Earnings Call: Q2 2021

Jul 29, 2021

Good afternoon, everyone, and welcome to MG Energy Achille's Second Quarter 2021 Results Conference Call. If you need a copy of the press release issued yesterday, it is available on the company's website at www.ng 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 NG Energy at 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. So as usual, I'm here today with Bernardo Del Fante, Head of Corporate Finance and Marcela Munoz, Investor Relations Officer. Today, we will present our first half results and the recent progress on our transformation plan. So please let's move directly to Page number 3, and we'll go through the key messages for this call. So first, as we explained last quarter, the industry is facing a complex 2021 with very high spot prices. These high spot prices are explained by the lack of hydro generation, the unavailability of several efficient thermal coal power plants during the year and also the lack of additional LNG in the system to partially mitigate the absence of hydro and the efficient coal production. So all these factors, together with an increase in commodity prices, mainly coal and LNG, have created a perfect storm and are pushing the spot prices far above where the industry was expecting for this year. In summary, I can say that we're facing average spot prices that are almost twice what we should expect under normal circumstances. And this should be a wake up call, of course, for the industry. 2nd, we'll give you an update of our projects under construction. The Kalama wind farm is almost ready with 34 out of 36 turbines already connected. And in fact, the wind farm is already producing its full output and its official COV should be achieved very soon. We'll discuss in a couple of minutes the status of our 4 projects under construction. 3rd, as we explained in our previous call, we announced on April a second wave of 1,000 megawatts of additional renewals, together with the conversion of 3 coal power plants to biomass and natural gas by 2025. So in this line, during the last quarter, we secured through land concessions the optionality to build up to 1.4 gigawatts of renewables, while we already filed permits for the future conversions. And 4th, I know this is not something new, but we continue to keep a solid and flexible capital structure, while the company continues to have a strong cash generation that should allow ICL to finance its transformation plans with a mix of internal cash flow, financial debt, while gradually increasing the dividend payout ratio in the future. In this line, the Board approved last Tuesday a provisional dividend for $41,500,000 to be paid by the end of August. So with these key messages, let's go through the presentation and discuss some additional topics and details. Before we jump into the Q2 results, on Pages 4 to 6, we show the overall operating performance and main actions implemented over the recent years to transform the company. Page 5 shows ICL main strength, which is its long term contracted portfolio of PPAs with top tier names in the country and an average life close to 11 years. In fact, this graph only shows PPAs up until 230, but most of the company's PPAs are maturing 230. On Page 6, we show an update of the first part of our transformation plan. I mean by that the first 1,000 megawatts of renewals and the closure of 6 coal units. Between the recent acquisitions and projects under construction, we are on track to cover 70% of this first phase in or during the next 12 months with a total investment of $500,000,000 while the remaining projects should reach soon, are ready to build stage and this is something that we'll probably announce during the next quarters. And this also means that the first phase will require a total CapEx below the approximately $1,000,000,000 we initially announced for this first phase. Now let's move to Page 7, in which we present our results of 2021 compared to 2020 by quarter. And this is something new to give you a better view of the operating evolution considering the extraordinary times due to the COVID crisis and the extraordinary quarters we're also facing during 2021. Now what are the key events and effects? As I mentioned at the beginning of this call, the first half of this year, the EBITDA is affected by higher marginal costs due to droughts and availability of thermal plants and gas supply interruptions. From a demand perspective, we can see a positive evolution in physical energy sales during the last three quarters. In fact, we can see a 6% increase in physical energy sales in the Q2 of this year compared to the same quarter of 2020 and a 1% increase comparing first half of this year despite the pandemic and the end of San Divar PPA back in June 2020. This is indeed positive because this higher demand can partially offset the negative impact coming from higher spot prices. And once spot prices return to normality, we should have a positive and permanent impact if demand continues at new levels. If we see the evolution in 2021 and compare the 1st and second quarters, we can see an important improvement in the 2nd quarter. In fact, the EBITDA in the Q2 of 2021 is almost 20% higher than the same quarter of 2020. Considering that the average spot price in the second quarter was even higher than