Good afternoon, everyone, and welcome to Engie Energia Chile's First Quarter 2021 Results Conference Call. If you need a copy of the press release issued last Wednesday, 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 morning to everyone, and thank you for joining us today. As usual, I'm here today with Bernardita Infante, Head of Corporate Finance, and Marcela Munoz, our Investor Relations Officer, and considering our recent announcements, I am also glad to welcome Axel Lévêque, CEO of our company, who will join us to explain the additional phase of the transformation plan that we recently announced. We are pleased to share this time with you today to convey our main messages of the quarter, which in some cases are not what we would have liked to communicate, as well as some interesting announcements concerning the evolution, scope, and speed of our transformation plan. I am now on slide three.
Just a few words on the Engie Group, which now holds 60% of our company after the group bought an additional 7% stake at the end of last year, demonstrating, of course, the commitment of the group to our operation in Chile. Engie is a global reference in the transformation of the energy business. Today, the group is organized along four global business lines: renewables, networks, thermal, and client solutions. In Chile, we are working in organizing ourselves functionally along these business lines. Engie has a new CEO, Catherine MacGregor, who took office at the beginning of this year. Who has virtually come to Chile these days to communicate, together with the Chilean President, Mr. Piñera, and the Ministries of Energy and Environment, the second phase of our transformation plan. On slide four, which you all know pretty well, please note the generation pie for the industry.
In the first quarter, hydro generation represented just 22% of the generation in the system, down from 26% in the same quarter of last year. Renewables increased their stake, reaching 20%. Thermal generation covered 58% of demand, as we will discuss later, unfortunately, many efficient thermal plants were out of service as their maintenance outages were rescheduled from 2020- 2021 due to the COVID situation that we are currently facing. Also, there was no gas from Argentina, and the LNG arrivals were delayed and more expensive due to weather issues in the U.S. While a high thermal generation is normal in the first quarter of any year, it was the drier hydro conditions, together with the high cost of this thermal generation, which basically stressed the system during this year. Let's move, please, to slide number six, which shows the four main messages for this call.
First, we will talk about this challenging first quarter after demonstrating resilience to live through the COVID pandemic in 2020. We reported an $18 million net loss, mainly explained by a $33 million decrease in EBITDA, and one-shot financial expenses of $41 million related to the sale of accounts receivable generated as a consequence of the Price Stabilization Law. This is, of course, bad news. The good news is that most of the factors behind the EBITDA will be improving during the rest of the year, with higher availability of efficient thermal units and the start of the hydrologic year during the second half. While we do not expect another financial discount of this magnitude during the rest of the year. Second, in the next place, we will give you an update of our projects under construction.
In one year, we will have completed 70% of the first phase of our transformation plan of 1 GW. The 150-MW Calama Wind Farm is on track, and we expect it to achieve COD during the third quarter of this year, as we had previously informed. The energization process will start in some weeks. Unfortunately, this is not the case with the 95-MW Capricornio PV project, which is suffering delays attributed to archaeological permits for track prints, also known as huellas troperas, frequently found in the Atacama Desert. The second impact is related to contractors' financial issues. Our project teams, of course, are working on different solutions to bring the project back on track, and COD is now scaled between the last quarter of this year and the first quarter of 2022.
The 114 MW Tamaya PV plant should be commissioned in two stages in the third and fourth quarters of this year. Earth-moving works have started at the almost 200 MW Coya PV. We should be ready in the first quarter of 2022, totaling almost 600 MW of new green sources. If we add the additional assets that we acquired, we will almost be completing 70% of the 1 GW that we announced back in 2019. Third, what you may have heard about, the message that our CEO has conveyed to the Chilean government and to all our stakeholders, Engie is accelerating and enhancing its transformation in Chile. Along these lines, Engie will completely exit coal in Chile by year-end 2025, it is going to develop an additional one gigawatt renewable energy plan during the next years.
Finally, the full coal exit requires the conversion of our newest and most efficient coal plants. IEM will be converted to gas, while CTA and CTH power plants will change their fuel to biomass, as their boilers are already suited for biomass. Fourth, our transformation plans are supported by a robust and flexible capital structure with a low leverage, a flexible dividend policy, and available credit lines such as the innovative $125 million financing we announced last quarter with IDB Invest, which, as of today, remains fully available to be drawn for our CapEx needs. Finally, in this section, we will talk about the sale of long-term receivables from distribution companies related to the Price Stabilization Law.
While this transaction explains the hit on financial expenses in the first quarter, it has strengthened our liquidity as we received $100 million from this true sale, which does not represent financial debt in our balance sheet. On slide seven, I would like to point out a couple of things. First, the importance of securing power supply sources while we build the renewable projects. This is what we call our physical hedge. We still have 0.7 GW of efficient core units. We have LNG supply agreements for our combined cycle units, and we have backup PPAs and are trying to sign more with other generation companies. In the chart at the right side of the page, you may see a slight decrease in our physical energy sales, mainly due to four factors.
The COVID effect, the end of the Zaldívar PPA, a lower pro rata in the PPAs with the distribution companies, and the fact that in 2020 was a leap year. The first quarter this year had one day less than last year. Slide number eight. In this slide, we show the power sources to meet the demand from our clients, as well as the resulting average realized prices and direct supply cost. This is a graphic explanation of what happened in the first quarter. Our IEM, CTA, and CTH plants continued to operate as base load units. However, CTA was only available for a few days in March after being out of service for almost four months, as the turbine had to be repaired at the workshops in Europe.
The variable 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 21% 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 quarter, representing 10% 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. We were able to supply 37% 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 direct supply cost increased from $59- $68, as we can see in the graph. If you multiply that difference by the total energy sold of almost 3 TW hour, you get to around $26 million. There you have most of the explanation of the quarter's results. In slide number nine, we see that we continue our commercial efforts to attract new clients with whom we are signing green PPAs in line with our transformation strategy. This also seeks to maintain and extend the current 11-year average remaining life of our PPA portfolio. Last year, we signed a PPA renegotiation with Antofagasta Minerals, while we continue working with Codelco to reach an agreement to decarbonize its 150 MW PPA, which is the only large PPA left to complete our PPA greening process with mining clients.
