ENGIE Energia Chile SA
SGO:ECL
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Good day, everyone, and welcome to Engie Energia Chile's Third Quarter 2021 Results Conference Call.
If you need a copy of the press release issued last week, it is available on the company's website at www.engie-energia.cl.
Before we begin, I would like to remind you that this call is being recorded and that information discussed today may include forward-looking statements regarding the company's financial and operating performance. All projections are subject to risks and uncertainties and actual results may differ materially. Please refer to the detailed note in the company's press release regarding forward-looking statements. We would like to advise participants that this call is dedicated to investors and market analysts, not for the press. We ask all journalists to contact Engie 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 with Bernardita Infante, Head of Corporate Finance; and Marcela Munoz, Investor Relations Officer. Today, we will present [indiscernible] third quarter results and the recent progress on the results and transmission projects that we have under development.
So let's start, and please turn to Page #3, where we introduce the key messages for this goal. First, as we explained during the last 2 quarters, the power industry is facing a complex year with a very high spot prices. The third quarter was probably the worst of this year, and this can be [indiscernible] results for the quarter.
As we explained before, these high spot prices are driven by an extreme drops in availability of several thermal coal power plants during the year, a stronger power demand, and finally, a new element in this already complex context, which is an important increase in LNG and coal prices. So all these elements together created a perfect storm and pushed spot prices far above where the industry was expecting for this year.
So in summary, we are facing average spot prices that are more than 2x what we were expecting under normal market conditions. And this difficult context requires different reductions to reduce the year exposure to spot prices volatility. And within them, the most 3 relevant are: first, signing additional backup supply, BDA. We will explain that in a couple of minutes, and what we recently implemented; second, important additional LNG to avoid further risks; and third, EECL power plants fully available during this period. We'll explain also in some minutes what we could expect for the fourth quarter of this year, and also for next year.
Second, we will give you an update on the renewable projects under construction. The Calama wind farm is ready with its 36 turbines and 151 megawatts adjusting to the grid. So this project reached its formal COD, its commercial operation date, last Friday, while [indiscernible] is also almost ready, and will reach its COD in the coming weeks. The plant, again, is also adjusting to the grid. We will discuss also in a couple of minutes the status of the different projects under construction and also under development.
Third, as we explained in our previous call, we announced in April a second wave of 1,000 megawatts of additional renewables, together with the conversion of 3 coal power plants to biomass and natural gas by 2025. During this year, we secured also through land concessions, the optionality to build up to 1.5 gigawatts of renewables in 2 lines: Pampa Yolanda and Pampa Fidelia, where we already filed also permits for the future conversions.
And fourth, despite the results in 2021 are below our initial budget and guidance, ECL continues to keep a solid and flexible capital structure, where the company continues to have a strong cash generation that should allow ECL to finance its transformation plan with a mix of internal cash flow, financial debt, while increasing globally the dividend payout ratio.
Then, before we explain the third quarter results on Pages 4 to 6, we show the overall operating performance, the recent announcement related to ECL business plan, and main actions implemented over the recent years to transform the company. On Page 5, we show the -- a complete snapshot of the transformation plan. On top we show the implementation of up to 2 gigawatts of renewables between 2019 and 2025, that would also be combined with the storage options. And below, we show the 6 coal power plants which actually connect within the same period. So this plan will require a total investment above $1.5 billion, of which by 2022, next year, more than 1/3 will have been implemented.
Then Page 6 shows ECL's main strength, which is its long-term portfolio of PPAs with the top-tier names in the country, and an average life close to 11 years. The graph shows PPAs until 2030, and as you know, considering energy sales and revenues should be predictable over time with this contracted portfolio. Our main objective is to control and optimize the supply costs. This is the main challenge to optimize our margins during the 11-year contracted sales and to build also a new platform to capture additional PPAs in the long term.
Now let's move to Page 7, in which we present ECL 2021 financial results by quarter and year-to-date compared to 2020, to give you a better vision of the operating evolution during this complex year. The 2021 EBITDA is negatively affected by higher marginal costs due to the drop, the unavailability of thermal plants, and also because of higher fuel costs. From a demand perspective, we can see a positive evolution in physical energy sales.