in the Q1, you could have expected a similar quarter. But we need to consider that in the Q1, ECL was strongly exposed to the spot market because CTA and other of our power plants were not available. While in the Q2, most of ECL power plants were available and the company reached during some weeks an historic maximum production above 1700 megawatts. This means the stop loss limit or physical hedge was available to cover our contracted demand. And in addition, hydrology temporarily improved during June, while given the higher prices of commodities and inflation, the price on PPAs was also adjusted to reflect these higher production costs. So the Q2 was positively impacted by regulated revenues, higher demand from mining companies and a lower supply cost compared to the Q1. Now what comes next? To be honest, hydrology is not improving and we may be facing one of the driest years of the last 60 years. This will keep pressure on the supply cost during the Q3 and probably more, probably during the next 9 months. In this scenario, the availability of efficient thermal plants and LNG in the system will be key to keep the system's security and running without problems. Finally, net income was impacted by the upfront recognition of $48,000,000 financial expenses on the sale of regulated refills. This is a one shot and upfront recognition of the long term financial costs of selling these receivables. And this operation, as we explained before, will release more than $120,000,000 in 2021 for our cash flow. Now please turn to Page 8. These three graphs show better what I explained at the beginning of this call. On top, we can see the average spot price evolution during the last 4 years. The average spot price of the first half of twenty twenty one is close to $70 even a bit more. Well, 1 year ago, we were expecting something similar to 2020 levels. I mean, by that half of the current spot price. How this happened? On the bottom right, we can see hydro generation during the last 3 years. 2019 and 2020 were already dry years. So this means that unfortunately, we have a new record in 2021. During June, we had a temporary improvement in hydro generation, but I anticipate you that this is this was not the case during July. Then to the left, we can see the unavailability of coal power plants in the system. We can see the difference, almost 700 megawatts less in 2021 compared to 2020. Both effects combined have created the current stress for the system. Then what can we do to mitigate this lack of hydro and efficient coal? Well, the answer is natural gas. Unfortunately, this year, there were no imports from Argentina. There were some supply issues. And finally, the LNG spot price skyrocketed above $10,000,000 $12 per 1,000,000 BTU, sometimes even closer to $14,000,000, $15 per 1,000,000 BTU. This means LNG can give some relief, but not as in previous years because with the current LNG prices, the variable cost with LNG is close to $100 and that's the $50 or $60 of previous years with the previous LNG prices. Next on Page 9, we show an example of the spot price evolution during 10 days in June. Even considering June was not under the same stress than other months, we can see the high volatility and the decoupling between day and night spot prices. We are facing spot prices during the day in the range of $30 to $40 and during the night above 100 dollars sometimes close to $150 Now on Page 10, we have added a snapshot of ECL and regulated customers. Both graphs are showing the physical sales to these clients and we can clearly see how April, May June were positive, even considering the COVID restrictions and lockdowns. So if this trend continues, we could expect a positive impact during the second half that will certainly help to offset the higher spot prices in this period. Then Page 11 shows as usual DCO demand supply balance. This graph shows the power sources to meet the demand from our clients as well as the resulting average realized prices and direct supply costs. So this is a graphic explanation of what happened in the first half of this year. IEM, CTA and CTH power plants continued to operate as baseload units. However, CTA was only available during the Q2 being out of service for 4 months as the turbine had to be repaired in Europe. The overall cost of our coal plants in general was higher because of higher coal prices and technical limitations and intermittence, which caused them to operate less efficiently. As we move to the right, we see that our 2 combined cycle units running with natural gas represented around 20% of our energy supply. The rest of our core units, which last year were marginally dispatched because of their higher production costs, had to be often dispatched this year, representing around 13% of our power supply. As I mentioned earlier, this was the result of the systems supply issues in terms of low hydro and lower availability of efficient coal plants. Finally, ECL supplied 32% through purchases from both the spot market and a supply agreement with another generation company. So our physical energy purchases decreased compared to last year, but spot prices increased significantly. The result was that our average supply costs, as we can see in the lines in the graph, increased from $56 to $66 per megawatt hour. However, on the positive