Good afternoon, everyone and welcome to ENGIE Energía Chile 's first quarter 2023 results conference call. If you need a copy of the press release issued on April 26th, it is available on the company's website at www.engie-energia.cl. Before we begin, I would like to remind you that this call is being recorded, and that information discussed today may include forward-looking statements regarding the company's financial and operating performance. All projections are subject to risks and uncertainties, and actual results may differ materially. Please refer to the detailed note in the company's press release regarding forward-looking statements. We would like to advise participants that this call is dedicated to investors and market analysts, not for the press. We ask all journalists to contact ENGIE Energia Chile's PR department for details. I will now turn the call over to Mr. Eduardo Milligan. Please go ahead, sir.
Thank you. Good afternoon. Today I'm here with Bernardita Infante, Alison Saffery, and Marcela Muñoz. Today we'll present this year results for the first quarter and our guidance for the rest of the year. We can start directly on page four. On the left side of this page, we're highlighting our main challenges. Record high fuel prices materially impacted ENGIE energy margin in 2022. Now on the positive side, these higher fuel prices have positively impacted PPA tariffs in 2023. Fuel prices have significantly declined in the last four months, and we expect this positive trend to materialize in lower average spot prices during the second half of this year.
As we explained also during our last quarterly call, our LNG supplier didn't confirm the delivery four LNG cargoes in 2023, and we had to search alternatives in the LNG spot market to replace these volumes. In this line, we were successful to find LNG, but at higher costs. As we also mentioned, we will seek compensation. Something that is still a problem for the system is increased unavailability of thermal power plants, which is adding additional pressure to spot prices together with the transmission bottlenecks in some regions, which are pushing spot prices and in some specific nodes like Puerto Montt in the south. Last, but certainly not least we continue the accumulating long-term account receivables arising from the regulated Tariff Stabilization Law.
As of March of this year, we have accumulated a significant amount of, approx. $440 million that will start to be collected through a monetization structure that we are currently completing. The accumulation of these receivables in the investment context of ECL explain why ECL, working capital and short-term debt needs increased in the last 12 months. On the right side of this page, we are highlighting some elements that are key to understand the trajectory for 2023. First, as we mentioned during previous quarters, there is an indexation lag in our regulated PPAs of about six to eight months. The higher fuel prices in 2022 materialize into higher PPA prices in 2023.
This will bring a positive impact on the revenue side during at least half of the year. While on the average supply cost side, we have some positive elements that will allow ECL to turn around the financial results. ECL will have additional renewable generation in 2023, and we'll have additional hedges or what we call backup PPAs for additional 1.2 TWh, 1.4 TWh. We recently added an additional contract of 200 GWh for the April to December period of this year. This is why now we have 1.3 TWh-1.4 TWh more that are reducing ECL's risk and spot market or exposure to spot market volatility. As I explained before, there is a positive impact coming from lower fuel prices.
We were also able to source additional LNG for the system, which is helping to keep spot prices under control. In relation to the new hydrological year, there are also positive signs that we could expect a better year than 2022, and certainly much better than 2021. Some experts are forecasting a similar year to 2018, but let's be prudent, concentrate on what we can control and see how this evolves during the next months. Between all these elements, our short position would reduce from the 4 TWh we had in 2022 to less than 2 TWh in 2023, which, as I was explaining, will reduce the volatility and risk in case spot prices increase again. Finally, the monetization of the PEC receivables will be key.
As of March 23, I mentioned that the amount ECL didn't collect is close to $440 million. We will sell the last portion of PEC 1 in the coming days. It is already closed. The size of this last tranche is $51 million, and ECL will receive net proceeds for $38 million. This means there is a $13 million implied financial cost in this last sale. This also means that after this sale, we will still have close to $390 million related to the PEC 1 excess and the new mechanism. These amounts are expected to be monetized through the structure we are working together with authorities, banks and other GENCOs, and we expect to start the monetization of these receivables in the upcoming months. Next page, five, shows the evolution on ECL physical sales.
Total sales grew 3% mainly explained by higher sales to regulated customers which is positive for ECL and a potential upside in the future considering that our SIC regulated PPA has an average consumption of less than 75% vis-a-vis the fixed 4.5 kWh constructed volume. We can see an important increase in regulated demand of our PPAs. That is explained by some factors. The first and most obvious is the natural growth in GDP. There are other non-obvious factors that are also driving this increase. One of them is the end of regulated PPAs in 2022. This means our PPAs have then a larger participation of the pipe, and we have also seen some regulated PPAs that were not renewed and the clients returned to the regulated system.
