Good afternoon, everyone, and welcome to ENGIE Energía Chile's Q2 2022 results conference call. If you need a copy of the press release issued, 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 the information discussed today may include forward-looking statements regarding the company's financial and operating performance. All projections are subject to risk 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 Energía Chile's PR department for details. I would now like to turn the call over to Mr. Eduardo Millán. Please go ahead, sir.
Thank you. Good afternoon to everyone. Today I'm here with Ramonette Infante, Head of Corporate Finance, and Marcela Muñoz, Investor Relations Officer, and we will discuss ECL results for the H1 of this year. We can go directly to page number 3, in which we are presenting the main topics we want to address this afternoon. First, ECL results have been severely impacted during the H1 of 2022 by extraordinary events that impacted spot prices and consequently increased the supply cost from average $66 per megawatt hour in the H1 of 2021 to around $118 megawatt hour during the H1 of 2022, with a material impact, as you have seen, on EBITDA and net results.
Second, we will talk about our projects under construction. We'll be commissioning 268 MW of additional solar PV power plants located in the north during the next month. The development team expects to launch the construction of one additional wind project that will provide an additional physical hedge to ECL portfolio of PPAs. In relation to the supply agreements signed with other generation companies, or what we call backup PPAs, we have detailed on page 12 the volume, type of contract, and the tenure of the existing contracts that are providing a hedging to spot market volatility. The volume of ECL sales in 2023 covered with these contracts will reach approx 2.8 TWh that are equivalent to approx 25% of ECL's contracted demand.
Third, we continue developing more than 20 projects in different regions and through different technologies, but mainly focused on wind, solar, and batteries. We don't have yet additional news on the start of new constructions but will come soon to reduce ECL exposure to spot market volatility. Fourth, the extraordinary market context, together with the regulated tariffs stabilization mechanism and related H1 2022 results, have added pressure to ECL net debt to EBITDA ratio. This situation is mainly linked to the lower EBITDA, while ECL raised additional debt to finance the CapEx plan and the postponement on cash collections related to the regulated tariff stabilization law.
In this context, we do not foresee dividend payments in the short term until leverage returns to our target level, which under the current market context should improve during next year. We will discuss this in a couple of minutes. On page 4, we can see the evolution of ECL results during the last 3 years. Despite the average realized price of ECL portfolio increased to $145 per MWh, with operating revenues increasing in 24% compared to same quarter of previous year. EBITDA was materially impacted by higher supply costs due to droughts, extremely high fuel prices, the lack of LNG due to a fire in Freeport Terminal, and the other unavailability of thermal plants in the system.
Net results of the Q2 reached negative $44 million, and we have an accumulated loss of $40 million during the H1 of 2022. Net debt increased in line with the CapEx plan to $1.3 billion, which, as I mentioned before, impacted the leverage ratio as EBITDA was far below the expected range. We will discuss in some minutes our view for the H2 of this year. On page 5, we can see the evolution of unregulated and regulated PPAs. As we mentioned on this slide, we are facing a strong demand of unregulated clients in 2022, exceeding the 3 previous years due to recovery in mining activity and higher copper prices. On the other hand, regulated demand was relatively flat.
In this context, there are no incentive for clients migration, while past initiatives on further migration or portability have more challenges to become feasible in the medium term. In fact, during the last two months, we have seen an important increase in regulated demand in the market. The next five pages will describe the main variables that are materially impacting spot prices and the overall systemic costs in Chile. We need to recall that approximately 50% of the electricity in Chile is directly linked to the international market of fuels, mainly coal, LNG, natural gas, and unfortunately diesel. The other 50% of the electricity is produced with local resources, mainly hydro and renewables. This means there is still a high dependency on imported fuels and also on how hydrology behaves from one year to the other.
As we all know, we have faced several dry years during the recent years. On page six, we can see the spot price evolution on the three main regions. Despite average prices could be misleading, and it is always important to analyze margins during day and night, we can see the average price in the H1 of 2022 is 50% higher than the already high average price of 2021, and more than three times the average price of 2017-2020. For ECL, net commercial exposure to the south is close to 0.6 terawatt hour per year and mainly related to regulated PPAs, while in the center, the net commercial exposure is close to 2 terawatt hours and below 1 terawatt in the north.