As we can see in the chart, during the first 9 months of 2021, total physical sales increased in 3% in 2021 compared to 2020, even considering one important PPA with Zaldivar ended by June 2020. This will be positive once spot prices stabilize in the future.
Then, on the supply cost side, spot purchases during this year decreased in 29% compared to 2020. This is mainly explained by the lack of hydro production in the country, which required ECL's less efficient thermal power plants to be dispatched. For example, units 14 and 15 in Tocopilla sites that are planned -- disconnected by the end of this year, are expected to produce almost 0.6 terawatt-hour in 2021 and representing 7% of ECL total sources, while 2020, this percentage was only 1%.
However, we will see in a couple of minutes, the average spot price at which ECL bought a portion of its energy needs was much higher than in 2020, and much higher than in the business plan for this year. So this negative impact on the average supply cost is explained in the lower EBITDA and net results in 2021 compared to 2020, and also compared to the business plan and our budget for this year. Net income was impacted by both the operating performance we just explained, and also by the upfront recognition of $48 million financial expense on the sale for regulated receivables which is related to the PEC.
So these are one shot and actual recognition of the long-term financial costs. And as you know, this operation is releasing approx $120 million in 2021, and we provide additional $76 million between the end of this year and probably 2022, or it could be 2023, once we complete the full monetization of these receivables.
And finally, net debt increased in line with the disbursement of the $125 million green loan arranged with IDB Invest, and also because of the recognition of financial leases related to Pampa Yolanda and Pampa Fidelia land concessions, that were granted to ECL in 2021.
Now we will go through each of the elements which are impacting the spot price. So please turn to Page 8. These 2 graphs show the average spot price in the north and in the center south regions. We can see how in both regions, spot prices in 2021 are almost 2x higher than 2020. Then, considering that ECL is expected to rise between 2.5 and 3 terawatt-hour in '21, we can get between $125 million to $150 million additional costs that are impacting the energy margin, that would only be partially offset with the average PPA prices that also increase in these contexts, but at a slower pace.
Next, Page 9 shows hydro production over the last 3 years in Chile. 2019 and 2020 were already dry years and then 2021 has been difficult and somehow, let's say, volatile. When we had our second quarter call, I said we may be in few 100s, or in other words, in one of the driest years of the last 50. And afterwards, we had rainfalls during August and September, which improved the expectations for the last quarter of this year, and we may be facing a similar quarter than in 2020. So this means 2021, 2022 hydro years, would be close to P97 on average. It means among the driest 3% of the last 60 years.
There are good news, and there are bad news. The good news is that, as I said, the fourth quarter will be better with this new hydro scenario. The bad news is that the ice melt may not be sufficient to keep this improved scenario until the new hydro year 2023 starts. This means the second quarter of 2022 would be again difficult, and electricity produced with coal, LNG, and hopefully, gas from Argentina, would play a key role to replace hydro production. And in this line, the fuel prices will be a key driver for 2022. We will speak about this in a couple of minutes.
And this can be seen in next pages, 10 and 11. On Page 10, we see how coal prices skyrocketed during the recent months. The good news is that the Chinese government may be applying certain controls on coal prices decreased in approx 30% over the last 7 days. This is very recent. But this also means we are in a volatile environment. So we need to be very cautious with this variable, considering still 30% to 35% of the electricity in Chile is produced with coal. So this means it has an important impact on the spot prices.
Next, Page 11, shows the LNG prices in different markets. We can see the LNG price materially increased in the European and Asian markets, and this opportunity cost for LNG producers is driving the LNG price for spot purchases, and unfortunately, that's how this reduced the electricity average supply cost in Chile. The good news is that we are expecting some imports on uninterruptable basis from Argentina in the central region, that may help to partially mitigate these negative impacts.
Next, Page 12 is a new snapshot we added to explain what we are doing to manage the spot price volatility risk, and the average supply cost for the 11-year average life of PPAs. The general area of this graph represents the annual contracted energy with other generation companies, and we can see an important ramp-up in 2022. These are what we call backup PPAs. And in practice, ECL replaces in the systems, energy balance, the generation company providing this hedge for the contracted volume.
