Good day everyone, and welcome to Engie Energía Chile's third quarter 2021 results conference call. If you need a copy of the press release issued last week, 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. We would like to advise participants that this call is dedicated to investors and market analysts, 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, and thank you for being with us today. As usual, I'm here with Bernardita Infante, Head of Corporate Finance, and Marcela Muñoz, Investor Relations Officer. Today, we will present ECL's third quarter results and the recent progress on the renewables and transmission projects that we have under development. Let's start, and please turn to page 3, where we introduce the key messages for this call. First, as we explained during the last two quarters, the power industry is facing a complex year with very high spot prices. The third quarter was probably the worst of this year, and this can be easily seen in the results for the quarter. As we explained before, these high spot prices are driven by an extreme drops, the unavailability of several thermal coal power plants during the year, a stronger power demand, and finally a new element in this already complex context, which is an important increase in LNG and coal prices. All these elements together created a perfect storm and pushed spot prices far above where the industry was expecting for this year. In summary, we are facing average spot prices that are more than 2 times what we were expecting under normal market conditions. This difficult context requires different actions to reduce GCO exposure to spot prices volatility. Between them, the 3 most relevant are first, signing additional backup supply PPAs. We'll explain that in a couple of minutes, and what we recently implemented. Second, importing additional LNG to avoid further risks. Third, to keep GCO power plants fully available during this period. We'll explain also in some minutes what we could expect for the fourth quarter of this year and also for next year. Second, we'll give you an update of the renewable projects under construction. The Calama Wind Farm is ready with its 36 turbines and 151 MW connected to the grid. So this project reached its formal COD, its commercial operation date, last Friday, while Tamaya is also almost ready, and will reach its COD in the coming weeks. The plant, again, is also injected to the grid. We'll discuss also in a couple of minutes the status of the different projects under construction and also under development. Third, as we explained in our previous call, we announced in April a second wave of 1,000 MW of additional renewables, together with the conversion of three coal power plants to biomass and natural gas by 2035. During this year, we secured also through land concessions the opportunity to build up to 1.5 GW of renewables in two lines, Pampa Yolanda and Pampa Fidelia, while we already filed also permits for the future conversions. Fourth, despite the results in 2021 are below our initial budget and guidance, ECL continues to keep a solid and flexible capital structure, while the company continues to have a strong cash generation that should allow ECL to finance its transformation plan with a mix of internal cash flow, financial debt, while increasing probably the dividend payout ratio. Before we explain the third quarter results on pages four to six, we show the overall operating performance, the recent announcement related to ECL business plan, and the initiatives implemented over the recent years to transform the company. On page five, we show the complete snapshot of the transformation plan. On top, we show the implementation of up to 2 GW of renewables between 2019 and 2035. That could also be combined with the storage options. Below, we show the six coal power plants we plan to disconnect within the same period. This plan will require a total investment above $1.4 billion, of which by 2022, next year, more than one-third will have been invested. Page 6 shows our main strength, which is its long-term contract portfolio of PPAs with the top tier names in the country and an average life close to 11 years. This graph shows PPAs until 2030. As you know, considering energy sales and revenues should be predictable over time with this contracted portfolio. Our main objective is to control and optimize the supply costs. This is the main challenge to optimize our margins during the 11-year contracted phase, and to build also a new platform to secure additional PPAs in the long term. Now let's move to page seven, in which we present the Q2 2021 financial results by quarter and year to date compared to 2020, to give you a better view of the operating evolution during this complete year. 2021 EBITDA is negatively affected by higher marginal costs due to the drought and the availability of thermal plants, and also because of higher fuel costs. From a demand perspective, we can see a positive evolution in physical energy sales, as we can see in the chart, during the first 9 months of 2021. Total physical sales increased 3% in 2021 compared to 2020, even considering one important PPA with Zaldívar ended by June 2020. This will be positive once spot prices stabilize in the future. On the supply cost side, spot purchases during this year decreased in 29% compared to 2020. This may be explained