This is important, because in this context and with some transmission congestions in the system, we need to analyze the exposure and the action plans by region. The situation in the south, for example, is critical due to congestion and during the H1 of this year, also due to lack of hydro production. The spot prices is permanently driven by diesel power plants. As I mentioned before, ECL net commercial exposure to the south is close to 0.6 terawatt hour per year and mainly related to regulated PPAs, while in the center, as I was mentioning before, is close to 2 terawatt hours and 1 in the north. In other regions, we are also facing diesel prices at night.
In this context, until the congestion is solved in the south, each megawatt hour sold in, for example, the regulated PPA in that region, represents a loss until the congestion is solved. Now, what comes next? Rain and snowfall are expected to reduce the pressure on marginal costs starting August, September of this year. On page seven, we present the hydroelectric production during the last 4 years in Chile. As we all know, 2019, 2020 were already dry years, and 2021 was the second driest of the last 60 years. The lower hydro generation has increased the dependency on fossil fuels.
In addition, due to the dry context, the market coordinator built during the H1 of 2022 through an emergency decree, a 372-gigawatt hour hydro reserve to face potential energy shortages. This is an insurance for the system. Now, the rainfall and the snow accumulation during July allowed the market coordinator to recently reduce the reserve limit to 205 gigawatt hours. This means the system will release average 250 megawatts during August. That will certainly add some relief to spot prices. Of course, if conditions allow, it should be even better to release 100% of this hydro reserve. We will explain our view for the H2 in a couple of minutes when we discuss our overall view for the rest of the year.
Now, on page eight, we explain what is happening with coal prices. As you know, close to 30 to 35% of the electricity in Chile is produced with coal, around 15 to 20% with LNG, and even diesel is today relevant for the market during night hours. This means the country relies on 50% on imported fuels, which are impacted by international prices and currently by the extraordinary international crisis, which is impacting the demand for coal and LNG mainly in Europe. This crisis is materially impacting the Chilean power market because coal prices and LNG skyrocketed both to all-time highs. Coal, in this context, is the key driver for spot prices in Chile and will continue to be key during the next years.
As I mentioned before, 35% of electricity will continue to be produced with coal power plants. Since the crisis and war started in Europe end of February, coal prices have been extremely volatile, reaching during some days, for example, $500 per ton to then stabilize at around $350. This sharp increase is also supported by the European need to replace natural gas with other energy sources. Now, the average forward coal price for the H2 of this year is even 15 to 20% higher than the average price of the H1 . Meantime, the average production cost of coal power plants in Chile would remain above $450 per megawatt hour.
This is why, today, with this production cost and with a still strong dependency on coal production, the spot price is at current levels. Next, page nine presents the average availability of coal power plants during the last 30 months. The system evolved from 4.3 gigawatts in 2020, as we can see on the left, to only 3.5 gigawatts during the H1 of 2022. The difference, 800 megawatts, is a lot for a system with a total demand of around 10,000 megawatts. This is between 8 to 10% in only two years. The last month of June, for example, was critical and had a material impact on ECL results.
During June, for example, IEM power plants had programmed maintenance, and at the same time, there was a fire in Freeport Terminal, which didn't allow our LNG supplier to load an LNG cargo, and we faced an important exposure to extremely high spot prices. Together with the unavailability of several coal power plants in the system, at the same time, we are facing an important drought, and at the same time, we were having this hydro reserve for unforeseen circumstances in the future. On page 10, we present the LNG prices in different markets. We can see the LNG price materially increase after the recent crisis. The good news, if we talk about gas, is that Argentina is exporting gas to Chile in the central region that is helping to mitigate the lack of hydro.
This is these are good news because this is happening right now. We know that until April of 2022 there was a permanent export of gas from Argentina to Chile. Gas from Argentina represented almost 10% of the system's electricity production during this period. The same volume of 2021, or even an additional volume, would be available again since October. The graph below in this page shows the LNG firm contracts and volumes from ENGIE and other cogenerators. These contracts are indexed to Henry Hub and hence not impacted in the same proportion than LNG prices in Europe.
As I mentioned before, one of our LNG cargos faced a force majeure on June 8, only two days before the cargo was planned to be loaded at the Freeport Terminal due to a fire, which led to cancellation of 3.3 TBtu LNG shipment. We lost this cargo, which was planned to support our portfolio during June and July. As a consequence, ECL bought more energy in the spot market at very high spot prices. The impact of this cargo in ECL EBITDA could be estimated in around $40 to 45 million. In this context, we are discussing remedial actions with our LNG supplier, which are required as part of the contract.
