Ormat Technologies, Inc.

Thank you, operator. Hosting the call today are Doron Blachar, Chief Executive Officer; Assi Ginzburg, Chief Financial Officer and Smadar Lavi, Vice President of Investor Relations and ESG Planning and Reporting.

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 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 Co-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 reasons 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 via the presentation link that is found on the Investor Relations tab.

With all that said, I would now like to turn the call over to Ormat's CEO, Doron Blachar. Doron?

Thank you, Josh, and good morning, everyone. Thank you for joining us today.

2024 was another successful year for Ormat as we delivered solid operational and financial performance and made market advancements executing against the key pillars of our multi-year growth strategy. This success was highlighted by top-line improvement of 6.1% and an adjusted EBITDA improvement of 14.3%, with solid growth demonstrated across all three of our business segments.

As you can see on Slide 4, in the Electricity segment, we celebrated the successful acquisition of Enel assets, a strategic move that has substantially boosted our revenues and EBITDA. This acquisition coupled with a remarkable recovery and resource stability at Puna and Olkaria enabled us to more than offset the operational events and curtailments to deliver strong financial results and impressive adjusted EBITDA growth.

In addition, we secured three new PPAs for our Boyan power plant in Guadeloupe, as well as Hebe 1 and Mammoth 2 in California, which captured significantly higher rates than our current agreements, demonstrating the strong demand we are experiencing in The U.S. and globally for geothermal.

Turning to the Storage segment, we brought three new facilities online including the 80 megawatts, 320 megawatts hour Bozident project, the largest storage facility in our portfolio. This milestone along with the signing of two tolling agreements in Texas and one resource adequacy agreement in California has transitioned this segment towards lower overall volatility and more consistent profitability, while growing its way within our overall portfolio.

In the Product segment, we have fully recovered our top-line, improved our segment profitability and reached an all-time high backlog with the support of the approximately $210 million contract in New Zealand. This achievement combined with our successful efforts in raising over $500 million in corporate and finance debt and the receipt of significant tax benefits highlights our strategic financial management and robust market presence.

These accomplishments are a testament to our unwavering dedication to growth. They position us for continued success and reinforce our commitment to delivering value to our stakeholders.

Now before I provide further updates on our operations and plans, I will turn the call over to Assi to review the financial results for the quarter. Assi?

Thank you, Doron. Let me start my review of our financial highlights on Slide 6.

Total revenues for 2024 were $879.7 million marking growth of 6.1% year over year and revenue for the fourth quarter was $230.7 million down 4.4% year-over-year. The improved top line performance on a full year basis was driven by growth across all three of our business segments with the magnitude of year over year revenue growth driven largely by the strategic expansion on our electricity portfolio.

Ormat gross profit for 2024 was $272.6 million, a 3.3% increase compared to 2023. Gross profit in the fourth quarter declined 6.2%, primarily due to the unexpected impact we saw in Electricity segment due to curtailments.

In the fourth quarter of 2024, net income attributable to the company's stockholders was $40.8 million or $0.67 per diluted share marking solid growth in comparison to $35.7 million or $0.59 per diluted share in the same quarter last year. On an adjusted basis, net income attributable to the company's stockholders was $43.6 million or $0.72 per diluted share, an increase of 7.7% and 7.5% respectively.

In the full year 2024, net income attributable to the company's stockholders was $123.7 million or $2.04 per diluted share in comparison to $124.4 million or $2.08 per diluted share last year. On an adjusted basis, net income attributable to the company's stockholders for the full year 2024 was $133.7 million or $2.2 per diluted share, an increase of 9.7% and 7.3% versus last year respectively.

Full year adjusted EBITDA was $550.5 million marking an impressive increase of 14.3% compared to 2023. Our fourth quarter adjusted EBITDA results were $145.5 million, an increase of 4.6% compared to the fourth quarter of last year.

This year-over-year growth in adjusted EBITDA was driven by the contribution of new projects added in both Electricity and Storage segment, the improved performance of our Olkaria complex and better pricing at our Puna power plant as well as by the sale of tax benefits from newly built plants. In addition, we had significantly increase in the product segment EBITDA, driven mainly by the improved margins.