These are the energy contracts only without any link to capacity. So between 2022 and 2025, we have secured backup PPAs for average 2.5 terawatts-hour per year. So this means, at least 20% of ECL's total contracted demand is hedged, supported with these backup PPAs until 2030, to basically reduce the exposure to spot market volatility.
On the other hand, the blue area represents ECL generation plus the remaining spot purchases, which should reduce over time with the construction of new renewables by 2026. And after the renewables have been implemented, if you have purchases in the spot market -- should only be linked to the intermittency of renewables, and this is something we are planning to manage with the combination of our technologies and with potentially storage solutions.
Let's move now directly to Page 14, where we can see the demand-supply balance for the first 9 months of the year. This graph shows average realized PPA prices compared to the average supply cost, which is a result of the different power sources to meet the total demand from our clients. This is a graphic explanation of what happened during 2021. We can see that a small area, in general, starts to vest in this graph.
And then, IEM, CTA and CTH coal power plants operate as the base load units. The overall cost of our coal plants in general was higher because of higher coal prices. The rest of our coal units, which last year were marginally dispatched because of their higher production costs, had to be open dispatched this year, and representing 14% of our power supply.
As we move to the right, we see that our 2 combined cycle units running the natural gas represented 21% of our energy supply. The third quarter shows that the production cost of our combined cycles increased compared to previous quarter, in line with additional LNG spot purchases we did to hedge our spot exposure, but unfortunately, at very high LNG prices.
Finally, ECL supplies 59% of its demand through purchases from both the spot market and backup PPA supply agreements. Our physical energy purchases decreased compared to last year. That's what we can see here. But spot prices increased significantly. The result was that our average supply cost increased from $54 to $72, as we can see in both continued and bottom lines. However, on the positive side, the average monomic price of our PPA portfolio also increased from $101 to $108 per megawatt hour, as we can see on top. And this means, despite the total cost increased in $18, the average monomic price increased in $7, but only partially offsetting the negative impact. Hydrology approved prices during the fourth quarter and the first quarter of next year will be key to continue seeing a reduction in the average supply cost, in combination with the start of new backup PPAs in our portfolio of, let's say, sources.
Now, let's go to Page 16 to explain what we could expect for the fourth quarter, and discuss the drivers for 2022. As you know, and this would not be a surprise given the current market context, the EBITDA guidance we gave at the beginning of this year will not be reached. The last 12 months EBITDA as of September is $361 million, and this should be a mid-point for the new range we could expect for 2021, considering the additional rainfalls and the ice melt process have helped to recover the reservoir levels to similar ranges of 2020.
Then, for 2022, we need to consider the following key drivers. First, spot prices are not expected, at least in the first half of the year, to reduce dramatically. Second, fuel prices, mainly coal and LNG will be key, considering its impact to the systems spot prices. During the last weeks, we saw an important increase in coal prices, which was afterwards corrected, but the market continues to have some volatility. And third, ECL would be less exposed to spot prices with the new renewals and also with the backup PPAs that we signed with other generation companies.
All in all, let's say, 2022 should be better from a margin perspective, but we need to be cautious on the new hydrologic year that will start around April, May. And also, on coal prices, given its relevant impact on systems, spot prices, and also on our own production costs. The last element is the entry of new renewables, those that are developed by ECL, and also those from third parties. So a further delay in renewable projects may not help to mitigate a lower hydro production and/or increased coal prices.
Now please turn to Page 17. We have updated our CapEx forecast for 2021, and we expect investments for approximately $300 million, mainly focused on our renewable and transmission projects as well as maintenance and these monthly costs of units 12 and 13 in Tocopilla, which were shut down back in 2019. In this forecast, we are including expected CapEx for 2022, which includes the completion of the renewable and transmission projects that are currently under construction, and additional CapEx related to the additional wind projects that we expect to launch next year.
As we mentioned in previous calls, we plan to finance this CapEx with a mix of internal cash generation and financial debt. Our net debt-to-EBITDA ratio increased 2x to 3x, given the lower EBITDA of 2021 under the current perfect storm. Now, during the next 3 -- during the next years, we should return to the baseline we define to keep our leverage ratio as not exceeding 3x on a structural -- on regular basis in the long-term.
We faced, of course, temporary increases in this ratio during the construction phase, but this will only be temporary, considering renewables will rapidly generate an additional -- for the company. So in practice, very doable. ECL is developing -- will replace the energy purchases that we were showing in the supply demand balance.