Next, page 11 gives an example of the volatility the market is facing on spot prices during day and night hours. The red dotted line shows the spot price in the north region, in which most of ECL demand is concentrated with mining companies. Spot prices during June ranged between $0 and $350 per MWh. If we move to page 12, we show the volume of energy ECL contracted during the last four years with other generation companies to manage the supply risk. In 2022, 2023, ECL will have this hedge for almost 25% of its contracted demand. We know this volume is helping, but not enough, and the volatility of results we are facing certainly demonstrates the importance of being fully balanced, and that's why we need to accelerate the construction of additional efficient capacity.
As suggested by some of you, this quarter, we divided the contracted volume of supply agreements with other generation companies between 24/7 and solar profiles to give you more clarity on how these contracts are supporting our PPA portfolio. We can see an important ramp-up in 2022 to reach a full ramp-up by 2023. In this sense, we may add additional hedging contracts if we find a good fit with other generation companies. On average, between 2022 and 2025, we have secured backup PPAs for average 2.5 terawatt hours per year. On the other hand, the blue area in this graph represents ECL generation, plus the remaining spot purchases, which should reduce over time with the construction of renewables.
As we explained before, this is a complementary strategy to the construction of renewables during the transformation phase. Let's move to page 13, where we can see the demand supply balance for the H1 of 2022. This graph shows average realized PPA prices compared to the average supply cost, which is the result of the different power sources to meet the total demand from our PPA contracts. We can see that a new area in yellow starts to increase at the left part of this graph, so we will see this every quarter. I already mentioned this during the previous quarters. Our thermal power plants come on the dispatch ranking right after these renewables. The variable costs of our coal power plants in general was much higher because of higher coal and LNG prices.
As we move to the right, we see ECL supplied 33% of its contracts through purchases from the spot market and 16% through supply agreements with other generation companies, and both are together representing almost 50% of total sales. The result was that our average supply cost increased from $66 to 118 per megawatt hour. This was partially compensated by the increase in the average economic price, which also increased from $108 to 134 per megawatt hour. This means despite the total PPA price increased in $26, the average supply cost increased almost twice, in $52.
Now, it is important to highlight that ECL is currently facing the cost of supply with its own generation power plants and also through the spot market, while there is a lag in the fixation formula of the regulated PPAs, and this lag is of approx six to eight months. This means that during the next months, and in 2023, the prices in these PPAs will be adjusted to reflect the higher supply costs we are facing right now in 2022. This was, in the past, not material because fuel prices were not changing dramatically as we are seeing today. In this context, this six to eight months lag is relevant. Let's talk about our view for the H2 of the year and discuss some elements that are also relevant for 2023.
Please, turn to page 14, and we will go through each of these elements. First, hydrologic conditions. The H1 of 2022 was still impacted by 2021 drought with a P98 exceedance probability. In addition, as I was explaining before, the market coordinator implemented a hydro reserve until May. Now, in fact, for the H2 of the year, the hydro reserve will be reduced to only 205 gigawatt hours, thanks to rainfall and snow accumulation. What means in terms of hydrology, what we experienced during July, it means that we may be closer to a P90 for the new hydrologic year, which will continue until 2023.
The snow's melting should start during August, September. Of course, the main doubt is until when in 2023 this improved hydrology will last. Overall, this is positive for the rest of the year. Second, coal prices continue to increase from average 200, 250 during the H1 and potentially to 300, 350 dollars per ton expected during the H2, but still with a lot of volatility. Coal prices are still changing very fast, and forwards are also changing very fast in this context. Unfortunately, coal is not moving in the right direction. It's still very expensive, so we expect this variable will continue to be negative for the system. Third, Argentinian natural gas supply.
As I was explaining before, it was key until April of this year, and then it was initially expected to come back with relevant volumes since October. The good news is that, following the new regulation and higher prices in Argentina to promote investments, since July, Argentina is again exporting relevant volumes to Chile through the center region. Approximately 3.5 million cubic feet per day is what today Argentina is exporting to Chile, which is a bit more than half the volume Argentina exported between October 2021 and April 2022. This is, of course, positive, while the volume to be exported during the next summer season is also expected to increase. We need to wait and see, but it seems there could be.
There is a possibility that Argentina will export a higher volume of gas during the next summer season. Number four, LNG supply. As I also mentioned before, we are facing the force majeure of one cargo between June and July. This means at least $45 million negative impact, which was accrued half in June and half in July. The rest of the LNG cargoes are coming from other terminals, so this also means the situation in Freeport will not be impacting our view for the rest of the year. Number five, efficient plant outages. During the H1 , IEM was limited to only 250 MW. That's an around 100 MW. It went to maintenance during June.
