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Doron Blachar

Thank you, Josh, and good morning, everyone.
Thank you for joining us today. 2024 was another successful year Ormat we delivered solid operational and financial performance and made marked advancements executing against the key pillars of our multi-year growth strategy. This success was highlighted by a toplines movement 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 an assets, a strategic move that has substantially boosted our revenues and EBITDA. This acquisition coupled with the remarkable recovery and resource stability at Puna and Olkaria enabled us to more than offset the operational events and curtailment to deliver strong financial results and impressive adjusted.
In addition, we secured three new PPAs for our Bouillante power lant in Guadeloupe, as well as, Heber 1, Mammoth 2 in California, which captured significantly higher rates than our current agreement, demonstrating the strong demand we are experiencing in the US and globally for geothermal.
Turning to the stores. We brought three new facilities online, including the 80 megawatts, 320 megawatt-hour bottleneck project, the largest storage facility in our portfolio. This milestone, along with the signing of two toning 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 of stability, 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 markets.
These accomplishments are a testament to our unwavering dedication to. 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 Assaf to review the financial results for the quarter.
Assaf?

Assaf Ginzburg

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 topline performance on a four-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 extension 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 segments due to curtainment.
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 stockholders was $123.7 million or $2.04 per diluted share in comparison to $124.4 million or $2.08 for 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 $2.20 per diluted share, an increase of 9.7% and 7.3% versus last year respectively.
Fully adjusted dividend 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 of the year growth in adjusted EBITDA was driven by the contribution of new projects added in both electricity and storage segments, 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 have significantly increased in the product segment EBITDA driven mainly by the improved margins. We note that our adjusted EBITDA growth continues to meaningfully outpace our already strong topline 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 second level. Electricity segment revenue for the fourth quarter decreased by 2.1% to $180.1 million due to a $5.4 million reduction in Dixie Valley driven mainly by the previously reported outage and the approximately $4 million reduction driven by containments in the US.
While we touched based on this briefly in the last quarter earnings cost, our fourth quarter revenue results reflect a greater than originally anticipated curtainment from local transmission owners as they conducted maintenance on the tea line. For the full year, electricity revenue increased by 5.3% to $702.3 million which was driven by the contribution of the assets we acquired at the beginning of 2024.
The Heber complex with powering project as it came back towards full capacity and improved generation performance inOlkaria and pricing at the Pula power plant largely offset by the reduction in Dixie Valley and the containment in the US.
In the product segment, revenues 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 segment revenue increased by 56.7% in the fourth quarter and by 30.6% to $37.7 billion in the full year.
It is mainly related to new energy storage facility which commenced operation during 2023, including Bowling Green, Endeavor, Upton, and Pomona, as well as the East Flemington and Botanic 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 cooperation experience was due to lower revenue resulting from the curtainment 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 curtailment in the US and even national, 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 curtainment we saw in Q4 to continue in 2025, as major teli 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 US. The impact was taken into consideration in our 2025 revenue guidance. In the product 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 per year.
As the previously mentioned, this improved performance was driven by our continued progress to transition the revenue and margin profile of the segment, as we have achieved greater degree of balance between our merchant market exposure and tolling contracts. Also, in the fourth quarter, we saw better merchant prices at CGM.
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 March's total consolidated adjusted Ibida in 2024. The product segment contributed 6% and the energy storage segment accounted for 5% of the total adjusted dibido. Reconciliation of EBITDA and adjusted EBITDA are provided in the appendix slide in the back of the presentation.
Moving to slide 10 in the fourth quarter. We recorded the $20 million in income related to tax benefits 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 HIPA complex, ITC benefits for storage assets that will still be in 2025, and PTC transfers.
We expect tax rates 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 exclude any changes in law and a one-time event.
Looking at slide 11. Our net debt as of December 31, 2024, was $2.2 billion equivalent to 4 times net debt to EBITDA. The leverage decrease compared to earlier this year was supported by improved DBA and 32.8% increase in cash flow from operation 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 our ma ability to generate strong cash flow to reinvest in the strategically grow the business, while simultaneously service our debt obligation and returning capital to our shareholders.
Our cash on farm operation increased by 32.8% to $411 million supported by the improved performance of our assets, increased collection in Kenya and Honduras, and the monetization 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 are on the payment schedules. 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 liquidity. Our total expected capital expenditure for 2025 are approximately $570 million 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 we fund our capital.
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.