by the lack of hydro production in the country, which required more less efficient thermal power plants to be dispatched. For example, units 14 and 15 in Tocopilla sites that are to be disconnected by the end of this year are expected to produce almost 0.6 terawatt-hours in 2021, and representing 7% of our total sources. While in 2020, this percentage was only 1%. However, we will see in a couple of minutes, the average spot price at which ECL bought a portion of its energy needs was much higher than in 2020 and much higher than in the business plan for this year. This negative impact on the average supply cost is explained in the lower EBITDA and net results in 2021 compared to 2020, and also compared to the business plan and our budget for this year. The margin was impacted by both the operating performance we just explained, and also by the upfront recognition of $28 million financial expense on the sale of regulated receivables. This is related to the PEC. This is a one-off and upfront recognition of the long-term financial costs. As you know, this operation is releasing $120 million in 2021, and may provide additional $76 million between the end of this year to probably 2022 or 2023, once we complete the full monetization of these receivables. Finally, net debt increased in line with the disbursement of the $125 million green loan arranged with IDB Invest, and also because of the recognition of financial leases related to Capella Land and Pampa Fidela Land concessions, which were granted to CO in 2021. Now Now we will go through each of the elements we mentioned are impacting the spot price. Please turn to page eight. These two graphs show the average spot price in the north and in the center south regions. We can see how in both regions, spot prices in 2021 are almost 2 times higher than in 2020. Considering that CO is expected to rise between 2.5 and 3 terawatts power in 2021, we can get between $125 million-$150 million additional costs that are impacting the energy margin. That would only be partially offset with the average PPA prices that also increase in this context, but at a slower pace. Page 9 shows hydro production over the last three years in Chile. 2019 to 2020 were already dry years, and then 2021 has been difficult and somehow, let's say, volatile. When we had our second quarter call, I said we may be in P100, or in other words, in one of the driest years of the last 60. Afterwards, we had rainfalls during August and September, which improved the expectations for the last quarter of this year. We may be facing a similar quarter to in 2020. This means 2021-2022 hydro year will be close to a P87 on average. It means among the driest 3% of the last 60 years. There are good news and there are bad news. The good news is that, as I said, the fourth quarter will be better with this new hydro scenario. The bad news is that the ice melt may not be sufficient to keep this improved scenario until the new hydro year, 2023, starts. This means the second quarter of 2022 could be again difficult, and electricity produced with coal, LNG, and hopefully gas from Argentina, would play a key role to replace hydro production. Along these lines, the fuel prices could be a key driver for 2022. We will speak about this in a couple of minutes. This can be seen in the next pages 10 and 11. On page 10, we see how coal prices rocketed during the recent months. The good news is that the Chinese government may be applying certain controls, and coal prices decreased by approximately 30% over the last 7 days, which is very recent. This also means we are in a volatile environment, so we need to be very cautious with this variable, considering still 30%-35% of the electricity in Chile is produced with coal. This means it has an important impact on the spot prices. Page 11 shows the LNG prices in different markets. We can see the LNG price materially increased in the European and Asian markets, and this higher cost for LNG producers is driving the LNG price for spot purchases, and unfortunately, that's helping to increase the electricity average supply cost in Chile. The good news is that we are expecting some imports on interruptible basis from Argentina to the central region, that may help to partially mitigate these negative impacts. Next, page 12 is a new section we added to explain what we're doing to manage the spot price volatility risk and the average supply costs for the 11-year average life of PPAs. The yellow area of this graph represents the annual contracted energy with other generation companies, and we can see an important ramp-up in 2022. These are what we call backup PPAs, and in practice, ECL replaces in the system's energy balance the generation company providing this hedge for the contracted volume. These are energy contracts only without any link to capacity. Between 2022 and 2025, we have secured backup PPAs for average 2.5 TWh per year. This means at least 20% of ECL total contracted demand is hedged or supported with these backup PPAs until 2030 to basically reduce the exposure to spot market volatility. On the other hand, the blue area represents ECL generation, plus the remaining spot purchases, which should reduce over time with the construction of new renewables. By 2026, and after the renewables have been implemented, ECL purchases in the spot market should only be linked