We note that our adjusted EBITDA growth continued to meaningfully outpace our already strong top-line expansion, which further builds upon a track record of profitability maximization as we execute our portfolio growth strategy. Turning now to Slide 7.

We break down the revenue performance at the segment level. Electricity segment revenue for the fourth quarter decreased by 2.1% to $180.1 million due to a $5.4 million the approximately $4 million reduction driven by curtailments in the U.S.

While we touched based on this briefly in the last quarter earnings call, our fourth quarter revenue results reflect a greater than originally anticipated curtailment from local transmission owners, as they conducted maintenance on the T-line. For the full year, electricity revenue increased by 5.3% to $702.3 million, which was driven by the contribution of the Enel assets we acquired at the beginning of 2024, the Heber Complex repowering project as it came back towards full capacity and improved generation performance in Olkaria and pricing at Puna Power Plant, partially offset by the reduction in Dixie Valley and the curtailments in the U.S.

In the Products segment, revenue declined by 21.4% to $39.6 million during the fourth quarter, and for the full year, they grew by 4.4% to $139.7 million. Energy Storage segment revenue increased by 56.7% in the fourth quarter and by 30.6% to $37.7 million in the full year.

This increase is mainly related to new energy storage facility, which commenced operation during 2023, including Bowling Green, Andover, Uptown and Pomona II as well as the East Flemington and Buckle Neck energy storage facility, which commenced operation during 2024. Moving to Slide 8.

The gross margin for the Electricity segment was 34.9% and 34.6% in the fourth quarter and full year. Largely, in the recent quarter and modestly in the full year, the margin comparison experienced was due to lower revenue resulting from the curtailments in the USA and Kenya and the Dixie Valley Outage, which returned to full operation towards the second half of the fourth quarter of 2024.

Excluding the impact of curtailments in the U.S. and Evonational, gross margin of the Electricity segment was higher by 2.2 and 1.8% in the fourth quarter and the full year of 2024, respectively.

We expect the curtailments we saw in Q4 to continue in 2025 as major T-line is being replaced in Nevada during the year. In addition, the recent wildfires in California caused a reduction in demand of electricity in the region and resulted in overload on the grid that forced grid operators to curtail part of the supplied power.

We currently expect total revenue in 2025 to be negatively impacted by $10 million to $15 million in the U.S. The impact was taken into consideration in our 2025 revenue guidance.

In the Iroduct segment, gross margin of 18.4% in the full year increased by 500 basis points versus last year. We have improved our margin in 2024 through better contract pricing and looking into 2025, we expect to see margin between 18% to 20%.

The Energy Storage segment reported gross margin of 9.5% and 10.9% during the fourth quarter and full year respectively marking a significant improvement versus prior year. As Doron previously mentioned, this improved performance was driven by our continued progress to transition the revenue and margin profile of this segment as we have achieved greater degree of balance between our merchant market exposure and towing contracts.

Also, in the fourth quarter, we saw better merchant prices at PGM and we continue to see improved prices also in the first two months of 2025 at these markets. Breaking down adjusted EBITDA at the segment level on Slide 9 where you can see significant increase in full year 2024 at all three segments.

The Electricity segment generated 89% of our max total consolidated adjusted EBITDA in 2024. The Product segment contributed 6% and the Energy Storage segment accounted for 5% of the total adjusted EBITDA.

Reconciliation of EBITDA and adjusted EBITDA are provided in the appending slide in the back of the presentation. Moving to Slide 10 in the fourth quarter we recorded a $20 million in income related to tax benefit compared to $18.7 million last year.

Also in the fourth quarter we recorded a$20.4 million ITC benefit in the income tax line related to the three storage facilities, East Flemington, Bottleneck and Montague. In the fourth quarter we collected $46.7 million in cash for the Bottleneck ITC.