IEM is back since July at full capacity, and we expect to continue improving availability during the H2 of the year for the rest of our thermal power plants. Number 6, PGA indexation. As I was explaining, the regulated PGAs have an important lag in its indexation formula of approximately 6 to 8 months. This was not material when fuel prices were relatively stable but given the current increase in coal and energy prices, it has become material because the supply cost is recognized today where the indexation formula will only reflect the higher fuel prices in some months in the future. This means part of the loss we are facing in 2022 will be recovered during the H2 of this year and also during 2023.
Number seven, new renewables coming online during the H2 of 2022 will provide some relief in 2022, and also during 2023, when we expect to have them at 100% of their production capacity. In addition, in 2023, we will see the ramp up of additional volume coming from supply agreements signed with other generation companies. These seven main elements explain our current view for the H2 of 2022. On the other hand, July has been again a complex month because there were transmission failures in the south and north, together with failures in coal power plants.
The average spot price in June was close to $200 per MWh, and in July is approximately $150 per MWh, which is still very high and almost two times the average of the last five years within the same period of time. In 2023, we should also see an improvement in ECL overall position. However, this considers coal prices and hydrology will remain at current conditions. We need to have in mind that if coal prices continue to increase, or if hydrology worsens, then the system will face again higher spot prices than the ones we are expecting. Now please turn to page 15. Our CapEx forecast for 2022 remains stable compared to previous quarter and includes an additional CapEx related to new renewable projects.
The block in green considers all CapEx for 2022 in renewables. Around $90 million have already materialized in the H1 , and the remaining committed amount related to projects under construction is close to $40 million, while the difference of around $60 million is related to additional projects we plan to launch, but that are not yet committed. On the other hand, total net debt to last twelve months' EBITDA ratio increased from 3.9 to 7 times, given the lower EBITDA and the recognition of operating and land leases as financial debt. Without considering the leases, the net debt to EBITDA is close to 6 times. During the next years, we should return to the baseline we defined to keep our leverage ratios not exceeding 3 to 3.5 times on a structural and regular basis.
What will also help by the end of this year probably is the monetization of the long-term receivables coming from the Tariff Stabilization Law. In addition to the lower EBITDA and results, what we are also facing in this context is the accumulation of these receivables until the new mechanism is ready, and then we will be able to monetize a relevant amount of money, probably by the end of this year. As we explained before, conceptually, we may face temporary increases in the leverage ratio during the construction phase or during complex years like 2022, but this should be temporary considering renewables will rapidly generate an additional EBITDA.
In this context, while margins don't return to previous levels, dividends would be kept at minimum ratios probably. As we explained also in previous calls, the renewables is developing will replace the energy purchases in the spot market to supply the PPAs. This means, approx every 1 terawatt hour per year of renewables production should create additional $40 to 50 million EBITDA under normal market circumstances. Now, Bernardita will cover the following section to explain in detail the variance analysis on the consolidated financial performance.
Thank you. The floor is now open for questions. If you have a question, please press star then one on your touch tone phone at this time or at any time. If at any point your question is answered, you may remove yourself from the queue by pressing the pound key. Questions will be taken in the order they are received. We do ask that when you pose your questions, that you pick up your handset to provide optimum sound quality. Please hold while we poll for questions.
The first question will come from Alejandro Andrade with JP Morgan. Please go ahead.
Hi, how are you? Thank you for taking my question. I wanted to see if you guys could give an update on the stabilization fund, specifically what is the status of the new fund being created, and how would your accumulation of receivables change or not going forward? Thanks.
Thank you. Sorry, apparently there was a problem with the system. Let's continue with the questions. We already started. Well, yes, there was a first stabilization mechanism. Today we have already sold 5 decrees, and the remaining decree, number 6, should be monetized between or during the next months. We expect to do this by the end of this year, hopefully. We're talking about CLP 40 million, around CLP 40 million. It comes the second stabilization mechanism, which went through a fast track, and it was approved by the Congress during or over the last 3 or 4 weeks. The new law was already published. How this new mechanism will work, so basically, first, tariffs will be adjusted with a certain focalization.
That means that the most vulnerable residential consumers will not face an increase in their electricity bills, while other consumers with a higher demand will have higher increases in their electricity bills. In between, there will be again an accumulation of long-term receivables, which in this new scheme will be monetized again. This time, the receivables will include the financial cost that generation companies in the past were assuming. This means that for every dollar that a generation company will accrue as a long-term receivable, the financial cost will be included when these receivables will be monetized. How these receivables will be monetized this time through a monthly mechanism in which generation companies will receive these credit rights.