Between these factors, we're seeing a positive evolution in our total load factor. On page six, we can see the spot price evolution over the last seven years and how the Chilean system moved from $41 megawatt hour in 2020 to $127 in 2022 and $141 during the first quarter of 2023. Why ECL results are improving in 2023 with even higher spot prices than in 2022? There are two explanations. The first part is mechanical, and it's explained by the indexation lag, mainly in regulated PPAs, which means that the increase in regulated PPA prices is higher than the increase in spot prices.
The second is that all the actions that we implemented since the energy crisis started are materializing in 2023, including LNG sourcing, additional backup PPAs, the acquisition of a wind farm in Chiloé, a region in which we are exposed to very high spot prices. All in all, our portfolio is better balanced and hedged during 2023. Next page seven , shows the evolution on hydrology, which improved in 2022 compared to 2021, but it was still a dry year. The estimated probability of exceedance for the April 2022, March 2023 hydrological year was 87%, which is far better than the 97%, 98% of the previous year. What will be key for the system is the probability of exceedance of the current hydrological year.
We could conservatively expect between 1 TWh and 2 TWh additional of hydro generation in the coming year, which would be positive for spot prices. As I was explaining before, we could expect a similar year to 2018, 2019, but let's see how this evolves in the upcoming months. On page eight, we can see the unprecedented evolution on coal prices. Coal hit all-time highs in 2022, impacting spot prices in the system. The average price per ton in 2022 reached 314, which can be translated into a production cost of approx $130 megawatt-hour. Now, this trend has reverted in 2023.
As of March, the average coal price decreased to $177 per ton, which is almost half the price of 2022. At $177 per ton, the production cost with coal power plants decreases to the $70-$80 megawatt hour range. We can see that as of today, the average API index is close to $150 per ton CIF. As we mentioned in our previous call, lower coal prices will impact spot prices in the second half of 2023 once the expensive coal that we have in our coal yards at country level, not only for ECL, is consumed and replaced by cheaper coal. Next page nine shows the evolution on coal power plants availability for the overall system.
The message in this page is that the system has less room for forced outages. In the first quarter of 2023, IEM coal power plant had a failure in its transformer and has been out of service since early February. To mitigate IEM unavailability, we first bought additional LNG, then we moved IEM plant maintenance from August to March, and then we implemented a solution to recover the power plant until the new transformer arrives in July. The good news is that the physical solution is ready, and the IEM should be returning to operation in the upcoming hours or days. Let's go to next page 10 and discuss about the natural gas, which, as you know, is together with coal, a key source for the system.
The graph on top shows the evolution of the international LNG prices. We can see the all-time highs in 2022, as we know, because of the Russia-Ukraine conflict. LNG reached around $40 million BTU, which made it possible to buy LNG in the spot market because as you know, with $40 million BTU, the production cost will be close to $300 megawatt hour, and this is probably even higher than producing with the diesel. The graph below shows the LNG source through firm long-term contracts and the natural gas coming from Argentina.
We have seen in the recent years steady volumes imported from Argentina during the summer. We expect between 2 million cu m and 3 million cu m per day to continue flowing between May and September, which will also be positive for the system. On the LNG side, as we explained in our last call, we have two long-term contracts for an aggregated volume of 23 TB BTU per year. One of these contracts was confirmed by our supplier for about 10 TB BTU, while the second contract with a volume of about 13 TB BTU was not confirmed and therefore we were not able to add this LNG volume to the annual delivery program at the regasification terminal. As a consequence, ECL will be exercising its rights under the contract and the applicable law to seek redress from the supplier.
Now, to partially mitigate, this situation, we have secured around 14 TB BTU of replacement LNG in the ordinary course of business, but as expected at higher costs. The purchase of these 14 TB BTU together with the other actions have been key to reduce our short exposure in 2023, which we now expect to be less than 2 TWh . If we move to next page 11, we show an update on the hedges or backup PPAs signed with other GENCOs. This page shows an additional volume of backup PPAs signed for 2023 and 2024. In fact, after March closing, we secured an additional backup contract for 2023, which is not in this graph yet.
