Good afternoon, everyone, and welcome to Engie Energía Chile's third quarter 2022 results conference call. If you need a copy of the press release issued last week, it is available on the company's website at www.engieenergia.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 subjects 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 will now turn the call over to Mr. Eduardo Milligan. Please go ahead, sir.
Thank you. Good afternoon to everyone, and good morning also. First, we apologize for the delay. I'm here with Bernardita Infante, Head of Corporate Finance, and Marcela Muñoz, Investor Relations Officer. Today, we will discuss the ECL results for the third quarter of 2022. For now, let's start. We can go directly to page number three to go through the main topics we will discuss today. First, on the left, we can read the main messages and challenges for this period. As you know, ECL results were impacted during the first half of this year by extraordinary events. Coal and gas prices, together with poor hydro generation and lower availability of efficient thermal power plants and transmission bottlenecks impacted generation costs and spot prices, having altogether a material impact on the EBITDA and net results.
On the cash flow side, ECL liquidity was impacted by the price stabilization law, also known as PEC, and the new mechanism that will be implemented soon. Bernardita will explain in some minutes how this mechanism will work and the action plan we are implementing to improve liquidity. Second, on the right side of this page, we added some elements that are key to understand our view for the future performance of the system and the company. On the market evolution, some conditions have improved during the last months with better hydrology and the availability of gas from Argentina in the central region of Chile. Both conditions should alleviate pressure on spot electricity prices, even considering high fuel costs to remain for a longer period.
On the development front, ECL will be completing the commissioning of 268 MW solar PV power plants located in the north of Chile. In addition, as probably you have seen, we recently announced the acquisition of 100 MW wind farm located in the southern region of Chile. The completion of this acquisition is subject to the final approval of the FNE. In summary, ECL will have added 369 MW of renewable capacity for 2023, + 0.7 TWh of additional backup PPA signed with other generation companies that will certainly be very welcome to reduce the company's electricity purchases in the spot market. Something worth highlighting also, to understand the future performance, is the indexation formula on PPAs, mainly for regulated PPAs.
As we explained in our previous two calls, we have an indexation lag of six to eight months on the regulated PPAs. This means we were facing higher production costs during the first eight months of 2022, which were not yet factorized in the PPA price. Since August, PPA prices are better reflecting the higher fuel costs, and the new tariff revision is expected in October. This will allow PPA tariffs to match the higher production costs, of course. Finally, as I was explaining before, we will face a new tariff stabilization mechanism to restore liquidity issues resulting from the PEC mechanism. We will go through this mechanism in some minutes. On Page 4, we can see the evolution of ECL results during the last two years.
Despite the average realized PPA price of ECL portfolio increased to $149 per MWh , with operating revenues increasing 29% compared to same quarter of previous year. The EBITDA of the first nine months of 2022 was materially impacted by higher supply costs. However, most of this negative impact was booked during the first seven months of the year. Since August, we have seen a potential tipping point in the market context and ECL performance, and this is explained by the EBITDA of the last quarter that reached $57 million, slightly above the EBITDA of the same quarter of previous year. Net result of the third quarter reached - $18 million, and this comes then with an accumulated loss of $58 million for the first nine months of the year.
Net debt increased in line with the CapEx plan, higher coal inventories to secure supply, and need to temporarily finance the tariff stabilization mechanism until a final solution to monetize receivables is implemented. On page five, we can see the evolution of the regulated and unregulated PPAs. As we mentioned on this slide, we are facing a strong demand from unregulated clients in 2022, exceeding the three previous years due to recovery in mining activity and higher copper prices. It is not necessarily positive when spot prices are extremely high and volatile. On the other hand, regulated demand was relatively flat due to a lower share of the pool of regulated PPAs, and also due to the end of a regulated PPA back in December 2021.
In the next five pages, we are describing the evolution on electricity prices and how our electricity prices impacted by hydrology, thermal availability in the system, coal and natural gas prices. As we mentioned in the previous call, we need to highlight that approx more than 50% of the electricity in Chile is directly linked to the international market fuels, mainly coal, natural gas, and diesel. The other 50% is produced with local resources, hydro and renewables. This means there is still a high dependency on imported fuels and how hydrology and thermal availability evolve from one year to the other. On Page 6, we can see the electricity spot price evolution. The system experienced until July extreme spot prices in all regions.