In slide 10, we provide a view of our contract portfolio of about 12 terawatts per year through 2030. Now, on slide 11, to complete this section on where we stand today, we provide a quick update of phase I of our transformation plan. On the upper section of the slide, we see the progress of the 1 GW investment in renewables as the Calama Wind Farm and the three PV projects under construction begin operations between the third of this year and the first quarter of next year. We will have completed 0.7 GW, including the acquisitions that I mentioned before, and an investment of about $500 million. We have other wind projects for over 300 MW in our development portfolio, and we expect to announce their construction soon.
Below, we can see the coal plant disconnection scale, which has already represented impairments for around $187 million between 2018 and 2019. We have disconnected 171 MW, and will disconnect another 268 MW at the end of this year. Once we close two coal units in Mejillones with 334 MW at year-end 2024, we will have closed 0.8 GW of the 1.5 GW we had at the beginning of the transformation process. Let's move to the next section for some details of the first quarter results. Slide number 13 shows our financial highlights for the quarter, with operating revenues decreasing 1% and EBITDA falling 33% to $66 million. As explained before, this was mainly due to higher costs.
The entire electricity system in Chile was stressed and reported higher costs because of the low hydro generation, the reduced availability of efficient coal plants, and the absence of gas from Argentina to mitigate this unavailability. Our own generation was more expensive, as the CTA was out of service most of the period and our oldest coal units were dispatched. In terms of our energy purchases, we bought less energy, but at higher prices. The lower EBITDA added to $41 million in costs and discounts applied to the sale of accounts receivable related to the Price Stabilization Law cost an $18 million net loss in the quarter. In slide 14, we can see details of the factors behind the higher generation costs reported by the industry in the first quarter.
If we move now, please, to slide 15, you will see the challenging industry environment, which included the dispatch of expensive diesel plants and flows of expensive thermoelectric generation from the north to the south of the country during the night to basically compensate for the lack of backup hydro and gas generation in the south. The red line, representing the marginal cost, was very volatile, with lows around $30 during the day and highs of over $160 at night. Now, on page 16, after this first quarter, our results are below our guidance. In our last quarterly call, we said that we had to keep an eye on the marginal costs, as we had already begun to see an increase explained by higher commodity prices and the unfortunate lack of gas from Argentina.
This is an important variable we need to have in mind, since in the short term, we will continue supplying part of our clients' needs with around 30% purchases in the spot market. Now we are making our best efforts to meet the lower range of our initial EBITDA guidance at $460 million. On the positive side, our CTA plant is back in service and we are working on the insurance arrangements, while there is now more gas available in the system, all of which should contribute to stabilize marginal costs. On the negative side, the delay in our PV projects will prevent us from reducing the amount of energy purchases from the spot markets. We will have to wait a little longer to replace spot purchases at, let's say, $40-$50 with our own renewals production at, let's say, $5. Slide number 17.
For 2021, we have updated our CapEx forecast for 2021. We expect investments for approximately $350 million, mainly focused on our renewable and transmission projects, as well as maintenance. In this forecast, we are including the four renewable projects under construction as well as two wind projects to complete the one gigawatt capacity of phase one of our transformation. This should represent total CapEx of $290 million for 2022, without including any expenditures related to phase II of our transformation. We plan to finance these capital expenditures with a mix of internal cash generation and bank finances. Our net debt to EBITDA ratio increased to two times. It could continue increasing in the following years to optimize our capital structure. We intend to keep our leverage ratios not exceeding three times on a structural and regular basis during this transformation process.
Our liquidity is strong since we recently received $100 million for the sale of the accounts receivable from distribution companies. This transaction should allow us to raise funds for an additional $90 million between now and 2023, without affecting our leverage ratios. Also, we signed, as you know, the $125 million loan agreement with IDB Invest, which is today available to finance the CapEx of the Calama Wind Farm. On page 18, 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. Now, the following section includes details and pictures of the renewal projects under construction, which we have already talked about.
Once they start operations between the third quarter of this year and the first quarter of 2022, we'll have completed an approximate $500 million investment and 0.7 GW of the 1 GW we announced for our first phase of transformation. With Calama on page 21, has a global advance of 92%, up from 75% last quarter. We maintain its full commercial operation date target in the third quarter of 2021. In fact, we are planning to start the energization process in the upcoming weeks. Capricornio Solar plant has shown very limited progress due to issues related to the delay in the obtainment of certain archaeological permits for some ground tracks, known as huellas troperas, as I mentioned at the beginning of the call. We went through problems and financial issues with the main contractor. The COVID pandemic, of course, has influenced both.
Now, as I said at the beginning also, our teams are doing our best efforts to come back on track. The Tamaya Solar Plant has a global advance of 83%, up from 78% the previous quarter. We expect it to start commercial operation in two phases, one in the third quarter, and the second phase in the fourth quarter of this year. Earth moving works began at the Coya Solar Park, which reports a 5% global advance. Coya is the largest of these three PV projects, with almost 200 MW capacity and representing an estimated CapEx of $117 million. Its COD is scaled for the first quarter of 2022. Regarding the four transmission projects described on page 25, with a total investment of $53 million, two of them, Nueva Crucero - Encuentro and El Rosal substations were completed.
The other two projects and Nueva Chuqui ata transmission line will be ready in May and November of this year. Five of the six additional projects awarded in 2020 described on page 26 are ready to start construction, since their corresponding decrees were issued by the authority. The Roncacho substation is still awaiting the decree issues. These six projects will require a total investment of $43 million and have an estimated commercial operation date for 2023. This means between 2021 and 2023, we will be adding to our portfolio of regulated transmission assets all these projects, which required a total investment of approx $100 million. Let's move to the following section to present the second phase of our transformation, recently announced the day before yesterday with the President and the ministries.
For that, I'm glad to invite Axel Léveque, ECL CEO, to present the next section of our presentation. Welcome, Axel, and the floor is yours. Sorry, operator, he's not connected?
Yes. It looks like his line is disconnected. Please stand by while we reconnect.