The contracted volumes between 2023 and 2026 will be close to 3.5 TWh per year. In summary, we have additional 1.3 TWh, 1.4 TWh of additional 1.3 TWh, 1.4 TWh in 2023 compared to previous year. This is why I was mentioning that the short position is materially decreasing in 2023, and this volume will remain stable, as you can see in the graph, until 2027. Page 12 shows a graph with the energy sources and average supply costs for the portfolio. Our main objective is to rebalance our portfolio as fast as possible to reduce risks and the exposure to spot market volatility. As we can see in the graph, the average supply cost materially increased between 2021 and 2023.
In the first quarter of 2023, we can see how sources are moving in the right direction. We have more renewables, more gas, more hedges or contracted volume with other GENCOs, and as a consequence, the less purchases in the spot market, which are represented by the light blue area in the graph. On next page 13, we present the usual supply demand curve for the overall portfolio. The average monomial price in the first quarter of this year reached $181, compared to $123 in the first quarter of 2022, or $146 for the full 2022.
This means an increase of $58 compared to the same quarter of previous year, or an increase of $35 compared to the average monomial price of last year. This increase, as we mentioned before, is mainly explained by the indexation on PPAs to coal, LNG, and inflation. On the other hand, the average supply cost reached $135 compared to $120 in 2022. The broader relative spread between sales and costs is explained by the indexation lag in our regulated PPAs, together with relative lower supply costs given the actions explained before on LNG, backup PPAs, and higher generation from renewables.
In this first quarter of 2023, we can see how the generation coming from renewables and LNG with our own CCGTs and the tolling agreement with Kelar, plus the additional backup PPAs are replacing spot purchases which only reached 0.5 TWh compared to 1 TWh during the same quarter of previous year. This is in line with the action plan to rebalance our portfolio and to reduce our short position to the spot market. Now, we will continue with Bernardita with the detailed financial results.
Okay. Thank you, Eduardo. Good afternoon to everyone. Let's go to slide 14 to give a closer look at the first quarter results. EBITDA recovered by 49%. Revenues increased mainly due to the increase in energy prices, which began to capture the extremely high fuel prices and inflation observed in the second half of 2022. This is because price indexation in our PPAs reflect the increase in fuel prices with a six to eight month lag. Physical sales were rather flat, with an increase in sales to regulated customers. Costs remained high as the fuel used in generation in the first quarter came from high price stock, stocks build up in 2022, and marginal costs remained affected by a declining hydro generation. Prices increased further, explaining the margin widening.
To meet our sales commitments, we bought 19% of total volumes from the spot market, down from 34% in the first quarter of last year, in line with our strategy of reducing our exposure to spot prices. Backup PPAs represented 28% of total volumes sold, up from 19% in the first quarter of 2022. Renewables accounted for 14%, up from 8% last year. All of this is allowing us to close the gap between our sales commitments and our own generation to reduce our exposure to the spot market on the cost side. Net income almost tripled due to improved operating results, offsetting the increase in financial expenses, which was explained by higher debt levels and the increase in interest rates. On slide 15, we see more details on the EBITDA recovery.
Clearly, average realized prices captured the increase in fuel prices and inflation observed in the previous months, exceeding the effects of the increase in operating costs. Spot sales increased due to higher realized spot prices. The increase in physical sales was explained by higher demand from regulated clients. In terms of our short position, the decrease in energy purchase volumes was a good sign, although these purchases were made at higher prices. With all this, EBITDA reached $102 million in the first quarter, a 49% increase compared with the first quarter of last year. Slide 16 shows the evolution of net results. The improvement is mainly explained by the EBITDA recovery. A favorable evolution of foreign currency results and insurance recoveries also contributed to mitigate the $12 million negative effect of the increase in interest expenses.
Net income before one-offs increased from $7 million to $25 million in the first quarter of 2023. In terms of one-offs, in the first quarter of 2022, we reported a $3 million interest expense from the discount on sales of accounts receivable related to the Price Stabilization Law. In 2023, we reported a $6 million impairment on intangibles. The following slide, page 17, shows a $62 million increase in net debt in the first quarter, with net debt reaching $1.7 billion, excluding $207 million of financial leases related to very long land lease contracts.
The main causes for the net debt increase were the investment in renewables, which reached $113 million, and the $111 million build-up of accounts receivable related to the Price Stabilization Law in the first quarter. This chart shows the significant impact of the Price Stabilization Law in terms of the deterioration in leverage and liquidity ratios and the financial cost of the additional debt we have had to take. In terms of the first program, PEC 1, we will sell the final $51 million of accounts receivable on May 12th, we'll receive $38 million in cash proceeds with a $13 million hit in financial expenses. The positive news is that in the first quarter, the company reported almost $180 million in cash from operations.
