Good afternoon, everyone, and welcome to Engie Energia Chile'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.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, actual results may differ materially. Please refer to the d etailed 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 Energia 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 today with Bernardita Infante, Head of Corporate Finance, and Marcela Muñoz, Investor Relations Officer. Today, we will present our first half results and the recent progress on our transformation plan. Please, let's move directly to page number three, and we'll go through the key messages for this call. 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.
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. Second, we'll give you an update of our projects under construction. The Calama Wind Farm is almost ready, with 34 out of 36 turbines already connected. In fact, the wind farm is already producing its full output, and its official COD should be achieved very soon. We'll discuss in a couple of minutes the status of our four projects under construction.
Third, as we explained in our previous call, we announced on April a second wave of 1,000 MW of additional renewables, together with a conversion of three coal power plants to biomass and natural gas by 2025. In this line, during the last quarter, we secured, through land concessions, the optionality to build up to 1.4 GW of renewables, while we already filed permits for the future conversions. Fourth, 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 ECL 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 $41.5 million to be paid by the end of August.
With these key messages, let's go through the presentation and discuss some additional topics and details. Before we jump into the second quarter results, on pages four to six , we show the overall operating performance and main actions implemented over the recent years to transform the company. Page five shows ECL 's main strength, which is its long-term contracted p ortfolio 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 2030, but most of the company's PPAs are maturing post-2030. On page six, we show an update of the first part of our transformation plan. I mean by that, the first 1,000 MW of renewables and the closure of six 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 million , while the remaining projects should reach soon a ready-to-build stage. This is something that we'll probably announce during the next quarters. This also means that the first phase will require a total CapEx below the approximately $1 billion we initially announced for this first phase. Let's move to page seven, in which we present our results of 2021 compared to 2020 by quarter. 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 are also facing during 2021. 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, unavailability 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 second quarter 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 Zaldívar PPA back in June 2020. This is indeed positive because this higher demand can partially offset the negative impact coming from higher spot prices. 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 first and second quarters, we can see an important improvement in the second quarter. In fact, the EBITDA in the second quarter 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 first quarter, you could have expected a similar quarter. We need to consider that in the first quarter, ECL was strongly exposed to the spot market because CTA, another of our power plants, were not available. While in the second quarter, most of ECL power plants were available, and the company reached, during some weeks, an historic maximum production above 1,700 MW. This means the stop-loss limit or physical hedge was available to cover our contracted demand.
In addition, hydrology temporarily improved during June, while giving the higher prices of commodities and inflation, the price on PPAs was also adjusted to reflect these higher production costs. The second quarter was positively impacted by regulated revenues, higher demand from mining companies, and a lower supply cost compared to the first quarter. 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 third quarter and probably more, probably during the next nine 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 million financial expenses on the sale of regulated receivables.
This is a one-shot and upfront recognition of the long-term financial cost of selling these receivables. This operation, as we explained before, will release more than $120 million in 2021 for our cash flow. Please turn to page eight. 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 four years. The average spot price of the first half of 2021 is close to $70, even a bit more. One 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 three years. 2019 and 2020 were already dry years. This means that unfortunately, we have a new record in 2021.
During June, we had a temporary improvement in hydro generation. I anticipate you that this was not the case during July. To the left, we can see the unavailability of coal power plants in the system. We can see the difference, almost 700 MW less in 2021 compared to 2020. Both effects combined have created the current stress for the system. 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, $12 per million BTU, sometimes even closer to $14, $15 per million 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 not the $50 or $60 of previous years with the previous LNG prices. On page nine, 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-$40, and during the night, above $100, sometimes close to $150. 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, and June were positive, even considering the COVID restrictions and lockdowns. 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. Page 11 shows, as usual, ECL 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. This is a graphic explanation of what happened in the first half of this year, i.e., CTA and CTH power plants continued to operate as base load units. However, CTA was only available during the second quarter, being out of service for four months as a 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 two 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 system's 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. Our physical energy purchases decreased compared to last year, but spot prices increased significantly.
