Good afternoon, everyone, and welcome to ENGIE Energía Chile's Fourth Quarter, 2023 Results Conference Call. If you need a copy of the press release issued on January 31st, it is available on the company's website at www.engie-energia.cl. Before we begin, I would like to remind you that this call is being recorded, and that information discussed today may include forward-looking statements regarding the company's financial and operating performance. All projections are subject to risks and uncertainties, and actual results may differ materially. Please refer to the detailed note in the company's press release regarding forward-looking statements or contact Investor Relations Officer, Marcela Muñoz. We would like to advise participants that this call is dedicated to investors and market analysts and not for the press. We ask all journalists to contact ENGIE Energía Chile's PR department for details. I will now turn the call over to Mr. Eduardo Milligan. Please go ahead, sir. Thank you. Good afternoon to everyone. Today I'm here with Bernardita Infante, Alison Saffery, and Marcela Muñoz. We will present ECL results for 2023, together with an updated guidance and business plan for the next two years. We can start directly on page 3. In this page, we are highlighting the main elements and drivers that we will discuss today. Among them, the positive evolution on fuel prices, its positive impact on production costs, and their impact on PPA energy prices through their indexation formula. Also, the evolution of our transformation plan with new renewables and additional hedges, or what we call backup PPAs, to reduce risk. Then, how we managed to supply LNG in 2023 and our plan for 2024. Of course, where we are with the Tariff Stabilization Law, also known as PEC, and its expected evolution for 2024. As you know, this law has an important impact in our liquidity. And as of December, we have accumulated approx $300 million of receivables that are ready to be monetized during this year. And finally, as you have probably seen, the status on the storage batteries projects that we are rapidly implementing, that all combined will provide more than 250 MW during 5 hours. So these batteries are key during non-solar hours to reduce risk and exposure to high spot prices. Let's continue on page 4, that shows the evolution on ECL physical sales. There is a positive evolution on regulated sales, which increased 6% compared to previous year. This increase in demand is, of course, good news, and is in line with our view on regulated demand evolution for the future, which is expected to increase over time, since there is still room in the contracted capacity of the former central-south regulated PPA. Then on page five, we can see the evolution on spot prices. The Chilean market moved from an average $127/MWh in 2022 to an average of $87/MWh in 2023. In fact, the average spot price in the fourth quarter of 2023 averaged $37/MWh, which is almost 60% lower than the same quarter of 2022. Moving into 2024, the average spot price in January remained stable, below $45/MWh, explained by close to zero spot prices during several solar hours and approx. 70 $/MWh during non-solar hours. This trend is mainly explained by a material improvement in rainfall and snow accumulation, together with lower coal prices and the commissioning of new renewables, and is certainly positive for the overall system and for ECL's energy margin. We can see the detailed evolution on hydrology conditions in next page 6, which shows a material improvement compared to all previous years. As of the end of December 2023, the accumulated probability of exceedance is 58%, compared to an average of 95% in previous two years. So this better hydrology, together with new renewables and lower fuel prices, are currently setting spot prices during solar hours close to zero, and spot prices during non-solar hours, as I mentioned before, close to $70/MWh. This is reflected in the daily average spot price of approx $40-$45 in most of the system nodes. In terms of volume, this means that the system started with a 2.2 TWh more of accumulated energy in the different reservoirs, and this additional water will help to keep spot prices under control until the new hydrologic year starts. On page 7, we can see the positive evolution on coal prices. After hitting all-time highs in 2022, coal prices first returned to an average of $130-$140 per ton, while in the last months, coal price continued to decline to stabilize again at around $100 per ton. At $100, the production cost with a coal power plant decreases to the $50 now at our range. Coal futures in this line have remained at such levels in the recent months, which is also positive for the future spot price. Since, as you know, gencos are starting to buy coal to be delivered in the future at these new levels. This also means that electricity produced with coal is again cheaper than with spot LNG. Of course, we need to bear in mind that coal power plants are less flexible than CCGTs