to the intermittency of renewables, and this is something we are planning to manage with the combination of our technologies and with potentially storage solutions. Let's move now directly to page 14, where we can see the demand supply balance for the first 9 months of the year. This graph shows average realized PPA prices compared to the average supply cost, which is the result of the different power sources to meet the total demand from our clients. This is a graphic explanation of what happened during 2021. You can see that a small area in yellow starts from the left in this graph, and then IEM, CTA, and CTH coal power plants operate as base load units. The variable costs of our coal plants in general was higher because of higher coal prices. The rest of our coal units, which last year were marginally dispatched because of their high production costs, had to be often dispatched this year, representing 14% of our power supply. If we move to the right, we see that, our combined cycle units running with diesel or gas represented 21% of our energy supply. The third quarter shows that, the production cost of our combined cycles increased compared to previous quarter, in line with additional LNG spot purchases we did to hedge our spot exposure, but unfortunately, at very high LNG prices. Finally, ECL supplied 79% of its demand through purchases on both its long-term budget and backup PPA supply agreements. Our physical energy purchases decreased compared to last year. That's what we can see here. Coal prices increased significantly. The result was that our average supply cost increased from $54 to $72, as we can see in both continuous and broken lines. However, on the positive side, the average economic price of our PPA portfolio also increased from $101 to $108 per MWh, as we can see on top. This means despite the total cost increase in $18, the average economic price increased in $7, but only partially offsetting the negative impact. Hydrology and fuel prices during the fourth quarter and the first quarter of next year will be key to continue seeing a reduction in the average supply cost in combination with the start of new backup PPAs in our portfolio of, let's say, sources. Let's go to page 15 to explain what we could expect from the fourth quarter and discuss the drivers for 2022. As you know, and this will not be a surprise given the current market context, the EBITDA guidance we gave at the beginning of this year will not be reached. The last 12 months EBITDA as of September is $361 million. This should be a midpoint for the new range we could expect for 2021, considering the additional rainfalls and the ice melt process have helped to recover the reservoirs levels to similar ranges of 2020. For 2022, we need to consider the following key drivers. First, spot prices are not expected, at least in the first half of the year, to reduce dramatically. Second, fuel prices, mainly coal and LNG, will be key considering its impact to the system's spot prices. In the last weeks, we saw an important increase in coal prices, which was afterwards corrected as the market continues to have some volatility. Third, this year we'll be less exposed to spot prices with the new renewables and also with the backup PPAs that we signed with other generation companies. All in all, we say 2022 should be better from a margin perspective, but we need to be cautious on the new hydrologic year that will start around April/May, and also the coal prices, given its relevant impact on spot prices and also on our own production costs. The last element is the entry of new renewals, those that are developed by ECL, and also those from third parties. A further delay in renewable projects may help to mitigate a lower hydro production and/or increased coal prices. Now, please turn to page 17. We have updated our CapEx forecast for 2021, and we expect investments for approximately $300 million, mainly focused on our renewable and transmission projects, as well as maintenance and the dismantling costs of units 12 and 13 in Tocopilla. These were shut down back in 2018. In this forecast, we are including CapEx from 2022, which includes the completion of the renewable and transmission projects that are currently under construction and additional CapEx related to the additional wind projects that we expect to launch next year. As we mentioned in previous calls, we plan to finance this CapEx with a mix of internal cash generation and financial debt. Our debt-to-EBITDA ratio increased 2-3 x, given the lower EBITDA of 2021 under the current Perfect Storm. Now, during the next three years, we should return to the baseline we defined to keep our leverage ratios not exceeding 3 x on a structural, on regular basis, in the long term. We may face, of course, temporary increases in these ratios in the construction phase, but this will only be temporary considering renewables will rapidly generate an additional for the company. In practice, the renewables we are developing will replace the energy purchases that we were showing in the supply-demand balance. This means every 100 kW power per year of renewables production would create between $3 million and $4 million additional EBITDA. Right? This is the idea of this transformation plan, replacing the spot purchases and reducing the volatility with our own renewables and during the transition