We anticipate that we will receive in 2025 up to $160 million in cash proceeds related to PTC and ITC benefits mainly from tax equity transactions for the HIPAA complex, ITC benefits for storage assets that will fill the in 2025 and PTC transfers. We expect Ormat’s tax rate will be positively impacted by ITC benefits in 2025, and for modeling purposes we expect the annual tax benefit rate to be positive of 5% to 10%.

This rate excludes any changes in law and on one time event. Looking at Slide 11, our net debt as of December 31, 2024 was $2.2 billion equivalent to four times net debt to EBITDA.

The leverage decrease compared to earlier this year was supported by improved EBITDA and 32.8% increase in cash flow from operations compared to 2023 cash and cash equivalent and restricted cash and cash equivalent as of December 31, 2024 was approximately $206 million compared to $288 million at the end of 2023. Slide 11 breaks down our use of cash flow for the last 12 months, illustrating Ormat's ability to generate strong cash flow to reinvest in and strategically grow the business while simultaneously service our debt obligation and returning capital to our shareholders.

Our cash flow from operation increased by 32.8% to $411 million supported by the improved performance of our assets increased collection in Kenya and Honduras and demonetization of bottleneck ITC at $0.93 on the dollar. Our total debt as of December 31, 2024 was approximately $2.4 billion net of deferred financing cost and is Presented on Slide 30 in the Appendix which outcome the payment schedule the average cost of our debt for the company stands at 4.66%.

The majority of our debt liabilities are at fixed interest rates, providing for good stability and creating protection from fluctuation in the market. Moving to Slide 12, we have approximately $667.1 million of total available liquidity.

Our total expected capital expenditure for 2025 are approximately $570 million. As detailed in Slide 31 in the appendix, we plan to invest approximately $355 million in the electricity segment for construction, exploration, drilling and maintenance.

We also plan to invest $200 million for the construction of our storage assets during 2025. As we continue to progress with executing our growth plan, we have shown the ability to consistently increase our cash generation profile while combined with the expected cash from utilizing the tax benefits will fund our CapEx.

We continue to maintain excellent liquidity and have ample access to additional capital as needed. On February 26, 2025, our Board of Directors declared approved and authorized payments of quarterly dividends of $0.12 per share payable on March 26, 2025 to shareholders of record as of March 12, 2025.

In addition, the Company expects to pay a quarterly dividend of $0.12 per share in each of the next three quarters. That concludes my financial overview.

I would like now to turn the call over to Doron to discuss some of our recent developments.

Thank you, Assi. Turning to Slide 14 for a look at our Electricity segment operating portfolio.

Since the beginning of 2024, we successfully added 133 megawatts of new net capacity organically, as well as through strategic accretive M&A. Generation increased 3.5% and excluding curtailment, our generation grew by 10%.

This growth was driven by our acquired assets, improved performance at Puna, a full year of operations at Heber 1 at higher capacity, the repower of [Biowi] and the increase in our carrier capacity to nearly 150 megawatts in the latter half of 2024. Earlier this month, we announced the successful COD for the Ijen Geothermal power plant, which we jointly own with PT Metco Power Indonesia.

The Ijen facility began operation with its first phase delivering 35 megawatts to the Java grid with our share of the facility being 17 megawatts. In 2024, we secured multiple land parcels in Nevada and Utah to support our short and long-term growth plans for geothermal energy in the U.S.

This reinforces our commitment to advancing renewable energy solutions, and meeting the increasing demand for sustainable energy in these key markets. Moving to Slide 15.

Subsequent to year-end, we are now signing a favorable ten year PPA with Calpine Energy Solution to provide up to 15 megawatts of clean renewable energy from our Mamox 2 geothermal power plant. We are currently negotiating PPAs for more than 250 megawatts with hyperscalers with rates exceeding $100 per megawatt hour.

These agreements will secure our growth and revenues post 2028. Turning to Slide 16.

Our Product segment backlog reached a record of $340 million, up 124% compared to Q4 of 2023. This increase was largely driven by the signing of a large EPC contract in New Zealand for the Timihi 2A 101 megawatt power plant and the Dominica BOT project.