side, the average monomix price also increased from $100 to $108 per megawatt hour. So this means despite the total cost increase in $10 the average monomic price increased in $8 offsetting then a good portion of the negative impact. Hydrology during the rest of the year will be key to continue seeing a reduction in our average supply cost. But as I said before, the initial information is not optimistic on the new hydrologic gear, but we do expect that marginal costs will go down. Now the question will be to what levels and based on which hydrology. Now let's go to or let's go through our guidance on Page 12. Given the current context, we have decided to revise our EBITDA guidance and reduce the range from the original €460,000,000 to €480,000,000 to a new range €20,000,000 below that will still be challenging given the higher conditions foreseen for the rest of the year. The net recurring income, excluding the financial expenses related to the sale of receivables, was updated to EUR 150,000,000 to EUR 170,000,000. This means EUR221,000,000 final dividends will be proposed considering this range and excluding the one shot impact related to the sale of regulated receivables. Now please turn to Page 13. We have updated our CapEx forecast for 2021 and we expect investments for approximately EUR 350,000,000 mainly focused on our renewable and transmission projects as well as maintenance and dismantling costs of Units 12 and 13, which were shut down back in 2019. So in this forecast, we are including the expected CapEx for 2022, which includes the completion of the renewable and transmission projects that are currently under construction and also additional CapEx related to an additional wind project from our portfolio. That should be announced soon. We plan to finance these capital expenditures with a mix of internal cash and bank financings. Our net debt to EBITDA ratio increased slightly above 2 times and it could and it should continue increasing, in fact, in the following years to optimize our capital structure once we continue executing the renewals that we have in our pipeline. But we intend to keep our leverage ratio not exceeding 3 times on a structural and regular basis. Our liquidity is strong since we recently have received more than EUR 100,000,000 for the sale of long term accounts receivable from distribution companies arising from the tariff stabilization law. And this transaction should allow us to raise funds for an additional €17,000,000 between today and €223,000,000 So this is the remaining amount without affecting our leverage ratios. Also, we expect to draw the €125,000,000 loan agreement with the EIBB, which is currently completely available to finance our renewable projects. This is something that we should draw in the upcoming weeks or months. On Page 14, we are sharing the main regulatory topics that will be in the agenda for the medium and long term. There are no relevant changes compared to the main topics we presented in our last quarter. As you know, most of these initiatives are under analysis. Some of them are frozen and others are following its regular process. The following section includes the description of our transformation projects. The 4 pillars are described on Page 16. Then on Pages 1718, we present our portfolio of clients and how the indexation of these PPAs will evolve in the medium term. Now this is key to understand and better model our future cash flows. As you can see on Page 18, from 2020 to 2022, we will see an important switch in the indexation of our portfolio of contracts. U. S. CPI will represent almost 80% by 2022 compared to 60% back in 2020, while coal will move from 30% to close 10%. LNG will continue driving the regulated PPA in the north and a small portion of the PPA in the center. Page 19 shows a complete view of the transformation plan by type of technology until 2025. The key component is the development of up to 2 gigawatts of renewables. And this brings us to next Page 20, in which we can see how by 2022, we will have completed 70% of the first phase and soon we will launch the construction of additional renewables to reach the objective by 2025. The additional component of the transformation plan is the conversion of the remaining 3 coal units to biomass and natural gas. So please turn to next Page 21. And as we explained in our previous call, the plan is to perform work as much as possible without interfering with the normal operation and maintenance scales for these plants. In the case of IEM, the existing coal fired boiler will be converted to gas, representing CapEx of approx 50,000,000 dollars It will provide a natural hedge in case of high marginal costs. For the future and depending on how technology and the industry evolve, we will study a potential repowering of the plant with a to fire also a mix of hydrogen and natural gas in the long term. But that would be a second phase that needs to be properly evaluated. Under the current plan, several works for the conversion will be made in advance during the maintenance periods scaled between now and 2025. The final conversion works will be made during the planned overhaul in the second half of twenty twenty five. So in such a way, the plant will be ready to operate with gas starting 2026 with limited unavailability until 