Enel Chile Q3 and Nine Months 2025 Earnings Call - Strong Operational Resilience Amid Dry Hydrology and Regulatory Developments

Carmen, Operator/Moderator: Good morning, ladies and gentlemen, and welcome to Enel Chile Third Quarter and Nine Months 2025 Results Conference Call. My name is Carmen, and I will be your operator for today. During this conference call, we may make statements that constitute forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Such forward-looking statements reflect only our current expectations, are not guarantees of future performance, and involve risks and uncertainties. Actual results may differ materially from those anticipated in the forward-looking statements as a result of various factors. These factors are described in Enel Chile’s press release reporting its Third Quarter and Nine Months 2025 results. The presentation accompanying this conference call and Enel Chile’s annual report on Form 20-F included under Risk Factors.

You may access our Third Quarter and Nine Months 2025 Results Press Release and Presentation on our website at www.Enel.CL and our 20-F on the SEC’s website at www.SEC.gov. Readers are cautioned not to place undue reliance on those forward-looking statements, which speak only as of their dates. Enel Chile undertakes no obligation to update these forward-looking statements or to disclose any development as a result of which these forward-looking statements become inaccurate except as required by law. I would now like to turn the presentation over to Ms. Isabela Klemes, Head of Investor Relations of Enel Chile. Please proceed.

Isabela Klemes, Head of Investor Relations, Enel Chile: Buenos días, good morning, and welcome to Enel Chile’s 2025 Third Quarter and Nine Months Results Presentation. We greatly appreciate you taking the time to join us today. My name is Isabela Klemes, and I’m the Head of Investor Relations. Joining me this morning is our CFO, Simone Conticelli. Our presentation and financial related information are available on our website www.enel.cl in the Investor section, as well as through our app, Investors. In addition, a replay of the call will be soon available. At the end of this presentation, there will be an opportunity to ask questions via webcast chat through the link Ask a Question. Media participants are connected in listening mode. Simone will kick off the presentation by covering key highlights of the period, our portfolio management actions, providing us updates on the regulatory context, and an overview of our business, economic, and financial performance for the period.

Thank you all for your attention. Now, let me hand over the call to Simone. Simone.

Simone Conticelli, CFO, Enel Chile: Thank you, Isabela. Good morning, and thank you for your participation. Let’s start the presentation with our main highlights of the period. Let’s begin with portfolio management. We observed a high-level performance of our thermal generation fleet, which helped us offset lower hydrological conditions during the quarter. This outcome reflects our ability to adapt to evolving market dynamics and maintain operational stability. In addition, our gas optimization activities continued to support our margin, reinforcing their strategic role in balancing our portfolio and mitigating exposure to spot market volatility. On the distribution side, we achieved successful implementation of the comprehensive winter plan aimed at strengthening grid resilience and improving service continuity under challenging climate conditions. Indeed, our performance in the period was one of the best in Chile.

The winter plan included the deployment of emergency crews strategically positioned in high-risk areas, extensive vegetation management action, and the installation of new telecontrol units to reduce restoration time. Additionally, targeted measures were implemented to support vulnerable customers, ensuring continuity of supply during adverse weather events. Now, let’s move on to the Chilean regulatory context. With reference to the VAD 2024-2028, a key milestone was the publication in the last weeks of the consultant report, followed by the preliminary regulatory technical report. I will give you more details about it. Furthermore, in October, was also released the preliminary regulated energy tariff report for the first half of 2026. Now, the Generation Association, of which Enel is a part, is working with authorities regarding the outcomes of the report. Looking ahead, two regulated energy auctions are scheduled for the fourth quarter of 2025. Let’s now turn to business profitability.

We closed the first nine months of 2025 with a stable EBITDA compared to the previous year, despite the difficult context and significantly lower hydrology, demonstrating the resilience of our operations. Our SFO remained positive, driven by the recovery of $261 million of receivable generated by the PEC mechanism. This inflow significantly strengthened our cash position for the year. As a result, we maintain a strong liquidity position, enabling us to support our development plan and to mitigate potential headwinds associated with the market and climate uncertainties. In the next slide, we will take a closer look at these topics to provide further insight, but let me anticipate that these achievements demonstrate our focus on operational excellence and sustainable growth. We remain committed to delivering long-term value to our shareholders while advancing in the energy transition and strengthening the resilience of our business.