running natural gas, which are currently key to provide flexibility and support the system during the ramp-up and non-solar hours. Next, page 8 shows the evolution on coal power plants availability for the overall system. Again, other positive element for the system is that coal power plants availability remains stable at around 3.5 gigawatts in 2023, and didn't continue its decreasing trend. Now, please, let's continue on page 9 to discuss about LNG and natural gas. The graph on top shows the evolution of international LNG prices. As we explained in the previous quarter, the evolution on LNG international indexes allowed us to import spot LNG and partially mitigate the lack of LNG that was not delivered by our supplier, but of course, at much higher costs. Then the graph below shows the LNG sourced through firm long-term contracts, and the natural gas coming from Argentina that is arriving between October 2023 and April 2024. This natural gas is imported through ECL's pipeline in the north of Chile. Then on the LNG side, as we explained in previous calls, we have two long-term contracts for an aggregated volume of 23 tera BTU per year. In 2023, one of these contracts was confirmed by our supplier for about 10 tera BTU out of the 23, while the second contract with a volume of about 13 tera BTU was not confirmed, and therefore, we didn't have that volume available for our CCGTs, and we had to buy LNG in the spot market at higher costs. Now, for 2024, we confirmed to the GNL Mejillones terminal that in 2024, our LNG supplier will be delivering the full LNG volumes that are contracted with ECL. This means we will have the full 23 tera BTU available in 2024, and we will not need to buy LNG in the spot market. Next, page 10 shows an update on the hedges or backup PPA signed with other gencos. This page shows an additional volume of backup PPA signed for 2024 and 2025. Vis-a-vis the information we shared in the previous quarter. In summary, we'll have 3.6 terawatt hours for 2024, and average 3.5 terawatt hours between 2025 and 2026. As you know, the purpose of these PPAs is to hedge our exposure to material changes in the spot market, and vice versa for the other gencos. Page 11 shows a graph with the energy sources and average supply costs for the portfolio. As we explained before, our main immediate objective is to rebalance our portfolio of PPAs and supply sources to first bring stability and results, and then to reduce risks and exposure to spot market volatility, while, in parallel, being prepared to sign new PPAs for the future. In 2023, fuel costs decreased 9%, and costs mainly declined in the second half of 2023 due to falling fuel prices and improved hydrologic conditions. On next page 12, we present the supply-demand curve for the overall portfolio of PPAs and supply sources. The average energy price of our portfolio of PPAs reached $144 in 2023. As you have seen each quarter, downstream prices declined gradually, and this decrease is mainly explained by the indexation on lower fuel prices, together with a specific indexation lag on the regulated PPAs. On the other hand, the average supply cost reached $95, compared, for example, to the $137 we had in the first half of 2023. This means both PPA prices and the average supply costs materially decreased compared to the second half of 2022 and the first half of 2023, but the reduction in the average supply cost was bigger. This also explains the energy margin reached $49 in 2023, almost $50, and this is very close to the average energy margin ECL had back in 2020 or even 2019. Now, now we will continue with Bernardita, who will present the detailed financial results and action plans to improve ECL's leverage and liquidity. Well, thank you, Eduardo. Good afternoon to everyone. So let's go to Slide 13 for a look at financial highlights. EBITDA more than doubled, reaching $403 million. So total revenues increased 14% to $2.2 billion, mainly as a result of a 3% increase in average prices, since physical sales remained pretty stable overall at about 12 terawatt-hours. Gas sales also increased significantly, as in 2023, the company bought enough LNG volumes to generate electricity at its own plants, and through a tolling agreement with another generation company, as well as to sell gas to other companies. But the most relevant cause for the EBITDA improvement was the decrease in operating costs. On the one hand, fuel costs fell 9%, mainly due to the reduction in coal generation, explained by the IEM outage and the lower dispatch of coal plants in the second half of the year, due to improved hydro conditions in the system. This offset the effect of the use of high-price coal stocks built up in 2022. In 2023, we succeeded in our efforts to reduce our exposure to the spot market during non-sun hours. We had a more balanced position, with a 47% increase in renewable generation and a 54% increase in backup PPA volumes. This together explained a 1.7 terawatt-hour reduction in our exposure to the spot