Revenues from this backlog will be recognized over the next two years. Moving to Slide 17, our Energy Storage segment saw higher revenues on both a quarterly and full year facilities that came online in 2023 and 2024, including the East Flamington facility.

We expect this performance to continue in 2025 as we benefit from the COD of our Bottleneck and Montague storage facilities. Additionally, we made significant progress in transitioning our Storage segment to a more predictable portfolio with stronger profitability.

This is highlighted by the REI agreement with the City of Riverside for Oshir 80 megawatts, 320 megawatt hour’s facility and our first two tolling agreements in Texas for the Lower Rio and Bergdorf facilities each with the generating capacity of 60 megawatts or 120 megawatt hour. Moving to Slide 19.

We continue to remain on track to have our portfolio capacity target to reach between 2.6 gigawatt to 2.8 gigawatts by year end 2028. This year we added 253 megawatts of new capacity with 133 megawatts in our Electricity segment and 120 megawatts in the Energy Storage.

This aligns with our long-term capacity target for 2028 and we expect it will straighten our earning generation in 2025 and beyond. We expect a capacity CAGR of 14% to 16%, primarily driven by the strong U.S.

market, where we see increasing demand for base load electricity. Our focus remains on capturing this demand through our Electricity and Storage segment.

Turning to Slide 20 and 21, which displays our geothermal and hybrid solar PV projects underway. We anticipate adding an additional 158 megawatts to our generating capacity from geothermal and solar PV projects by the end of 2026.

Moving to Slide 22 and 23. We currently have six projects under development in our Energy Storage segment, which are expected to add 385 megawatt or 1.3 gigawatt hour to our portfolio.

Our focus remains on balancing contracted revenues and merchant market pricing in our Storage portfolio. We removed the Luiza project due to interconnection delays, which have pushed the project COD to 2029.

We are discussing alternatives with the grid operator and will update as needed. Additionally, we added two new projects in Israel awarded through tolling agreements in partnership with Allied Infrastructure LTT, a leading infrastructure company in Israel.

Our share of the project is 150 megawatts or 600 megawatt hours. Please turn to Slide 24 for a discussion of our 2025 guidance.

We expect total revenues to increase by 9% year-over-year at the midpoint ranging between $935 million and $975 million and Electricity segment revenues are projected to be between $710 million and $725 million, Product segment revenues between $172 million and $187 million and Energy Storage revenues between $53 million and $63 million. Adjusted EBITDA is expected to increase by approximately 5% at the midpoint ranging between $563 million and $593 million with annual adjusted EBITDA attributable to minority interest at approximately $23 million.

I will end our prepared remarks on Slide 25. In light of the fluid policy situation in the United States, we have taken proactive measures to ensure our geothermal projects are safe harbor for PTC eligibility through 2028 and ITC benefits for energy storage through 2026 and in some cases, even beyond.

These steps are crucial as we navigate the evolving landscape of executive order related to the IRA tax credit and geothermal energy production and create confidence in our growth trajectory and our goals of achieving 2.6 to 2.8 gigawatt of generating capacity by 2028. We do see exciting growth opportunities for geothermal energy as part of the National Energy Emergency Executive orders with potential easing of project permitting time lines and increased focus on geothermal research and development.

These factors, along with the growing global demand for renewable energy, reinforces our confidence in geothermal energy's role in the transition to a cleaner energy future. To summarize, we are proud of our accomplishment in 2024, and remain focused on our long-term growth target while delivering strong financial results.

As we look ahead, we anticipate growing demand for renewable energy to support AI datacenter and the transition to a cleaner energy future. We believe, we can secure improved project return through higher PPA pricing and tolling agreements, driving improved profitability for Puna.

We look forward to continuing our multi-year growth path and consistently delivering enhanced shareholders and stakeholder value as we execute our strategy. This concludes our prepared remarks.

Now I would like to open the call for questions. Operator, please.

Good morning. Thanks for taking the questions.

The first one, just how we should think about the electricity generation expectations for the Electricity segment in the portfolio embedded in the '25 guide? It looks like most of the new projects you expect to come online are really kind of tail end of the year.