Now, let’s move to slide four to talk about the energy market situation, especially regarding hydrology and gas opportunities. On the left side of the slide, you can see our hydro production over the last 10 years. For 2025, we set our target at 10.7 terawatt-hour based on the last 10-year average. Although 2025 has been a particularly dry year, our hydro production has remained in line with our strategic plan. This was possible thanks to the flexibility of our hydro plants, with access to hydrological basins. For this reason, we are keeping our hydrology guidance unchanged. To manage this dry scenario, we relied also on the flexible and competitive thermal fleet, supported by strong and diversified LNG and Argentine gas supply. This helped us respond quickly to market needs and reduce exposure to hydro volatility.

As a result, we increased thermal production, using competitive gas and seized favorable trading opportunities, adding $74 million in margin during the first nine months of 2025. Regarding gas business, in October, we completed a gas sales to Europe with margins similar to those recorded in the second quarter of 2025. Looking ahead to 2026, we are evaluating the option to secure competitive gas from Argentina through firm contracts in line with the past year’s strategy. Now, moving on to slide five, let’s review our generation portfolio and energy balance. During the first nine months of 2025, net production decreased by 9% compared to the same period of 2024. This decline was driven by lower hydro dispatch during the first nine months of 2025. Reduction in renewable energy production due to the maintenance of two solar plants, and higher curtailment levels also caused by transmission line limitations.

These effects were partially offset by higher contribution from the efficient CCGT. The same factors impacted the third-quarter generation that amounted to 5.4 terawatt-hour, lower by 1.1 terawatt-hour versus the same period of 2024. Energy sales reached 22.7 terawatt-hour, mainly due to the lower sale to regulated customers following the expiration of regulated contracts. The regulated contracts’ volume reduction is also the main cause for the decrease of the third-quarter sale from 8.4 to 7.6 terawatt-hour. I would like to take a moment to review an important milestone in the resilience program of our distribution business. We are pleased to share that we successfully implemented a comprehensive winter plan aimed at strengthening the stability of our grids and guaranteeing service continuity during the most challenging months of the year, particularly for our most vulnerable customers. First of all, we deployed 376 emergency crews across our service territory.

These teams were mobilized to respond to outages and restore power. One of the most impactful initiatives was the execution of more than 115,000 tree trimming actions, which significantly reduced feeder failures in areas exposed to severe weather. We also modernized the grids, installing new telecontrol units. This helped us to isolate faults and reduce service interruption time. In parallel, we implemented several infrastructure upgrades that enhanced network reliability and quality of service for more than 193,000 customers. Supporting vulnerable customers remained a priority for Enel Chile, so we assisted more than 3,000 electrodependents, ensuring continuity of supply through targeted measures. Among them, more than 2,000 were equipped with digital meters, while almost 2,900 received backup power solutions, such as generators or battery systems. Finally, we strengthened the collaboration with municipalities to improve coordination during extreme weather events. This joint approach has enhanced emergency response capabilities.

All these efforts translated into tangible improvements in the performance of our distribution network, with results that clearly demonstrate the effectiveness of the winter plan. Now, let’s take a look at slide seven, where we highlight key updates on the energy regulatory context. In 2025, we saw key changes in the regulatory framework. The distribution cycle for 2024-2028 is under development. In September, the consultant final report was published. In October, the CNE released its preliminary technical report with changes in maintenance and technical standards. Companies have until the 10th of November to submit comments. The final report is expected in 2026. In parallel, we are currently awaiting settlement of outstanding debt related to the VAD decree for 2020-2024, published in April 2025, that is expected to be settled in 2026.

Passing to generation business, on the 14th of October, the CNE published the preliminary technical report for the first half of 2026. It includes a correction related to the inflation effects. We are reviewing the impact and waiting for the final report. Passing to the stabilization mechanism, as of September 2025, we have $149 million PEC-1 receivable to be fully recovered by the end of 2027. Going to other relevant topics, in August, came into effect a resolution on BESS remuneration that authorized the BESS to provide ancillary services. In the last week, changes have been introduced in 2025 regulated auctions, increasing the volume of the 2027-2030 auction from 1.7-3.4 terawatt-hour per year. The offer deadline is now the 14th of November. Launching a 1.5 terawatt-hour per year short-term auction for 2026. The offer deadline is the 2nd of December.