market. During the year, we bought LNG on the spot market to cope with the unfulfillment of one of the two long-term gas supply agreements by our main LNG supplier. Gas generation, through a tolling agreement with another generation company, allowed us to reduce our net exposure to the spot market by another 1.3 TWh. Spot prices decreased because of improved hydro conditions in the second half of the year, and also because of a decline in international fuel prices. Therefore, our average direct cost of electricity sold reached $95 per MWh, down from $114 per MWh in 2022. In 2023, net income was affected by non-cash asset impairments, just as it was in 2022. The difference is that in 2023, the company would have reported net income of $89 million, had it not been for the one-offs, while in 2022, we reported net losses before the one-off effects. Our net debt, excluding IFRS 16 leases, increased significantly in 2022, as we had to finance capital expenditures, as well as heavier working capital needs due to the steep increase in fuel prices, while the Price Stabilization Law compressed our liquidity. Net debt reached $1.65 billion at year-end 2022. In 2023, we have been focusing on reducing our leverage ratio while extending the average maturity profile of our debt. So in spite of the continued CapEx required for our transformation program, our net debt at the end of December increased by $200 million to $1.8 billion. Now, Slide 14 shows the reasons behind the EBITDA recovery. The reduction in net energy purchases from the spot market contributed $190 million to 2023 results, while the lower fuel costs contributed $57 million. In the first half of 2023, average realized prices captured the increase in fuel prices and inflation observed in 2022, while they started to decrease in the second half of the year. Overall, during 2023, average realized prices increased by $4 to $144 per megawatt hour, accounting for a $38 million positive effect on EBITDA. The increase in physical sales, explained by higher demand from regulated clients, which compensated for the decrease in free clients, contributed $24 million. Among the factors that caused a reduction in EBITDA, we can mention $37 million explained by an increase in net capacity purchases, a $27 million reduction in the margin on the gas and transmission businesses, and a $30 million increase in OpEx and SG&A expenses, mainly related to the addition of new renewable assets and development costs. All of this explains the $214 million increase in EBITDA, which reached $403 million. Slide 15 shows the evolution of our net results. If we look at the center of the slide, we can appreciate the turnaround in net recurring results, which climbed from a $52 million loss in 2022 to an $89 million profit in 2023. This was due to the strong EBITDA recovery, only partly offset by an increase in interest expense, explained by the increase in debt and interest rates. In both years, we reported heavy one-offs. In 2022, we reported a $325 million after-tax impact from impairments and an $11 million in interest expenses related to the sale of PEC one receivables. In 2023, we reported a $9 million after-tax effect on the sale of PEC one receivables and a $491 million after-tax effect from additional asset impairments related to coal assets, which will stop working under the current conditions beyond 2025. This led us to report a $411 million net loss in 2023, despite the good operating performance. In slide 16, we see the status of our net debt, which increased by almost $200 million to $1.8 billion after financing CapEx of $524 million. This moderate increase in net debt, compared to the investing activity, was possible due to the strong operating cash flow generation, which reached $507 million. We have added a new slide, number 17, to show the effects of the price stabilization laws, which have been effective since late 2019. So here we can see that over the three-year period, ended December 2023, the company accumulated accounts receivable for a total amount of $650 million, on top of the $142 million initial balance reported at the end of 2020. All this represented sales revenue that could not be collected because of the enactment of price stabilization for regulated consumers. Thanks to the PEC One monetization program, structured by the Inter-American Development Bank and Goldman Sachs, the company could collect cash proceeds amounting to $193 million over the period, and had to bear financing costs of $79 million, as these receivables were sold at a discount. PEC Two notes began to be sold in 2023. Under this program, we collected $221 million in cash, plus $11 million of interest income, which contributed to alleviate liquidity pressures in 2023. At the end of the year, the account receivable balance amounted to almost $300 million, of which we could expect to sell around $50 million under the remainder of the PEC Two program, until it reaches the $1.8 billion cap stipulated by law. A PEC Three program, which is similar to