ENGIE Energia Chile SA
SGO:ECL
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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, 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 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. So as usual, I'm here today with Bernardita Infante, 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 #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 are facing our export 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 will give you an update of our projects under construction. The Calama 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 COD should be achieved very soon. We will discuss in a couple of minutes the status of our 4 projects under construction.
Third, as we explained in our previous call, we announced in April a second wave of 1,000 megawatts of additional renewables, 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 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 plan 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. So 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 4 to 6, we show the overall operating performance and main actions implemented over the recent years to transform the company. Page 5 shows ECL 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 to 2030, but most of the company's PPAs are maturing post 2030.
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 renewables 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 $0.5 billion, while the remaining projects should reach soon a 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 billion 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, 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 3 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. 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 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 would have expected a similar quarter, but we need to consider that in the first quarter, ECL was strongly exposed to the spot market because CTA and other 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, a historic maximum production above 1,700 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 of PPAs was also adjusted to reflect these higher production costs. So the second quarter was positively impacted by regulated revenues, higher demand from mining companies and lower supply costs compared to the first quarter.
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 third quarter 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 systems 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 costs of selling these receivables. And this operation, as we explained before, will release more than $120 million in 2021 for our cash flow.
Now please turn to Page 8. These 3 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 2021 is close to $70, even a bit more, while 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. And 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 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, 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 and 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, 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. 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 second quarter, 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 coal 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 cost, 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 monomic 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 costs. But as I said before, the initial information is not optimistic on the new hydrologic year, but we do expect that marginal cost 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 million to $480 million to a new range of $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 million to $170 million. This means 2021 final dividends will be proposed considering this range and excluding the 1-shot impact related to the sale of regulated receivables.
Now please turn to Page 13. We have updated our CapEx forecast for '21, and we expect investments for approximately $350 million, mainly focused on our renewable and transmission projects as well as maintenance and dismantling cost of units 12 and 13, which were shut down back in 2019. So in this forecast, we are including the expected CapEx for $222 million, 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/EBITDA ratio increased slightly above 2x, and it could -- and it should continue increasing. In fact, in the following years, to optimize our capital structure, once we continue executing the renewables that we have in our pipeline. But we intend to keep our leverage ratio not exceeding 3x on a structural and regular basis.
Our liquidity is strong. 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. Also, 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 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 17 and 18, 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, we represent almost 80% by 2022 compared to 60% back in 2020, while coal will move from 30% to close 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 gigawatts of renewals. 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 works 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 million. 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 CCGT, with the combined cycle, and the possibility 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 period scales between now and 2025. The final conversion works will be made during a planned overhaul in the second half of 2025. So 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 updations 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 $25 million for both in total.
Then the next pages give some additional details and pictures of the renewable projects under construction. Once they start operations within the third quarter of this year and the first half of 2022, we will have completed our approximate $500 million investment on 0.7 gigawatts out of the 1 gigawatt 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 megawatts for this project, but given some technical optimizations during the execution, we will be able to reach almost 160 megawatts when the last 2 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 delay in the tension of certain archeological 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 energization during this quarter and its commercial operation to be achieved in 2 phases, 1 in the third quarter and the second phase in the fourth quarter 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 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. And as probably you know, the marine transportation industry is also under stress and facing increased costs.
Then on Page 26, we are 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 2 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 $53 million, 2 of them were completed and 1 additional project will be ready very soon, while the last one is expected for the first quarter of next year. And finally, on Page 26 (sic) [ Page 28 ], 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.
So 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. Now if we isolate each effect, we see a positive $50 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, which PPA tariffs are indexed, and also by the smaller tariff discount of the [indiscernible] as compared to last year.
The most 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 a tariff decree.
So excluding [ the signing ] effect, the average realized price on regulated sales have been around $120 to $130 per megawatt hour in the second quarter as opposed to $140, reflecting an approximate 7% price increase, similarly attributable to fuel and CPI increases. So please do not consider the $140 second quarter average as a recurring number, but rather a figure in the $125 to $130 area as current fuel price list.
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 Zaldívar PPA in June of last year.
Now as our own generation increased compared to last year, we reported lower physical energy purchases, representing a $3 million positive effect on EBITDA. Our first 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 increase in marginal cost, which Eduardo already explained.
So we bought less from the spot market, but at much higher price. The second most important effect was 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 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 nonrecurring expenses of $10 million related to the premium paid on the early redemption of our $400 million 144A bond, which will be financed with a new $500 million bond. So 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 -- 2 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 rate and greater capitalization basis 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. This resulted from the sale at a discount of $167 million in long-term accounts receivables from distribution companies related to the tariff stabilization law.
We sold these to a company called Chile Electricity PEC, which in turn issued a 144A/RegS bond to finance the purchase of accounts receivable from 4 groups of generation companies. In June, this company completed a 4a2 private placement with the participation of the IDB, Allianz and Goldman Sachs to raise funds for the purchase of accounts receivables through the end of the accrual period in July 2022.
Now 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. And 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 concesión de uso oneroso in Spanish, such as the Pampa Yolanda and Pampa Fidelia landslides 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 through Chile Electricity PEC. This sale of receivables has allowed us to enhance liquidity and ensure financing for investment in renewables without increasing our debt. The cash from operations provided $23 million, while we also received an $8 million payment from our 50% own subsidiary, TEN.
On Slide 33, we provide an overview of our ratings and debt details. Net debt to EBITDA increased from 1.8 to 2.1x, 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. This operation will be retained by the Calama wind farm. So our balance sheet remains strong, leaving us room to finance our planned investments in renewables.
This has been acknowledged by rating agencies. So our BBB+ rating was confirmed by Fitch last June. And we keep our BBB rating by Standard & Poors, while our local AA minus by Feller was given a positive outlook in January of this year.