Finally, regarding subsidies, the third electricity subsidy round ran from the 3rd of June to the 15th of July, covering the period from July to December 2025. Around 341,000 Enel distribution customers benefited from it. A bill to expand the subsidy is still pending in the Congress. Now, I will start reviewing the alliance of our financial performance over the period. Before we review the results, a quick reminder. As of January 1, 2025, Enel Chile changed its functional currency from Chilean pesos to US dollars. For comparison, nine months and third quarter 2024 figures are shown using the average exchange rate of these periods. I will enter into details of our financial and economic performance in the next slide. Let’s move to the next slide to look at the progress made on CAPEX.

Our total CAPEX reached $245 million during the first nine months of the year, maintaining a focus on grids and power plant fleet performance. Let’s review the allocation in more detail. 41% or $101 million was directed towards grids investments. 31% or $76 million supported thermal power projects. 27% or $67 million was invested in renewable and storage. Regarding grids, the focus remained on the resilience program to strengthen the grids and ensure service continuity under adverse weather conditions. In the thermal segment, the priority is the maintenance and performance enhancement of the power plant fleet. In the renewable segment, we have centered our efforts on finalizing the PMGD program, enhancing hydro facility performance, and maintaining fleet availability. Now, let’s move on to the breakdown by Nasher.

Asset management CAPEX totaled $139 million, accounting for 57% of total CAPEX, mostly used for the maintenance of Atacama, Quintero, and San Isidro CCGT. The improvement of renewable fleet availability and corrective maintenance and digitalization of grids. Development CAPEX was $60 million, mainly driven by investment for grid reliability enhancement, digital meter programs, and telecontrol deployment. And for the completion of the 2024 investment program for PMGDs. The 2025 development CAPEX for battery-related projects will be recorded starting from the next quarter. Finally, customer CAPEX totaled $46 million, mainly invested in low and medium voltage connection projects and initiatives to support load increase. Let’s now turn to the next slide, which provides a closer look at our EBITDA performance. During the last quarter, our EBITDA totaled $345 million, representing a decrease of $63 million compared to the same period of 2024, mainly explained by the following factors.

Starting with the generation business, we recorded a decrease of $89 million in PPA sales, mostly due to the termination of some high-price regulated contracts that impacted on volumes and average price of the regulated portfolio, partially offset by the negative impact of exchange rate hedges recorded in 2024. Regarding sourcing, its contribution remained in line with the same period in 2024. This result was mainly achieved thanks to our optimized sourcing strategy and the issuance provision, mainly coming from Gas Atacama, which effectively offset higher costs in the energy spot market, mainly due to the higher purchase volume. Gas trading contributed positively with a $5 million margin increase, mainly fueled by expanded trading activities in the third quarter of 2025.

Turning to grids, we recorded a positive impact of $70 million, mainly driven by a regulatory provision reflecting the settlement adjustment for the previous year and higher OPEX recorded in the third quarter of 2024 due to the extreme weather events that occurred in May and August. These effects were partially offset by the increase of OEM expenses, mainly associated with the implementation of the comprehensive winter plan. Now, let’s move on to the next slide to review the main impacts on EBITDA during the nine-month period. Our EBITDA reached $1,004 million, remaining flat compared to the same period of 2024.

Starting with the generation business, we recorded a decrease of $244 million in PPA sales, mainly due to the termination of high-price regulated contracts, partially offset by the negative impact of exchange rate hedges recorded in 2024 and the positive price effect due to the indexation of the free market contracts. Regarding sourcing, we recorded a positive effect of $192 million despite the $34 million negative impact related to the transmission line restriction following the February blackout and the additional second quarter issues. The result was obtained thanks to lower spot and third-party energy purchase costs, energy settlements from previous periods, already anticipated insurance provision, and finally, lower transmission costs. In the first nine months of 2025, gas margin contributed for $27 million, also thanks to the increase of the gas trading activity versus the same period in 2024.

Passing to grids, we recorded a positive impact, primarily driven by the provision reflecting the higher tariff expected for the 2024-2028 regulatory period and tariff indexation, some settlement adjustment from the previous year, higher OPEX recorded in the period 2024, mainly due to the extreme weather events, partially offset by the increase of OEM expenses, mainly associated with the implementation of the comprehensive winter plan. We also recorded an increase of generation costs due to the new developed capacity and the maintenance activities. Finally, in 2025, specifically in the second quarter, we recorded the personal cost one-off effect, mainly for the incentivized early retirement plan to support the company organization aimed at improving internal skills and performance. Now, let’s move on to the next slide, where we will review the net income evolution.