And this means every 100 gigawatt hour per year of renewables production would create between $3 million and $4 million additional EBITDA, right? So this is the idea of the transformation plan, replacing the spot purchases and reducing the volatility with our own renewables and during the transition period, of course, with a higher amount of backup PPA.
Now [indiscernible] is strong, since we have received $120 million for the sale of long-term accounts receivable for distribution companies facing from the [indiscernible] loan. And we also drove the $125 million loan agreement with the IDB to finance the renewable plan. We expect to receive around additional $70 million when we will sell an additional group of renewables between 2021 and next year.
The following section describes ECL's transformation project. The 4 pillars are described on Page 19. Then on Pages 20 and 21, we present our portfolio of trends and how the indexation of these PPAs will evolve in the medium-term. This is key to understand then -- and also forecast ECL's future cash flows. As you can see on Page 21, from 2020 to 2022, we will see an important -- in the indexation of our portfolio of contracts. U.S. CPI will represent 79% by 2022 compared to 60% back in 2020, while coal will move from 29% to only 11%. LNG will continue driving the regulated PPA in the north, and a small portion of the PPA in the center. And this structure should remain stable until 2025 at least.
Page 22 shows a complete view of the transformation plan by type of technology until 2025. The key component is a development of the 2 gigawatts of renewables.
And this brings us to next Page 23, in which we can see how by 2022, we will have completed 70% of the first pace. And soon, we'll finish the construction of additional renewables to reach the objective by 2025. We keep 2025 as the main objective, and we are implementing several actions to accelerate this plan.
The additional component of the transformation plan is a conversion of the remaining 3 coal units to biomass and natural gas, that are described in Page 24. And as we mentioned before, the plan is to perform work as much as possible, without interfering with the normal operation of these plants, to have them ready by the end of 2025.
The next pages give us some details and pictures of the renewable projects under construction. Calama, on Page 25, had a global advance of 99% as of September. And as I already mentioned, this 151 megawatt project reached its foremost COD last Friday, and became the first renewable project of the transformation plan that we have added to ECL generation portfolio.
Then, if we move to the next project on Page 26, Capricornio has an important delay. It's original still, and it's expected to be ready next year, due to issues related to the delays of certain permits as well as the financial issues its contractor had during the last year. The COVID pandemic also influenced both the situations that impacted the project.
On Page 27, we present the [indiscernible] plant with a global advantage of 98%. The plant is already injected energy to the grid, and we expect the commercial operation in the coming weeks.
On Page 28, we present the global advantage of Coya. The project has a 40% global advance. And we scale its amortization for the third quarter of 2022, and COD during the fourth quarter. We have experienced in this project the delays in transportation of equipment from the land due to COVID restrictions. And as you know, the marine transportation industry is also under stress and facing increased costs.
Then on Page 29. Last quarter, we presented this new section. We have secured 2 land concessions, Pampa Fidelia and Pampa Yolanda in the northern region, close to our operation and mining clients, with a combined capacity of 1.4 gigawatts between wind, solar and storage. The exact design and configuration is under analysis, and we will continue developing these projects to get them to a ready-to-build stage as soon as possible. This means between the existing portfolio of renewal projects and these additional 2 land concessions, we have secured project potential for more than 3 gigawatts.
On next Page 30, we can see some examples of the different projects that are under development. Business with [indiscernible] with combined capacity of 0.5 gigawatts should be the next one in construction, and should receive their notice to proceed next year, and become the next week projects to be added to this year's portfolio.
Regarding the 4 transmission projects described on Page 31, with a total investment of $53 million, 3 of them are almost completed and what is expected for 2022.
And finally, on Page 32, we present 7 projects that have received their respective decrees and that are entering into the construction phase, with a total investment of $43 million. This means almost $100 million investment in transition projects that will add a total VATT of around $10 million per year, or approximate $9 million EBITDA contribution since 2023. Most of this amount and the remaining amount will be completed in 2024.
And last but not least, ECL was awarded at the end of September, with an additional transmission project which involves the construction of [ Saldiva ] substation, which requires a total CapEx of $19 million. This project will be added to ECL portfolio of projects, and our development team is also preparing to participate in 2022 new transmission options that are related to the annual expansion plan of the [ Sono ] and national transmission systems.