Let's give him 10 seconds. If not, I will continue. Okay, we will continue.
Sorry. I have the speaker to rejoin.
Is Axel back?
Yes, I'm back, Eduardo.
Okay, great.
Sorry, I got disconnected. Nothing personal, I suppose, no?
Perfect. The floor is yours, Axel.
Okay. Thank you, guys, and thank you, Eduardo, for the time. Thank you to all of you. Good afternoon. Not often that I join you guys for this kind of meeting, I'm very pleased to be with you today. Today, we'll focus on presenting the transformation plan that we announced just on Wednesday, together with President Piñera and two of his ministers. I suppose that we should go on slide 28, if I'm getting it right. On that slide, we present you our transformation that is globally two aims. The first would be the coal exit, and that's great news because now we have a date. That's going to be by the end of 2025.
Secondly, that we will recover through this transformation of our asset base, and we will recover the competitiveness, and we will be able, in the close future, to capture again new PPAs and provide growth to the company. I'd like presenting all this transformation through four pillars. Some of them, you know them, and probably the third one is a new one. If you look at the first two, as you know, we have already made a lot of progress in the first two, these two of them, which are the greening our PPAs portfolio and the closing of 100 MW of coal stations between 2019 and 2024. The third pillar is new, I just mentioned that, and it's related to our newest and most efficient coal plants with an aggregate capacity of 700 MW.
To fully leave coal by end of 2025, which was the greatest announcement, by converting this newest coal station to alternative fuels. We think that this is probably, that was a little bit our conclusion, that this organic transformation of ECL was the best for the value protection and the feasibility of the implementation of the plan. On this conversion, accordingly, I would say that the IEM coal station will be converted into a natural gas plant, while the CTH and CTH RediseñBet, already partially designed to burn biomass, will be converted to the full biomass operations in the future. Conversion will not deeply affect the power islands themselves, but much more the ancillary systems, such as the common facilities of the coal stations as a fuel yard, the unloading port, the conveyor belts, and the burners of the IEM.
Technically, these units will not lose in technical efficiency, but will have, rather, I would say, an higher variable cost during their operation. Accordingly, be located lower in the dispatch merit order used by the ISO to dispatch the units. This means they will act in the future much more as a backup facility, to support the renewable fleet, in particular, the intermittency of that renewable fleet. We have the fourth pillar, which is well known. We already announced 1,000 MW of additional renewable capacity, if you like, to go with the first step of the coal closing, the six-unit coal closings. The day before yesterday, we added 1,000 additional megawatts to this plan to get to 2,000 MW in total for the full transformation.
Going on page 29, I will dig a little bit into details on each of these pillars. On 29, in getting directly to the PPAs, it shows the PPA extension and the concept of the greening process that we have been through during the few last years with the main customers of ECL. We can see here how we are gradually lowering prices and changing indexation from coal prices to CPI. This is in line with our customer needs. Obviously, we had a tough request from this guy, because obviously they have their own agenda of getting carbon neutral as soon as possible.
To be complete, obviously, in order to maintain the value of all these PPAs, we reduce prices, we change indexation, but at the same time, we extend the maturity of these PPAs in order to keep it, I would say a little bit PV neutral. Hopefully we are clearly creating value, not destroying value, out of the contracts. At the time being, in a nutshell, I would say between 75% and 80% of the three customers PPAs have been renegotiated into green corporate PPAs. There is one pending that is the last PPAs we have into force with Codelco, supplying electricity to Chuquicamata and to Gaby. That's next in row and it's going to come in the course, let's say of the year.
Once we have been or say that the renegotiation of all these PPAs is over, we will get, let's say back on track on further development in terms of new PPA and gross in other type of infrastructure. To slide 30, there is a snapshot there on the tariff indexation mix of our portfolio will change between now and end of 2025. This only considers the PPA that have already been renegotiated. By 2025, you see that 78% salary of our portfolio will be indexed by CPI, 11% to natural gas and RIL. Mainly our contracts with distribution companies in the north will be indexed to gas. 11% related to remaining coal indexation, which is basically as of today, the PPA with Codelco.
Bear in mind that this will be negotiated in the close future, and then we will have the remaining indexation with coal. That is the second regulated PPA, the one that is center south of the country. Coal indexation will not go to zero. On slide 31, it points out an instrumental snapshot on how ECL generation portfolio will evolve between 2018 and 2025. As you can see, in 2018, coal power plants represented 58% of the total installed capacity of ECL and the renewable, just a tiny 1%. By 2025, only seven years later, we should reach 58, by chance it's the same figure, of installed capacity in terms of intermittent renewable. Basically there, it's the wind, the sun, and some act. Gas representing another 29% of the installed capacity.
Basically, then you will have the 10% of CT and CDH converted into biomass. In a nutshell, you can see that basically, more or barely three quarter of the company will be totally green, and the rest will be based on natural gas. How do we get there? Well, just look at the different arrows in between those graphs. You see the 2,000 megawatts of renewable that will be added into the portfolio during this time frame. We will be closing the six coal stations, 700 MW of oldest units, then the famous conversion of 700 MW of the newest coal stations, CDH to biomass, the IEM to natural gas. Getting to slide number 32. There are another view of our investment in just snapshot on the renewable this time, by technology, by capacity. You see the expected CapEx on a basis.
As you can see, well, it's well-defined on the first 1,000 MW. In the last part of the transformation plan, we'll still be depending on the evolution of the market, the transmission, maybe some investment from competitors. The idea of us is not especially to rush into expanding all that CapEx, but to be sure that each part of the CapEx meets the profitability thresholds that we are into force in the company. Going on to slide 33, this talks about the conversion of our newest coal units to the gas and biomass. The plan, as explained, is to perform these works as much as possible without interfering with the normal operations of the plant, because these plants are very efficient at the time being, so needed by the system. Make obviously, the use of the scheduled downtime for making of this plan.