Doron Blachar

Thank you, Assaf.
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 a creative M&A.
Generation increased 3.5% and excluding, our generation grew by 10%. This growth was driven by our acquired assets, improved performance at Puna, a full year of operations at hither won at higher capacity, the repa ofawi, and the increase in kaya capacity to nearly 150 megawatts in the latter half of 2024.
Earlier this month we announced the successful COD for the age geothermal power plant, which we jointly owned with PTEco Power Indonesia. The Agen 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 US. This reinforces our commitment to advancing renewable energy solutions and meeting the increasing demand for sustainable energy in these key markets.
Moving to slide 50. Subsequent to year end, we announced signing a favorable 10 year PPA with Calpine Energy Solutions to provide up to 15 megawatts of clean renewable energy from our mammoths to geothermal power plant.
We are currently negotiating PTAs for more than 250 megawatts with hyper scales which raise 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 GPC contract in New Zealand for the Temihi 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 segments saw higher revenues on both a quarterly and full year basis, benefiting from facilities that came online in 2023 and 2024, including the Ace Flemington 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 Agreement with the city of Riverside for our Shield 80 megawatts, 320 megawatt hour facility, and our first two tolling agreements in Texas for the lower Rio and build up facilities, each with a 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 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 segments and 120 megawatts in the energy storage.
This aligns with our long term capacity targets for 2028, and we expect it will strengthen our earnings generation in 2025 and beyond. We expect a capacity gap of 14% to 16%, primarily driven by the strong US market, where we see increasing demand for base load electricity.
Our focus remains on capturing this demand through our electricity and storage.
Turning to slide 20 and 21, which displays our geothermal and hybrid solar pivot 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 slides 22 and 23. We currently have six projects under development in our energy storage segment which are expected to add 385 megawatts 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 Louisa project due to interconnection delays, which have pushed the project COD to 2029. We are discussing alternatives with the grid operator and we'll update as needed.
Additionally, we added two new projects in Israel awarded through tolling agreements in partnership with Allied Infrastructure LTD, a leading infrastructure company in Israel. Our share of the project is 150 megawatts or 600 megawatt hour.
Please turn to slide 24 for a discussion of our 2025 guide. We expect total revenues to increase by 9% year over year at the midpoint, ranging between $935 million and $975 million. 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 $53.63 million. Adjusted EBITDA is expected to increase by approximately 5% of 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 harbors 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 orders related to the IRA tax credits and geothermal energy production and create confidence in our growth trajectory and our goals of achieving 2.6 to 2.8 gigawatts 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 projects permitting timelines 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 goal targets while delivering strong financial results. As we look ahead, we anticipate growing demand for renewable energy to support AI data center and the transition to a cleaner energy future.
We believe we can secure improved product return through higher PPA pricing and tolling agreements, driving improved profitability for all. We look forward to continuing our multi-year growth paths 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.
Operators, please.

Question and Answer Session

Operator

(Operator Instructions)
Noah Kaye, Oppenheimer.

Noah Kaye

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 are really kind of tail end of the year. You mentioned some of the curtail and impacts, so. It kind of looks like we should assume a fairly modest, maybe low single digits increase in generation year every year or possibly flattish, but it also looks like that could set up perhaps something close to double digit growth in generation in '26.
Is that a fair way to think about it? How should we assume?

Doron Blachar

I know, thank you. I think you got it exactly right. We didn't have too many projects coming online at the beginning of. We do see all the enhancement that we're doing for the coming on towards the end of the year and we do see some more carts in the US than what we see in the past all in all. This year, as presented in the guidance is similar generation maybe a little. '26, the impact will be basically following the power plant coming online towards the end of the year that would have the the positive impact for '26, and all the projects that we've listed that will come on June 26th as well.

Assaf Ginzburg

Maybe a few more if you don't mind, I'll let a few more things, while the curtailment in the US, 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 one 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.

Noah Kaye

Embedded in the CapEx guide is a doubling year over year of exploration and kind of preliminary drilling activities. Can you just comment on that program a little bit? What would drive the the increase in activities and to what extent you would consider this kind of, truly early stage versus, something that could help accelerate the portfolio growth over say the next three to four years.

Doron Blachar

So we have been working to increase our exploration activity over the last year, and we've changed the way we approached the exploration starting in 21. Basically we're starting to focus on fours before really full-size wells. We've been drilling between 8 to 124 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 side. So this side and once the coal campaign is successful, and the work is successful, then we move to the pool side really. So it is our plan to increase exploration. We see the PPA rising above 100 today.
So we feel 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 pool size drilling.
And we expect that with the Trump administration we'll be able to get additional permits for full size and for constructing. The exploration that we are doing this year, previous year and obviously in the coming years, we have the growth coming in the following years, and we are focusing on many fields that was.
So of the development in the past, but nowadays we're focusing to increase and it kind of development. We want to increase our staffing in the US to support this growth. And we do see this and as we move forward and we will update the market policy once we confirm the.