So now I will leave you with Bernardita to cover the following section of our financial performance.
Thank you, Eduardo, and good afternoon to everyone.
Please go to Slide 34. As Eduardo already explained, EBITDA fell 38%. Now, if we look into the details, we can see some positive impact. First, an increase in physical energy sales, which had a $29 million positive impact. While regulated physical sales began to recover in the second quarter, free client sales increased despite the end of the Zaldivar PPA in June of last year, given the reactivation of the mining industry.
Our own generation increased since the dearth and the absence of Argentine gas led to the dispatch of our coal plants. Therefore, we reported lower physical energy purchases, representing a $67 million positive effect on EBITDA. Another positive impact was a $5 million insurance recovery from a past loss at the IEM plant.
Now the increase in average realized prices from $101 to $108 per megawatt hour had a $59 million positive impact on EBITDA. And it is mostly explained by the increase in the applicable Henry Hub, CPI and coal prices, in the tariffs of our PPAs. Also a tariff discount that we agreed in the March 2020 renegotiation on the Centinela PPA was smaller in 2021 than in 2020.
So this time, the most significant negative impact was the increase in fuel costs due to the increase in our own generation and the record high coal and LNG prices, particularly in the third quarter, which includes, as Eduardo mentioned, export LNG shipments bought as a hedge to prevent a further problem regarding the marginal cost. So the fuel price increase had an estimated $127 million negative effect on EBITDA.
The next most relevant hit estimated at $108 million was the increase in marginal costs. So we bought less, which is positive, but at much higher prices. So all of these changes led us to a 9-month EBITDA of $243 million, down from $338 million in the same period of last year.
We go to Slide 35. This shows the evolution of net results, which went from $123 million last year to $39 million in the first 9 months of this year. Last year, we reported nonrecurring expenses of $10 million, related to the premium paid on the early redemption of the $400 million 144A bond, which we refinanced with a new $500 million bond. So our net recurring income in the first 9 months of last year was $133 million.
This year, we had a couple of positive effects, such as FX gains and lower financial expenses due to lower average coupon rates and greater capitalization of interest in our investment projects. So it was the EBITDA decrease we just discussed about what caused the reduction in our recurring net income. We would have reported $75 million in net income had it not been for the $36 million one-shot financial expense. This is shown after taxes. This resulted from the sale at a discount of $167 million in long-term accounts receivables from distribution companies related to the price stabilization law. As you may recall, we sold these receivables to Chile Electricity PEC, which, in turn, issued notes to finance the purchase of accounts receivables from 4 groups of generation companies, including NT.
So now let's turn to Slide 36. Our net debt increased by $315 million from year-end 2020. The main cash outflows included $138 million in CapEx, mostly in our renewable projects, $91 million in dividends, including the final dividend on 2020 net earnings, and the $41.5 million provisional dividend paid in August, as well as $23 million in income taxes. This time we reported a $75 million net cash outflow, mainly due to higher fuel prices and lower collection from distribution companies, due to the price stabilization law. So this part was offset by the proceeds from the true sale of long-term receivables from distribution companies through Chile Electricity PEC, which amounted to $118 million, and is shown in the last green column to the right.
Now if you look at the center of the chart, you will note one of the main reasons for the increase in our net debt. This relates to an $81 million increase in financial leases, which qualify as financial debt per IFRS 16. These are primarily related to land concessions such as the Pampa Yolanda and Pampa Fidelia land sites in the Antofagasta region, for the future development of hybrid renewable projects. These contracts consider annual payments for up to 40 years, and the present value of future installments is accounted for a financial debt.
On August 27, we disbursed the $125 million loan from IBD Invest to finance the Calama wind farm. The loan does not appear in this net debt graph, as the debt increase is fully netted out with the corresponding cash increase. Finally, we also received an $8 million payment from our 50% owned [indiscernible].
Now if you go to Slide 37, this shows our ratings, which remained unchanged at BBB+ and BBB and our debt details. Net debt-to-EBITDA increased from 1.8x to 3.1x because of the financial leases, the IBD Invest loan, and the EBITDA decrease, with last 12 months EBITDA of $361 million.