You have just an idea of what this is expected to be as of today. This might evolve obviously, according to the system operation. In the case of IEM, the existing coal-fired boiler will be converted to gas. This represents a CapEx of around $50 million. As I said, due to the lower economical efficiency compared to the particular CCGT, the unit will be less dispatched in the merit order. It will provide a natural edge in case of high marginal cost to the portfolio. For the future, depending on all the technologies and the breakthrough of different technologies existing today, the evolution of the industry, we will study other type of conversion and repowering of IEM.
Today, we just convert the boiler to natural gas, but I do not close the door that in any close future, we get converting the unit to a full CCGT. We do not rush to the decision. Today it's not viable because of the size, because of the CapEx that would have to be invested into the CCGT. I do not, again, close the door that anytime soon there might be the possibility according to the gas price as well, et cetera, the transmission, that the CCGT gets viable in the north. Key here is keeping options open, and to adapt to the evolution of the market. There is also a call for at the time being as some ideas on thermal storage and the famous Carnot batteries. Not viable today, but might show up in the future.
Obviously, at some point in time and depending upon the evolution of the system and investment, there might be hydrogen. That's not going to be on the close future. I would bet that by 2030, the IEM might have a good chance to use the hydrogen if Chile is evolving into the direction that we expect, being a net producer of hydrogen or derivative of hydrogen. That's the IEM. In the case of CTA and CDH, I think that has already been said at some point, the units will require only limited modifications as they are pre-designed beds. I'm not going to say by chance, but it was like that at the infancy of the development of CTA, CDH. The flexibility of fuel was already a design parameter, and these units can burn biomass today.
It's a limited amount, a certain percentage, if you like, of biomass, not 100%. The conversion will push the units to be able to burn 100% of biomass. At the end of the day, it's not affecting the boiler itself, but just the ancillary systems, like the courtyard, like the fuel silos and things like that. There we will need a little bit less than two months, probably, during one of the overall in 2022, where we will tackle or part of these modifications. There is also a plan to build up the biomass stock needed for the plants to be ready to generate with biomass end of 2025, early 2026. We plan to use black pellets. Black pellets will be imported. Why black pellets? Because they are much more resistant and can be stored outdoor. That's very important.
We do not anticipate to have a full coverage of the pellet yard. Biomass has a higher cost compared to coal. Units, once converted into biomass, will be displaced in terms of priority of dispatch, and they will remain as a backup unit, two of them, or both of them will remain as backup units into the portfolio generation. Providing the physical edge to the operations of our portfolio and the CapEx needed to adapt these plants to full operation with biomass is around $25 million, which is quite low, actually. That's what this is about, and I was willing to tell you guys. I will leave you now with Bernie to cover the following sections with the financial department. Thank you.
Well, thank you, Axel. Good afternoon to everyone. Now please turn to slide 35 for some details about our first quarter financial evolution. Here, the $33 million decrease in EBITDA when comparing to the first quarter of last year, is made up of positive and negative effects. Among the positives, we can mention $10 million explained by the decrease in spot electricity purchase volumes since our own generation increased. We also reported a $5 million insurance recovery from a past loss at IEM. Finally, our operating and administrative expenses decreased by $7 million. Among the negatives, we reported a decrease in volume sales due to COVID, a lower pro rata of the PPA with distribution companies, and the end of the Zaldivar PPA. This decrease in physical sales had an estimated impact of $100 million.
Average realized prices decreased due to PPA renegotiations with an $8 million estimated impact. By far, the most significant impact, amounting to $23 million, was the increase in marginal costs. We had an $11 million also reduction in gas and transmission, largely because of cancellation fees paid for the deviation of an LNG shipment. Finally, fuel costs increased due to the increase in generation and also because of higher fuel prices. We turn to slide 36. This shows the evolution of net results, which went from a $26 million net income in the first quarter of 2020 to an $18 million net loss in the first quarter of this year.
In the first quarter of last year, we recorded non-recurring expenses of $10 million, which were related to the premium paid on the early redemption of a $400 million 144A bond, which we refinanced with a new $500 million bond in January 2020. Our net recurring income in the first quarter of last year was $36 million. Apart from the EBITDA decrease that we just explained, in the first quarter of 2021, we reported $41 million in one-shot financial expenses, which turned our results into a $17.6 million net loss. These financial expenses, as Eduardo Milligan explained earlier, were because in February and March, we sold at a discount almost $140 million in long-term accounts receivable from distribution companies related to the Price Stabilization Law. We sold these receivables to a company called Chile Electricity PEC SpA.
This last company issued a 144A Reg S bond to finance the purchase of accounts receivable from generation companies. On slide 37, we can see our net debt, which increased by $34 million from year-end 2020. In the first place, we reported a $66 million net operating cash outflow, mainly because we paid in early January some fuel and other expenses accrued in December of last year. We reported $40 million in CapEx, mostly in our renewable projects, and we paid $17 million in income taxes. Our gross debt remained unchanged except for a $7 million increase in leases that qualify as financial debt under IFRS 16. The main cash inflows that we reported in the first quarter were an $8 million payment from our 50% owned subsidiary, TEN, and $98 million in proceeds from the sale of accounts receivable to Chile Electricity PEC.
On slide 38, we provide an overview of our ratings and debt details. Our net debt to EBITDA ratio increased from 1.8x-2x , mainly because of the EBITDA decrease in the first quarter, because gross debt remained virtually unchanged. This is a strong position, which gives us room to finance our planned investment in renewables, this year and the next one. In terms of ratings, we have split international ratings of Triple B Plus by Fitch and Triple B by S&P, while our local Double A Minus rating by Feller was given a positive outlook in January of this year. If we move to slide 39, this summarizes our financing activity in the last 12 months. In January 2020, we issued the $500 million 144A Reg S bond to refinance the old $400 million bond with maturity in January 2021.
This allowed us to extend our average debt maturities to 7.7 years and to lower our average interest rate. Last December, we signed an up to 12-year, $125 million loan with IDB Invest, which has an innovative structure. The loan has two tranches, a $110 million loan to be funded by the IDB and China Fund, and a $15 million loan from the Clean Technology Fund. This loan will finance the construction of the Calama wind farm, and it includes an incentive to accelerate the closure of coal plants. The idea is to monetize the actual displacement of CO2 emissions from coal plants, whose generation will be replaced by the Calama wind farm, through a lower interest rate. We have not yet drawn this loan, so it remains fully available.