Noah Kaye

Yeah. Just to get one more in. You talked about the 250 megawatts of potential PPA contracting with data center hyper scales, and the pricing expectations there. I think you mentioned on that you would expect those to be for off takes post 2028.
Can you just comment on a reasons for that timing? And be any kind of sense of expected 10 or length of the agreements. And possible location of agreements, is it, would be necessarily be for centers located near your production or would these perhaps be, more for let's call them sort of, virtual optics for plants located elsewhere in the country.

Doron Blachar

So the reason we're talking about falling 28 is if you remember three years ago we signed for the PTA with the energy and with the power that covers the field at 28. So we are actually looking for the duration after that.
On top of that, we just talked about the exploration. We believe these green fields will come to the end of '28 or probably the beginning of '29, some of them. So that's the place that we are looking, that's why we're talking following '28.
The ones that we are talking, some of them are looking for us to sign contracts with them with the local utility. Actually do direct negotiation with us using the system, the network to get the electricity.
We're not negotiating some decisions that will be the data center adjacent to our facility, but it is definitely something that we're looking across our fleet, and 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 some form.

Operator

Justin Clare, Roth Capital Partners.

Justin Clare

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 time frame beyond 2028 and into 2029 for geothermal, or can you extend the the storage safe harbor projects beyond 2026?

Doron Blachar

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 main project, there is much less than that, which means that all the drilling that just spoke about a few minutes ago that should enable us to add somewhere around 250 megawatts between 2027 and 2028.
All of that was already safe harbor. So when you talk about geothermal, we save harbor many projects that are not on the list. Everything that we're doing cohorts already or full sizes we also did that and we're also doing it through sale of equipment.
On the storage side, we are also, as we speak today, looking to get 4 more projects in addition to what you see on the list in Texas and California, and we already safe harbor 2 more projects that are not on the list, so there will be at least 6 more projects that are not on the list that will be safe harbored in the already harbored in the next few months.
And we will do it also through a start of construction. We will look at 2025. What else can we do in order to secure an additional 2029 project.
That's our goal.

Justin Clare

And then wanted to touch on the product segment here, wondering in 2025, are you expecting a meaningful contribution from the $210 million contract in 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 than previously expected. And then just wanted to touch on the margins as well. Product segment margin and Q4 very strong at 24%.
Can you talk about your gross margin expect, expectation for the product segment in 2025 and kind of what you're seeing in the backlog?

Doron Blachar

Thanks, one question. So when we have a very large product like that, it stands over 2.5 years, we started basically in November when we actually got the the notice to proceed, and the revenue is spread roughly evenly towards the entire period. So we see revenues from the TB project in '25 6 and 7 it went.
And so usually we will start, with engineering, then manufacturing, then the construction part and so 26 would probably be the higher with the most revenue out of the contract, but '25 has a significant amount of revenue from TB as well.
And regarding the margin that you said, I think we should look on the annual basis, quarter margins sometimes are impacted by specific projects that can do better or worse, depends on the situation.4 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.

Operator

Julien Dumoulin-Smith, Jefferies.

Hannah Velasquez

Hannah Velasquez on for Julien and thanks for the update and a 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 you? How would that get you potentially to the higher end of the range toward $593 million?
Is any contribution expected from the 2025 assets, or should we think about it largely driven by a full year contribution of the 2024 assets added being operational?

Doron Blachar

I think what will put us towards the higher end of the range in the electricity segment specifically it's not the addition of new assets. It's mainly the amount of curtailment we will experience in the US and in Kenya.
We've been told by NV Energy that they will replace the lat 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.
That's on one hand. On the other hand, in Kenya, the plant, as you already know, is very close to get to 150 megawatts, 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 always can impact us. I can tell you that in Q1, the weather was a little bit warmer than anticipated in.
On the electricity segment and we saw in February we just we are now in Reno, Nevada or close to it and it was quite warm. On the other hand, when you talk about the high end of the rage 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 are a 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 the 2026. Hopefully that answers the question.

Hannah Velasquez

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 repowering 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?

Doron Blachar

Thank you. The recontracting that we see is very mean tell you that the last the last re contracting that we did that we announced for recalpine for the mammoth G2 facility. The mammoth G2 facility and it's TPA at the end of '26, starting '27, the PPA with a little bit lower than the $70 per megawatt hour. The PPA that that we signed was over $100.
And so we see a big change and we signed a couple of years ago and portfolio PPA with the 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 hyperscalar willingness to look or include some indication to pricing that we didn't have in the past.
We still don't have any contract that we signed, but we are seeing a willingness to discuss it into the PPA, so it's a big will have a big impact going forward.

Operator

Derek Podhaizer, Piper Sandler.

Derek Podhaizer

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 as 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. It's just some help around the margin outlook and then how tariffs could be impacting this business?

