ENGIE Energia Chile SA
SGO:ECL
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Good afternoon, everyone, and welcome to Engie Energia Chile's Second Quarter 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 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 analysis, not for the press. We ask all journalists to contact Engie Energia Chile's PR department for details.
I would now like to turn the call over to Mr. Eduardo Milligan. Please go ahead, sir.
Thank you. Good afternoon to everyone. Today, I'm here with Bernardita Infante, Head of Corporate Finance; and Marcela Munoz, Investor Relations Officer. And we will discuss ECL results for the first half of this year. We can go directly to Page #3, in which we are presenting the main topics we want to address this afternoon.
So first, ECL results have been severely impacted during the first half of 2022 by extraordinary events that impacted spot prices and consequently increased the supply cost from average $66 per megawatt hour in the first half of 2021 to around $118 megawatt hour during the first half 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 will be commissioning 268 megawatts of additional solar PV power plants located in the North during the next months. And the development team expects to launch the construction of 1 additional wind project that will provide an additional physical hedge to ECL portfolio of PPAs. Well, 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 tenor of existing contracts that are providing a hedging to spot market volatility. The volume of ECL sales in 2023 covered in these contracts, we reached approx 2.8 terawatt hour 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.
And fourth, the extraordinary market context, together with the regulated tariff stabilization mechanism and related first half 2022 results [ how the ] pressure to ECL net debt to EBITDA ratio. So the 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.
So 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 and 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 megawatt hour with operating revenues increasing 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 unavailability of thermal plants in the system.
Net results of the second quarter reached negative $44 million, and we have an accumulated loss of $40 million during the first half 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. And we will discuss in some minutes our view for the second half of this year.
On Page 5, we can see the evolution on unregulated and regulated PPAs. As we mentioned on the slides, 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, the regulated demand was relatively flat. In this context, there are no incentive for clients' migration while past initiatives further migration or portability of more challenges to become feasible in the medium term. In fact, during the last 2 months, we have seen an important increase in regulated demand in the market.
The next 5 pages will describe the main variables that are materially impacting spot prices and the overall systemic costs in Chile. We need to recall that approx 50% of 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 in how hydrology behaves from 1 year to the other. As we all know, we have faced several dry years during the recent years.
On Page 6, we can see the spot price evolution in the 3 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 first half of 2022 is 50% higher than the already high average price of 2021 and more than 3x the average price of 2017 to 2010. Engie Energia Chile 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 terawatts hour and below 1 terawatt in the North. So this is important because in this context, 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 first half of this year also due to lack of hydro production. So the spot prices is permanently driven by diesel power plants. And as I mentioned before, you see our 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 10 terawatts hour and 1 in the north.
In other regions, we are also facing diesel prices at night. So in this context and until the congestion is solved in the South, each megawatt hour is 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 7, we present the hydroelectric production during the last 4 years in Chile. As we all know, 2019 to 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 first half of 2022 through an emergency degree, a 372 gigawatt hour hydro reserve to face potential energy shortages. This is an insurance for the system.
But now the rainfall and the [ small generation ] during July, allowed the market coordinator to recently reduce the reserve limit to 205 gigawatts hour. So 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 second half in a couple of minutes when we discuss our overall view for the rest of the year.
Now on Page 8. We explained what is happening in coal prices. As you know, close to 30%, 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. So 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. So 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 we continue to be key during the next year. As I mentioned before, 30%, 35% of electricity will continue to be produced with the coal power plants. Since the crisis and war started in Europe end of February, coal prices have been extremely volatile, reaching in some days, for example, $500 per ton. Today, it stabilized at around $300, $350. But 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 second half of this year is even 15%, 20% higher than the average price of the first half. Meantime, the average production cost of coal power plants in Chile would remain above $450 per megawatt hour. And this is why today, with these production costs and with still turn dependency on coal production, the spot price is at current levels.
Next, Page 9, will present 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 first half of 2022. The difference of 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 2 years.
The last month of June, for example, was critical and had a material impact on ECL results. In June, for example, [ hydro ] power plants has a programmed maintenance. And at the same time, there was a fire in Freeport terminal, which didn't allow our LNG supplier to load the 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, we talk about gas, is that Argentina is exporting as 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 systems electricity production during this period.