Finally, last January, ECL, together with the other three main generation groups in Chile, signed agreements with Goldman Sachs and the IDB Invest related to a financing operation for the accounts receivable related to the Tariff Stabilization Law. Under this transaction, as said earlier, we sold without recourse accounts receivable from distribution companies. The sales of receivables are being perfected in groups. Once the CNE publishes each Average Node Price Decree, including the corresponding charge with the balances owed by distribution companies to generation companies. In the first quarter, we sold the receivables for a total nominal amount of $139 million, corresponding to the first two decrees. We estimate we could sell up to an additional $127 million. This amount will, of course, depend on the evolution of exchange rates and other variables, between now and 2023.
This transaction will help us enhance our liquidity and ensure financing for our investment in renewables without increasing our debt. On slide 40, we talk about our dividend distribution that accounted for 72% of our 2020 net income. This is equivalent to 65% of our recurring net income, which reached $181 million in 2020. We are distributing $118 million in dividends in two payments. The first one corresponding to a provisional dividend amounting to $67 million paid last November, and a final dividend for $51 million to be paid on May 20 this year. Over the last 12 months, our stock price fell 13%, while the IPSA showed a 40% recovery over the same period. You can see there that beginning September 2020, the Engie stock decoupled from the IPSA.
Engie SA purchased an additional stock package in our company last December, which allowed it to increase its share to almost 60% as a demonstration of trust in our country and the long-term strengths provided for our PPA reprofiling and decarbonization strategy. Well, this is all on my side. Now I will leave you with Axel and Eduard for the final remarks and of course, our Q&A session. Thank you.
Yeah, thanks a lot, Bernie. I will take it up here. Well, to conclude, I just want to summarize now some main takeaways, and I will provide you on this slide four of them. First, as Eduardo explained at the beginning of the call, the first quarter being extremely challenging. I must say that we have paths for improvements. We have identified the action items, and we do expect some recovery in the following months. I would say that we are doing our best for the time being to get to the low end of our EBITDA guidance. Secondly, we are expanding our renewable asset portfolio, and also we are recording some delays in a couple of PV stations.
We do feel confident that by the end of the first quarter of 2022, next year, we will have completed 700 MW of the first 1,000 MW of renewable plan that is under development, of final development. This is consistent with our commercial strategy of greening the different PPAs we have been discussing and preparing our organization for future and further growth. Thirdly, I would say that we just announced the second phase of our transformation plan, which will allow for full exit of coal by end of 2025, with clear priorities for sustainable and long-term value creation. This includes the conversion of the newest coal assets, to other fuels, mainly the CTA, CDH to biomass and the IEM to natural gas, plus an additional 1,000 MW on top of the other 1,000 megawatts of new renewable power stations.
Fourth, last but not least, all this transformation remains supported by a solid balance sheet with liquidity enhanced by two innovative financing structures, a true sale of long-term accounts receivables and green financing from IDB. I think that's a fair summary of the big bits today. Eduardo, anything to add from your side?
Perfect. Well, thanks, Axel. With these final messages, I think we are finalizing our first quarter presentation. As always, we hope the presentation was helpful, that you have a good time with us. Thank you. Now we are ready for any questions, recommendations, or comments you may have for us. Thank you.
Thank you. The floor is now open for questions. If you have a question please press star one on your touchtone phone at this time or any time. If at any time your question is answered you may remove yourself from the queue by pressing star two. Questions will be taken in the order they are recieved. We do ask that when you pull your questions you pick up your handset to provide optimum sound quality. Our first question comes from Murilo Ruccini with Santander. Please go ahead.
Hello, everyone. Thanks for the call. Trying to understand the economics of the announcement. Could you tell us what is the expectation of the value creation with the conversion of the plants? Or if this is much more related to the mitigation of future risks for the company. The second one, how do you expect to manage the spot exposure in the coming years and also the current PPAs, mainly those indexed to the coal prices? Finally, regarding your financial position, looking to the announcement of the $51 million dividend distribution, how will you plan to fund the renewable capacity CapEx, and how should we expect the management between these investments and dividend payments in the future? Thank you.
Okay. Thank you, Murilo. I think I can take the three questions. I will start with number two, in terms of portfolio, how we expect to cover our contracted PPA portfolio over the next 10 years. Basically, I will start between 2021 and 2025. Basically, we will keep our three newest coal units running with coal, and at the same time, we will start seeing the COD of the renewables that we have announced. Next year, we will have 700 MW of renewables. On top of that, we will continue having our coal units. On top of that, we will continue having our combined cycles running with natural gas. I think we are pretty covered between now and 2025, with the portfolio that we currently have. It's important to have them available.
Of course, under normal circumstances, our physical hedge should be there, and our combined cycles running with natural gas should also help to cover any intermittence or any unavailability of our coal units. Now, after 2025, when we will convert the CTA, CTH, and IEM to other technologies, and these plants will be displaced in the merit order of the system. We need to consider that in 2026, an important PPA will end. A PPA in the north will end with a total demand of almost, let's say, 2 TW hours per year. That means that we will need to cover not anymore a 12 TW-hour portfolio, but a 10 TW-hour portfolio of PPAs.
With 2,000 MW of renewables, we will be able to cover half of this portfolio with our physical hedge, while the other half should be covered by the PPA backups, by the PPAs that we have signed with other generation companies. There, we will have around 2.5 TW-hours per year covered with these contracts. The other 2.5 should be covered with our existing combined cycles running with gas and combining them with the renewables that we'll have in our portfolio. The conversion will reduce our physical hedge or efficient physical hedge at the current cost, but we will add more renewables to basically replace this physical hedge that will be displaced in the merit order. This is how our portfolio will evolve over the next years.