period, of course, with a higher amount of backup PPAs. Now, ECL liquidity is strong since we have received $150 million for the sale of a long-term accounts receivable for distribution companies pacing for the tariff stabilization law. We also drew the $125 million loan agreement with the IDB to finance the renewable plan. We expect to receive around additional $17 million when we will sell an additional group of renewables between 2021 and next year. The following section describes ECL transformation projects. The four pillars are described in pages 18 to 19. On pages 20 and 21, we present our portfolio of clients and how the inflation of these PPAs will evolve in the medium term. This is key to understand and also forecast ECL future cash flows. As you can see on page 21, from 2020 to 2022, we will see an importance in the indexation of our portfolio of contracts. US CPI will represent 79% of 2022, compared to 60% in 2020, while coal will move from 59% to only 11%. LNG will continue driving the regulated PPA in the North and a small portion of the PPA in the center. This structure should remain stable until 2035, at least. Page 22 shows a complete view of the transformation plan by type of technology until 2035. The key component is the development of the 2 GW of renewables. This brings us to next page, 23, in which we can see how by 2022, we will have completed 70% of the first phase. Soon we'll launch the construction of additional renewables to reach the objective by 2025. We keep 2025 as the main objective, and we are implementing several actions to accelerate this plan. The additional component of the transformation plan is the conversion of the remaining three coal units to biomass and natural gas that are described in page 24. As we mentioned before, the plan is to perform works as much as possible without interfering with the normal operation of these plants to have them ready by 2025. The next pages give us some details and pictures of the renewable projects under construction. Calama, on page 25, had a global advance of 99% as of September. As I already mentioned, this 151 MW project reached its formal COD last Friday, and became the first renewable project on the transformation plan that we have added to ECL generation portfolio. We will move to the next project on page 26. Capricornio has an important delay in its original schedule and is expected to be ready next year due to issues related to the delayed delivery of certain permits, as well as the financial issues its contractor had during the last year. The COVID pandemic also influenced both the situations and impacted the project. On page 27, we present the Tamaya solar plant with a global advance of 98%. This plant is already injecting energy to the grid, and we expect its commercial operation in the coming weeks. On page 28, we present the global advance of Colla. The project has a 40% global advance, and we expect its energization for the third quarter of 2022, and COD during the fourth quarter. We have experienced in this project a delay in the transportation of equipment from Vietnam due to COVID restrictions. As you know, the marine transportation industry is also under stress and facing increased costs. On page 29, last quarter we presented this new snapshot. We have secured two land concessions, Pampa Fidelia and Pampa Yolanda in the northern region. Those are operational at many times with a combined capacity of 1.4 gigawatts between wind, solar and storage. The exact design and configuration is under analysis and we will continue developing these projects to get them to a ready-to-build stage as soon as possible. This means between the existing portfolio of renewable projects and these additional two land concessions, we have secured project potential for more than 3 gigawatts. On next page 30, we can see some examples of the different projects that are under development. Vientos de Loa and Lomas de Taltal, with combined capacity of 0.5 gigawatts, should be the next one in construction, and should receive their notice to proceed next year and become the next wind projects to be added to ECL portfolio. Regarding the four transmission projects described on page 31, with a total investment of $53 million, three of them are almost completed and one is expected for 222. Finally on page 32, we present seven projects which have received their respective decrees and that are entering into a construction phase with a total investment of $43 million. This means almost $100 million invested in transmission projects that will add a total VATT of around $10 billion per year or approx $9 billion in EBITDA contribution since 2023. Most of this amount and the remaining amount will be completed in 2024. Last but not least, ECL was awarded as of September with an additional transmission project, which involves the construction of La Ligua substation, which requires a total CapEx of $19 million. This project will be added to ECL portfolio of projects and our development team is also preparing to participate in 222 new transmission auctions that are related to the annual expansion plan of the zonal and national transmission systems. Now, I will leave you with Bernardita to cover the following section, our financial performance. Thank you, Eduardo, and good afternoon to everyone. Please go to slide 34. As Eduardo already explained, EBITDA