In the next slide, number 18, we see the status of our debt as of the end of March. Gross debt, excluding financial leases, reached $1.8 million. Net debt to EBITDA reached 7.7x, which represents a decline compared to the record high 8.7x at year-end 2022. In our last quarterly call, we said that we had three main objectives related to our debt profile. First, to reduce net debt to EBITDA through EBITDA recovery and by maintaining relatively flat net debt despite the financing of our capital expenditures in renewable and transmission projects. Second, to secure funding for the construction of the Lomas de Taltal Wind Farm and the BESS Coya storage projects, whose objectives are to reduce our costs, our exposure to the spot market, and curtailment and intermittent risks associated to PV plants in the future.
Third, to extend the maturity profile of our debt. On the bottom left corner of the slide, we show the maturity schedule of our debt as of the end of April. We have made progress in these three objectives by extending short-term debt maturities, optimizing working capital, working in the future monetization of receivables related to Price Stabilization Laws, working with the IFC in a $400 million long-term financing, and registering bond lines in the local market. We also received a $150 million short-term liquidity facility from under which we drew $75 million in April. This has been a first sign of explicit support from our parent company. We expect to announce positive results of all of these actions in the coming months.
As discussed in our last call, we do not expect our net debt to increase significantly in 2023, thanks to the true sale of certificates related to the Price Stabilization Law, which should bring between $300 million and $400 million in cash resources. This includes the $38 million in cash funds from the last sale of receivables under the PEC 1 law on May 12th. So far, our ratings have been confirmed at BBB. However, Standard & Poor's placed our rating in CreditWatch Negative due to liquidity pressures. According to S&P, the CreditWatch Negative reflects a 50% chance of a downgrade if ENGIE Chile is unable to remediate the current liquidity pressures through a successful refinancing strategy in the next three months.
S&P expects that an improvement of the company's debt maturity profile would come from either monetizing its accounts receivable, a liability management program, or explicit support from its parent. As I just said, we have been working in the three points, and we expect to start monetizing the PEC 2 receivables, as early as June of this year. Now I'll leave you with Eduardo, who will brief us on the recent events, action plans, and key takeaways.
Thank you, Bernardita. The actions mentioned on page 19 are driving the improved results and ECL's operational performance. We will comment them again because I think are key to understand the trajectory for this year. First, we secured 24 TW year of LNG for this year, and we also implemented a tolling agreement with the Kelar CCGT. We rescheduled IEM maintenance and launched three action plans in Barlo to recover the power plant. IEM is ready as of early May, and we are just waiting for the approval from the market coordinator to synchronize, and this should occur as soon as possible.
Third, we secured additional backup PPAs for this year, and we have 3.2 TWh, 3.4 TWh, even 3.5 TWh, average backup PPAs for the next years. Fourth, in 2023, we have additional 0.9 TWh renewable generation coming from the recently commissioned power plants and the recently acquired wind farm in the south. Finally, we are implementing two additional projects, a 342 MW wind farm in the north and 638 MWh storage solution to be added to our existing solar plant, Coya, also in the north. We expect both projects to be ready by the end of 2023 and by the fourth quarter of 2024.
As a result, as we highlight below, the spot exposure is expected to be less than 2 TWh in 2023, leading to cost reductions and cash flow stability, considering also that a portion of this 2 TWh is an exposure that we have during the day in which the market has lower spot prices. In these periods of time, it's also a positive exposure, let's say. Our main goal is to reduce our exposure at non-solar hours. On page 20, we are presenting the evolution of renewables, the committed CapEx for 2023 and 2024.
Once we complete the two projects currently under construction, we will have reached 1.3 GW of renewables since we started this transformation plan. We expect to start building other projects in between to reach our objectives by 2025, 2026. Page 21 presents the detailed CapEx by type of project. On top of the $600 million+ we are investing in renewables, we are also investing $180 million in transmission projects, which contribute with a stable and regulated cash flow. The detailed contribution of those regulated projects can be seen in section 2.2. In page 22, we provided last quarter our guidance for 2023 and 2024. The guidance for 2023 remains in line with our reduced exposure to the spot market.