In 2026, it's a tipping point, because in 2026, we'll have the renewables, we'll convert the others, and we'll still have the PPA in the North. We have some years to find probably a hedge instructor for that year, and probably with additional backup PPAs. In terms of valuation, as we were probably explaining or we mentioned in the presentation, the conversion responds to basically mitigating some risks for our portfolio. Instead of keeping coal units, what we are doing is converting them to other technologies and basically changing the profile of the company and having the opportunity then to add more renewables to replace them, and becoming a more sustainable company for the long term. As you know, coal units probably have a limited life in this system, at least.
By the chance that we convert these units, we trigger, automatically, the investment in additional renewables. We will be able to compete with other generation companies in the country to capture more regulated and unregulated demand with a more balanced portfolio between gas renewables and, why not, in between, probably adding some storage too. Finally, in terms of funding, today, our balance sheet should be able to finance 100% of the plan without putting at risk our net debt to EBITDA or rating. This is because the renewables that we are building will add an additional EBITDA. By this, I mean if we should have an average EBITDA of $500 million, let's say, under normal circumstances in 2021 or between 2020, 2021 or close to $500 million, the additional renewables will probably add between $150 million and $200 million of additional EBITDA.
Of course, with an important investment in CapEx in this period. This should also allow us to raise additional debt in our balance sheet. Together with that, we still have a strong cash flow generation during this period, so we are planning to keep the same combination that we have been using so far, 50% internal cash flow and 50% additional debt. With that combination, we should be able to finance the whole plan. We will still have some additional room for additional debt in case we win additional PPAs and we add more renewables on top of the 2,000 megawatts that we have announced. Did I answer your three, or am I missing something?
That was very clear. Thank you, Eduardo.
Great. Thank you, Murilo.
Our next question comes from Andrew McCarthy with Credicorp Capital. Please go ahead.
Good afternoon, everyone. Thanks very much, Axel, Eduardo, Bernardita, for the presentation. I had a couple of questions. The first one, a more general one. Obviously, the announcement of the Engie group exiting coal came to the market at the end of February, and thereby you had to obviously take a decision as to what to do about the remaining efficient coal plants you had. You've gone down this, obviously, the route then of pursuing a reconversion of those plants. I was just wondering if you could maybe help us or maybe take us a little bit through sort of the decision-making process there in terms of why you went down that route. Why not, for example, a sale of the plants maybe tied with some of the PPAs you have, or why you didn't just simply shut down the plants? Just be helpful to understand that, if possible.
The second question, a bit more of a specific one. You mentioned that obviously with the reconversion of the plants, their position on the merit order will obviously change. I was just wondering if you could provide a bit more information or color on your expectations on what the sort of variable cost of those plants should be post 2025, and also what your sort of expectations are on the reduction in terms of the sufficiency payments those plants may be receiving also post-2025. That will be great. Thanks very much.
Thank you, Andrew. I think those are also very good questions. In terms of decision process, what we have announced this week is not something that was triggered by the recent announcement of Engie to exit coal by 2025 in Europe and by 2027 in the rest of the world. I think, or to give you some insight, this is something that we have been working on since 2018. When we started with this transformation process for the company, probably we were first movers in renegotiating some PPAs and transforming them in the long- term. I think that was also a good move because things changed since then. We were ready, some time ago, to go in this direction. I think what we have announced now is that we will start the implementation phase.
The development phase of this plan started as I said before, some time ago, and is in line with our purpose and is in line with the DNA of the company and what we are planning to execute worldwide, in relation to people, planet, and profit. I think what we are doing today will become more sustainable business. We are, of course, probably first movers again or very close, or at least we are in the pole position to go in this direction. We will see, and I'm sure that in the long- term, this is something that will be positive. In terms of the cost or.
Yes. Can I speak to the second question? I think it's actually an extremely good question, and I can assure you that all options actually have been analyzed. Well, you can imagine what it means, all options from the standpoint of Engie. Actually everything has been analyzed in the deepest detail. The strategy that is on the table today is a strategy that is allowing the best value creation for the minority shareholders and for the main shareholders. You might be thinking that at some point the divisions could have been better aligned, but it has not been the case. We've been tried at some point to investigate in the market if selling down, for instance, one of the coal station with one of the PPAs was a solution. At some point we asked the market, we've been engaging discussion on that.
We realized very quickly that it was considered as a fire sale, that it was considered as, obviously Engie is saying so many things on the market that we should obviously be careful, and there to get, between brackets, to get rid of the coal assets. The beauty of this strategy is to show that actually the organic transformation of Engie Energia Chile is creating value because we realize that being a pure coal player, your results will erode over time. It's a matter of time. Because financing will get more expensive, because insurance will get more expensive, because your customers will push you into the green market.
I would add that if you sell, if you get rid of one of your assets in PPA today, obviously you lose market share, and you lose position in the market, and you lose a certain capability to grow in the future. This is, in my perspective, the beauty of this plan is that ECL back on track in competitiveness at the same time, and being based on a green story, it means that at the same time, you can recover the confidence of your customer and have, again, a growth platform for the future. Let's face it, today if you like to participate to some of the newest PPA showing on the market, like big American players like Walmart, like, I don't know, Microsoft, Apple, whoever you like, you have to be green.
These guys in a couple of years, they will not contract someone with coal assets. Being their PPA attached or not to the coal assets. I think that altogether, we shaped, if you like, the market, the visions, the risk, et cetera. I think that the plan that is on the table, that is being digested by the different teams, and when I'm discussing about different teams, this is probably, and Eduardo, stop me if I'm wrong, but this is all in all, more than 100 people between the regional office of Engie, between Paris, between the people of ECL, to attack and tackle all the options. I think that what is on the table we're getting today has been so digested that it makes sense. The company will have a new profile by 2025.
It's going to be totally different from what it is today. Obviously, it's going to be challenging to implement that transformation because it's not a walk in the park, let's say. This is the new aim and the new vision of the company, and I'm pretty sure that we will attract a lot of customers behind us. The future of the mining industry in Chile will be green, and they know that. So the closest we are from being totally green, the best place we are to keep growing with the mining industry. You can go on as well. Sorry.