2025. In the case of CTA and CTH, the units will require only limited modifications as they are already capable of burning biomass. And the adaptations need to be made in the material handling system, the coal yard and the fuel silos. There is an overhaul planned for the last quarter of 2022 where these common facilities will be changed to make them suitable to store and transport biomass. Now these plants will remain as backup units, providing a physical hedge for our operations, supporting during in the long term the expansion with renewables. And the CapEx needed to adapt these plants to burn biomass is approximately EUR 25,000,000 for both in total. Then the next pages give some additional details and pictures of the renewal projects under construction. Once they start operations within the Q3 of this year and the first half of twenty twenty two, we will have completed an epoxy made €500,000,000 investment and 0.7 gigawatts out of the 1 gigawatt we announced for the first phase. Win Kalama on Page 22 has a global advance of 97%. And as I mentioned before, this project is already injecting energy to the grid, which in the current market context is very important. One important piece of information, we announced 151 megawatts for this project. But given some technical optimizations during the execution, we will be able to reach almost 160 Megawatts when the last two turbines are ready. This project is then on budget and performance with a limited delay in its scale. Then if we move to the next project on Page 23, Capricornio Solar Plant has an important delay in its original schedule and it's expected to be ready next year due to issues related to the delayed detention of certain archaeological permits for some ground trucks as well as financial issues of its contractor. So the COVID pandemic has influenced both. And currently, the related permits have been obtained. So these are good news. And a new team and contractor will be ready to finish this project in 2022. So we are almost ready to restart the construction. On next Page 24, we present Tamaya solar plant with a global advance of 90%. We expect it to start and the second phase in the Q4 of 2021. So again, this is a project that is on track with some delays, not huge, but with some and that will be ready during this year. On Page 25, we present the global advance of Koya Solar project. The project is on track to reach its synergization during the Q2 of 2020 2. In this case, we have experienced so far limited delay in the transportation of equipment from Vietnam due to COVID restrictions. And as probably you know, the marine transportation industry is also under stress and facing increased costs. Then on Page 26, we're presenting good news for our renewable plan. We have secured 2 land concessions, Pampa Fidelia and Pampa Yolanda in the northern region close to our operations. So we have synergies and also very close to our mining clients. And these two concessions provide us a combined capacity of 1.4 gigawatts between wind, solar and storage or the so called hybrid projects. So the exact design and configuration of these projects is under analysis and will continue its development phase to reach a ready to build stage as soon as possible. So this means between the existing portfolio of renewable projects and these additional 2 land concessions, we have secured projects with a potential for more than 2.5 or 3 gigawatts, which will be needed for the transformation, but also for growth opportunities that we are looking in the future. Now regarding the 4 transmission projects described on Page 27, with a total investment of EUR 53,000,000, 2 of them were completed and one additional project will be ready very soon, while the last one is expected for the Q1 of next year. And finally, on Page 26, we are ready to start construction of the latest transmission projects that were awarded since the decrease were issued and we are completing the basic engineering. So now I will leave you with Bernardo Dita to cover the following section and go through our financial performance. Thank you, Eduardo, and good afternoon to everyone. Please turn to Slide 30 for details on our EBITDA financial evolution in the first half of this year. EBITDA reached 188,000,000 dollars a 7% decrease compared to the first half of last year. Now if we isolate each effect, we see a positive $60,000,000 impact from an increase in average realized prices in both the regulated and free client segments. The 3% tariff increase in the free client segment is explained by the increase in CPI and core prices, which PPA tariffs are indexed and also by the smaller tariff discount of the ANSAP BPA as compared to last year. The more significant 12% increase in average realized prices on sales to regulated customers is mostly explained by the sharp increase in the applicable Henry Hub, CPI and coal prices. But the wider variations observed from quarter to quarter in average regulated prices are explained by an uneven recognition of price increases due to the late publication of the tariff agreement. So excluding this timing effect, the average realized price on regulated sales should have been around $130 to $120 per megawatt hour in the second quarter as opposed to $140,000,000 reflecting an approximate 7% tariff increase, clearly