We just closed April. We expect results to keep the same trend as in the previous three months of this year. The graph shows the expected EBITDA, CapEx, and net debt to EBITDA evolution, considering the updated fuel prices and the actions we explained during this presentation. Variables impacting the EBITDA are mainly related to the improvement in ECL's short position, while the actions on net debt are mainly focused, as Bernardita mentioned, on the monetization of the PEC receivables and the financing of the additional CapEx through a green loan we are structuring together with IFC. In summary, we believe that we are on track for the guidance that we provided some months ago. On page 23, we are just adding additional details on these actions on the operational side.
On the right side, the two transactions we are working on to monetize the PEC receivables, releasing, as we mentioned, between $300 million-$400 million of cash sources in 2023. The $400 million green 10-year loan we're structuring with IFC. Finally, to end our presentation, we are summarizing the main key takeaways of the first quarter on page 24. First, the action plan that was launched in 2022 to accelerate the reduction in our short position to better balance our portfolio is delivering results. We expect the first quarter of 2023 to become a tipping point in this regard, and today we consider that we are well on track to deliver the guidance we gave for this year.
We are also on track on the construction of two additional projects, and we expect to announce soon the construction of additional ones that will help us to reduce our short position in 2025 and 2026. Finally, will be key to accelerate the monetization of the PEC receivables. As we explained, we accrued $440 million by March, probably another $20 million during April. The monetization of these receivables that is also well advanced should improve our liquidity profile. This is, as you know, a specific issue that should be solved within the next months. Well, with this summary, we end our presentation, and we are ready for any comments, suggestions and questions. Thank you very much.
The floor is now open for questions. If you have a question, please press star then one on your touch tone phone at this or any time. If at any point your question is answered, you may remove yourself from the queue by pressing star then two. Questions will be taken in the order they are received. We do ask that when you pose your question that you pick up your handset to provide optimum sound quality. Please hold a moment while we poll for questions. Our first question here will come from Fernando González with BTG Pactual. Please go ahead with your question.
Yeah. Hi, Eduardo and Marcela . I have three questions. The first one is, you know, thinking, you know, for the longer term for the upcoming years, will you try to get rid of your LNG contract with TotalEnergies because of what we've seen, happening?
Sorry, Fernando. We can't hear you very well. Sorry for interrupting, but...
Okay, let me get closer to mic. Okay. Can you hear me better now?
No.
Oh. I don't know. How about now?
Now it's better. Let's see.
Okay. I was wondering about your LNG contract with TotalEnergies. Thinking longer term, would you try to perhaps get rid of this contract and seek an alternative supplier because of what has happened recently, or will you continue with them going forward? My second question is that you mentioned that you plan to balance the portfolio as soon as possible, as fast as possible to reduce the risks. Does this mean that you will not participate in the regulated energy auction that will materialize later this year? Also you wouldn't have much of an interest in bidding in the unregulated PPAs that are also going to be happening this year as well.
My third question is regarding the unannounced CapEx or the new projects that you haven't yet announced. Where will you build those? Will they be in the north, or are you thinking about diversifying into the south and possibly into the center of the country as well? Those are my three questions here.
Thank you. Sure. Let's start with the second one. Yes. The answer is yes. Before we are not balanced, our commercial activity is not today, let's say, our first priority. Our first priority is to first rebalance the portfolio. Once we have a balanced portfolio, then we will be able to participate again in additional auctions, in new auctions, being regulated or unregulated. This means that today we are 100% focused on delivering the projects and reducing our exposure to spot market. Then once we get there, we will have a different company, and we will have a different portfolio that will allow us to recontract the projects that we are currently developing in the future.
This means that in the very short term, we are not looking into those alternatives. That's the second one. The third one was related to the CapEx and the investments in renewables. Today we have different projects that are being developed all across the country. We are not only focused in the north, we are also focused in the center and center south. Why? Because we start first from our contracted demand. This is what we need to solve today. We want to reduce our regional exposure in some PPAs, because as you know, we don't have generation in the center and center south.
Now, in the south of the country, with the wind farm that we acquired, we are more balanced, but still, we need to complete some megawatts in the south to be fully balanced. In the center south, we are not. That's one of our key priorities today. The analysis starts from demand by region, and then we need to see where we should add those projects. That doesn't mean that we will not develop or build any additional projects in the north, because we also have an important volume of contracts in the north. It means that we're also looking to center and center south to be better balanced in those regions. The first one... Okay, okay.