Afterwards, generation companies will be able to monetize these receivables through a new monetization structure in which financial institutions and multilaterals are currently working with the ministry. We expect this mechanism to be implemented by the end of this year. In our specific case, the total accrued receivables for this new mechanism during 2022, in addition to the 40 I was mentioning before that we still need to monetize coming from the first mechanism, could be around $125 to 150 million that we are not at this stage collecting, and that we will only collect once the new monetization structure is ready, hopefully by the end of this year, which is the target date.
Afterwards, the idea is to be able to monetize these receivables on a monthly basis.
Thank you.
You're welcome.
Hello. Hi, this is Bernardita. I just got a problem when Eduardo told me I was going to speak. I will continue with the presentation, if you don't mind. If we can go to slide 17, we'll talk about the evolution of EBITDA. I'm afraid I will repeat a few things that Eduardo said, but it's just another form of viewing the same thing. EBITDA reached $60 million in the Q1 , which is a 68% drop compared to the H1 of last year. A closer look to the reasons behind the weaker performance takes us again to the severe and prolonged drought affecting Chile and the dramatic increase in fuel prices as a consequence of the Russia-Ukraine war.
These two factors caused an increase in the country's energy generation prices, as evidenced by spot prices, which reached averages well over $100 per megawatt hour in all nodes of the country, and even over $200 per megawatt hour in the south and at the Puerto Montt node. Particularly in June, as Eduardo said, average marginal costs went up to levels between $190 to 225 per megawatt hour in all nodes. What happened in June, the hydro reserve buildup continued through the month. Argentine gas supply fell. Large cost-efficient coal plants like IEM were out for maintenance. The Freeport force majeure took place in early June, affecting gas supply and coal prices. On their side, remained at high levels of about $400 per ton.
All these factors are reflected in the different bars of the chart. The increase in coal and gas prices, as well as U.S. inflation, triggered increases in PPA prices, causing an estimated $100 million positive effect on revenues. About half of the price increase came from the free client segment, whose prices are tied mainly to inflation, with about one-third of these, of this segment linked to coal prices. The other half came from the regulated segment, with tariffs tied to a mix of U.S. inflation, coal, and gas prices. The indexation is normally reflected with a certain lag in the revenue line, particularly in the case of regulated contracts, which takes place semiannually in April and October.
We note that the exponential increase in fuel prices has been triggering increases of more than 10% in the calculated tariff, which is a reason to lead to additional tariff adjustments expected this time for August and December. We should expect revenues to continue increasing until they fully reflect the current levels of fuel prices. The next bar, showing an increase in sales to the spot market, is explained by generation surplus from Eólica Monte Redondo as one of its PPAs with CTE for 175 gigawatt hour came due at the end of 2021. The Los Loros PV plant and CTH plant sold power to the spot market in the first two months, and starting March, they both began to sell all the energy they produced to ECL pursuant to supply agreements.
The increase in spot sales contributed $38 million to EBITDA due to higher volumes and prices. There was a net increase in physical sales coming from free clients, which offset a decline in sales to distribution companies due to the lower pro rata in the pool of regulated contracts and the maturity of the Eólica Monte Redondo's PPA with CTE. Our gas margin increased by $29 million, which was a turnaround from the loss reported last year as a result of a force majeure event declared in 2021 by our main LNG supplier, TotalEnergies, which led to the cancellation of one shipment. This year, we reported a $17 million settlement paid by TotalEnergies. We can see $140 million
Perhaps you've muted yourself.
Well, if not, let's continue. Well, we have
The next
Are you back?
Yes, sir. No, the next question will come from Martin Arancet with. Are you back?
Sorry, yes. Did it cut, the communication? I'm sorry about that.
The floor is yours.
Okay. I don't know where it got cut, but anyway, I'm talking about the $140 million negative impact from fuel costs explained by higher prices as our thermal generation decreased 33%. In fact, our LNG generation fell by 40% due to the maintenance of our combined cycle units and the Freeport force majeure, affecting generation in the last weeks of June. Coal generation dropped 30%, basically due to the IEM overhaul. This was partly offset by renewable generation, which more than tripled due to the commencement of operations of the Calama wind farm and the Tamaya solar plant. Now, in terms of energy purchases, we reported an increase in volume.