Great. Thanks. Yes, indeed. Andrew, you were asking about the variable cost of these plants. I will start with efficiency to explain you a little bit how it will change. In terms of efficiency, currently, the efficiency is close to around 41% LHV. The efficiency of the conversion from coal to biomass or to gas will not change. Basically, the efficiency will be the same. What will change is that the fuel cost will increase. In the case of CTA and CTH, with probably a current cost of around $40-$50, will double with the biomass. For IEM, with a cost of around $35-$45, will probably increase to $55-$70 range, depending on the cost of gas, of course.
Why, in the case of CTA and CTH, we don't see any impact there is because after 2026, and with the penetration of renewables that we expect during the next years, the dispatch of these units would have been marginal using coal. In the specific case of IEM, what we are doing is converting this unit to natural gas, which is the type of fuel that today should be there to join renewables in our portfolio, providing a hedge during nights, probably. This will allow us to reach a 24/7 production cost for our clients. This is today for IEM, considering IEM in simple conversion, let's say, or this light gas conversion, because we'll continue using the same turbine.
In case IEM is converted in a second stage to a combined cycle, but adding more CapEx, probably $250 million more, then you will have not 41% efficiency, but you will have a 53 or 54, 55 efficiency. Then your production cost could go down again with the current LNG price to the current price of this unit running with coal, so to the 35- 45 range. This decision will, of course, need to be taken in the future, considering how the market evolves, how other technologies evolve and are available to be combined with renewables. This is an optionality that today we have, and that's a second, probably, stage for IEM that could happen or not, and that will depend, as I was saying, on how conditions in the market evolve.
In terms of capacity, well, these units today running with coal are not flexible because coal is not flexible, as you know. You need several hours to run these units and for the ramp-up. Changing them to biomass will not change their current condition. In the case of IEM, converting IEM from coal to gas will probably improve a little bit its flexibility. In terms of sufficiency or capacity payments, we don't expect any change. In terms of flexibility, IEM opens a new option in the future.
Thank you very much.
You're very welcome.
Our next question comes from Juan Carlos Petersen with Inversiones. Jeff Quinn, please go ahead.
Yeah. Good morning or good afternoon. Can you hear me well, Eduardo?
Hello, Juan Carlos.
Thank you very much for the presentation. Thank you, Axel and Bernardita. Axel, sorry. I have a question related to what Axel just explained very well, and it's linked to page 31 and 32. As Axel explained very clearly, it seems that being greener is a ticket to play. There's no option not to do this. I would like to understand two things, Axel or Eduardo. In terms of generation, your aim is to be not only growing capacity and generation capacity to 3.4 GW, but of course, being cleaner and greener. In terms of EBITDA, if the company today has an EBITDA in the range of or in the vicinity of $500 million per year, what would be, at that time, in 2025, the new EBITDA of the company?
Related to that, would it be possible to understand from you, Axel, if, yes, the company will be greener, and could we also say that the company will not only be greener but also more profitable? Being greener will be at the expense of being less profitable? My second question is regarding the projects related to hydrogen. We have seen on the news certain initiatives that the company is promoting, which looks very interesting. Can we have a guess or a range of the magnitude of those green hydrogen projects, in terms of EBITDA, if possible? Lastly, my third question, Eduardo, is related to the flexibility of your balance sheet and the implications on dividends. For instance, for this 2021, could we say that the last two or three years' dividend policy should not be exposed, given the flexibility of the balance sheet that you do have?
All, of course, in view of the CapEx projects that you have announced recently. Thank you very much.
Thank you. Look, I will start with the first one, to give you a view on what we expect in terms of EBITDA. I think, Axel, you can explain how we are becoming greener and more profitable with this strategy and the sustainability of our business in the long term. Also, the third one, in relation to hydrogen and what we expect in Chile and the pilots that Engie is developing. At the end or at the beginning, I will go through the fourth one in relation to the flexibility of our balance sheet, because I think it's related to the first one. In relation to the first one, which is related to the EBITDA that we could expect.
We should expect an increase in our EBITDA between 2021 and 2025, which is basically explained by the fact that we will start replacing spot purchases at $40, $45, $50 during this period with our own production, with renewables at almost zero, or let's say $5. That means that if we are adding 2,000 MW of renewables equivalent to, let's say, 4 TW hours or 5 TW hours, let's say four terawatt hours on average during this period, we should be adding between $150 million and $200 million EBITDA to our P&L. It's a simple math. We need to multiply four or five times the 40 or 50, and then we will reach between $150 million to $200 million additional EBITDA for our P&L. This additional EBITDA will, of course, add additional flexibility to our net debt to EBITDA. Now, this is to 2025 and to 2026, probably.
In 2027, as I was mentioning before, we will have the end of an important PPA in the north, a regulated PPA, with almost 2 TW hour of total demand. It's a bit lower, but let's round the figure. With a margin of probably $40-$50. That means that the additional $200 million after 2026 should go down in between $70 million-$90 million after this PPA ends. This is probably what we expect today without doing anything else. Of course, Axel, Bernardita, Marcela, and we all are here to bring more PPAs and to grow during the next years, because this is, of course, the most, let's say, important objective of what we're doing today. In relation to the flexibility and the dividends, of course, with an additional EBITDA, we will have more balance sheet to finance this expansion plan.
We should expect that the current, and I'm using the current because it could be around 50% dividend policy, should remain stable during this period, assuming that our free cash flow during this period remains stable at the current levels or as we should expect under our base case. Of course, if we can or if we have additional CapEx needs in this period, we have some additional flexibility without putting at risk or reducing the dividend policy that I was mentioning. In any case, at some point, if we have more and more CapEx, we will have some tools by probably reducing, again, to 30%. This is not in our base case. In our base case, I think we have enough cash generation to do everything at the same time. We can go, Axel, to the other two.
Yeah. Well, to the question, is greening the company destroying value or destroying profitability of the company? Definitely no. Why no? I think what has happened, it's actually a disruption at the level of the industry. When you realize at some point that variable cost of operating coal and the marginal price, including investment of a new portfolio of renewable assets, is actually cheaper. What it means that your legacy business has been disrupted. At the same time, your customers, they can, let's say, pick the best options because the market has evolved, provides more alternatives on green energy. If you do not react, you are just out of the market.