The result was that our average supply cost, as we can see in the lines in the graph, increased from $56 to $66 per MWh. On the positive side, the average monomic price also increased from $100 to $108 per MWh. 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 costs. As I said before, the initial information is not optimistic on the new hydrologic year. We do expect that marginal costs will go down. The question will be to what levels and based on which hydrology? 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 million-$480 million to a new range, $20 million below. That will still be challenging, given the hydro 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 $150-$170. This means 2021 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 $350 million, mainly focused on our renewable and transmission projects, as well as maintenance and the dismantling costs of units 12 and 13, which were shut down back in 2019.
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 x, 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. We intend to keep our leverage ratio not exceeding 3 x on a structural and regular basis. Our liquidity is strong. Since we recently have received more than $100 million for the sale of long-term accounts receivable from distribution companies arising from the tariff stabilization law.
This transaction should allow us to raise funds for an additional $17 million between today and 2023, so this is the remaining amount, without affecting our leverage ratios. We expect to draw the $125 million loan agreement with the IDB, 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, others are following its regular process. The following section includes the description of our transformation projects. The 4 pillars are described on page 16.
On pages 17 and 18, we present our portfolio of clients and how the indexation of these PPAs will evolve in the medium term. 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 less than 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 GW of renewables. This brings us to next page 20, in which we can see how by 2022, we will have completed 70% of the first phase. 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 three coal units to biomass and natural gas. Please turn to next page 21. 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 schedules for these plants. In the case of IEM, the existing coal-fired boiler will be converted to gas, representing CapEx of approx $50 million. It will provide a natural hedge in case of high marginal costs.
Depending on how technology and the industry evolve, we will study a potential repowering of the plant with a CCGT, with a combined cycle, and the possibility to fire also a mix of hydrogen and natural gas in the long term. 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 scheduled between now and 2025. The final conversion works will be made during a planned overhaul in the second half of 2025. In such 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 courtyard, 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. These plants will remain as backup units, providing a physical hedge for our operations, supporting, in the long term, the expansion with renewables. The CapEx needed to adapt these plants to burn biomass is approximately $25 million for both in total. The next pages give some additional details and pictures of the renewal projects under construction.
Once they start operations within the third quarter of this year and the first half of 2022, we will have completed an approximate $500 million investment and 0.7 GW out of the 1 GW we announced for the first phase. Wind Calama, 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 MW for this project, but given some technical optimizations during the execution, we will be able to reach almost 160 MW when the last two turbines are ready.
This project is on budget, on performance, with a limited delay in its schedule. 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 delay in the obtainment of certain archeological permits for some ground tracks, as well as financial issues of its contractor. The COVID pandemic has influenced both, and currently, the related permits have been obtained, so these are good news. A new team and contractor will be ready to finish this project in 2022. 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 energization during this quarter, and its commercial operation to be achieved in two phases, one in the third quarter and the second phase in the fourth quarter of 2021. 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 Coya Solar Project. The project is on track to reach its energization during the second quarter of 2022. In this case, we have experienced so far a limited delay in the transportation of equipment from Vietnam due to COVID restrictions. As probably you know, the marine transportation industry is also under stress and facing increased costs. On page 26, we're presenting good news for our renewable plan.
We have secured two 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. These two concessions provide us a combined capacity of 1.4 GW between wind, solar, and storage, or the so-called hybrid projects. 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. This means between the existing portfolio of renewable projects and these additional two land concessions, we have secured projects with a potential for more than 2.5 GW or 3 GW, which will be needed for the transformation, but also for growth opportunities that we are looking in the future.
Now, regarding the four transmission projects described on page 27, with a total investment of $53 million, two of them were completed and one additional project will be ready very soon, while the last one is expected for the first quarter of next year. Finally, on page 26, we are ready to start construction of the latest transmission projects that were awarded since the decrees were issued, and we are completing the basic engineering. Now, I will leave you with Bernardita to cover the following section and go through our financial performance.
Well, 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 million, a 7% decrease compared to the first half of last year. If we isolate each effect, we see approximate $60 million 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 coal prices, to which PPA tariffs are indexed, and also by the smaller tariff discount of the AMSA PPA 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.
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 decrease. Excluding this timing effect, the average realized price on regulated sales would have been around $120-$130 per MWh in the second quarter, as opposed to $140, reflecting an approximate 7% tariff increase clearly attributable to fuel and CPI increases. Please do not consider the $140 second quarter average as a recurring number, but rather a figure in the $125-$130 area at current fuel price levels. We do not show any effect from volume sales, as these were quite stable, which is good news.