On Slide 38, we can see an increase in our dividend yield. However, like other utilities, our share price underperformed [ ISA ] index due to factors such as slower operating performance due to the broad and high fuel prices, potential regulatory changes, and pension fund withdrawals, among others.
So well, this is what I have to tell you, and I will leave you with Eduardo for the final remarks.
Thank you. We summarize the main takeaways on Page 39.
So first, 2021 has been a very difficult year for ECL and also for the industry, due to the extreme drop, combined with other several factors that negatively -- the spot prices. And as we know, with negative consequences in our financial results. We do expect an improvement during the fourth quarter, but as we mentioned in our previous call, we are still navigating through this storm, and we need to be cautious on the systems evolution, given the uncertainty on hydro conditions for 2022 and volatility on fuel price.
Second, we would like to say that our first renewal project reached its commercial operation date on budget and performance, with a very limited delay. But this is just the beginning, and we have a lot of challenges ahead to complete the plan. So in this line, we have secured additional backup PPAs with other generation companies to reduce our exposure to the spot price volatility during the transmission phase in which we will be developing these renewables, and we will also be implementing several actions to accelerate the construction of renewables.
And third, despite increasing net debt to EBITDA, explained by the lower margins in 2021, if you also keep a rather contextual balance sheet to support the future investments, enhanced by 2 innovative financial structures implemented this year, first, the 2 sales long-term accounts receivables that as I mentioned will still provide additional $70 million to $80 million between this year and the next one, and also $125 million green financing from IDB Invest.
So well, with these final messages, we are finalizing our third quarter presentation. We hope, as always, this presentation is helpful for you, and we are ready for any questions that you may have for us.
[Operator Instructions] And the first question today will be from Fernan Gonzalez with BTG Pactual.
And I have 3 questions. And the first one is related to the conversion of the CTA and CTH units into biomass. I believe the project is just going to burn woodchips or black or white pellets, right? So could you share, where do you actually source it from? Do you have a contract already for that? And how much is the transport cost of that into the site?
What I'm wondering is, ultimately, what is the level of energy prices that you need for the economics of this project to work. My second question is on that bill that we have at the Senate currently that is aiming to prohibit the fossil fuels generation by 2030. So if we assume that Congress approves that, how would that change your strategy going forward, because the IE conversion wouldn't make sense anymore? And what will be the impact on other businesses like the gas transportation or the ports?
And my final question is on this backup PPA that you mentioned. If you could share a bit more color on them, the type of conditions behind those contracts, so we can better understand them.
Okay. Thank you for your questions. So first, maybe I can start with the conversion. The conversion of CTA or CTH to biomass, as we explained, it's more than a conversion. It's a change in the type of fuel that these 2 coal power plants will use first, because these 2 plants are ready to burn biomass. Now the conversion to biomass is basically a conversion to [indiscernible] coal, considering after 2025, 2026, these 2 plants are not expected to dispatch.
And the ways to keep them as some kind of cold reserves with a much higher production cost than producing with coal. The production costs would be close to $100, $120, and this production cost is related to black pellets or white pellets. Both type of products could be burned. And the $100 to $120 includes the transport plus the biomass that we need to acquire. And today, this is a market that is under development. There are some sellers in Europe and Asia. And today, we are working with MG Global Energy Management division, the management of MG that is also working with coal, with LNG, et cetera. And they also have started working with biomass to secure the supply of these products by 2025.
Then, if I continue with the second one, the exit by 2030. I could say, similar to the potential idea of exiting coal by 2025, it would be, I think, very difficult by 2030. Maybe some years later could be possible. But again, the system will need to adapt. And once the new technologies are available, once storage is economically viable, then the market will adjust by itself.
So we do expect at some point in time that there could be a full decarbonization, but this is something that will need some time and will need to combine the renewables that are already part of the energy transition with gas, with storage, with CSB, at some point in time with hydrogen, but this is not something that could be developed overnight, and that will need time, and also we need transmission lines. So the HVDC transition line that is expected for the end of this ticket, it's also very important in this equation.