fell 28%. Now, if we look into the details, we can see some positive impacts. First, an increase in physical energy sales, which had a $29 million positive impact. While regulated physical sales began to recover in the second quarter, free client sales increased despite the end of the Saldivia PPA in June of last year, given the reactivation of the mining industry. Our own generation increased since the drop in the issuance of Argentine gas led to the dispatch of our coal plants. Therefore, we reported lower physical energy purchases, presenting a $67 million positive effect on EBITDA. Another positive impact was a $5 million insurance recovery from a past loss at the IEM plant. Now, the increase in average realized prices from $101 to $108 per MWh had a $69 million positive impact on EBITDA, and it is mostly explained by the increase in the applicable Henry Hub, CPI, and coal prices in the tariffs of our PPAs. Also, the tariff discount that we agreed in the March 2020 renegotiation on the Centinela PPA was smaller in 2021 than in 2020. This time, the most significant negative impact was the increase in fuel costs due to the increase in our own generation and the record high coal and LNG prices, particularly in the third quarter, which includes, as Eduardo mentioned, a spot LNG shipment bought as a hedge to prevent further problems from regarding the marginal cost. The fuel price increase had an estimated $127 million negative effect on EBITDA. The next most relevant hit, estimated at $108 million, was the increase in marginal costs. We bought less, which is positive, but at much higher prices. All of these changes led us to a nine-month EBITDA of $243 million, down from $338 million in the same period of last year. If we go to slide 35, it shows the evolution of net results, which went from $123 million last year to $39 million in the first nine months of this year. Last year, we reported non-recurring expenses of $10 million related to the premium paid on the early redemption of the $400 million 144A bonds, which we refinanced with a new $500 million bond. Our net recurring income in the first nine months of last year was $133 million. This year, we had a couple of positive effects, such as FX gains and lower financial expenses due to lower average coupon rates and greater capitalization of interest in our investment projects. You can see EBITDA decrease we just discussed about, of course, the reduction in our recurring net income. We would have reported $75 million in net income had it not been for the $36 million one-shot financial expense. This is shown after taxes. This resulted from the sale at a discount of $167 million in long-term accounts receivable from distribution companies related to the price stabilization law. As you may recall, we sold these receivables to Chile Electricity PEC, which in turn issued notes to finance the purchase of accounts receivable from four groups of generation companies, including ENGIE. Let's turn to slide 36. Our net debt increased by $315 million from year-end 2020. The main cash outflows included $138 million in CapEx, mostly in our renewable projects, $91 million in dividends, including a final dividend on 2020 net earnings and the $31.5 million provisional dividends paid in August, as well as $23 million in taxes. This time, we reported a $75 million net cash outflow, mainly due to higher fuel prices and lower collection from distribution companies due to the price stabilization law. This part was offset by the proceeds from the full sale of long-term receivables from distribution companies through Chile Electricity PEC, which amounted to $118 million, and is shown on the last green column to the right. Now, if you look at the center of the chart, you will note one of the main reasons for the increase in our net debt. This relates to an $81 million increase in financial leases, which qualify as financial debt per IFRS 16. These are primarily related to land concessions, such as the Pampa Yolanda and Pampa Fidelia land sites in the Antofagasta Region for the future development of hybrid renewable projects. These contracts consider annual payments for up to 40 years, and the present value of future installments is accounted for as financial debt. On August 27, we dispersed the $155 million loan from IDB Invest to finance the Calama Wind Farm. The loan does not appear in this net debt graph, as the debt increase is fully netted out with the corresponding cash increase. Finally, we also received an $8 million payment from our 50 percent-owned TEN. Now, if we go to slide 37. This shows our ratings, which we haven't changed, are BBB+ and BBB, and debt details. Net debt to EBITDA increased from 1.8 to 3.1x because of the financial leases, the IDB Invest loan, and the EBITDA decrease. This last one to EBITDA at $361 million. On slide 38, we can see an increase in our dividend yield. However, like other utilities, our share price has underperformed the IPSA index due to factors such as the slower operating performance due to the drought and high fuel prices, potential regulatory changes, and pension fund withdrawals, among others. Well, this is what I have to tell you, and I will leave you with Eduardo Milligan for the final remarks. Thank you. We summarize the main takeaways on page 39. First, 2021 has been a very difficult year for ECL and also