Regulated physical sales began to recover in the second quarter, while free client sales remained almost even despite the end of the Zandivar PPA in June of last year. As our own generation increased compared to last year, we reported lower physical energy purchases, which is sending a $3 million positive effect on EBITDA. A third positive impact was a $5 million insurance recovery from a past loss at IEM. Just as we discussed in our first quarter call, by far the most significant impact, amounting to $36 million, was increasing marginal cost, which Eduardo already explained. We bought less from the stock market, but at much higher prices. The second most important effect was increasing fuel costs due to increases in both our own generation and also the higher fuel prices.
Slide 31 shows the evolution of net results, which went from $66 million net income in the first half of 2020 to $30 million in the first half of this year. Last year, we reported non-recurring expenses of $10 million related to the premium paid on the early redemption of our $400 million 144A bond, which we refinanced with a new $500 million bond. Our net recurring income in the first half of last year was $76 million. 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 Eólica Monte Redondo and the major maintenance of the Unit 16 combined cycle plant. 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 million in net income, had it not been for the $36 million after-tax effect of one-shot financial expenses. These resulted from the sale, at a discount, of $167 million in long-term accounts receivable from distribution companies related to the price stabilization law. We sold these to a company called Chile Electricity PEC SpA, which in turn is sued a 144A/ Reg S bond to finance the purchase of accounts receivable from four groups of generation companies. In June, this company completed 4(a)(2) private placement with the participation of the IDB, Allianz, and Goldman Sachs, to raise funds for the purchase of accounts receivable through the end of the accrual period in July 2022. let's go to slide 32, please. Our net debt increased by $113 million from year-end 2020.
The main cash outflows included $83 million in CapEx, mostly in our renewable projects, the $50 million final dividend on 2020 net earnings, and $19 million in income taxes. The next bar we see on the chart is the biggest one, explaining most of the increase in our net debt. This relates to an $87 million increase in financial leases, which qualify as financial debt for IFRS 16. These are primarily related to land concessions, which we call concesiones de uso oneroso in Spanish, such as the Pampa Fidelia and Pampa Iberia land sites in the Antofagasta region, for the future development of hybrid renewable projects, which Eduardo already mentioned. Among the most relevant cash inflows during the first half, we have in first place, $118 million in cash proceeds from the sale of accounts receivable to Chile Electricity PEC SpA.
This true sale of receivables has allowed us to enhance liquidity and ensure financing for our investments in renewables without increasing our debt. The cash from operations provided $23 million, while we also received an $8 million payment from our 50%-owned subsidiary, TEN. On slide 33, we provide an overview of our ratings and debt details. Net debt to EBITDA increased from 1.8x to 2.1 x, 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 million loan with IDB Invest supporting our decarbonization plan. Through a lower interest rate, this loan will monetize the displacement of CO2 emissions from the early closure of coal plants, whose generation will be replaced by the Calama Wind Farm.
Our balance sheet remains strong, leaving us room to finance our planned investment in renewables. This has been acknowledged by rating agencies. Our BBB+ rating was confirmed by Fitch last June, and we keep our BBB rating by Standard & Poor's, while our local AA- by Feller Rate was given a positive outlook in January of this year. On slide 40, we would like to highlight that our board approved a $41.5 million traditional dividend that will be paid on August 26th, and which increases our dividend yield to 17.5%. Over the last 12 months, our stock price fell 50%, while the IPSA showed a 9% recovery. The Engie stock and electric utilities in general decoupled from the IPSA 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, Bernardita. To conclude the presentation, we want to summarize, as always, some key takeaways on page 35. First, we reported a challenging first quarter in our previous call. The second quarter shows an important improvement compared to the previous quarter. 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. Second, 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. This is just the beginning, and we have a lot of work and challenges ahead to complete the full plan.
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. This process is on track, and we have already filed the required permits for those conversions. All this transformation remains supported by a solid balance sheet, with liquidity enhanced by two innovative financing structures: a true sale of long-term account receivables and the green financing with IDB. With these final messages, we are completing our second 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. Questi ons will be taken in the order they are received. We do ask that when you pull your question, that you pick up your handset to provide optimum sound quality. First question will come from Murilo Riccini of Santander. Please go ahead.