So we do believe that this could be possible, but not as 2030 probably. Today, we don't have a bigger view on that. And of course, your point is very good. I -- would make sense to natural gas. If by 2030, will need to be disconnected, will be something that we need to assess in more detail. I don't have an answer now because we do believe that this is something that needs to be better assessed by the authorities and the country.
And finally, in terms of backup PPAs, what we mentioned is that between 2022 and 2030, we will have, on average, 20% of our total contracted demand covered by these backup PPAs. Most of these backup PPAs are 24X7, and the average cost for us of these backup PPAs is energy only. There is no transaction related to the capacity.
And average cost, it's in the mid-$40s probably during this period. So you can consider that we will have 2.5 terawatts-hour of backup PPAs between 2022 and 2025, 2026, at an average $45, between $45 to $50, probably energy only, and this will become part of our supply cost. And basically, what we are doing with these backup PPAs is reducing the volatility in -- of buying this electricity in the spot market.
Okay. Perfect. Just a follow-up on question #2 is, I agree with you, with everything you said, and that is commonsense. The problem is that Congress is not always very reasonable. The track record for the past few years is somewhat questionable. They're not listening much to technocrats. So it is possible that they could approve this. And that's why I was just wondering if this would drive a complete overhaul of your long-term strategy in Chile?
Not a complete overhaul because our 2 combined cycles, U16 and CTM3, are in the mid-stage of their economic life. So basically, these plants are very important until 2030, maybe 2035. So this would not change the fact that we will continue operating debt, that we will continue building the renewables. That could change probably -- or that could make us think better about IEM commercial. That's a logic, let's say, conclusion. But all the other parameters and elements of the transformation should remain stable even under that type of, let's say, scenario.
And the next question will be from [ Francisco Shoemaker ] from [ Fundamenta ].
Just -- I don't know if you mentioned it, but I wanted to confirm if there's going to be any spot LNG consumed during 4th quarter '21, and conceptually, for next year, can you decide whether to purchase the spot LNG, if you're having a lot of gas or depending on where the spot ride is that you decide if you can buy it or not?
[Indiscernible]. It's exactly what you're saying. First, for 2021, no, we don't have any additional cargo of LNG at those very, very expensive prices Bernardita mentioned, we took to basically assess our position during September, that was to avoid a further margin deterioration. So we looked, let's say, some type of loss during September. We don't have any additional spot cargo in our plan.
And for 2022, we are bringing all the cargos that we have in our long-term contracts. So those are at much lower prices than the spot prices. And as you were saying, buying more gas spot is something that will depend on the spot price evolution, because producing today with LNG that you can buy at $20 even in BTU, it's sometimes more expensive than producing [indiscernible]. So that's why we don't have any plans to bring now LNG spots, but there is always the alternative in case -- again, we have very high spot prices. We have maybe thermal unavailability in the system, then it could be an action to mitigate the evolution of the spot price.
And the next question will be from Andrew McCarthy from CrediCorp Capital.
First question was just to double-check if you -- given the very tough scenario at the moment outlook, whether you've given any thoughts again to maybe delaying the withdrawal of the U14 and U15 coal plants? That was first question #1. The second question was with respect to the PEC. With the higher fuel prices and also the more depreciated pace, so just wondering what your thoughts were there with respect to what the solution could be, given that maybe by second half next year we might be getting quite close to the $1.35 billion ceiling on that tariff stabilization mechanism.
And then the third question was if you could share some more color on -- you talked a little bit in the presentation and the questions about the importance of the HVDC line, Kimal-Lo Aguirre. Just wondering if you could share some color on why you maybe decided not to continue reviewing that project? It's interesting once you guys are ready to invest in? Those are my 3 questions.
Hello, Andrew. Thank you. So first question, Unit 14 and 15. As we were saying, this year, these 2 units almost produced 0.6 terawatts-hour per year, and that's much more than we were expecting for this year. So this is a very good job because those units were not expected to be dispatched.
Now today, the plan is to close them or to disconnect them by January 1, 2022. That -- the market coordinator is currently analyzing if some units could be needed in 2022. And in that line, we are waiting for any new development and information. So today, the plan is to keep them until the end of this year. And in our own projections, it depends a lot on the hydro evolution for January and February. But apparently, it should not be needed, but this is something -- this is an analysis in progress during the recent base.