for the industry, between the extreme drought combined with other several factors that negatively the spot prices. As we know, with negative consequences in our financial results. We do expect an improvement during the fourth quarter, but as we mentioned in our previous call, we are still navigating through this storm. We need to be cautious on the system's evolution, given the uncertainty on the hydro conditions for 2022 and volatility on fuel price. Second, we are glad to say that our first renewable project reached its commercial operation date on budget and performance with a very limited delay. This is just the beginning, and we have a lot of challenges ahead to complete this plan. In this line, we have secured traditional backup PPAs with other generation companies to reduce our exposure to the spot price volatility during the transmission phase, in which we will be developing these renewables. We will also be implementing several actions to accelerate the construction of renewables. Third, despite the increase in the debt e xplained by the lower margins in 2021, ECL still keeps a robust financial position to support the future investments, enhanced by two innovative financial structures implemented this year. First, the sale of long-term accounts receivable that, as I mentioned, will still provide additional $70 million-$80 million between this year and the next one. Also, $165 million green financing from IDB Invest. Well, with these final messages, we are finalizing our third quarter presentation. We hope as always, this presentation is helpful for you and we are ready for any questions that you may have for us. Thank you. The floor is now open for questions. If you have a question, please press star then one on your touchtone phone at this or any time. If at any point your question is answered, you may remove yourself from the queue by pressing star then two. Questions will be taken in the order that they are received. We do ask that when you call for your question that you peek at your handset to provide optimum sound quality. Please hold while we take your questions. The first question today will be from Fernán González with BTG Pactual. Please go ahead. Hi, Eduardo Milligan, Bernardita Infante, Marcela Muñoz. Thanks for the presentation. I have three questions. The first one is related to the conversion of the CTA and CTH units into biomass. I believe the project is designed to burn wood chips or black or white pellets, right? So could you share where do you actually source it from? Do you have a contract already for that? How much is the transport cost of that into the site? What I'm wondering is ultimately, what is the level of energy prices that you need for the economics of this project to work? My second question is on that bill that we have at the Senate currently. It is aiming to prohibit the fossil fuel generation by 2030. If we assume that Congress approves that, how would that change your strategy going forward? Because the IE conversion wouldn't make too much sense anymore. What would be the impact on other businesses like the gas transportation or the ports? My final question is on this backup PPAs that you mentioned, if you could share a bit more color on them, you know, the type of conditions behind those contracts so we can better understand them. Okay. Thank you for your questions. First, maybe I can start with the conversion. The conversion of CTA and CTH to biomass, as we explained, it's more than a conversion. It's a change in the type of fuel that these two coal power plants will use first. Because these two plants are ready to burn biomass. Now, the conversion to biomass is basically a conversion to exit coal, considering between 2025-2026, these two plants are not expected to dispatch. The idea is to keep them as some kind of cold reserves with a much higher production cost than producing with coal. The production cost could be close to $100-$120. This production cost is related to black pellets or white pellets. Both types could be burned. What the $100-$120 includes, the transport plus the biomass that we need to acquire. Today, this is a market that is under development. There are some sellers in Europe and in Asia. Today we are working with ENGIE Global Energy Management division. The management team of ENGIE that is also working with coal, with LNG, etc. They also have started working with biomass to secure the supply of these products by 2025. If I continue with the second one, the exit by 2030, I could say similar to the potential idea of exit, exiting coal by 2025. It would be, I think, very difficult by 2030. Maybe some years later it could be possible. Again, the system will need to adapt once the new technologies are available, once storage is economically viable, then the market will adjust by itself. We do expect at some point in time that there could be a full decarbonization, but this is something that will need some time and will need to combine the renewables that are already part of the general transition with gas, with storage, with CSP, at some point in time with hydrogen. This is not something that could be developed overnight, and that will need time, and also we need transmission lines. The HVDC transmission line that is expected for the end of this decade, it's also very important in this equation. We do believe that this could