PEC Two, is currently being discussed and is expected to be enacted during 2024. Now, let's move to Slide 18. Our BBB stable outlook ratings were confirmed by both Fitch and Standard & Poor's. Our net financial debt reached $1.8 billion at the end of the year, with net debt to EBITDA down to 4.6x after the record-high 8.7x reported at year-end 2022. We have continued making progress in our debt profile objectives. First, to reduce net debt to EBITDA through EBITDA recovery, with moderate increases in net debt, despite the financing of capital expenditures in renewable and transmission projects. Second, to fund the construction of the Lomas de Taltal wind farm and the BESS storage projects, whose objectives are to reduce our costs, our exposure to the spot market, and the curtailment and intermittence risks associated to renewables. And third, to extend the maturity profile of our debt. On the bottom left corner of the slide, we show the maturity schedule of our debt as of the end of December. In December, we made the second $200 million disbursement under the ten-year IFC loan, and ended the year with $300 million in cash balances. As noted, in a little note below the chart on the bottom left corner of the slide, of the 2024 maturities, we have already extended the maturity of a $50 million loan through 2026, and repaid another $30 million loan. We have also started working in the refinancing of the $350 million 144A bond, maturing in January 2025. The PEC and the IFC transactions are helping us to reprofile our short-term debt and to finance the CapEx needs for 2024. So now, I'll leave you with Eduardo, who will brief us on the recent events and action plans. Thank you, Bernardita. The actions mentioned on page 19 explain the improved operational performance in 2023. So first, as we mentioned before, we secured 24 terawatt hour of LNG, together with a tolling agreement with other CCGT. IEM returned in operation after an important failure in its transformer. Then we secured additional backup PPAs for 2023, 2024, and even until 2026. Fourth, in 2023, we reached almost 1 terawatt hour of renewable generation, and this comes with an important effort to combine batteries with our existing solar PV power plants. In 2023, PV Coya, or BESS Coya, that was added to PV Coya, reached its full capacity, and we are just waiting the formal COD from the market coordinator. While we launched the construction of two additional projects to install batteries in existing PV solar plants, Tamaya and Capricornio. Between these three storage systems, we will have around 250 megawatts during 5 non-solar hours, that are equivalent to slightly more than 1.3 gigawatt-hours per day, to support our portfolio and the system, mainly during non-solar hours. As a result, as we highlight below, the spot exposure during non-solar hours decreased to 1.5 terawatt-hours in 2023, which is materially below the 2.5 terawatt-hours we had in 2022. For 2024, we expect an additional reduction with more renewable generation, additional natural gas, the contribution from batteries, and of course, the additional backup PPAs. As we explained in previous quarters, we are highlighting the exposure during non-solar hours, because this is when spot prices could be out of control under certain circumstances, like the ones the system experienced in 2022, and this is the risk we need to tackle in the rebalancing of our portfolio. On page 20, we are presenting the evolution of our investment plan and the committed CapEx for 2024 and 2025. Once we complete the three projects that we have currently under construction, that are wind, the Taltal, and the batteries added in Tamaya and Capricornio, solar plants, we will have reached 1.4-1.5 gigawatts of renewables plus batteries, and we expect to reach our ready-to-build status in other projects very soon. Page 21 presents the detailed CapEx by type of business. We invested $750 million in renewables, plus batteries between 2022 and 2023, and we will invest another $650 million between 2024 and 2025. On top of this, we are also investing $100 million in transmission projects. This is also why our leverage is not declining at a faster pace, because we are investing an important amount in new CapEx. Which once ready, will contribute with higher operational results and will allow ECL to be better balanced and start reconstructing its portfolio of PPAs for the long term. Each megawatt hour that is produced by the new renewables and batteries is replacing energy purchases in the spot market. Hence, the energy margin will increase with this new capacity in our portfolio. Now, in page 22, we are highlighting the main drivers for our new guidance. On the left side, we describe these elements. So we expect, as of today, lower fuel prices for coal and gas. We already have a better hydrology, at least until the end of the first quarter of this year. Then we'll depend on the new hydrologic year, but despite new forecasts are not pessimistic. To be conservative in our