attributable to fuel and CPI increases. So please do not consider the $140 second quarter average as a recurring number, but rather as a year in the $125,000,000 to $130,000,000 area at current euro prices. We do not show any effect on volume sales as these were price stable, which is good news. Regulated physical sales began to recover in the Q2, while key client sales remained almost even despite the end of the Santira CPA in June of last year. Now as our own generation increased compared to last year, we reported lower physical energy purchases, representing a $3,000,000 positive effect on EBITDA. A third positive impact was a $5,000,000 insurance recovery from a past launch at ION. Just as we discussed in our Q1 call, by far the most significant impact amounting to 36,000,000 dollars plus the increase in marginal cost, which Eduardo already explained. So we bought less from the spot market, but at much higher prices. The second most important effect was the increase in fuel costs due to increases in both our own generation and also the higher fuel prices. Slide 31 shows the evolution of net result, which went from $66,000,000 net income in the first half of twenty twenty to $30,000,000 in the first half of this year. Last year, we reported non recurring expenses of $10,000,000 related to the premium paid on the early redemption of our $400,000,000 144A bond, which we refinanced with a new $500,000,000 bond. So our net recurring income in the first half of last year was $76,000,000 Apart from the EBITDA decrease we just talked about and which was one of the main two causes for the net income decrease, we can see an increase in depreciation expenses due to the purchase of Aerobica Monza Veronza and the major maintenance of the Unit 16 combined cycle plan. Recurring financial expenses decreased due to lower average coupon rates and greater capitalization of interest in our investment projects. All of this would have led us to report $66,000,000 in net income, having not been of the $36,000,000 after tax effect of 1 shop financial expenses. This resulted from the sale at a discount of $167,000,000 in long term accounts receivable from distribution companies related to the price stabilization loss. It's own fees to a company called Tiller Electricity Tech, which in turn issued a 144A Regus bond to finance the purchase of accounts receivable from 4 groups of generation companies. In June, this company completed for a 2 private placement with the participation of the IBE, Allianz and Goldman Sachs to raise funds for the purchase of accounts receivable through the end of the accrual period in July 2022. Now let's go to Slide 32, please. Our net debt increased by $113,000,000 from year end 2020. The main cash outflows included BRL 83 1,000,000 in CapEx, mostly in our renewable projects, the BRL 60,000,000 final dividend on 2020 net earnings and BRL 19,000,000 in income taxes. The next bar you see on the chart is the biggest one, explaining most of the increase in our net debt. And this relates to an $87,000,000 increase in financial leases, which qualify as financial debt for IFRS 16. These are primarily related to land concession, which we call Concepciones de Unso Oneroso in Spanish, such as the Pampa Yolanda and Pampa Yuria Land Site in the Antebarraca region for the future development of high risk renewable projects with Gerardo already mentioned. Among the most relevant cash inflows during the first half, we have in first place $118,000,000 in cash proceeds from the sale of accounts receivable to 3 electricity tech. This true sale of receivable has allowed us to enhance liquidity and ensure financing for investments in renewables without increasing our debt. The cash from operations provided $23,000,000 while we also received an 8 $1,000,000 payment from our 50% owned subsidiary, Penn. On Slide 33, we provide an overview of our ratings and debt business. Net debt service increased from 1.8 to 2.1 times mainly because of the financial leases and the EBITDA decrease. We did not report any other change in debt. As we discussed in our last call, we have an available $125,000,000 loan with IBD Invest supporting our decarbonization plan. Due to a lower interest rate, this loan will monetize the displacement of Tier 2 emissions from the early closure of coal plants, whose operation will be repaid by the Calama reserve. So our balance sheet remains strong, giving us room to finance our planned investment in renewables. This has been acknowledged by the rating agency. So our BBB trust rating was confirmed by Fitch, Massimo and we keep our BBB rating by Standard Force, while our local AA- bystander was given a positive outlook in January of this year. On Slide 14, we would like to highlight that our Board approved a $41,500,000 traditional dividend that will be paid on August 26 and which increased our dividend yield to 72%. Over the last 12 months, our stock price fell 60%, while the East side showed a 9% recovery. The energy stock and electric utilities in general, decoupled from the EBITDA beginning September 2020. Well, this is all on my side. Thank you very much. And I will now leave you with Eduardo for the final remarks. Thank you, Frederica. Well, to conclude the presentation, we want to summarize, as always, some key takeaways on Page 35. So first, we reported a challenging Q1 in our previous call. The second quarter shows an important improvement compared to the previous quarter. But unfortunately, and to be honest, we are still in the middle of this storm. The system is under pressure, and we are doing our best efforts to reach the revised EBITDA guidance that we gave today. 