They are not suggesting that there is a double forward reduction in tariffs. Again this is their request from us which we haven't seen yet. Everything we've seen through the report. And as I told you before and we said before we're always ready to talk to our customers any customers that will talk to us and request any kind of change in the agreement we are ready to talk to them. And I'm sure there is a win-win situation similar to what happened in Puna in the past when we lowered the tariff and we got extension and more capacity. So this is something that I'm sure can be on the table. But overall right now there is no negotiation and we will continue to support KPLC.

Right. And maybe actually if I can clarify that. You talked about being 10% higher than Ken-Gen. But what about royalties, for instance, in other costs in your cost structure that may not exist for instance with Ken-Gen? I mean when you think about this negotiation presumably some of those factors would presumably try again, try to reconcile one versus the other there as well, I take it.

Exactly as Doron mentioned during the script. Our cost structure and Ken-Gen's cost structure is different including royalties. We don't have the details of exactly what's in their numbers. We know that our numbers do include a small amount of royalties that we do pay. It's a few million dollars a year. But as I said, it's very clear in the report that they would like us to reduce the tariffs slightly. And we will discuss with them and we'll do the negotiation between us and them and not on Wall Street paper.

I truly appreciate that. That's great. However, it's just a few million dollars compared to the $12 million identified here in annual costs. While it's a nontrivial amount in percentage terms, I would like to clarify the cadence of opportunities in California. I know this has been asked several times, but considering the next 24 months and the resources you can allocate to California, especially given the severe situation with negative reserve margins, how quickly can you act? How many resources can you deploy to address the California resource adequacy deficit that appears to be ahead, particularly in response to what seems to be a request for at least a full gigawatt of resources in the current RFP, not to mention further procurement? I'm interested in understanding what resources you can provide in the immediate term for the next 24 to 36 months.

I believe that if you look at the next 24 months, ending in 2023, you will see most of the assets listed in our presentation. There may be one or two additional assets in the final stages of exploration that could fit into this timeframe. However, looking ahead to 2024 and 2025, and if I recall correctly, the requirement extends until 2026. We are currently exploring multiple sites in Nevada and California, so we will be able to expand our resources for 2024 and 2025 significantly. As you know, in February, when we released our guidance for 2022, we also updated our outlook for 2024, emphasizing growth. There we will be able to showcase the exploration and prospects we anticipate.

Got it. And the one to two additional projects you just alluded to do they have interconnect already, or where are you in the process with transmission there just being able to get those done in the next couple of years? You seem to allude to actually being able to get that prior to 2024?

Look, we hope we will be able to get them. As I said, and we said multiple times, permitting in California and Nevada is a big challenge today and we need the legislations and to push and to make sure that on one hand if they put targets for renewable energy on the other hand they also allow renewable energy to develop and build. So this is a challenge that will work all the time. And that's what we believe we'll be able to do until 2023 and 2024 we are working now to get you the best number in February.

Excellent. I wish you guys best of luck. And hopefully those permits come along. All right.

Thank you.

Thank you. This now concludes our Q&A session. I will hand back to Doron Blachar for any further comments. Thank you.

Thank you. I would like to thank you all for joining us. We see the boost for renewable energy coming across the globe and specifically in the US and we see the increased demand. And as the leading Geothermal company, we plan to supply a big part of this demand. Thank you very much.

Thank you everyone. You may now disconnect your lines.