86% of the volume increase is explained by contracted purchases from other generation companies, which increased 4 times to 990 gigawatt-hours in the H1 of the year. The remaining 14% of the increase is due to spot purchases compensating for the decrease in coal and gas generation. The increase in energy purchase volume represented a CLP 103 million increase in operating costs. Now, there was a CLP 78 million negative effect from an increase in spot prices, in turn explained by the drought and high fuel costs. Finally, we had no insurance compensations this year, while we did report a CLP 5 million payment in 2021. Operating and maintenance costs also reported an increase, which caused a CLP 14 million contraction in EBITDA.
Now let's move to slide 18 for an overview of the evolution of net results, which went from a $30 million net profit, excuse me, in the H1 of last year, to a $40 million loss this year. Last year, we reported one-off financial expenses from the discount on the sale of accounts receivable from distribution companies related to the Tariff Stabilization Law. Netting out this effect, we would have reported a $66 million profit in the H1 of last year. In the H1 of 2022, we reported $94 million after-tax reduction in EBITDA, which added to other smaller effects in terms of FX, financial expenses, and insurance recoveries, resulted in a $37 million net loss before one-offs.
This year, we also reported financial expenses from the sale of receivables related to the Tariff Stabilization Law, but these were much smaller, with an after-tax impact of $3 million, which led us to report a $40 million net loss in the H1 of 2022. Just for you to know, in July, we sold accounts receivable for a nominal amount of $41.3 million, which will represent a financial cost of $11.6 million, affecting our Q3 results. Please turn to page 19 to talk about cash flow and net debt. The main cash outflows included $137 million used in operations, primarily fuel and energy purchases. We invested $106 million in capital expenditures, mainly in PV plants, wind farms, and substations.
We paid $35 million in taxes, mostly CO2 taxes, and almost $23 million in interest expenses. IFRS 16 leases decreased by $10 million, mainly due to non-cash FX adjustments as the liability is denominated in Chilean pesos, which depreciated through the H1 of the year. Finally, we received almost $10 million in proceeds from the true sale of long-term receivables from distribution companies to Chile Electricity PEC. In July, we received almost $30 million cash proceeds from the sale of these receivables. Since we financed part of the cash uses with new debt and cash, we had available at the end of 2021, our net debt increased to $1.3 billion at the end of June.
On page 20, we see the sharp increase in net debt to EBITDA, mostly due to the decrease in last twelve months' EBITDA, which reached only CLP 187 million, compared to CLP 440 million reported in the same period one year before. Also, as we just discussed, our net debt increased by CLP 285 million from the end of last year, including primarily CLP 230 million in one-year loans and a reduction in cash balances. On page 21, we note the lack of dividend payments in 2022 and the 35% drop in ECL's share price, which is relatively aligned with the industry affected by all the circumstances we have already explained. Now I will leave you with Eduardo for an update of the transformation plan.
Thank you, Bernardita. Let's focus on two topics. Let's go fast in this section. Projects under construction on page 32. Capricorn PV is already producing and is expected to reach the full COD by the end of October. This project required a total investment of $97 million. While Coya Solar PV has also started to produce, and the full COD is expected by the end of the Q4 of this year. This project required a total investment of $149 million. Between these two projects, ECL will add 268 MW capacity to our new portfolio.
I was explaining before, these two projects will contribute to our portfolio in 2023 at their full production capacity. To finalize the presentation and, as suggested by some of you, on page 36, we have added a specific section for our transmission business and the related development activities. Page 37 describes ECL transmission assets. There are three main types of assets. First, dedicated 1,800 kilometers of transmission lines that are used to connect ECL's generation assets to our clients or to the grid. This means these transmission assets are remunerated by the generation business. Second, regulated transmission assets between national and zonal transmission lines. ECL has 618 kilometers that are remunerated by the system. Third, 24 substations.
Five of them are part of ECL generation business, and 19 substations are regulated and remunerated by the system. In summary, if we focus on the regulated business, ECL has annual regulated revenues of approximately $23 million. Rule of thumb, 80 to 85% of these revenues contribute to ECL's EBITDA. These figures are 100% consolidated and do not consider the contribution from TEN Transmission Line. In addition, as we can see on page 38, ECL is developing other transmission projects that are detailed on pages 40 and 41. You can see there all the information per project with a total investment of $150 million that are expected to contribute annually $10 million, starting with $6 million in 2023 to reach $10 million by 2026.