guidance, we are using a probability of exceedance of 95% for the future. We do expect lower regulated tariffs since the lower fuel prices will be reflected in the indexation formula of regulated PPAs, but this will also come with lower production costs. In relation to LNG and natural gas sourcing, we expect to be at full capacity in 2024, now that our LNG supplier confirmed the delivery of the 23 tera BTU that we have contracted with them. We will have also more renewable generation, mainly explained by the ramp-up of Wind Taltal, a 343-MW wind farm located in the north, that will gradually start its production phase during this year, and that will be combined with additional batteries that will also be ready between 2024 and 2025. Finally, in relation to transmission bottlenecks, this is always a risk to have in our radar. In relation to Puerto Montt node in the south, it is foreseen that transmission works in that area will be postponed to 2025, and this could provide some relief to spot prices in that area during 2024. Considering all these elements, same as in 2023, we are upgrading our guidance for 2024 to a new range of $450 million-$500 million. Then, next page 23 shows the detailed evolution of ECL's EBITDA, CapEx, and leverage ratio. Liquidity and ratios and leverage should improve also under this new context. For 2024, we are certainly in better position from an operational and a risk perspective, considering the additional renewals, backup PPAs, the new contract to import gas from Argentina, and also because we confirmed the... to the GNL Mejillones terminal, the 23 tera-BTU volumes of LNG for our CCGTs. All these elements will be key to reduce our exposure during non-solar hours. In this new context, we expect them to have a short exposure during non-solar hours of less than 1 terawatt-hour in 2024, compared, as I mentioned before, with 1.5 in 2023, and slightly more than, or slightly above 2.5 in 2022. Then in 2025, we will have the full contribution of the new 343-MW wind farm, Taltal, and the full contribution of the three storage systems that, as I mentioned before, have a combined capacity of 250 MW during non-solar hours. So this means in this new context, we expect a global improvement in ECL's operational results to reach $500 million plus in terms of EBITDA. In this context, we will also continue developing additional renewables or batteries, or and batteries, to bring them to a ready to use status, and launch their construction once the returns are attractive and create value for the overall portfolio. And finally, to end our presentation, on page 24, we would like to share with you some messages and and key takeaways. So we are facing a new market context compared to 2021, 2022, and the first half of 2023. This new context is positive for ECL, considering that we are highly contracted with an average life of nine years. However, we can't rely on external market events or commodity prices, and this is why we are fully committed to accelerate the implementation of new renewables and batteries to reduce our exposure to market risk and complete the development of a sustainable and greener portfolio of generation assets that will allow ENGIE to recontract its portfolio and, of course, grow in the future. So in this line, we have already committed investments to reach almost 1.5 gigawatts out of the 2.1 that were initially planned. We also signed additional backup PPAs with other gencos to mitigate market risks on the remaining exposure to the spot market. All actions, together with better market conditions, are allowing us to upgrade our guidance for 2024 and 2025, even still considering some conservative assumptions on hydrology and the evolution on electricity demand. So with these messages, we end our presentation, and as always, we are ready for your questions and comments. Thank you very much to all of you for your participation today. Thank you. The floor is now open for questions. If you have a question, please press star one on your touchtone phone at this or any time. If you are connected on the web phone, use the onscreen keypad. If at any point your question is answered, you may remove yourself from the queue by pressing star two. Questions will be taken in the order they are received. We do ask that when you pose your question, that you pick up your handset to provide optimum sound quality. Please hold while we poll for questions. Our first question today comes from Florencia Mayorga with MetLife. Please go ahead. Hey, Eduardo. Congratulations on results. I have a couple of questions. One is regarding funding of 2024 CapEx, because you are targeting the leveraging. So I am curious, what are your expectations regarding funding on that? And the other one is: You are thinking any strategy or start to believe to address the 2025 notes? So it should be very helpful if you can provide details on that. Thank you. Hello, Florentina. So, yes, for 2024, we still have an important amount of CapEx to be invested, and our financial plan