be possible, but not at 2030, probably. Today we don't have a clear view on that. Of course, your point is very good. High income could make sense to natural gas. If by 2030 it will need to be disconnected. This is something that we need to assess in more detail than to have an answer now. Because we do believe that this is something that needs to be better assessed by the authorities in the country. Finally, in terms of backup PPAs, what we mentioned is that between 2022 and 2030, we will have on average 20% of our total contracted demand covered by these backup PPAs. Most of these backup PPAs are 24/7. The average cost for us of these backup PPAs is energy only. There is no transaction related to the capacity. The average cost is in the mid-forties, probably during this period. You can consider that we will have 2.5 kWh of backup PPAs between 2022 and 2025, 2026 at an average 45, between $45-$50, probably energy only. This will become part of our supply cost. Basically what we are doing with these backup PPAs is reducing the volatility of buying this electricity in this contract. Okay, perfect. Just to follow up on question number 2, I agree with you with everything you said, and that is common sense. The problem is that Congress is not always very reasonable. The track record for the past few years is somewhat questionable. They're not listening much to technocrats. It is possible that they could approve this. That's why I was just wondering if this would, you know, drive a complete overhaul of your long-term strategy in Chile. Not a complete overhaul because our two combined cycles, unit 16 and CTM 3, are in the mid stage of their economic life. Basically, these plants are very important at least till 2030, maybe 2035. This will not change the fact that we will continue operating them, and we will continue building the renewables. That could change probably or could make us think better about buy-in conversion as a logic, let's say, conclusion. All the other parameters and elements of the transformation should remain stable even under that type of, let's say, scenario. Okay, thank you. You're welcome. The next question will be from Francisco Schumacher from Fundamenta. Please go ahead. Hi. Thank you very much. Just, I don't know if you mentioned it, but I wanted to confirm if there's gonna be any LNG consumed through fourth quarter 2021. Conceptually, for next year, can you decide whether to purchase the spot LNG if you're having a lack of gas? Depending on where the spot price is, then you decide if you can buy it or not. Francisco, yes, it's exactly what you are saying. First, for 2021, no, we don't have any additional cargo of LNG at those very, very expensive prices that Mario mentioned, we took to basically assess our position during September. That was to avoid a further margin deterioration. We'll look to take some type of loss during September. We don't have any additional spot cargo in our plan. For 2022, we are bringing all the cargos that we have in our long-term contracts. Those are at much lower prices than the spot prices. As you were saying, paying more for spot gas is something that will depend on the spot price evolution. Because producing today with LNG that you can buy at $50 per million BTU is sometimes more expensive than producing with diesel. That's why we don't have any plans to bring in now LNG spots. There is always the alternative in case, again, we have very high spot prices. We have maybe term availability in the system, then it could be an auction to mitigate the evolution of the spot price. Very clear. Thanks. The next question will be from Andrew McCarthy from Credicorp Capital. Please go ahead. Good afternoon, everyone. Many thanks for the presentation. First question was just to double check if you know, given the very tough scenario at the moment outlook, whether you'd given any thoughts again to maybe delaying the withdrawal of the U fourteen and U fifteen coal plants. That was first question number one. The second question was with respect to the PEC, you know, with the higher fuel prices and also the more depreciated peso, just wondering, you know, what your thoughts were with respect to what the solution could be, given that maybe by second half next year, we might be getting quite close to the $1.35 billion ceiling on that capacity utilization mechanism. The third question was if you could share some more color on, you know, you talked a little bit in the presentation, on the questions about the importance of the HVDC line to Malargüe. Just wondering if you could share some color on why you maybe decided not to continue reviewing that project as an interesting one for you guys to invest in. Those are my three questions. Many thanks. Hello, Andrew. Thank you. First question, units 14 and 15. As we were saying, this year, these two units almost produced 0.6 terawatt-hours per year, and that's much more than we were expecting for this year. The team did a very good job because those units were not expected to give this much. Today, the plan is to close them or to disconnect them by January 1, 2022. The market coordinator is currently analyzing if some units could be needed in 2022. In that line, we are waiting for any new development and new information. Today, the plan is to keep them until the end of this year. In our own projections, it depends a