Hi, Eduardo, Marcela, and Bernardita. This is Murilo Riccini from Santander. Thanks for the call. My first question is regarding your coal generation. We saw that IEM and some other efficient coal plants producing more than their normal during the second half of this year in order maybe to reduce the system costs. Could you tell us a little bit more about these dynamics and if this could lead to a decrease in the coal availability during the second half of this year, perhaps due to the postponement of some maintenance during the second quarter of this year? The second one is, what's your view for the marginal cost in the second half of 2021, and what is implicit in your EBITDA guidance of around $260 million for the second half? The last one is, why is retiring and renewable CapEx going up?
Is this explained by some inflation pressures, and how much are you expecting to spend with dismantling costs in total? If you could also provide us more details on this, it would be very helpful. Thanks.
Hi, Murilo. Thanks for your question. I will start with the first one. In terms of coal generation, we need to recall that during the first quarter, not most, but some of our coal units were not available. CTA was in maintenance due to a failure in the turbine. The plant came back during the second quarter. We also had some restrictions on IEM. During the second quarter, most of our plants were available except a programmed maintenance that we postponed some months before for CTA, which was not available during May. It has been very important during the second quarter to keep most of our units available to basically provide a stop-loss limit for our contracted sales.
This is what is probably explaining also the difference between the second quarter and the first quarter 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 second quarter than in the first. 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 CTM1 and CTM2, which are expected to be disconnected by 2024.
This is basically explained by the graph that we showed during the presentation, where we have on average 700 MW 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. What is important in the second half of the year is to keep a high availability of our thermal plants. For the marginal costs, your second question, it's a bit difficult to say what will be the marginal costs. We do expect a lower marginal cost than in the first half of this year. The hydrologic year should start in this second half, let's say, and the ice melting should help to reduce the marginal costs. The question is when this will start. Will it start in August, September, October, or by the end of the year?
Our expectation is that marginal costs could be around $50, $60, but it will depend on how hydrology evolves. We also need to consider that this particular year, we are seeing a huge volatility also on LNG prices, and this will also impact the average marginal costs. Today, if we want to buy an additional cargo, probably the price will be between $14 and $16 per million BTU. You can remember that one year ago, it was around $3 or $4. This is a huge impact also because gas will be dispatched during peak hours, and instead of producing at $60, we will see $190 or $110 spot prices when we dispatch gas. It's helping, but it's not helping a lot.
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. 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. In fact, as you know, with the plan that we are developing and the implementation of renewables, our recurring CapEx will go down over the next years. Once the plants also are converted to the other technologies, will continue going down, and we will keep a portfolio with a much lower annual recurring CapEx based on renewables mainly and the combined cycles.
Great. Many thanks, Eduardo.
The next question will be from Rodrigo Mora of Moneda. Please go ahead.
Hello, good afternoon. Hi, Eduardo, Marcela, Bernardita. Thank you for the presentation and taking my questions. My first question is related, if you would explain again, repeat the explanation of the higher sales of regulated customer. I didn't understand it was a reverse of provision of something like that could explain the higher implicit price of this sale. My second question is related to LNG cargoes and how easy is that the supplier could cancel future cargoes due alleging to force majeure? Thank you.
Hi, Rodrigo. How are you? Well, good questions. The first one, let me explain it a little bit more. You remember that back in 2019, we started with this new price stabilization mechanism. During some time, let's say, we started to work with a new mechanism. The decrees were not issued six months after the new tariff or the new system started, but the decrees were only known this year. This year, we saw the final one, two, and third decree, which at the end, is bringing us the exact amount of energy and the final prices. It is not a reverse, but it is 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 first quarter of 2021.
This means our provision was lower than it should have been in this period, and once the final decrees were issued, we are recognizing these additional revenues. It's not a reverse of a 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 first quarter of 2021. Once we had the final decrees, then we were able to adjust the total invoice, and that's why, in the second quarter, we have this one shot, as Bernardita was explaining, which is impacting, in some way, the average prices, et cetera.
Bernardita, I think, explained this, the $140 should be around $125-$130, and the total impact is around $15 million-$20 million. These additional revenues that we're recognizing now in 2021, that we should have recognized in 2020. In 2020, we didn't have, let's say, the final decrees, 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.