Our nine-month 2025 net income reached $352 million, a 21% decrease compared to the last year figure, mainly explained by higher depreciation, amortization impairment, and bad debt expenses for $84 million, mainly due to the commissioning of new renewable capacity amounting to $32 million, the impairment related to our decision not to proceed with the new PMGD solar project initially planned for development in this area, and finally, the $12 million increase of grids bad debt provision, mainly due to the higher billing resulting from tariff increase and longer overdue customer debt. Regarding financial result, we recorded a negative variation of $38 million, mostly explained by the lower capitalized expenses on renewable projects by $61 million, partially offset by lower financial expenses for $29 million, resulting from lower average outstanding debt and lower average interest rate.

The latter was partially offset by a $20 million reduction in corporate income tax expense, mostly explained by lower results. Focusing on the quarter, net income decreased by $74 million, mainly due to a $63 million decrease in EBITDA, a $29 million increase in depreciation, amortization, and bad debt, primarily due to the operation of the new renewable capacity, and an $11 million increase in financial results, mainly due to the lower capitalized expenses on renewable projects. The latter was partially offset by a $23 million reduction in corporate income tax expenses, mostly explained by lower results of the period. Now, let’s move on to the FFO analysis on the next slide. Let’s analyze the FFO composition for the first nine months of 2025 and the main effect compared to the same period in 2024.

Our FFO reached $615 million, representing an improvement of $248 million compared to the previous year. This is due to the following factors. First, EBITDA totaled $1 billion. Remaining flat compared to the same period last year, as previously explained. Second, the recovery of PEC receivable in 2025 contributed for $285 million, mainly thanks to factoring executed in April 2025, related to PEC 2/3, and recovery through the tariff of $31 million of PEC 1 receivable. It is worth mentioning that we observe a positive FFO variation of $248 million versus the nine months 2024, thanks to the end of accumulation of PEC receivable started in October 2024. Third, the increase of net working capital impacted for $329 million, mainly due to the 2024 development CAPEX payment, lower collection in our distribution business, and other seasonality effects.

The increase was higher by $255 million versus the previous year, mainly due to the negative effect of energy payment scheduling and the voluntary compensation paid in 2025 regarding the extreme climate event from May and August 2024. These effects were partially offset by lower CAPEX payments related to the new renewable capacity. Fourth, the income taxes impacted on FFO amounted to $231 million, mainly due to the tax payment in the generation business. Income taxes paid in the nine months 2025 were higher by $63 million compared to the nine months 2024. This difference is mainly due to the increased tax payment in the generation business, driven by both higher results and higher monthly payment tax rates. Finally, financial expenses were $113 million, mostly due to the debt-related costs.

These represent a reduction of $52 million compared to the nine months 2024, mainly driven by a lower average debt this year. Now, let’s take a look at our liquidity and leverage position. Our gross debt is $3.9 billion at the end of September 2025, in line with the gross debt as of December 2024. The average terms of our debt maturities decreased from 6.2 years as of December 2024 to 5.5 years as of September 2025, and the portion at the fixed rate is 87% of total debt. The average cost of our debt reached 4.8% as of September 2025, decreasing from 5.0% in December 2024, in line with our efforts to optimize the financial costs. Regarding liquidity, we are in a comfortable position to support our capital needs for the upcoming months and cope with the next year’s maturities.

As of September 2025, we have available committed credit lines for $640 million and cash equivalent for $373 million. Now, I would like to share the following closing remarks. In the coming months, significant regulatory updates are expected that will clarify tariffs and market mechanisms. These represent an essential step to refine our long-term strategy and to ensure that our investment decisions remain aligned with regulatory developments. We are implementing proactive initiatives to address portfolio dynamics and climate challenges. These include actions to strengthen our generation and distribution businesses, improve risk management, and enhance our ability to respond to extreme weather events. The measures are designed to safeguard service continuity and maintain system stability.

Our solid financial position and flexible business model allow us to follow with our business plan even through market uncertainties while continuing to invest in strategic renewable and best projects and deliver sustainable returns for our shareholders. Finally, we are preparing for our 2026 Investor Day, scheduled for the first quarter 2026, where we will share a comprehensive view of our strategy and the actions that will drive long-term value creation. Now, let me hand it over to Isabela for the Q&A session. Thank you, Simone. Now, let’s move on to the Q&A session. We will be taking questions via chat through the webcast. The Q&A session is now open. Okay, Simone, the first question is coming from Rodrigo Mora from Moneda Patria. Rodrigo has four questions, so I will be talking one by one, okay?