The first one was related to the LNG. Okay, for this year, we basically replaced 100% of contract one, which was not delivered. Now we are currently evaluating what will be the actions that we will take for the future. The LNG market, it's an open market and there are plenty of suppliers. Depending on how our discussion with our current supplier evolves, we will need to see what actions we will take for the future. This is not something that we have already decided, because this process is starting and we need to start thinking in 2024, 2025 and 2026 because the contract that is today not being delivered, lasts until 2026. Give us some time to come back with more, let's say, insights on what will be our strategy. This is something that, still not clear. There are some open points.
Okay, perfect. Thank you. Just a final question, if you may. About the S&P CreditWatch. Is what you've done so far enough to prevent a downgrade, or the timing of the monetization of the accounts receivables, is that gonna be a problem, or are you comfortable enough with it?
At this stage, we can start with improved results in 2023. Last year we had a double dip because our EBITDA results were half of what they should have been. On top of that, we had the accumulation of these receivables from the Tariff Stabilization Law. This year, we are returning to a, let's say, a normal or quasi-normal scenario in terms of results. There are still some upsides, but let's keep our guidance where we explained two months ago. On the financing side, it is true that the monetization of PEC will be key. The IFC loan, green loan will also be key to finance the future CapEx.
We also implemented in the last two months a revolver credit facility with ENGIE. ENGIE supported ECL in this context with a $150 million credit line to buy LNG or to finance or to pay for the CapEx in this period. On top of that, as Bernardita mentioned, we also registered a local bond program in the Chilean market, which is also ready. In the last two months, we also refinanced a part of the short-term debt for 18 months, $100 million. With all these actions, we believe that we should be on track to improve our leverage consistently in the next quarters.
Great. Many thanks, Eduardo.
You're welcome.
Our next question will come from Juan Carlos Peterson with Inversiones Chufquén . Please go ahead with your question.
Good morning, Eduardo. Can you hear me well?
Yes. Hello, Juan Carlos.
Good morning. I have two questions regarding page number 22, please, on the guidance for 2023. If we consider the first quarter result, plus the key variables that are already happening for the current year. My question is: would you say, would you agree that this guidance is probably on the conservative side, given the current scenario that the company is dealing with commercially and from the cost side? Secondly, second question is regarding the climate and El Niño factor.
I know that you cannot, of course, take that for granted, but the signs and the specialists are forecasting that El Niño will happen from a probabilistic point of view. Does this forecast for 2023 and 2024 include El Niño factor, or that's a possible upside in the event that occurs? Thank you.
You're welcome. Good questions. The first question in relation to how conservative is this case. Indeed, it could be conservative because this is the guidance two months ago. Since then, we have seen some positive elements that could make us think that this could be, let's say, achievable. Yes, the answer is yes, it could be conservative. What we are considering in this forecast, it's P95 of probability of exceedance. It's a conservative assumption for the rest of the year. It's a bit far from an El Niño case. Basically, this would bring an additional upside in the rest during the rest of the year.
Okay. Thank you very much.
Our next question is coming from Florencia Torres with MetLife. Please go ahead with your question.
Hey, Eduardo. Can you hear me well?
Yes. Hello, Florencia.
Yes. Hello. Thanks for taking my question. Congratulations on improved results. I have a couple of questions. One regarding realized prices and spot prices. You mentioned that in the second half, given lower fuel prices, you should start to see a decline in the spot prices. What's your target by year-end or your expectation on that point? Also, it should also translate the lower fuel prices in lower realized prices. What's also the impact there? I have a question, if you can provide more details regarding the pro forma, the maturity schedule, the latter liability management pursue after the first quarter results were out. Thank you.
Okay. Let's start with the first one. What we are seeing during the first half of 2023 is the indexation impact during the last six months of 2022. Average coal prices during the second half of 2022 were far above the current coal prices, probably 2x the coal prices that we are seeing in this first semester. This will certainly have an impact on the average economic price of our whole portfolio, mainly on the regulated PPAs that we have in the center. The regulated PPAs that we have in the north are indexed to Henry Hub. There, we shouldn't see a material change.
On the other PPAs, yes, there should be a decrease, which will be positive also for the accumulation of tech receivables, because this means that the tariff, the current tariff, which is closer to $200, will go down, in probably, 15%-20%. This will also come with, lower production costs during the second half of the year. This should be somehow symmetric. What we expect is that, our energy margin during the second half should remain, very similar to the energy margin we have in the, in the first semester. You will see a decrease in PPA prices in the regulated ones in the center.