You mentioned some of the curtailment impacts. So it kind of looks like, we should assume a fairly modest, maybe low single-digits increase in generation year-over-year or possibly flattish.

But it also looks like, that could set up perhaps something close to double-digits growth in generation in 2026. Is that a fair way to think about it?

How should we assume? I don't know.

Thank you.

I think you got it exactly right. We didn't have any too many projects coming online at the end of '24 beginning of '25.

We do see on the enhancement, the drag rate for the Enel project coming on for the end of the year and we said we do see some more curtailments in the U.S. than what we've seen in the past.

So, all in all, this year as presented in the guidance, we see similar generation maybe uptick. And '26, the impact will be basically following the power plants coming online towards the end of the year '26 and all the projects that we've listed that will come on June ‘26 is the worst.

Okay.

Maybe, Noah, if you don't mind, I'll add a few more things. While the curtailment in the U.S., we've been told by NV Energy that it will be towards the second half of the year, this thing can move also to the next year.

It can happen from time-to-time, and then this year will be higher than that allow us to be higher end of the range. Also both in January and February, we saw lower curtailment than the ones we anticipated in Kenya.

So from a generation perspective, there are a few things that can move us towards the higher end of the range. But as you said rightfully so, right now, we're seeing maybe slight up versus last year mostly as a result of the Dixie assets coming back online.

Okay, perfect. Embedded in the CapEx guide is a doubling year-over-year of exploration and preliminary drilling activities.

Can you just comment on that program a little bit? What would drive the increase in activities and to what extent you would consider this kind of truly early stage versus something that could help to accelerate the portfolio growth over say the next three to four years?

Great. So we have been working to increase our exploration activity over the last year.

We've changed the way we approach the exploration starting in '21. Basically, we're starting to focus on four wells, before really full size wells.

We have been drilling between 8 to 12 full wells in the last two years, and that will happen in the next coming years. Each core campaign is about three to four wells per site.

So this site and once the core wells campaign is successful and the work was successful, then we go to the full side at release. So it is our -- that was our plan to improve exploration.

We see the PPA pricing above 100 today. So it's still very comfortable to increase significantly the exploration.

And also on the permitting side, we have been able to get permitting faster for the forward campaign, which reduces the risk of the full size drilling. And we expect that with the Trump administration, we'll be able to get additional permits for full size and for constructing power plant faster.

So the exploration that we are doing this year, previously and obviously in the coming years will have the growth coming in the following years. And we are focusing on many, many Greenfield that was sort of a bit lower development in the past.

But nowadays, we're focusing to increase and expand the development. We also increased our staffing in the U.S.

to support this growth and we do see these partners. And as we move forward, we will update the market policy once we confirm.

Just to get one more in, you talked about the 250 megawatts of potential PPA contracting with and the pricing expectations there. I think you mentioned around that you would expect those to be for off takes post-2028.

Can you just comment on, A, reasons for that timing, and B, any kind of sense of expected tenure length of the agreements, and possible location of agreements, is it -- would these necessarily be for centers located near production or would these perhaps be more for let's call them sort of virtual offtakes for plants located elsewhere in the country?

So the reason we're talking about following '28 is if you remember three years ago, we signed a portfolio PPA with NV Energy and with the power that covers the period until '28. So we are actually looking for the duration after that.

On top of that, we just talked about the exploration. We believe this Greenfield will come towards the end of 2028 or probably the beginning of 2029, some of them.

So that's the place that we are looking. That's why we're talking following 2028.

The one that we are talking, some of them are looking for us to sign contracts with them with the local utility. Actually, we prefer to do direct negotiation with us using the system, the network to get the electricity.

We are not negotiating somebody. The system that will build the data center adjacent to our facility, but it is definitely something that we're looking across our fleet.

There are places that we can actually combine the two together. But at this stage, most of the discussions we have are combining the utilities in soft form.

Hi. Thanks for the time.

So I wanted to start out here on your, the safe harbor. You had mentioned that, you have safe harbored, all the geothermal projects with CODs through 2028.