is considering, of course, our general cash flow. During 2024, we also expect to monetize a portion of the PEC receivables. And, besides that, we do not expect an important increase in the amount of debt that we will have in our balance sheet. So we do expect, of course, in parallel, to restructure part of the debt that we have in our balance sheet. And, today we are evaluating different alternatives, including the refinancing of the bonds that are maturing in 2025. We'll come back with any news soon, as soon as market conditions are attractive for us. Thank you, Eduardo. Just a follow-up regarding the PEC receivable. So how much are you expecting to receive this year? And if this amount is already subject to the approval of the PEC Three, or you are already convinced that the $200 million that I believe that you mentioned will be monetized this year? Yes. In relation to PEC receivables, as of December 2023, we have around $300 million of accumulated receivables in our balance sheet. I would say that around 50-60 are already committed to be monetized in the first quarter half of 2024. And then the remaining amount should be monetized once the new, let's say, mechanism is in place. Today, we are targeting to monetize this additional amount during the second half of this year. But of course, in our financial plan, we need to be prudent, so that's why we are, let's say, less optimistic on the monetization date, and we need to be prepared in case we face any delay on this monetization. Okay, perfect. Thank you, Eduardo. Thank you. The next question is from Martin Arancet with Balance Capital. Please go ahead. Hi, thank you for taking my questions. I have two, and I would like to run them one by one, if that's okay. First, you had an increase in energy losses in the fourth quarter of 2023. I was wondering if you could give us some color on why, and what are your, your expectations on that regard for the upcoming years? Hello. Hello, Martin. What do you mean by energy losses? If I take the energy available to sell and for transmission lines and what you actually sold in the first quarter, I get a difference that I take as energy losses. I don't have the answer right now. Sorry. We'll need to come back to you, later. Okay, no problem. Then my second question, regarding dividends, if you are thinking of starting dividends in 2024 and if you have any debt with covenants that limit your ability to pay those? Okay, that's a, that's a good point. I think in this context, our main objective today is to, let's say, improve liquidity, to deleverage as fast as possible. And once we reach this objective, we will come back probably with a new, let's say, dividend policy. This should come also once we secure additional investments in the future. So, it will also depend on how fast our operational results increase in the next year. Now, is that our main objective today is to improve liquidity and to deleverage because we have the firm intention to comply with the average ratios for an investment-grade company like ECL. Okay, very clear. And, sorry, on the second part of my question, do you have any debt with the covenants that limit your ability to pay dividends? No. Okay, thank you. Very clear. The next question is from Peter Galbo with Bank of America. Please go ahead. Hello, Eduardo. Thank you for the call and taking my questions. I have two. CapEx per megawatt on your 2025-2027 guidance, I guess this would be slide 20, looks meaningfully higher than 2024. I was just wondering what drives this. Is it, like, the composition of technology being developed, cost inflation or other factors? And the second question is: Is there any update on the discussions or negotiations with the LNG supplier who did not supply in the past as to compensation? Thank you. Hello, Peter. Well, what, what probably you are seeing in this, let's say, forecast, is that, on one side, the, the CapEx that we are presenting in 2022-2023 is a realized CapEx, while the CapEx we are forecasting in 2024, 2025, it's a forecast. So that means that we are probably more conservative on, on that side. But besides that, it is true that, there has been some, let's say, evolution in, in, in the, in the cost of, implementation. So that means that in terms of, CapEx, we could expect a slightly higher CapEx in, in the future than in the recent years. And this is explained by several factors, among them, as you mentioned, inflation. So this is why we are seeing probably a higher CapEx in the forecast. On top of that, we need to consider that we are implementing different technologies at the same time. So the CapEx per megawatt of a PV solar plant is lower than the CapEx per megawatt of a wind farm. While in 2024, 2025, we are investing in a 343-megawatt wind farm, which is also driving, in comparison, a higher CapEx compared to previous years in which we had some PV solar plants. That's on the CapEx side. The second one was related to the fact that in 2023, our LNG supplier didn't deliver one of the contracts. So