The same volume of 2021 or even an additional volume would be available again since October. The graph below on this page shows the LNG fuel contracts and volumes from India and other [ regions ]. So these contracts are indexed to Henry Hub and hence not impacted in the same proportion than LNG prices in Europe. And as I mentioned before, one of our LNG cargo faced in June 8, only 2 days before the cargo was planned to be loaded at the current force majeure at Freeport terminal due to a fire, which led to cancellation of 3.3 TBtu LNG shipment. So we lost this cargo, which was planned to support our portfolio during June and July.
And as a consequence, ECL bought more LNG in the spot market at very high spot prices, the impact of this cargo in initial EBITDA could be estimated in around $40 million, $45 million. And in this context, we are discussing remedial actions with our LNG supplier, which are required as part of the contract.
Next, Page 11, gives some 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 megawatt hour.
Then if we move to Page 12, we show the volume of energy ECL contracted during the last 4 years with other generation companies to manage the supply risk. In 2022, 2023, ECL have this hedge for almost 25% of its contracted demand. We know this volume is helping, but not enough on the volatility of results we are facing, certainly demonstrates the importance of being fully balanced, and that's why 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 generation companies. On average, between 2022 and 2025, we have secured backup PPAs for average 2.5 terawatt hour 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 in the transformation phase.
Let's move to Page 13, where we can see the demand supply balance for the first half 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. You can see that a new area in yellow starts to increase in the left part of this graph, so we will see this every quarter. I already mentioned this during the previous quarters.
And then our thermal power plants come from the dispatch ranking right after these renewals. The variable cost 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 a decrease in the average monomic 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 indexation formula of the regulated PPAs, and this lag is of approx 6 to 8 months. So 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. But in this context, this 6 to 8 months lag is relevant.
Let's talk about our view for the second half of the year and discuss some elements that are also relevant for 2023. So please turn to Page 14, and we'll go through each of these elements. So first, hydrologic conditions. The first half of 2022 was still impacted by 2021 drought with P98 exceedance probability and in addition, as I was explaining before, the market coordinator implemented a hydro reserve until May.
Now for the second half of the -- not -- in fact, for the second half of the year, the hydro reserve will be reduced to only 205 gigawatts hour, thanks to rainfall and snow accumulation. So what means in terms of hydrology what we experienced in July, it means that we may be closer to P90 for the new hydrology year which will continue until 2023. So the snow's melting, should start during August, September. But of course, the main doubt is until when in 2023, this improved hydrology will last. But overall, this is positive for the rest of the year.
Second, coal prices continued to increase from average $200 to $250 during the first half and potentially to $300, $350 per ton expected during the second half, but still with a lot of volatility. Prices, coal prices are still changing very fast and forwards are also changing very fast in this context. But 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. But the good news is that following the new regulation and the higher prices in Argentina to promote investments in July, Argentina is again exporting relevant volumes to Chile to the center region, approx 3, 3.5 million cubic feet per day is what today Argentina is exporting to Chile, which is a bit more than half their 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.
Four, number four, LNG supply, I also mentioned before, we are facing the force majeure of 1 cargo between June and July. This means at least $40 million, $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 first half, IEM was limited to only 250 megawatts, that's in around 100 megawatts. And then it went through maintenance during June. IEM is back since July at full capacity, and we expect to continue improving availability during the second half of the year for the rest of our term for power plants. Number six, PPA indexation, as I was explaining, the regulated PPAs have an important lag in its indexation formula about 6, 8 months. This was not material when fuel prices were relatively stable. But given the current increase in coal and LNG prices, it has become material because as supply costs is recognized today, with the indexation firmly will not only reflect the higher crude prices in some months in the future. This means part of the loss we are facing in 2022 will be recovered during the second half of this year and also during 2023.