I was wondering, if you could share how many megawatts that includes. Is that just the projects that you have named in your deck, or is that a larger group of projects that would enable you to get to the 2028 targets that you have?

And then, just wondering, as we move through 2025, do you think you can extend the safe harbor timeframe beyond 2028 into 2029 for geothermal, or can you extend the storage safe harbor projects beyond 2026?

Good morning, Justin. That's a great question.

As you can see from our deck between now and 2028, we need to add close to 400 megawatts of solar and geothermal. And when you look at the named project, there is much less than that, which means that all the drilling that Doron just spoke about a few minutes ago that should enable us to add somewhere around 250 megawatts between 2027 and 2028, when you talk about geothermal, we safe harbor many projects that are not on the list.

Everything that we're doing co-holds already or full size wells, we also did that and we're also doing it through a sale of equipment. On the Storage side, we are also, as we speak today, looking to get four more projects in addition to what you see on the list in Texas and California and we already safe harbor two more projects that are not on the list.

So there will be at least six more projects that are not on the list that will be Safe Harbor in the next already harbored in the next few months. And we will do it also through a start of construction.

We will look through 2025 what else can we do in order to secure additional 2029 project. That's our goal.

Okay, great. Very helpful.

And then wanted to touch on the Product segment here. Wondering in 2025, are you expecting a meaningful contribution from the $210 million contract for the New Zealand project.

I think the revenue contribution for that project was initially going to be more in 2026 and 2027, but it seems like that might be moving a little bit faster than previously expected. And then just wanted to touch on the margins as well.

Product segment margin in Q4, very strong at 24%. Can you talk about your gross margin expectation for the Product segment in 2025 and what you're seeing in the backlog?

Thanks. Great question.

So when we have a very large project like that, it spans over two-and-a-half years, which started basically November when we actually got the TBDs in office to proceed. And the revenue is spread roughly evenly towards the entire period.

So we see revenues from the TBD project in '25, '26 and '27, and '28, so it is spread across. Usually, we will start with engineering, then manufacturing, then the construction part.

And so '26 will probably be the higher with the most revenue out of the contract, but '25 has a significant amount of revenue from TBE as well. And regarding the margin that you said, I think you should look on the annual basis.

Quarter margins sometimes are impacted by specific projects that can do better or worse, depends on the situation. Q4 was a better one to have more than 24% margin.

We are targeting an 18% to 20% margin within the range that we had in the '24, but that's the target that we're looking.

Hi, good morning. This is Hannah Velásquez on for Julien.

Thanks for the update and great quarter. I had a similar question to Noah at the beginning just in terms of your assets in 2025 coming online towards the second half or later end of 2025.

How does that impact USR? How would that get you potentially to the higher end of the range toward $593 million?

Is any contribution expected from those assets added being operational?

I think what will put us towards the higher end of the range in the Electricity segment specifically, it's not the additional of new assets. It's mainly the amount of curtailment we will experience in the U.S.

and in Kenya. We've been told by NV Energy that they will replace a large T-line in the second half of the year, actually in Q4.

And also, they will do some maintenance work in April. With that being said, this thing can shift between the years, and we're actually talking to them to see if they can smooth a little bit between the few years the maintenance.

So that's on one hand. On the other hand, in Kenya, the plant, as you already know is very close to get to 150 megawatt, which is full capacity but we've seen a lot of curtailment during 2024.

January and February, curtailment was significantly lower. So again, if we continue to see lower curtailment in Kenya throughout the year, that will be also very beneficiary and put us towards the higher end of the range.

And weather is also always can impact us. I can tell you that in Q1, the weather was a little bit warmer than anticipated on the Electricity segment and we saw February, we just -- we're now in Reno, Nevada, close to it, that it was quite warm.

On the other hand, when you talk about the high end of the range as a whole, as a company, on the Storage segment, the freeze that some of you guys experienced in January and February, we are very sorry for you guys, but I can tell you that for our Storage segment, it was very beneficiary. So weather can also impact us.

So there is few things that can happen that can move us to the upper end of the range. It's not about CODs this year.