I think that, no, it's not destroying value because what we are doing at the end of the day. To say it on another way of what Eduardo just explained, we replace fuel price by depreciation, if you like. The renewable will create much more EBITDA because there is no more fuel, natural gas remaining. At the end of the day, we will not have more coal, and the fuel cost is one of the biggest costs of the company, obviously. I think, it makes sense from the asset standpoint. It makes sense with the customers, because what we've been doing, renegotiating the different PPAs we have, is being, well, reducing the price, but against extension. It has been a de-risking of the PPAs, because being close to market price is much than being 3 x over the market price.
What at some point would have happened. Globally, I'm not going to say it creates value, because this is highly depending on the way you would today value ECL. I will just give you two more private opinions for myself. First of all, I think that the results will hold in the future. Because if you stay black with coal, your customers will be a mess, obviously, because they expect something different. Having a customer that expects something different in terms of price and in terms of technology than what you propose them, well, that's not the best way of being sustainable. Secondly, from the cost perspective, we know that at some point there will be more CO2 tax. The only question is when. Then just take insurance.
Three years ago, we had a certain market for talking about insurance to insure the different coal stations. I think that as of today, 50% of that market has barely disappeared. You have less people, less companies today willing to insure coal. This will happen tomorrow in terms of financing, in terms of everything. Results will be out. It's a matter of time. You have the cherry on the cake, if you like. It's growth. Having a coal company, there is no growth perspective. Forget it. I would even say that from there, from Engie standpoint, from the main shareholder of the company, probably the main shareholder of the company would have been reluctant in putting more CapEx in a company that is not aligned with the strategy of the company.
Globally, you have now the option to create more value with the company because there is a growth option. Obviously, valuating how much does it mean a growth option? That's a little bit more complex. Okay, this is what you are all pitched for. Take the market and look at the mining industry, look at what BHP, what Anglo American, what Antofagasta Minerals are explaining on their future in terms of sustainability, in terms of carbon neutrality, et cetera. I think that indeed, what we have been up to and the strategy that has been defined makes a lot of sense with regard to the evolution of the country and the main industry in the country. The plan would have destroyed value. Honestly, it wouldn't have go through the governance of ECL.
That would have been stopped either by Engie itself or by the board of ECL. I don't know if I replied to the question.
The last one was related to hydrogen. What are our plans with hydrogen? I think it's related to the three pilots that we announced and how that engages with ECL.
Yeah. Well, that's probably on the longer run. If you look at the three pilots, it's one with Scorpio that is, at the end of the day, a research and development project, with the aim to foster, let's say, the use of hydrogen into the mining industry, and specifically in this case, as a replacement to diesel or natural gas for moving the famous CAEX, these big trucks in the mining operations. There is no more plan. No, it will take time. The adoption of hydrogen will take time because it's extremely expensive for the time being, but better to be in and eyeing at that market than being at miles away from that evolution. You have Walmart. Walmart is an interesting one because it's the first real application of hydrogen with no subsidy.
By the way, I've been saying that some of these early adopters of green technology, well, Walmart is one of them. We have to be green if we want to keep companies like Walmart in the portfolio of customers. We will convert 189 forklifts to hydrogen. You have a very longer plan with Enaex and this vision of producing green ammonia in Chile. That might end up at some point with an export of ammonia or any derivative of hydrogen outside of Chile. On the shorter run, it would be producing this ammonia onshore in Chile and supporting, let's say, the evolution in terms of fertilizer or explosive with Enaex. Again, that will take time. This kind of project today is not viable without subsidy, and the development team is focused today on finding, I don't know what to call that.
It's not a debt because it's much more grants and subsidies and working with CORFO again, and government-to-government loans and things like that. What will be the role of ECL in this? If this hydrogen, at the end of the day, is just PV and wind transformed in something different. It's a huge market tomorrow, being the one of the CAEX and the one of Enaex. If there is an early adoption of hydrogen, ECL will benefit from all this green corporate PPAs that will allow growth to the company. That's the connection with ECL.
Thanks, Axel. Juan Carlos, I forgot to mention something, but I hope our announcement last Wednesday answered a little bit your suggestion during our last shareholders meetings. It was very interesting to have that suggestion, and I hope we were at the level. Thank you.
Can you hear me well, Eduardo?
Yes.
I'm online still. Yes, to answer your point, yes, definitely. Thanks for that. I don't think you did that because of my suggestion. I think it was part of your strategy, and you're spot on. You did very well. Thank you, Axel, for your comments and for taking the time. You have a busy agenda. Having you here explaining the strategy and with the high level of quality of information adds value. I have three comments, no more questions. For some reasons, Axel, the Chilean market has got nervous around all the changes in this industry and certainly with the discount that Engie Chile is having today, if you compare similar companies with a similar strategy, with a similar asset footprint, either in Europe or globally. The multiples that the company has in Chile are with a severe discount versus others.
That, for some reason, I don't know if it is ignorance from the market or lack of information, and that was one of the reasons why I suggested that on your AGM. To finalize, I did watch the audience that your President Catherine MacGregor did in the Sénat in France in March 2021. I think it was an outstanding presentation. Very challenging questions, but she did that very well, and hard questions very well answered. I guess that is something that could help also to apply in Chile, to go back to normal multiples for Engie and being treated fairly from the market on the share price. Thanks for that, Axel. Thanks, Eduardo, for answering the questions and keep doing the good work.
Thank you.
Thank you.
This concludes the question and answer session. At this time, I would like to turn the floor back over to Engie Energia Chile for closing remarks.
Well, thank you very much for your participation. Bernardita, Axel, if you want to say something, too.
Thank you to everyone. Appreciate it from my side. Appreciate the trust and happy to be part of all these announcements, because I think it's not every month that we take this kind of decision. Thanks for being here.
Okay. On my side, thank you for attending the call and for the good questions. That's all. I hope you all have a very nice weekend.
Thank you, everyone. See you soon. Bye-bye.
Thank you. This concludes today's presentation. You may disconnect your line at this time, and have a nice day.