On Slide 40 (sic) [ Slide 34 ], we will be able to highlight that our Board approved a $41.5 million provisional dividend that will be paid on August 26, and [indiscernible] dividend yield to 72%. Over the last 12 months, our stock price fell 50%, while the IPSA showed a 9% recovery. The [indiscernible] in general is coupled from the IPSA beginning September 2020.
Well, This is all on my side. Thank you very much. And I would love to be here with Eduardo for the final remarks.
Thank you, Bernardita. Well, to conclude the presentation, we want to summarize, as always, some key takeaways on Page 35. So first, we reported a challenging first quarter 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.
Second, Engie is fully committed to implement the transformation plan for our operations in Chile, and we are glad to say that our first renewable 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.
Third, 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 fourth, all this transformation remains supported by a solid balance sheet with liquidity enhanced by 2 innovative financing structures, a true sale of long-term accounts receivables and the green financing with IDB.
So well, 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.
[Operator Instructions] First question will come from Murilo Riccini of Santander.
This is Murilo Riccini from Santander. My first question is regarding your coal generation. We saw that IEM and some other efficient coal plants producing more than the 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 coal availability during the second half of the year, perhaps, lead 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 2021? And what is implicit in your EBITDA guidance of around $260 million for the second half?
And the last one is, why is recurring and renewable CapEx going up? Is this explained by some inflation pressures? And how much are you expecting to spend with these maintenance costs in total? If you could also provide us more details on this, it would be very helpful.
Murilo, thanks for your question. So I will start with the first one. In terms of coal generation, during the first -- we need to recall that during the first quarter, 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 second quarter. We also had some restrictions on IEM. And during the second quarter, most of our plants were available, except a programmed maintenance that we postponed some months before for CTH, which was not available during May.
So 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. And 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. 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 were -- 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. 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 a 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 should help to reduce the marginal costs.
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 evolved. And we also need to consider that, this year -- 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 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 will see $90 or $110 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 a plan that we are developing and the implementation of renewables, our recurring CapEx will go down over the next years. And 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.
The next question will be from Rodrigo Mora of Moneda.
My first question is related -- if you could explain again the explanation of the higher sales of regulated customers. I didn't understand, it was a reversal provision or something like that, that could explain the higher implicit price of these sales.
And the -- my second question is related to LNG cargoes, and how easy is that the supplier could cancel future cargoes due alligating to force majeure?
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 decrees were not issued 6 months after the new tariff or the new system started, but the decrees were only known this year. So this year, we saw the final 1, 2 and 3rd decree, 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 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 this 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 first quarter of 2021. Once we had the final decrees, then we were able to adjust the total invoice, let's say. 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.
And Bernardita, I think, explained this, the $140 should be around $125 to $130. And the total impact is around $15 million to $20 million. Let's say, this 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 decrees, so we didn't do it back in '20 and now we're doing in '21. it is clear or...?
Okay. This is a recognition of revenues undervalued of the last year?
Exactly.
Okay. So when you had the decrees, the 1, the 2nd, the 3rd, you knew the exactly amount of energy and the prices. And with that, the company will receive more revenues for the -- of the accounts?
Exactly.
Okay. That's why you explained the higher average price during the second quarter?
Exactly. So when we see the $120 million EBITDA, there are $15 million to $20 million that we are -- that it's a one shot, let's say. But even that the second quarter is much better than the first quarter 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 -- 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 1 supplier -- 1 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.
Yes.
Can you hear me? Hello?
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?
I don't know if you can hear me.
Yes, 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 is muted on your end.
I believe that Eduardo is going to reconnect.
Okay.
[Operator Instructions]
[Technical Difficulty]
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 Bernardita or Marcela can help you with your previous one.
Yes. I think there was -- there is a Rodrigo's question about the -- whether the supplier that has invoked force majeure would provide some sort of compensation. And we are working on that, Rodrigo. I don't have any more news on that.
[Foreign Language]
Maybe we will move on to the next question. He may have stepped away.
Okay.
The next question will be from Andrew McCarthy of CrediCorp Capital.
My first one was if you're looking at all, 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, is helping you on the sort of the physical hedge side. Any thoughts on that?
And then the second question was regarding the Slide #13, just seeing there in the graph, it seems like you're anticipating EBITDA in 2022 of around sort of $470 million to $480 million 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 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 if Eduardo is still on the line, as he is still unavailable to reconnect. But -- well, in terms of the considering delaying the planned closures, I've not heard of that. I do know that our plan is still to close those 2 units unless there is a requirement, let's say, from the authorities, I mean unless there is some sort of very critical situation, let's just assume that the drought will continue and probably 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 improvements come from? And as you said, it is very much related to the economy of renewables. So that should help us definitely reduce the average procurement cost of energy. And so that is what [indiscernible] EBITDA.
The next question will be from Fernan Gonzalez of BTG Pactual.
I have 2 questions. So one is a follow-up on the cancelation 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 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 Kimal–Lo Aguirre transmission line. Is this Engie Chile or is it their parent company? And if it is you guys, would this be through a consortium or would you be going by yourself?
Bernardita, can you hear me? I am back.
Great. Thank you.
No, thanks. So maybe I can help you with the first one also. And I think this was something Rodrigo was asking before. So this is 1 cargo -- and the cancelation that we faced 1 month ago is related to 1 cargo and related to a specific case of force majeure 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. This is not something that will continue during the second half, and we will continue 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.
And the second question was related to the potential participation in the new auction. Yes, this is something that we are evaluating to Engie Energia Chile. And 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 projects? 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-kilometer TEN transmission line.
And 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 any more 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 or Bernardita, 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.