Most of the CODs are towards the end of the year, and they will impact 2026. Hopefully, that answered the question.

Yes, super helpful, and I'm glad to hear you all benefited from the freeze. I am in Texas.

I did not. So just a follow-up question on some of the repowerings you all are going through.

I know some of the other companies we look at have talked about being able to renegotiate higher off of some of these repowerings. Are you seeing a similar opportunity?

And if so, how meaningful is the upside there? Thank you.

Thank you. The re-contacting that we see I can tell you that the last recontacting that we did as we announced with Calpine for the Mammo G2 facility.

The Mammo G2 facility ends its PPA at the end of 2026, starting 2027. The PPA with a little bit lower than $70 per megawatt hour.

The PPA that we signed was over $100 and so we see a big change. We signed a couple of years ago a portfolio PPA with NV Energy in similar ranges like we had in the around $70.

Today, we see prices above $100. So today, we see that the recontracting, all of them will be at higher prices than what we have today.

We also see, which we haven't seen in a while and mainly with the hyperscaler willingness to look or include some indexation to pricing because that we didn't have in the past. We still not have it in the portal that we signed, but we are seeing a willingness to discuss it into the PPAs.

So it will have a big impact going forward.

Hi, good morning. Maybe shifting over to Energy Storage, maybe the margins obviously fell a little bit here quarter-over-quarter.

Just can you talk about the different moving pieces as far as how margins step down below the 10% range? And how should we think about it looking into 2025, puts and takes between bringing on new projects and obviously a lot of the tariffs talk out of -- coming out of China.

I know a lot of your supply chain comes out of China for these energy storage units. Maybe just some help around the margin outlook and then how tariffs could be impacting this business.

Good morning. As you can see in general, 2024, we had around 10% to 11% margin between the quarters.

I would say that, in general 2024, there were no significant weather events across the fleet, and we only benefited from bottleneck, which -- there is a higher margin during the month of December. That's when it fully operated.

When we look at 2025, we are experiencing more weather events already in January and February and with the increased exposure in PJM with Montelieu coming online earlier, we are seeing now for the year roughly a margin of 15% to 20% for the full year. And I will say that, we will see a higher margin than expected in Q1 because of the weather events that we experienced.

Also in Q3, a bottleneck project has a better margin. In general, during Q3, the contract gives us a higher rate versus the remaining of the year.

This is a new tolling agreement that we have in place already in December 2024. So we think about the year, we expect Q1 and Q3 to lead the margin and for the full year, 15% to 20% margin.

That's all right. No, that makes sense.

And then maybe just some comments around the tariffs out of China, just your supply chain with the batteries and the cells and everything else that goes into it.

If you think about our CapEx this year, for example, on storage, total CapEx on storage is expected to be $200 million. I will say at least half of it is things that we bring from China.

So it will add some cost to our basically all investment and taken into consideration. But please remember that the battery prices are down from a high of $250 per battery three years ago to $130, $120.

You can even buy batteries now at $110, $100. So overall, from what the time we decided to buy the projects until now, the value of the batteries went down significantly.

So 10% should not impact almost anything our decision making, and it will not stop us from continuing the growth. The key for us is to get interconnection on time, and the key for us is to continue sign a good tolling agreement to allow us to develop more projects.

Got it. That's helpful.

And then you recently signed an MOU with SLB in the oil and gas world to develop traditional and the next generation geothermal assets EGS. Could you give us an update on how that's progressing?

Anything noteworthy you want to share, how you're viewing this MOU and how it's evolving? Thank you.

So it's a very important MOU from our prescription perspective and I'm seeing also from SLB, it basically has two, two arms. On one hand, SLB, one of the largest drillers, have many customers that are drilling around the world and have access through to potential geothermal sites.

They're also owning Geothermax, which is one of the consulting firms that deals with geothermal and we do hope that through their customer base and knowledge from geothermics, we will be able together to develop geothermal projects for hyperscalers or any of SLB customers. The other part is the EGS.