The first one is, what is the amount that Enel Chile must return to customers due to the miscalculation of the CNE included in the first half of 2026 CNE report? Thank you, Rodrigo. Just to give some context, in the first half of October, the CNE explained that they have changed the formula for the calculation of the CNE. This change in the formula will have some impact. We have calculated the impact for Enel in an amount that is between $40 million and $45 million. We have to expect a negative provision in terms of mainly financial costs. The impact will be mainly in the financial items. In your question, you talk about customer, but in any case, just to comment that the customer was impacted just for a small amount because just 2% of the total amount of the changes was transferred to customer in the tariff.

This amount will be accrued by Enel in 2025, and then we will pay back. In this moment, the process is not so clear, but in any case, we expect in the first half of 2026. The amount will not impact directly for the total value of the customer. Thank you, Simone. The second question now is on Enel distribution. What is the amount owed to Enel distribution Chile in connection to the VAD 2020-2025 freeze? Talking about the remuneration period 2020-2024, we are really now finalizing the last steps of the process. The amount was already defined, and what we are waiting is that the SEC will say when we have to receive back the missing part. The amount in this case is around $50 million-$55 million. There are two possibilities.

If you want to be prudent, you can imagine that the cashback can start middle of 2026, even if I remember an interview of the new Minister of. Energy that said that the process can also be faster and start earlier. Okay, thank you, Simone. Now let me check here. We have the third question. The third question of Rodrigo now is on generation side on the LNG strategy. Could you please explain about your strategy regarding LNG and Argentinum gas? Firm or interruptible for the year 2026, how many ships do you plan to buy? As you know, for us, the gas business is a very important business because we need gas for our thermal power plant, but also because we find during the year some creative opportunities to make margin to our gas contracts. We have basically a long-term gas contract for LNG.

More or less, the volume relative to this contract for a year is something more than 30 to terawatt-hour per year. In 2026, we will keep on using this contract. In these very days, we are working, we are negotiating with an Argentinian supplier to a new contract for Argentinum gas. In this moment, I cannot talk about this negotiation. The negotiation is ongoing, and it has not been finalized. Okay, thank you, Simone. Now, the last question of Rodrigo is regarding CAPEX on generation business. Regarding CAPEX for generation, could you please give us an update for 2025? Actually, we also received the same question from Balance as well. Very well.

Talking about this year, CAPEX, as you know, we followed the plan with one exception that was the CAPEX for the development of the new BESS system because we recorded a little delay for this project, and it was due to strategic reasons. I mean, we waited to have the new piece of regulation related to BESS, the regulation for the participation of BESS in the ancillary service market. We keep on studying the evolution of the market and the penetration of the BESS in the Chilean production system. We started a little bit late in the project, and in the first report, the amount of CAPEX related to the project was reduced compared to the expectation. The project has been already started, ongoing, and you will see in the last quarter, in total, talking about HGP and generation, investment for more or less $150 million-$160 million.

A part of this investment will be the BESS, at least $50 million. We keep on going also investment on thermal fleet. How strategic is the thermal fleet? Of course, in case of low water in the system, our efficient CCGT plants are called to produce, and we have to keep on these plants at the highest level of efficiency and performance. Okay, thank you. We have a final one. Sorry, Rodrigo. We have five questions from Rodrigo Mora. The last one is on distribution side, okay? On distribution, could you outline the measures being taken to address the increasing energy losses? Okay. Talking about losses in energy. We have discussed that the losses are getting higher in the last two years, starting from 2023. In this moment, the percentage of losses is a little bit higher than 6%. Which is the reason.

There can be many reasons, but the most important reason is the increase in the tariff. The bid to the final customer. A little bit a change in habit related also to this increase in tariff. What we are doing. From one side, we are increasing the activity to recover these losses. We have recovered more than expected in the initial planning related to losses. On the other side, we are making other actions. For example, launching flexible claimant plans for the customers that want to pay the new bill. We have a new smart expansion tool. We work on formulas to localize where the losses are originated. Then we can intervene. Finally, we are working with the regulator to try to find changes also in the regulation that can help to contain this phenomenon. Okay, thank you, Simone. Now, move on. We have questions from Javier Suárez from Mediabank.