2nd, ENGIE is fully committed to implement the transformation plan for our operations in Chile, and we are glad to say that our first renewal project is almost ready on budget and performance with a limited delay. But this is just the beginning, and we have a lot of work and challenges ahead to complete the full plan. 3rd, we just announced the second phase of our transformation, which will allow for a full exit from coal by 2025 with clear priorities for sustainable and long term value creation. So this process is on track, and we have already filed the required permits for those conversions. And 4th, all this transformation remains supported by a solid balance sheet with the liquidity enhanced by 2 innovative financing structures, a true sale of long term account receivables and the green financing with IDB. So well, with these final messages, we are completing our 2nd quarter presentation first half, and we hope this presentation was helpful. Thank you for attending this call, and we are ready, as always, for any questions, recommendations, suggestions and comments that you may have for us. Thank you. The floor is now open for questions. First question will come from Mario Rucini of Santander. Please go ahead. Hi, Eduardo, Marcela and Benavica. This is Mario Ricchini from Santander. Thanks for the call. My first question is regarding your coal generation. We saw that IEM and some other efficient coal plants produced more than their normal during the second half of this year in order maybe to reduce the system costs. So could you tell us a little bit more about these dynamics? And if this could lead to a decrease in the core availability during the second half of this year, perhaps due to the postponement of some maintenance during this the second half the second quarter of this year? The second one is what's your view for the marginal cost in the second half of twenty twenty one? And what is implicit in your EBITDA guidance of around EUR 260,000,000 for the second half? And the last one is why is recurring and renewable CapEx slowing up? Is this explained by some inflation pressures? And how much are you expecting to spend with these mentoring costs in total? If you could also provide us more details on this, it would be very helpful. Thanks. Hi, Maurillo. Thanks for your questions. So I will start with the first one. In terms of cogeneration during the first we need to recall that during the Q1, most of our coal units not most, but some of our coal units were not available. So CTA was in maintenance due to a failure in the turbine. The plant came back during the Q2. We also had some restrictions on IEM. And during the Q2, most of our plants were available except a program maintenance that we postponed some months before for CTH, which was not available during May. So it has been very important during the Q2 to keep most of our units available to basically provide a stop loss limit for our contracted sales. And this is what is probably explaining also the difference between the Q2 and the Q1 in terms of our exposure to the very high spot prices that we have seen during this half. Even having higher spot prices during the Q2 than in the first. Now in the second half of the year, we expect to keep most of our units available and we don't have important maintenances that are programmed during the second half of the year. What is also important to note is that some of our, let's say, oldest coal units or less efficient coal units like Unit 14 and 15 that are planned to be disconnected by the end of this year have been dispatched regularly during this first half. The same with the CTM-one and CTM-two, which are expected to be disconnected by 224. And this is basically explained by the graph that we showed during the presentation, where we have 700 on average 700 megawatts less of efficient coal. And the system is requiring to use less efficient power plants like the ones that last year were marginally dispatched from our side. So then what is important in the second half of the year is to keep a high availability of our thermal plants. Then for the marginal costs, your second question, it's a bit difficult to say what will be the marginal cost. We do expect lower marginal cost than in the first half of this year. The hydrologic year should start in the second half, let's say. And this should the smelting, the ice smelting should help to reduce the marginal cost. Now the question is when this will start? It will start in August, September, October or by the end of the year. And our expectation is that marginal costs could be around 50, 60, but it will depend on how hydrology evolves. And we also need to consider that this year, this particular year, we are seeing a huge volatility also in LNG prices. And this will also impact the average marginal cost. Today, if we want to buy an additional cargo, probably the price will be between $14 $16 per 1,000,000 BTU. You can remember that 1 year ago, it was around $3 or $4 So