we don't have news on that line. This is a process that will need to continue, and based on the confidentiality agreement, we can't disclose any details. We will come back once we have a final answer. Thank you. Thank you. Again, if you have a question, please press Star, then One. The next question is from Fernán Gonzalez with BTG Pactual. Please go ahead. Yeah, good. Hi, Eduardo. I have, I think three questions, and the first is, if you could elaborate a bit more on this reverse migration that we're seeing into the regulated segment. You mentioned that some unregulated clients went back to the regulated segment. So I'm wondering what's the reason behind this behavior and whether this trend could accelerate in 2024 and 2025. Then if we look beyond 2025, what's the size of new capacity, be it storage or renewables, that you might add in 2026 and 2027? And how would this expectation impact the leverage ratios beyond 2025? I mean, when could we see more normalized levels? And my final question is that, if I recall correctly, you still have one PPA with a mining client that is linked to coal. Is this PPA gonna be renegotiated into renewables? If you could comment a little bit about that. Thank you. Hello, Fernand. So, the first one, there are several elements in relation to our regulated demand. What we expect in 2024 onwards is that the load factor of the PPA that we have in the center to south should gradually increase. And this increase is basically explained because other regulated PPAs from other gencos are expiring during these years. So this means that our PPA will capture an additional volume from the overall system. This is one element and why we should see that the load factor of the PPA in the center to south should move from approx 70, 72, 73 to close to 80% in the future. And this will, of course, be positive for our, let's say, contracted profile. On the other hand, we have seen also recently an increase in the vegetative regulated demand in the system, which will also be positive, because then all regulated PPAs will have a higher load factor. Then on the market per se, what we have seen is that in the past years, there were several unregulated clients that migrated to the regulated. Sorry, to the several regulated that migrated to the unregulated. But given the current market conditions, what we have seen is that the price at which some generation companies are willing to renew those PPAs are much higher. And this is then explaining why remigrating, as you mentioned, to the regulated segment, could make sense in that case. Then, in relation to the second question about the additional CapEx that we could expect in 2025 or 2026, I think this is already, or at least partially included in the guidance that we are providing for 2025. We already included in the guidance close to $180 million of additional renewables in 2025. And in 2026, 2027, we could expect similar amounts. But as I also mentioned during the call, the renewables and the batteries that we are adding to the portfolio between 2022 and 2025 are directly replacing spot purchases. So that means that if every megawatt hour that we generate at zero replaces energy purchases at 50 or 60, then this is an additional margin that will increase our operational result during those years. So this means that the CapEx should also come with additional EBITDA during this phase. And in relation to the coal-linked PPA, yes, we still have one. We have already mentioned in previous calls that it is our intention to find a similar, let's say, deal with our clients as the ones we implemented in the past. And this is something that we are working on with them, and we will see if we find a win-win solution in the future. Okay, perfect. Thank you. Maybe just one final question, Eduardo. What is the biggest tail risk that you see for this year? I would say that, on the physical side, the unavailability of, let's say, flexible generation, I mean, combined cycles running natural gas. It's an important risk because those are running during non-solar hours. If you don't have them during non-solar hours, you will need to jump directly to diesel, and this means that, spot prices could jump from 80 to 200 in a very short time or period of time. That's on the physical side. Then on the, let's say, commodity side or on the fuel prices or on hydrology, if in case we have, again, a disruption on commodity prices, that will have a negative impact, but not as in 2022. Because I would say that the first half of the year is already plagued. During the second quarter to second half, new hydrologic conditions could also negatively impact the spot prices in the system. All right. Perfect. Thank you. Welcome. The next question is from Gabriela Bahachille with PineBridge Investments. Please go ahead. Hi, thank you very much for the call. So I have three questions. The first one is a follow-up on the PEC three situation. So I just was wondering, what are the stage of the negotiations of the third PEC? The second question