And number seven, new renewables was coming online during the second half of 2022, will provide some relief in 2022. And also during 2023, when we expect to have them at 100% of their production capacity. And in addition, in 2023, we will see the ramp-up of additional volume coming from supply agreements signed with other generation companies. So these 7 main elements to explain our current view for the second half 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 megawatt hour. And in July, is approximate $150 per megawatt hour, which is still very high and almost 2x the average of the last 5 years within the same period of time.
In 2023, which would 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 continued 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 some additional CapEx related to new renewable projects. The block grid considers all CapEx for 2022 in renewables, around $90 million orders have already materialized in the first half and the remaining committed amount related to projects under construction is close to 40, while the difference of around 60 is related to additional projects we plan to launch that are not yet committed.
On the other hand, total net debt to last 12 months EBITDA ratio increased from 3.9 to 7x, 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 6x.
During the next years, we should return to the baseline we define to keep our leverage ratios not exceeding 3 to 3.5x on a structural and regular basis. And 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, this -- 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 will face -- we may face temporary increases in the leverage ratio within the construction phase or during complex years like 2022, but this should be temporary considering renewables, we 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, that renewable [ ECL ] will replace the energy purchases in the spot market to supply the PPAs. So this means approx every 1 terawatt hour per year of renewables production should create additional $40 million, $50 million EBITDA under normal market circumstances.
Now Bernardita will cover the following section to explain in detail the various analysis on ECL financial performance.
[Operator Instructions] The first question will come from Alejandra Andrade with JPMorgan.
I wanted to see if you guys could give an update on the stabilization fund, specifically how a new fund would being -- where was the status of the new fund being created? And how would your accumulation of receivables change or not going forward?
Sorry, probably, there was a problem with the system, but let me continue with the questions. We already started. Well, yes, there was a first stabilization mechanism. Today, we have already sold 5 degrees and the remaining degree, #6 should be monetized between -- ordering the next month. We expect to do this by the end of this year, hopefully. And we are talking about $40 million -- around $40 million.
And then it comes to the second stabilization mechanism, which went through a fast track and it was approved by the congress over the last 3, 4 weeks, the new law was already published and 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.
And in-between, there will be, again, an accumulation of long-term receivables, which in this new scheme will be monetized again. And this time, the receivables will include the financial costs that generation companies in the past were assuming. So this means that for every dollar, then the generation company will accrue as a long-term receivable. The financial cost will be included when these receivables will be monetized, and how these receivables will be monetized this time through a monthly mechanism in which generation companies will receive these credit rights. And afterwards, the 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, and 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 million, I was mentioning before that we still need to monetize coming from the first mechanism could be around $125 million, $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. And afterwards, the idea is to be able to monetize these receivables on a monthly basis.
Hello. This is Bernardita. I just got a problem when a lot of -- told me I was going to speak. So I will continue with the presentation, if you don't mind. So 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.
So EBITDA reached $60 million in the first quarter which is a 68% drop compared to the first half of last year. And 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. So these 2 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.
So 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 and the Freeport force majeure took place in early June, affecting gas supply and coal prices [ and the site ] remained at high levels of about $400 per ton.
So 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 $130 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 1/3 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. So 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. So 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 CTE for 175 gigawatt hour came due at the end of 2021. The Los Loros PV plant and CPH plant sold power to the spot market in the first 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 3 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, Total, which led to the cancellation of 1 shipment. This year, we reported a $17 million settlement paid by Total. We can see $140 million mainly...
[Technical Difficulty]
Perhaps you've muted yourself.
Well, if not, let's continue. We have -- are you back?
Yes, sir. The next question will come from [ Martin Irransent ] with -- are you back?
Sorry, sorry, yes. Did it cut, the communication, I'm sorry about that. 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%. So 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 renewables 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 4x to 990 gigawatt hour in the first half 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 $103 million increase in operating costs.
Now there was a $78 million negative effect from an increase in spot prices in turn explained by the drought and higher fuel costs. Finally, we had no insurance compensations this year, while we did report a $5 million payment in 2021. Operating and maintenance costs also reported an increase, which cost $14 million contraction in EBIT.
Now let's move to Slide 18 for an overview of the evolution of net results which went from $30 million net profit in the first half 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 price stabilization law. Netting out this effect, we would have reported a $66 million profit in the first half of last year.