this is a huge impact also because gas will be dispatched during peak hours. And instead of producing at $60 we'll see $190 or 110 dollars spot prices when we dispatch gas. So it's helping, but it's not helping a lot. And finally, in relation to the CapEx, what I can say is that we haven't seen so far any impact related to inflation in the maintenance. So at this stage, I don't have, let's say, any figure or any heads up in this line that we should expect in the medium term a permanent increase in the recurring CapEx. And in fact, as you know, with the plan that we are developing and implementation of renewables, our recurring CapEx will go down over the next years. And once the plants also are converted to the other technologies, we'll continue going down and we will keep our portfolio with a much lower annual recurring CapEx based on renewals mainly and the combined cycles. The next question will be from Rodrigo Mora of Moneta. Please go ahead. Hello, good afternoon. Hi, Eduardo, Marcela, Bernadita. Thank you for the presentation and taking my questions. My first question is related, if you would explain again, repeat the expiration of the higher sales of regulated customer. I didn't understand it was a reverse of provision or something like that, that could explain the higher implicit price of this sale? And my second question is related to LNG cargoes and how easy is that the supplier could cancel future cargoes due allocating to 4th major? Thank you. Hi, Rodrigo. How are you? Well, good questions. The first one, let me explain it a little bit more. So do you remember that back in 2019, we started with this new price stabilization mechanism. So during some time, let's say, the price was not or let's say, we started to work with a new mechanism. The decrease were not issued 6 months after the new tariff or the new system started, but the decrease were only known this year. So this year, we saw the final 1, 2 and 33, which at the end is bringing us the exact amount of energy and the final prices. So this is not a reverse, but it's an additional income that we are recognizing in 2021, partially explaining part of the revenues that we should have considered in 2020 and in the Q1 of 2021. This means our provision was lower than it should have been in this period. And once the final decrease were issued, we are recognizing these additional revenues. So it's another a reverse of our provision, but it's a recognition of an additional income because we undervalued, let's say, the total invoice during part of 2020 and the Q1 of 2021. Once we had the final decrease, then we were able to adjust the total invoice, let's say. And that's why in the Q2, we have this one shot, as Verita was explaining, which is impacting in some way the average prices, etcetera. And Bernardo, I think, explained this. The €140,000,000 should be around €125,000,000 to 130,000,000 and the total impact is around €15,000,000 to €20,000,000 Let's say, these additional revenues that we're recognizing now in 2021 that we should have recognized in 2020. But in 2020, we didn't have, let's say, the final decrease. So we didn't do it back in 2020 and now we're doing in 2021. Is it clear or? Okay. This is a recognition of revenues undervalued of the last year? Exactly. Okay. Okay. So when you had the decrease, the 1, the second, the third, you knew exactly amount of energy and the prices. And with that, the company will receive more revenues for the of the accounts. Exactly. Okay. Exactly. And this is because That's why you explained the higher average price during the Q2. Exactly, exactly. So when we see the EUR 120,000,000 EBITDA, there are EUR 15,000,000 to EUR 20,000,000 that we are that is a one shot, let's say. But even that the second quarter is much better than the Q1 for all the reasons that we also explained before. So this is one. And the second one is LNG cargoes. Well, it depends on each contract. And force majeure and this type of situations, I mean, we need to continue discussing with our suppliers. These are long term suppliers. These are long term contracts. And once you have this type of situation, then you need to go through all the different, let's say, steps from a commercial point of view and also legally that you have to solve the situation. But who was the supplier, the LNG supplier that announced a cancel of the last LNG cargo? We only have one supplier, one long term supplier, which is Total. It's not ENGIE, by the way. Okay. So Total, at the end of June announced a cancel of LNG Cargo that the company could had to receive this July. Hello? Yes. Hello? Can you hear me? Yes, we can hear you. Okay. So at the end, it depends, but total was total announced a cancel of LNG. Are there any alternatives to receive some compensation? Eduardo, your line is open. Hello, Eduardo. Perhaps your line is muted on your end. Okay. This is the conference operator. Thank you for holding. We're going to continue the conference while we try to connect Eduardo once again. Rodrigo, your line is now open again if there's another question or if Bernard, Dieter and Marcella can help you with your previous one. Yes, please continue. Yes. I think there was there is Rodrigo's question about the whether the supplier that has involved course majeure would provide some sort of compensation. And