Also producing with the coal will go from $140-$150 to $70-$80. This will also help to reduce the average supply cost. All in all, margins should not be impacted by the lower indexation of the first half. I think that was your first question. The second one, sorry, was related to?
The pro forma, the maturity, that profile that you put on the presentations. I would like to know, after I remember that you mentioned in the press release that $100 million of loans with Scotiabank were refinanced post first quarter. I would like to know if there were further transactions?
What we refinance with a $100 million, a group of short-term loans, for 18 months. These short-term loans were extended to October 2024. This is what you can see on page 18. Now what we are working on is to see how we could extend a portion of the debt of 2023 with a higher duration. I mean, rates are not currently the best ones to, let's say, secure a good portion for the long term. You never know. Right now our objective is also to reprofile the debt maturity in our balance sheet.
One of the use of proceeds of the green loan that we are working with the IFC is to restructure and to reprofile part of the existing debt. This should also help us to improve our debt profile for the future.
Perfect. Regarding the timing of the green loan, is it still on June?
Where are we with this transaction? The transaction has been already published by IFC in their webpage, it will go for their board approval, as it is mentioned in the webpage on June seventh or eighth. This means that timing is still aligned with June 2023.
Okay. Perfect. Thank you so much.
Very welcome.
As a reminder, if you have a question, you may press star then one to join the queue. Our next question here will come from Martín Arancet with Balanz Capital. Please go ahead with your question.
Hello. Well, first of all, thank you for the materials and for taking my questions. I have two questions. I would like to run them one by one, if that's okay. My first question: you mentioned that one of the main ECL goals is reducing spot market exposure. Is this more related to a risk management practice or more because of a view at the company that the spot prices in Chile should remain high for, let's say until the Kimal-Lo Aguirre line gets commissioned?
Good question. I would say both, but from a risk management perspective, I think that what we experienced in 2021 when we had a very dry year, P97, P98, or the stressed situation that we also faced in 2022 because of the very high fuel prices and the impact on spot prices, I think it's an important lesson learned that we should try to be balanced and if possible long. From a risk management, it's something that makes sense because otherwise, you could be exposed without any stop loss limit.
The market, like Chile, which is not a liquid market in which you can buy, like in Europe or in other markets, a forward or a hedge, then it's something that you can't solve in the short term. All actions that you implement will only be materialized 1 year later, like what we are seeing today in 2023. That's on the risk management side. Then spot prices for the future, it's very difficult to predict them. I don't think it's easy to predict them even in three months or six months or one month. It is like the FX rate. It's very difficult to see where the FX rate is going to be.
In the specific case of Chile, the country still depends on imported fuels, LNG and coal. It depends a lot on where or where we see that coal prices will be during the next four or five years, where LNG prices are going to be during the next four or five years. Not only have we had the TTF or JKM because each market impacts also the price at which you can buy LNG. It will also depend on the volume of natural gas that will come from Argentina on hydrology.
There are so many variables that could impact spot prices that today it's very difficult to say it will be at $50 or at $60, at $70, at $80 or at $90. It depends on which variables you consider. What we need to be sure is that, we have a balanced portfolio to take controllable actions on our own business.
Very clear. Thank you. My final question is about PEC receivables. You mentioned that you expect to receive about monetize, around $300 million-$400 million as soon as June. I was wondering, do you think it could be delayed long after June, or is it more likely to be ready by June, July?
When I mentioned the $300 million, it's including the $51 million that we already executed. The difference should be coming from the first tranche to be monetized through the second securitization program. Everything, it's progressing. Several milestones were achieved in the last months. What today is missing to be able to monetize the first tranche of the new mechanism is that the state guarantee needs to be filed to the National Controller. Once it is, let's say, approved, we will be able to launch the process with the banks. We expect that this will be a regular process.
It's only probably one milestone today that, one important milestone that, separates us from executing the first tranche. We are confident that June, July could be a reasonable target for the first monetization.
Very clear. Thank you very much.
You're very welcome.
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.
Thank you, operator. Well, it's everything from our side, see you soon. Let's be in contact for the next quarter. Thank you very much.
Thank you. This concludes today's presentation. You may now disconnect your line at this time, and have a wonderful day.