In the first half of 2022, we reported $94 million after-tax reduction in EBITDA, which had 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 price 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 first half 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 third quarter results.
Please turn to Page 19 to talk about cash flow and net debt. So the main cash outflows including -- 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 noncash FX adjustments as the liability is denominated in Chilean pesos, which depreciated through the first half of the year. So 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 12 months EBITDA, which reached only $187 million compared to $440 million reported in the same period 1 year before. So also, as we just discussed, our net debt increased by $285 million from the end of last year, including primarily $230 million in 1-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.
So now I will leave you with Eduardo for an update of the transformation plan.
Thank you, Bernardita. So let's focus on 2 topics, let's go fast in this section. Projects under construction on Page 32, Capricornio PV is already producing and is expected to reach the full COD by the end of October. And this project recorded 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 fourth quarter of this year. And this project required total investment of $149 million. Between these 2 projects, ECL will add 268 megawatts capacity to our renewable portfolio. And as I was explaining before, these 2 projects will contribute to total 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 EECL for transmission assets. There are 3 main types of assets: first dedicated 1,800 kilometers of transmission lines that are used to connect ECL generation assets to our clients or to the grid. This means the transmission assets are accommodated by the generation business.
Second, we related to transition assets between national and zonal transmission lines. ECL has 618 kilometers that are remunerated by the system. And third, 24 substations, 5 of them are part of the ECL duration business and 19 substations are related and remunerated by the system.
In summary, and we will focus on the regulated business, ECL has annual regulated revenues of approx $22 million. Rule of thumb, 85% of these revenues contributed to ECL's EBITDA. These figures are 100% consolidated and do not consider the contribution from 10 transmission lines.
In addition, as you can see on Page 38, ECL is developing other transmission projects that are detailed on Pages 40 and 41. You can see there holding the information for projects 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. So this means ECL will have approximately $33 million coming from regulated transmission revenues, and it will follow the 80%, 85% rule of thumb and approx EBITDA of $26 million 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 and EBITDA during the next 4 years of approx $60 million, $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 is 50% of TEN, 50% of its net result is accounted as EBITDA in this year, and that is approx $8 million to $9 million. I hope this information is useful to have a clear view on the ECL transmission business, which is a strategic business for our operations in Chile and also at Engie level.
So 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 terminal availability, entry of new renewables, and also a new tariff stabilization mechanism to provide some certainty of 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 mix for these projects.
Thank you. And of course, we are ready for any questions you may have for us. So we can continue the Q&A.
Our next question will come from Martin [ Erenset ] with Valens Capital.
Yes. Well, first of all, thank you for the materials as always. I have 4 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 second half of the year. My question is, are there industrial contracts that should also show higher prices due to rising fuel cost?
Okay. First question. We have seen an increase in regulated demand between May and June. Part of it is seasonal. And other parts will come from economic activity. These PPAs, as I was explained before, have an indexation to LNG and coal prices plus U.S. CPI. Then on the unregulated side, the only PPA that remains indexed to coal, and this is for the energy price, is the PPA with linked to CTA coal power plants. All the other -- well, and also some smaller PPAs with other mining companies, but not as relevant as that one. So we are talking about 1.2 terawatt hour per year, which are still linked to coal and related to unrelated PPAs. On top of that, you have the regulated PPA, which also have an indexation linked to coal. All the other unregulated PPAs since 2021 or start in 2021 are now indexed to U.S. CPI as these PPAs were decarbonized back in 2017, 2018.
Great. My second question, are you considering tapping the debt market during the second half of the year?
The debt markets, you mean through an issuance in the international market bonds? No. No. The answer right now is no. Right now, we are focused on other type of instruments, we recently closed -- recently, like in the past 8 days, we closed $250 million 5-year bullet loan with Scotiabank for $250 million. And this will be key to support our CapEx plan during this year. And in part, we are working with other multilaterals and banks for the future. But right now, we don't have any plans but 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. Great. Then my third question. As you have shown, coal dispatch seemed 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.
Yes. As you've shown in -- during the call, coal dispatch seems low, especially under current macro conditions. Maybe if you could give us some color on the reasons behind it.