Doron Blachar

As you can see, in general, 2024 we had around 10% to 11% amount in between the quarters. I would say that in general 2024 there were no significant weather events caused the fleet, and we only benefited from a bottleneck which buries a higher margin during the month of December.
That's when it fully operated. When we look at the 2025, we are experiencing more weather events already in January and February, and with the increased exposure in PJM with Montague 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 experience, 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 which is just the.

Derek Podhaizer

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

Doron Blachar

And if you think about our CapEx this year, for example, on storage, total CapEx on storage is expected to be $200 million. I would say at least half of it is the things that we bring from China.
So it will add some cost to our basically investment and taking 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 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 to sign a good tolling agreements to allow us to develop more projects.

Derek Podhaizer

And then you recently signed an MOU with 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?

Doron Blachar

So it's a very important demo from our perspective and I think also from SLB and it basically has two arms on one hand, SLB, one of the largest drillers has many customers that are drilling around the world and have access to potential geothermal sites. They are also owning geothermals, which is one of the consulting firms that deals with geothermal.
And then we do hope that through the customer base and knowledge of geothermics we will be able together to develop geothermal projects for is a customer.
The other part is the ES as EGS is significantly focused and looking on drilling costs, drilling technologies, and SV is in the forefront of this technology, and we are working with them to decide that the framework where we will together develop an EGS solution.
Deal with the technology challenges that EGF has today between our experience in the resource management and SLB experience in the drilling, we believe that we have a good chance to deal better than others on these technology challenges.
And then once we do find the right economical EGS solution to start developing PGS projects. It's a process that we are starting with today, these days, finalizing the framework and going forward. It won't have a shorter impact, obviously, but hopefully will have a mid impact and longer term a significant impact.

Operator

Jeff Osborne, TD Cowen.

Jeffrey Osborne

Just two quick ones on the the contract renewals that you mentioned with 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? I assume those would also be north of 100 megawatts an hour?

Doron Blachar

The other recontracting that we have until '28 actually goes through the Energy portfolio. These are contracts that have I signed with the energy and we signed them 3 years ago and the portfolio is in a smaller lower number around $70. However, still these are higher prices and what we have today in this.

Jeffrey Osborne

So no new renewals between now and '28. 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 got the timing right.

Doron Blachar

These were relating relating to Nevada. We have a contract in in California that we signed with SAA. That contract ends in February 26. And we are waiting for the final signature from SAA which should happen in the coming weeks, and that contrast on average is about $100. Again significantly higher than.

Jeffrey Osborne

And my last question was the, I forget what year it was, maybe '22 or '23, you made an acquisition that had a power line associated with it, and I believe you're trying to sell that power line or have been for a while. Is there any update on that? What potential proceeds could be --

Doron Blachar

We have the power line connected to the controlled substation which is 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 commercial details, but this is a process that we are doing and we plan to finalize it.

Jeffrey Osborne

And just a clarification, I think you mentioned the prepared remarks but I failed to hear it correctly. The, did you name the particular in the energy project that was being curtailed that's leading to the electricity shortfall in '25?

Doron Blachar

I don't think we named it, but it's mainly in Nevada. It's the Guinness area, the Guinness.

Operator

Ryan Levine, Citigroup.

Ryan Levine

What's, I guess two questions. What's changed from the company's prior stands to go through a regulated utility to this direct PPA with with the hyperscalar and then related, another IPP or another power company indicated $70 or $70 to $90 per megawatt-hour range for hyper steroid deals that 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 $100 per megawatt-hour number?

Doron Blachar

First of all, we are negotiating with the hyper schedule, as I said, directly, and also through the utility company. So we're looking at, both alternatives. And we're trying to maximize the growth and profitability of the company between these two aspects.
When we signed the PA, we basically sell with the PA all the attributes of the renewable energy, including the res 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 the other technologies. Our technology is emission free. Other technologies have emissions that also might have an impact on the price people are willing to pay. New power plants get -- we see a tend to get higher pricing and we contrasting many times. So there are various issues that can impact the pricing of the PPA, but but we say that with the pricing that we are negotiating above 100.

Ryan Levine

And just in terms of the duration, I think it was previously mentioned or or or clarified, but do those duration conversations include all attributes of the of the, 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 or any color you can share on that front?

Doron Blachar

Yes. All the PPAs that we have said all the attributes at the same time of the PPA. So the PA 10 years, it will be for 10 years, 15 or 20. And the duration of the PTA is based on the negotiations we have with a specific customer ranges between 10 to 20 years.

Operator

This concludes the question and answer session.
I'll turn to CEO, Doron Blachar for closing remarks.

Doron Blachar

Thank you all for joining us today. 2024 was another very good year for all.
We see the significant increased demand in the US 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.

Operator

This concludes today's conference call. Thank you for joining. You may now disconnect.