Yes. Exactly.
Okay. When you had the decrees, the one, the second, the third, you knew the exact amount of energy and the prices, and with that, the company will receive more revenues of the accounts.
Exactly.
Okay.
Exactly.
That's why you explained the higher average price during the second quarter.
Exactly. When we see the $120 million EBITDA, there are $15 million-$20 million that is a one shot, let's say. Even that, the second quarter is much better than the first quarter for all the reasons that we also explained before.
Okay.
This is one. The second one is LNG cargoes. It depends on each contract, and force majeure and this type of situations, we need to continue discussing with our suppliers. These are long-term suppliers. These are long-term contracts, once you have this type of situation, 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.
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 TotalEnergies. It's not Engie, by the way.
Okay. TotalEnergies, at the end of June.
Hi
announced a cancel of a LNG cargo that the company had to receive this July.
Hello?
Yes. Yes. Can you hear me?
Hello.
Yes, we can hear you.
We can hear you. Hello. Can you hear me?
Yes, we can hear you.
Okay. At the end, it depends, but TotalEnergies announced a cancel of LNG. Are there any alternatives to receive some compensation?
Eduardo? Eduardo, can you hear us?
I don't know if you can hear me.
Yeah, we can hear you, Rodrigo, but we cannot hear Eduardo.
Okay.
Eduardo? Eduardo, are you there?
What happened?
We can hear you, Eduardo. Eduardo, your line is open. Hello, Eduardo. Perhaps your line's muted on your end. I believe that Eduardo is going to reconnect.
Okay.
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 Bernardita or Marcela can help you with your previous one.
Yes, please continue.
Yes. I think there is Rodrigo's question about whether the supplier that had invoked force majeure would provide some sort of compensation. We are working on that, Rodrigo. I don't have any more news than that.
I think m aybe we'll move on to the next question, or he may have stepped away.
Okay. Thank you. Okay.
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 physical hedge side, any thoughts on that? 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 $470 million-$480 million a year, just looking at the end of the red line there. Just wondering if you could provide any help to us on what the key drivers there would be to get that year-on-year growth.
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. Thanks very much.
Yeah. I don't know, Eduardo, if he's on the line. I think he's still unavailable to reconnect. Well, in terms of considering delaying the plant closures, I haven't heard of that. I do know that our plan is still to close those two units. Unless there's a requirement, let's say, from the authority, unless there's some sort of very critical situation, let's assume that the drought will continue and become even worse. Other than that, we continue with our current plans of closing these units by the end of the year. Now, in terms of your second question was about the EBITDA guidance for 2022, or where could some improvements come from. As you said, it is very much related to the incoming renewables. That should help us definitely reduce the average procurement cost of energy. That is what explains the improvement in EBITDA.
Great. Thanks very much.
The next question will be from Fernán González 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. The second question is that I've heard that Engie is interested in bidding for the Kimal - Lo Aguirre transmission line. Is this Engie Chile, or is it the parent company? If it is you guys, would this be through a consortium, or would you be going by yourself?
Hi there. Bernardita, can you hear me?
Yes.
I'm back.
Great.
By the way.
Great. Thank you.
No, thanks. Maybe I can help you with the first one also. I think this is something that Leo was asking before. This is one cargo. The cancellation that we faced one month ago is related to one cargo, related to a specific case of force majeure in the LNG terminal. This is not going to compromise, in any way, the future cargos or the existing contracts. This is a one-shot. We have to continue discussing with our supplier what were the impacts, find a commercial or any other type of solution. 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. 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. 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. This is a one-shot. This is 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 other players and companies in the system are doing the same. The second question was related to the potential participation in the new auction.
Yes, this is something that we are evaluating through Engie Energia Chile. Why? Because this is part of the transmission business, and part of the business perimeter that we have in Chile through Engie Energia Chile. How it could be developed, this type of project, again, something similar to TEN. If we participate in this auction, because this will be a very competitive auction, then we will probably do it through a similar structure like the one we developed for the 600 km TEN transmission line.
Okay, fantastic. Thank you.
You're welcome.
This concludes the question and answer session. At this time, I would like to turn the floor back over to Engie Energia Chile 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 , Bernardita, for any questions that you may have in the future. 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.