Okay. 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 megawatts during the first 5 months of the year. This is explained by a failure, it's a technical issue.
Now during June, the plant went through the programmed maintenance. And now it's working again with full capacity. So it has its 350 megawatts. On the other hand, we have seen in this market, several failures into 2021, 2022, which are probably explained by the way the market today is working, having several thermal power plants cycling on a day basis, several coal power plants not running at a full baseload 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. So several maintenances were postponed. And this also brought some issues probably to some units. But 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. And of course, nobody makes money when you run diesel for the system.
Very clear. And my last question -- sorry, my last question is what IRRs are you targeting on your transmission and substation projects in lever or nominal terms?
Initially, the returns are close to high 1 digit, low 2 digits to the equity.
[Operator Instructions] Our next question will come from Andrew McCarthy with Credicorp Capital.
Many thanks for the call and the presentation, Eduardo and the team. I have 3 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 set out there [ the coma ] for the regulated business of around $23 million. Just wondering how 1 sort of reconciles that number with the number you show in the notes, the financial statements where you talk about there being a kind of [Foreign Language] the approximately $95 million. Just trying to understand how those 2 numbers relate? That would be the first question.
Bernardita, you want to take that one? Or? But I think I don't have in front of me the financials.
Yes. I don't have them either, but I suspect, Andrew, that in our financial statements, we have all of the transmission. So that would include what they call the Cargo Unico and it also includes kind of costs and revenues that are passed through. For example, subtransmission type of services that you have to provide to the distribution companies. So you have revenues from that and you have the cost for that, okay? So it's not directly related. I mean, the number in the financials includes many other things. We can check some details afterwards, if you want.
Okay. No, that's good. I just wanted to double check because you're saying -- so you're saying that the EBITDA of this business is effectively, 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, yes. I think we do have that information. But on the other hand, since this -- since those lines are fully dedicated to the generation business -- of course, we can try to show in the future the potential EBITDA, but 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, will be limited to the life of the PPA, for example, or to be live the operation that the PPA is supplying. So that's why probably this time, we didn't include all this information because then we will need to go in detail. Because otherwise, if we start using that information to calculate or the multiple, the equivalent multiple would not be accurate. So 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.
That's very clear. And my second question was when you're talking there about the revised guidance for this year, you mentioned sort of seeing -- embedded in that, if I understood correctly, for the hydrology, you've kind of got this P90 assumption, which I understand mean probability of exceedance at 90% this year. Just trying to -- just wondering, given the rainfall we've seen, obviously, in the last few months, what -- I mean how should we think about that in terms of maybe systemically, maybe the way to think about it systemically, how much hydro generation are you kind of expecting in the second half? Just trying to gauge what you've got baked into that number, whether -- to see what upside or downside might be in that.
Good question. I think the answer is around 3 to 4 terawatts hour that are coming on top of the previous scenario related to the P90. But for the whole, let's say, period, so 2022 and 2023, we can say 2 during 2022 and 1.5 during 2023.
Yes. Okay. Okay. That's clear. And then just the last one, there'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 1 example that was also public information back in 2018. 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 wind farm, which has more variability. In the case of a PV solar power plant, you know the profile. [ Solar ], for example, the PPA that we signed with Atlas, 500 gigawatts per year starting last year. And then what we are having is the production during the day. So it's not a 24/7 in that case at a certain price, at a PV price, of course.
And 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 node at a certain price. That's the difference between both. So 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. And then you blend -- so your blended average is a mix of those 2 types, the lower-priced PV solar and the higher-priced 24/7 contracts?
Then you have an average price, of course. But the volumes we are seeing there are volumes wandering during the day and the other 1 is 24/7.
This concludes the question-and-answer section. At this time, I would like to turn the floor back to Engie Energia Chile for any closing remarks. Please go ahead.
I think that's all from our side, and thank you for being with us today. And hopefully, we expect to come back in some months with better news than the words we shared today. Thank you. Thank you very much for being with us.
Thank you.
Thank you. This concludes today's presentation. You may now disconnect your line at this time, and have a great day.