lot on the hydro evolution for January and February. Apparently it should not be needed. Again, this is an analysis in progress during the recent days. The second one, in relation to the PEC. Well, we do expect that, with the current curves, with the current FX evolution, that the PEC, the current, let's say, PEC will be fully used probably during the second half of next year. That means also that next year we will sell all those renewables through the structure that we have in place. Now, what will happen next? It's something that is currently under development and that the industry and authorities are probably analyzing in detail. I don't have yet nothing else to mention that in that line. For the HVDC and as probably you are all aware, ECL decided not to participate in this one basically because of their risk analysis and risk exposure that was let's say assessed by our team. It's basically that. Right. Thank you, Eduardo. Just to follow up, I mean, you know, in terms of the PEC, do you think one solution would be to effectively raise the ceiling or extend the life? Do you think the generators would likely have to agree to, you know, further measures? Or do you think that maybe this is a different type of solution would have to be found for a different part of the industry or from the state? Just on the HVDC line, could you just shed a bit more color on maybe what some of those in that risk assessment, what maybe some of the key issues were that perhaps made it a bit less attractive for yourselves? Sure. For the first one or the second one, in terms of the PEC, if you ask me, my best personal opinion is that this is something that should be managed through the demand, probably. It is something that, if we need to stabilize the price, you can do it for now, and afterwards, it could be collected by charging it to the end consumers. For the HVDC, basically, the main risks as we could be exposed are related. These are very long. It's a long-term project, right? You need several years. It could be exposed to the negative or positive evolution in the price of some commodities that are related to the topics. This is some type of risk that sort of sometimes we are not. We don't want to have in this type of project because you can end in any direction. The other part is probably related to the permits and the rights of use. That is also a very complex process. Understood. Thanks very much, Eduardo. You're welcome. The next question will be from Rodrigo Garay from BICECORP. Please go ahead. Hello. I want to ask about your awarded price of your recent fuel provision action that you made. Also if you can talk about the providers of these backup contracts of energy. Sure. Hi, Rodrigo. Sorry, the first one, it was related to the fuel? Yeah, I understand that you recently made an option or between your providers to provide your fuel for the next year, your fuel supply. Okay. You were in this process. I want to know the average prices of your fuel provision and also about the other question about the backup contract. Okay. First, in terms of fuel prices, there are two main fuels we use. The first one is, let's say LNG. I will start with the easy. It's LNG, and our provider is... Our supplier is Total. And this fuel comes through a fixed price, almost fixed price or linked to Henry Hub. And these are long-term contracts. We basically don't make annual options for this fuel. Now, for coal, we buy coal on a regular basis, sometimes for the next 6 months, sometimes for the next 3 months. And coal, as you can see the presentation, is mainly linked to API 2, API 6, API 10 indices. And basically, today you can see that. Well, let's say two weeks ago, the forwards and the curves of coal went up to $275 per ton of coal. Sometimes, or recently, we bought some coal for the short term at around $200 per ton. But this fuel is indexed to the API. That means that if the price goes down, then what you need to pay for the coal is also much less than when you started to buy it. Recently, based on the control on prices that the Chinese government announced for coal, we have seen that the forward went down from 235 to less than 170. The market is again coming back to previous levels, hopefully, but still with some volatility. Backup PPAs. The suppliers are. We mentioned that some time ago, we have backup PPAs with Enel. We have backup PPAs with Atlas. We have backup PPAs with Mainstream, with Sonnedix, and probably a couple of suppliers more. We have several backup PPAs. I think at the end, we are looking for this hedge in the whole market. There are also generation companies that are willing to also grow their own margins for the remaining energy that they plan to sell spot. Perfect. Thank you so much. You are going to still lease gas to the plant or have this option? Yes, we will keep that option to do some kind of a maquila with our own gas. Okay. Thank you. Perfect. Ladies and gentlemen, this concludes our question and answer session. At this time, I would like to turn the floor back to Mr. Eduardo Milligan for any closing remarks. Okay. There's nothing else from our side. Thank you very much for your attention, and we'll see you soon. Thank you, sir. This concludes today's conference call. Thank you for attending today's presentation. At this time, you may now disconnect your lines and take care. Thank you. Bye-bye.