This means ECL will have approx $33 million coming from regulated transmission revenues, and if we follow the 80 to 85% rule of thumb, an approx EBITDA of $26 to 28 million. On top of that, ECL has a 50% participation in TEN Transmission Line, which is described on page 42. TEN has an estimated average annual EBITDA during the next four years of approx $60 to 65 million, while the company has a total financial debt of around $600 million. How TEN contributes to ECL results? Well, since TEN is not consolidated and ECL owns 50% of TEN, 50% of its net result is accounted as EBITDA in ECL, and that is approx $8 to 9 million.
I hope this information is useful to have a clear view on ECL transmission business, which is strategic business for our operations in Chile and also at ENGIE level. To end the presentation, we are summarizing the main key takeaways on page 43. Given the extraordinary international context and market evolution, as I explained this afternoon, ECL faced the worst quarter in the company's recent history. The market will continue to be under stress, but there are some elements that are moving in the positive direction. Better hydrology, gas from Argentina, improved thermal availability, entry of new renewables, and also a new tariff stabilization mechanism to provide some certainty on regulated revenues. All of this together should be positive.
In this context, and as we also mentioned before, will be key to accelerate the development and construction of renewables, and also to keep a high availability of ECL thermal assets, while at the same time secure our funding needs for these projects. Thank you. Of course, we are ready for any questions you may have for us, so we can continue with the Q&A.
Our next question will come from Martin Arancet with Balanz Capital. Please go ahead.
Yes. Hi. Well, first of all, thank you for the materials as always. I have four questions. I would like to run them one by one, if that's okay. First, as you mentioned, we should see an increase in regulated PPAs during the H2 of the year. My question is, are there industrial contracts that should also show higher prices due to the rise in fuel cost?
Okay. First question. We have seen an increase in regulated demand between May and June. Part of it is seasonal and other part may come from economic activity. These PPAs, as I was explaining before, have an indexation to LNG and coal prices, plus US CPI. On the unregulated side, the only PPA that remains indexed to coal, and this is for the energy price, is the PPA with Colbún linked to CTA coal power plant. Well, and also some smaller PPAs with other mining companies, but not as relevant as that one. We are talking about 1.2 terawatt hours per year, which are still linked to coal and related to unregulated PPAs.
On top of that, you have the regulated PPAs, which also have an indexation linked to coal. All the other unregulated PPAs since 2021 or starting 2021 are now indexed to US CPI, as these PPAs were decarbonized back in 2017, 2018.
Okay, great. Thank you. My second question, are you considering tapping the debt market during the H2 of the year?
The debt market, you mean, through an issuance in international market bonds. No. No. The answer right now is no. Right now, we are focused on other type of instruments. We recently closed, like, in the past eight days, a $250 million five-year bullet loan with Scotiabank for $250 million. This will be key to support our CapEx plan during this year. In parallel, we are working with other multilaterals and banks for the future. Right now, we don't have any plans, or we are not planning to go to the market within the next months.
As you know, this is something that could change from time to time based on market conditions.
Okay. Right. Thanks. My third question, as you have shown, coal dispatch seem low, especially under the current market conditions. Maybe if you could share with us, your thoughts on the reasons behind it.
Sorry, I lost the first part.
Yeah. As you've shown, indeed during the call, coal dispatch seems low, especially under current market conditions. Maybe if you could give us some color on the reasons behind it.
Okay. From our side and also as a whole, I mean, from a market point of view. From our side, the lower dispatch coming from coal is explained because IEM coal power plant was limited to only 250 MW during the first five months of the year. This is explained by a technical issue. Now, during June, the plant went through the planned maintenance, and now it's working again at full capacity, so it has its 350 MW. On the other hand, we have seen in this market several failures in 2021, 2022, which are probably explained by the way the market today is working.
Having several thermal power plants cycling on a daily basis, several coal power plants not running at a full base load could bring some technical problems, and that's probably what we are facing in this year and what we faced last year, together with the postponement of some maintenance due to the COVID crisis that we faced in 2020. Several maintenances were postponed, and this also brought some issues probably to some units. In this line, and I know that the other generation companies are probably doing the same, we are all right now working on increasing the availability of our coal power plants, because running diesel makes no sense. Of course, nobody makes money when you run diesel for the system.
Very clear. Thanks. My last question is, what IRRs are you targeting on your transmission and substation projects in level or nominal terms?
Usually, the returns are close to high one-digit, low two-digit to the equity.
Great. Thanks.
Again, if you have a question, please press star then one. Our next question will come from Andrew McCarthy with Credicorp Capital. Please go ahead.