As you know, EGS is significantly focused looking on drilling, drilling costs, drilling technologies and SLC is in the forefront of this technology and we are working with them to design exactly the framework where we will together develop an EGS solution, deal with the technology challenges that EGS has today. Between our experience in the resource management and SLB experience in the drilling, we believe that we have a good chance to build better than others on these technology challenges.

And then once we do find the right economical EGS solution, start developing EGS projects. It's a process that we are starting with SLB today, these days, finalizing the framework and going forward.

It's not a short, it won't have a short term impact obviously, but it hopefully will have a mid-term impact and longer term significant impact.

Yes, thank you. Good morning.

Just two quick ones. On the contract renewals that you mentioned with Calpine for 15 megawatts, I think you had 88 total megawatts that were being renewed from '26 to '28.

Is there any update on the cadence of that expectation? And I assume those would also be north of 100 megawatts an hour?

The other contracting that we have until 2028 actually will go through the NV Energy portfolio. These are contracts that will go through the NV Energy portfolio.

These are contracts that have are signed with NV Energy and we signed them three years ago, the smaller, lower number around $70. However, still these are higher prices than what we have today in this contract.

Got it. So no new renewals between now and 2028 and then it would require new exploration to reach the $100 price point for anything above and beyond that.

Is that correct? Just want to make sure I get the timing right.

These were relating to Nevada. We have a -- contract in California that we signed with CPA.

That contract ends in February '26, and we are waiting to the final signature from CPA that should happen Again, significantly higher than what we have discussed.

Perfect. And my last question, was, I forget what year it was, maybe '22 or '23, you made an acquisition that had a power line associated with it.

I believe you're trying to sell that power line or have been for a while. Is there any update on that and what the potential proceeds could be?

We have off road power line connected to [Bishop] the control substation, which is we're waiting for an upgrade. We are not a transmission company.

And as you said, we are looking to sell it. We are in the process.

And obviously, since we're in the middle of the process, I cannot share some commercial details, but this is definitely a process that we're doing and we plan to finalize it this year.

Perfect. And just a clarification, I think you mentioned in the prepared remarks, but I failed to hear correctly.

Did you name the particular NV Energy project that was being curtailed that's leading to the electricity shortfall in 2025?

I don't think we named it, but it's mainly in Venezuela. It's the Lagunas area, Lagunas Hills.

Thanks for taking my questions. I guess two questions.

What's changed from the company's prior stance to go through a regulated utility to this direct PPA with the hyperscaler? And then related, another IPP or another power company indicated $70 to $98 per megawatt hour range for hyperscaler deals that did include capacity or ancillary service.

Can you provide some color, or is there anything that you're able to share as to what's included with the north of a $100 per megawatt hour number?

First of all, we are negotiating with hyperscaler, as I said directly and also through the utility company. So we're looking at both alternatives.

We're trying to maximize the growth and profitability of the company between these two aspects. When we signed the PPA, we basically said, with the PPA all the attributes of the renewable energy, including the rest and everything.

So we have one customer, one price that deals with everything. Maybe that's the difference.

I don't know who mentioned $70 to $90, but maybe that's part of the difference. But that's how we see it.

There are other technologies, our technology is emission free. Other technologies have emission that also might have an impact on the price people are willing to pay.

New power plants get -- we see -- tend to get higher pricing than recontracting many times. So there are various issues that can impact the pricing of the PPA, but what we said is with the pricing that we are negotiating above $100.

Okay. Appreciate that.

And just in terms of duration, I think it was previously mentioned or clarified, but do those duration conversations include all attributes of the power that you're selling? I mean, does this include capacity, some of the racks or any type of environmental attributes?

And are they all likely to be similar in duration or any color you could share on that front?

Yes, all the PPA that we have said all the attributes at the same time period time of the PPA. So the PPA is 10 years.

It could be for 10 years, 15 or 20. And the duration of the PPA is based on the negotiations we have with a specific customer, usually ranging between 10 to 20 years.

Thank you all for joining us today. 2024 was another very good year for Ormat.

We see the significant increased demand in The U.S. and globally, and we are fully committed to continue to focus on this growth and make sure that this is a profitable growth going forward.

Thank you, all.