we are working on that, Rodrigo. I don't have any more news from that. Maybe we'll move on to the next question. He may have stepped away. Okay. Thank you. The next question will be from Andrew McCarthy of Credicorp Capital. Good afternoon, everyone. Thanks for taking my questions. My first one was, if you're looking at all at perhaps delaying any of the planned closures of the coal plants? Thinking in particular, the planned closure of U14 and U15 at the end of this year, given how important that has been lately as helping you on the sort of physical hedge side, any thoughts on that? And then the second question was regarding the slide number 13. Just seeing there in the graph, it seems like you're anticipating EBITDA in 2022 of around sort of 4 $70,000,000 to $480,000,000 a year, just looking at the end of the red line there. Just wondering if you could provide any sort of help to us on what the key drivers there would be to get that year on year growth? I mean, I guess, largely, it's going to be to do with the incoming renewables projects, but it would be great to hear your thoughts on that. Yes. I don't know, Eduardo, if he's on the line. I think still unavailable to reconnect. But well, in terms of the considering delaying the plant closures, I haven't heard of that. I do know that our plant is still to close those 2 units. Unless there's a requirement, let's say, from the authorities, I mean, unless there's some sort of very critical situation, let's assume that the fraud will continue and become even worse. But other than that, we continue with our current plans of closing these units by the end of the year. Now the in terms of your second question was about the EBITDA guidance for 2022 or I mean, where could some improvement come from? And as you said, it is very much related to the economy renewables. So that should help us definitely reduce the average procurement cost of energy. And so that is what explains the improvement in EBITDA. The next question will be from Fernand Gonzalez of BTG Pactual. Please go ahead. Hi, guys. I have two questions. One is a follow-up on the cancellation of the LNG shipment. Just how significant was that shipment? Is the gas supply somewhat compromised for the second half? If you could walk us through your gas availability for the second half, especially considering this very dry scenario? And the second question is that I've heard that ENGIE is interested in bidding for the Quimaro Aguirre transmission line. Is this MG Chile or is it the parent company? And if it is, you guys, would this be through a consortium or would you be going by yourself? Hi there, Bernalita. Can you hear me? So maybe I can help you with the first one also, and I think this is something that Rio has seen before. So this is 1 cargo and the cancellation that we faced 1 month ago is related to 1 cargo and is related to specific case of Fort Major in the terminal, the LNG terminal. But this is not going to compromise in any way the future cargoes or the existing contracts. So this is a one shot, and we have to continue discussing with our supplier what were the impacts and find commercial or any other type of solution. But this is something that we are currently discussing with them at some point in time. Once we have more information, we will be able to share this information with you. But of course, not having this cargo in this current situation, it's very important. It's a material impact because instead of producing through our combined cycle at the expected production cost with the fixed price and long term price that we have secured through this contract, then we need to buy LNG spots or we need to buy electricity in the spot market to supply our contracts. So you can imagine that the impact is not marginal and that we will do everything we can to support our claim to our commercial partner or supplier, let's say, that's the first one. So this is a one shot. It's not something that will continue during the second half, And we will continue in business as usual bringing as much gas as we can to the system. And probably all the players and companies in the system are doing the same. And the second question was related to the potential participation in the new option. Yes, this is something that we are evaluating through Engineering Via Chile. And why? Because this is part of the transmission business and part of the business perimeter that we have in Chile through Engellia Chile. How it could be developed this type of project? Again, something similar to TEN. If we participate in this option because this will be a very competitive option, then we will probably do it through a similar structure like the one we developed for the 600 kilometer 10 transmission line. And this concludes the question and answer session. At this time, I would like to turn the floor back over to ENGIE Energy Atelli for any closing remarks. Thank you. No, not anymore from my side. Just apologize for the disconnection. I don't know what happened. But again, we are always available, and the team here is available, Marcela and Margita, for any questions that you may have in the future. And have a good day, and thank you for your participation in this call. Thank you. This concludes today's presentation. You may now disconnect your lines. Have a great day.