Thank you for the question. The question is, is the company Enel Chile confirming its latest guidance? The answer is simple. It’s yes, but just some context. This was a very tough year in terms of hydrological situation. Finally, the season was drier than expected. In any case, we show our flexibility as a company. We leverage on our very profitable gas contract. We use the flexible and efficient CCGT. We have those effects. We maintain high production also. Our hydropower plant can use reservoirs. Also, the production for Enel did not decrease so much. Given all this action and the flexibility the company built in the past year, we can react to these adverse climate conditions and achieve—well, achieve. We can confirm the result for the year. Okay. Thank you, Simone. Move on. The next one is also from Javier Suárez, Mediabank. It’s about the FFO.

Could you explain the dynamics of FFO during the nine months of this year and your expectation by the year-end? Okay. Talking about the FFO, talking about our business, the FFO usually is concentrated in the second half of the year, and particularly in the last quarter. The main reason is that EBITDA is higher in this period. This year, in the first nine months, in any case, we had a very high level of FFO. This was thanks to the not ordinary cashing from back regulatory process. We cashed in around $300 million, recovering cash credit from the past. Looking ahead, the cash flow from ordinary business will be higher compared to the first months. In the last period. Also, we will have more efficient management of the networking capital because in the last part of the year, the CAPEX are focused in the last part of the year.

Also, the networking capital can be managed in a more efficient way. We expect to improve the performance of FFO in this last quarter, which is more or less the dynamic. Okay, perfect. Now the next question is coming from Fernando González from BTG Pactual. Fernando is talking about the BESS, the storage that we are implementing. I will read here. I saw that BESS Las Salinas, 200 megawatts, and BESS Acebache, 58 megawatts, were declared under construction at the CNE. Do these projects involve additional solar capacity or just the energy storage? There are still an additional 200 megawatts of BESS capacity to meet your announcement plan. Will this be added to existing solar PV in the north? Simone? Yes. Talking about the strategy of BESS, we have launched three projects this year in line with what was expected in the plan. This project is a hybrid project.

We are going to implement BESS system in our solar power plant in the north. Why do we do this? In general, the BESS can be profitable, also like a standalone device. The profitability is higher if you use the BESS system to hybridize our power plant. Why? Because the project is faster. You need less environmental documents to be produced considering that you are building the BESS in your plan. Also, we have some savings in terms of cost and electrical infrastructure. I think that I have answered the question at this moment. We are not increasing the solar capacity. You are just hybridizing solar projects. Okay. Let me check here. We have another one from Tomás Peruchín, Balance Capital. Part of the question was already answered, so I will just keep the one that was not yet. Thank you for the presentations. He has one question.

If I’m not mistaken, you had a target for 2025 of $500 million for expansion projects, mainly relating to batteries, to storage. How has that changed by now, given that you are expecting a resolution on auxiliary services before moving forward? Was the resolution in line with your expectations? Do you think it will be enough to unlock higher investment in storage? Thank you. Okay. In our current power plant, we put more or less 600 megawatts of new capacity. You are right, 450 are related to BESS projects. This BESS project should have been launched at the beginning of the year and was launched in the second half. You can expect a movement also of the COD. The original COD was in 2026, in the second half. The new COD will be in 2027. This will have an impact.

But in any case, we start from a fleet of around 9 gigawatts of production, and this change is not a huge change. Talking about regulation, on August, the 4th of August, there was launched this new regulation that said BESS can participate in ancillary service month. It means that this is very good news for the country because the BESS are a very important element that can stabilize the system at a very low cost. Reducing the cost for the system is also reducing the cost for the participant. In terms of revenues, it is not a huge increase, but it is in line with what we expected. Talking about the current BESS that we have, the two hour BESS that we have already installed, it means something among $5 million-$7 million per year.

In any case, it is an important step because it permits to make the BESS project a little bit more profitable than considered in the beginning. It means that they are profitable also imagining a higher penetration of BESS projects in the future. Okay, perfect. We have the last question that is from Edward Palma from Itaú Asset Management. The question is, do you have any news for unregulated PPA contracts? Unregulated, in this moment, no, we do not have any news related to this topic. Okay, perfect. Let me just check if we have no more questions. Okay. If there are no further questions, we formally conclude our conference call. The investor relation team is at our disposal for any further inquiries. Many thanks for joining us and have a great rest of the week. Thank you. Ladies and gentlemen, this concludes our conference. Thank you for participating.

You may now disconnect.