would be regarding SG&A. So I saw in the, the info quarter, there was an important increase in SG&A costs that you explained by, by higher expenses on the, consulting services. So I just was wondering if this is more than more of a one-off or something that we could see more often in the future. And my third question is regarding about the, your exposure to the spot market by year-end 2024. So with, Tamaya, Coya, and Taltal, starting to operate, how much do you expect to reduce your exposure to the, spot market by year-end 2024? If you could give us some color about which quarter will each of the batteries start operating, it would be great. Thank you. Okay. Hi, Gabriela. I will start with the, with the PEC three question, which is a question also. The answer is a question. I mean, the IDB is currently working a lot with the different government and regulatory entities that have... I mean, that need to be to reach a solution that can be implemented during the year. And so they feel quite optimistic in the sense of how much time this will involve, and eventually expect some to have some monetization solution ready for, let's say, around half of the year, around July or something like that. Okay? As Eduardo said, we're normally very conscious in our projections, but just to tell you that this is working, the generation companies also have calls with the IDB, and so this is something that is going on. Then, Gabriela, hello. On SG&A, we need to check in detail what this is about, so we will need to come back later. I would say that on selling, we are including the development costs related to new projects. But let me let us check that part, just to be sure. And on spot market exposure, I think more than the total exposure, because as probably we explained some time ago, there is the good cholesterol and the bad cholesterol. Because being exposed to the spot market during solar hours is not necessarily bad, because during solar hours, the average spot price, at least during the last months, for example, is below $7-$8. What's relevant is when you are contracted, of course, like we are, it's not to be exposed to the spot market during non-solar hours. This means at night hours. So by the end, or as I mentioned, I think, before, for this year, the average exposure, the remaining exposure that we will have during non-solar hours, is expected to be around 1 TWh or even below. And this is, of course, without considering the two batteries that we are building, Capricornio and Tamaya. So this means that for next year, 2025, when these two projects are ready, and once the wind farm, which has an interesting profile too, I mean, during non-solar hours, is producing our exposure to the spot market at non-solar hours, should be even lower than 1 terawatt-hour. And this is why we were explaining during the call that we are better positioned in 2024, 2025, and less exposed to the type of risks that we were exposed back in 2021, 2022, and even the first half of 2023. Perfect. So, I understand that, that for 2025, your exposure will be considerably lower, and but versus 2023, could you make that comparison very quickly, please? Yes. In 2023, the exposure at non-solar hours was slightly above 1.5 TWh. Oh, okay. That's right. Thank you. Thank you very much. Okay. That's very helpful. And in 2022, was 2.5. So that gives you a relative comparison of why we're saying that we are less exposed to market risks in this new context. Thank you. That's very helpful. You're welcome. The next question is a follow-up from Florencia Mayorga from MetLife. Please go ahead. Hey, Eduardo. Sorry. One more question is regarding Lomas de Taltal. We have heard that has been some issues regarding police escort. So just to ask you if there is any delay on the COD of the project, or everything is going as planned? Thank you. Good point. Indeed, there was, or we have experienced together with the other generation company that is building a similar wind farm nearby Lomas de Taltal. We experienced some delays during the last months. Now, between the authorities and the police and generation companies, we have reached, let's say, a new process that is already in place. And there is a recovery plan to reach the schedule that was initially foreseen for this project. We could have a slight delay, but will not be material compared to the initial date that was foreseen for this project. Okay. So in summary, it's, let's say solved. It's already ongoing, and we expect to recover the time that was lost. Perfect. Thank you so much. Thank you. This concludes the question and answer session. At this time, I would like to turn the floor back over to ENGIE Energía Chile for any closing remarks. Well, thank you very much to all for your participation, and we will remain available in the next days, weeks, for any additional questions that you may have. And we will see you soon in our next quarterly call. Thank you. This concludes today's presentation. You may disconnect your line at this time, and have a nice day.