Then, the second one, in relation to the PEC. Well, we do expect that with the current curves, with the current FX evolution, that the PEC, the current, let's say, PEC will be fully used probably during the second half of next year. That means also that next year we will sell all those receivables through the structure that we have in place. Now what will happen next?
Again, it's something that historically under development and that the industry and authorities are probably analyzing in detail. I don't have yet nothing else to mention at -- in that line. And for the [ HDBC ], and as probably you are all aware, it decided not to participate in this one, basically because of the risk analysis and risk exposure that was, let's say, assessed by our team. It's basically that.
And just a follow-up. I mean, in terms of the PEC, would there -- do you think one solution would be to effectively raise the ceiling or extend the life? I do think the generators would likely have to agree to further measures. Or do you think that maybe this is a different type of solution we happen to -- be found for a different part of the industry or from the state? And just on the HVDC line, could you just share a bit more color on maybe what some of those -- in that risk assessment, what maybe some of the key issues were, that perhaps made the project less attractive for yourselves?
Sure. Sure. For the first one or the second one, in terms of the PEC, if you ask me about that, my personal opinion is that this is something that should be managed for -- through the demand probably. And this is something that, if we need to stabilize the price, you can do it right now and afterwards, it could be collected by charging it to the end consumers.
Then, for the HDBC, basically, the main risks that you could be exposed are related. These are a very longer -- it's a long-shot project, right? So you need several years -- you could be exposed to the negative or positive evolution in the price of some commodities that are related to the CapEx. And this is some type of risk that someone -- sometimes we are not -- we don't want to have any in this type of project, because you can end in any direction. And the other part is probably related to the permits and the rights of use, that it's also a very complex process.
The next question will be from [ Rodrigo Gray ] from [ Visay Corp ].
So I want to ask about your awarded price of your recent fuel provision action that you made. And also if you can talk about the providers of these backup contracts of energy?
Sure. Sorry, the first one was related to the fuel?
Yes, about the -- I understand that you recently made an option of -- give your providers to provide your fuel for the next year, you're supposed to collect them.
Ah. Okay.
[Indiscernible] -- you were in these -- for the -- so I want to know the average price of your final -- of your fuel position and also about the other question, about the backup...
Okay. So first, in terms of fuel prices, there are 2 main fuels we use. The first one is, let's say, energy. I will start with the EC. It's LNG and our provider is -- our supplier is Total. And this fuel comes through a fixed price, almost fixed price, or linked to Henry Hub. And these are long-term contracts, right? So we basically don't make annual options for this fuel.
Now for coal, we buy coal on a regular basis, sometimes for the next 6 months, sometimes for the next 3 months. And coal, as you can see in the presentation, is mainly linked to API2, API6, API10 interests. And basically, today, you can see that, well, let's say, 2 weeks ago, the forwards and the curves of coal went up to $275 per ton of coal. So sometimes -- or recently, we bought some coal for the short term at around $200 per ton. But this fuel is indexed to the IPI.
So that means that if the price goes down, then what you need to pay for the coal is also much less than when you decided to buy it. And recently based on the control on prices that, let's say, government announced for coal, we have seen that the forward went down from $275 to less than $170. So the market is again coming back to the previous levels, hopefully, but still with some volatility.
And the backup case, well, the suppliers are -- well, we mentioned some time ago, we have backup PPAs with Edel. We have backup PPAs with Atlas. We have backup PPAs with Mainstream, with Sonnedix, and probably a couple of suppliers more. But we have several backup PPAs. I think at the end we are looking for this hedge in the whole market, and there are also [ iteration ] companies that are willing to grow also their own margins for the remaining energy that they plan to sell spot.
So you are going to fill a lease in [ Casa Bahama ] or have lease exhaustion?
Yes, we always keep that option to some kind of [ Aguirre ] with our own gas.
Ladies and gentlemen, this concludes our question-and-answer session. At this time, I would like to turn the floor back to Mr. Eduardo Milligan for any closing remarks.
Okay. There's nothing else from our side. Thank you very much for your attention, and we will see you soon.
Thank you, sir. This concludes today's conference call. Thank you for attending today's presentation. At this time, you may now disconnect your lines, and take care.
Thank you. Bye-bye.
Okay. Thank you. Goodbye.