Good afternoon, everyone. Many thanks for the call and the presentation, Eduardo and the team. Had three questions. The first one, just following up on the transmission business. Many thanks for including that increased information disclosure. I think that's really helpful. Just a follow-up on page 37, you know, you set out there the regulated business of around $23 million. Just wondering how one sort of reconciles that number with the number you show in the notes to financial statements where, you know, you talk about there being a kind of approximately $95 million. Just trying to understand how those two numbers relate. That would, that'd be the first question.
Bernardita, you want to take that one? I think I don't have in front of me the financials.
Yeah. I don't have them either, but I suspect, Andrew, that in our financial statements, we have all of the transmission. That would include what they call the cargo único, and it also includes kind of costs and revenues that are passed through. For example, sub-transmission type of services that you have to provide to the distribution companies. You have revenues from that, and you have the cost for that. Okay. It's not directly related. I mean, the number in the financials includes many other things.
Okay.
We can check some details afterwards if you want.
Okay. No, that's clear. I just wanted to double-check because you're saying. So, you're saying that the EBITDA of this business is effectively, you know, if you were to assume 85% margin on that sort of $23 million historic, that's kind of the EBITDA of business of this business. What about the EBITDA of the dedicated line business? Is it possible to sort of have a sense for what that would be? Or is that not really available?
Yes. I think we do have that information. On the other hand, since those lines are fully dedicated to the generation business, of course, we can try to show in the future the potential EBITDA. Then you will need to analyze in detail to which PPAs in which area, because some of these lines probably are dedicated and will not last for the next 50 years, 30 or 40 years. They will be limited to the life of the PPA, for example, or to the life of the operation that the PPA is supplying.
That's why probably this time we didn't include all this information because then we'll need to go in detail, because otherwise, if we start using that information to calculate the multiple, the equivalent multiple, it would not be accurate. That's why we concentrated on the regulated business, which is straightforward. But it's something we can. We will explore for the next time how we can try to show this information.
Thanks very much. That's very clear. Thanks. Thanks, Eduardo and Bernardita. My second question was, when you were talking there about the revised guidance for this year, you mentioned sort of seeing a with embedded in that, if I understood correctly, for the hydrology, you've kind of got this P, the P90 assumption, which I understand to mean probability of exceeds at 90% this year. Trying to. Just wondering, given the rainfall we've seen obviously in the last few months, I mean, how should we think about that in terms of maybe systemically? Maybe the way to think about it is systemically, how much hydro generation are you kind of expecting in the H2?
Just trying to gauge what you've got baked into that number, whether, you know, and then to try and see what upside or downside might be in that.
Good question. I think the answer is around 3 to 4 terawatt hours that are coming on top of the previous scenario related to the P90. For the whole, let's say, period, so 2022 and 2023. You can say 2 during 2022 and one and a half to during 2023.
Yeah. Okay. That's clear. Thanks. Then just the last one. It's just another question on the presentation. I'm just wondering if you could, and apologies if you explained this already in the presentation, but just to understand the difference in the backup PPAs between the 24/7 and the PV profile contracts, just to have that clear.
Sure. No, the difference is like, let's use one example. One example that was also public information back in 2019. For example, we signed. When we talk about the PV profile, the probability or the certainty on the production is relatively stable, known. It's not like a wind farm which has more variability. In the case of a PV solar power plant, you know the profile. Let's use, for example, the PPA that we signed with Atlas. 500 gigawatt hours per year, starting last year. Then what we are having is their production during the day, so it's not a 24/7, in that case, at a certain price, at a PV price, of course. That's the difference with the 24/7.
In the case of 24/7, it's a flat production or flat consumption on a certain note at a certain price. That's the difference between both. We try to split both type of contracts because, of course, both are very different in terms of risk and exposure also in the current context in which the day could have very low prices and at night we can have very expensive prices.
Okay. Understood. Then you blended out. Your blended average is a mix of those two types, the lower priced PV solar and the higher priced 24/7 contracts.
You have an average price, of course.
Yeah. Yeah.
The volumes we're seeing there are volumes, one during the day, and the other one is 24/7.
Yes. Very clear. Thanks so much, Eduardo.
You're welcome.
This concludes the question-and-answer section. At this time, I would like to turn the floor back to ENGIE Energía Chile for any closing remarks. Please go ahead.
I think that's all from our side and thank you for being with us today. Hopefully, we expect to come back in some months with better news than the ones we shared today. Thank you. Thank you very much for being with us today.
Okay. Thank you.
Thank you. This concludes today's presentation. You may now disconnect your line at this time and have a great day.