Since August, we have seen an improved trend on electricity spot prices, aligned with an improvement in hydro generation and natural gas that is imported from Argentina. On Page 7, we present the hydro production during the last four years. We can see in this graph a material improvement in 2022 compared to last year. It is expected a better hydrologic year, 2022-2023. These levels are still far from the good old days. These better conditions are of course very welcome and will provide a certain relief to electricity spot prices in the short term. Page 8 explains what has been happening with coal prices.
Close to 30%-35% of the electricity is produced with coal, which is an international commodity and impacted by the current conflict in Europe. Coal is probably the main driver for spot prices in Chile and will continue to be key during the next years. Despite the material increase in coal prices between the last quarter of 2021 and September of this year, during the last weeks, we have seen a sharp decrease in coal forward prices. The average forward price at 12 months as of today is probably closer to $250 per ton. This is a CIF price. Compared to $350 some months ago, even $400 at the beginning of this year.
If this trend continues, we will certainly be positive for, or this will certainly be positive for electricity spot prices and also for working capital needs. Because as you can imagine at these prices, working capital needs increase as we need to finance higher inventories. Next, page nine presents the average availability of coal power plants during the last three years. The system evolved from 4.3 GW in 2020 to only 3.7 during 2022. The last quarter, the average of 2022 was only 3.5, so this means there was some improvement on thermal availability during the last quarter. This is still at the edge because 600 MW , it's a material change for the Chilean system. On Page 10, we present the LNG prices in different markets.
We can see the LNG price materially increased because of the European conflict. The good news is that Argentina is exporting gas to Chile in the central region. There are committed injections of between 6.5 to 8 million cubic meters per day for the period October 2022-April 2023, and this is aligned with the commercial agreements signed by two generation companies in the central region. Now, 6.5 million- 8 million cubic meters per day could be equivalent to 10%-15% of the Chilean electricity market, so these volumes are material for the system's operations. Next step, Page 11, gives an example of the volatility the market is facing on spot prices during the day and night hours.
The red dotted line shows the spot price in the north region, in which most of our demand is concentrated with mining companies. Maybe you can recall that spot prices in June ranged between $0 and $350 per MWh. In the example we are showing for the first 10 days of September, spot prices ranged between $0 and $150-$200. That is still high, but far below the extraordinary prices the system faced during the second quarter. Page 12 shows the contracted volume of PPAs until 2035. The average life of the portfolio is currently nine years. There are no changes on this page.
Page 13 shows the volume of contracted energy ECL contracted during the last four years with other gen cos to manage the supply risk. In 2022, 2023, this hedge will represent almost 25% of ECL contracted demand. We can see an important ramp up in 2022 and a new one in 2023 to reach approx. 2.8 TWh per year. This should remain stable at least until 2025, 2026. This means the volatility risk ECL faced in 2021 and 2022 should reduce in 2023 onwards, considering the ramp up of these backup PPAs and the additional renewable power plants that are coming online before year-end to our portfolio.
Now let's move to Page 14, where we can see the demand supply balance for the first nine months of 2022. This graph shows the 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 every quarter how a new area in yellow starts to become visible at the left part of this graph. Then our thermal power plants come on the dispatch ranking. The variable cost of our coal and gas plants in general was higher because of higher coal and LNG prices.
As we move to the right, we see ECL supply 32% of its contracts through purchases from the spot market and 17% through supply agreements signed with other generation companies, both representing almost 50% of total sales. The average supply costs increased from $72- $108 per MWh , and this was partially compensated by an increase in the average economic price, which is also higher by around $20. It's an increase from $11- $139 per MWh . This increase is not fully compensating the increase in the average supply cost. Last quarter, the difference was much bigger, and therefore the third quarter results are improving the year-to-date average.
Now, as I explained at the beginning of this call, it is important to highlight that ECL is currently facing the cost of supply with its own generation power plants and through the spot market, where there is a lag in indexation formula of regulated PPAs of approximately six to eight months. This means since August and October of this year, prices will start reflecting the higher supply costs the company faced during the first 9 months of the year. Now let's discuss some elements that are key for the last three months of this year and for next year too. Please turn to page 15, and we will go through each of these elements. First, hydrologic conditions. The first eight months of 2022 were still impacted by 2021 droughts with P97 exceedance probability.
In addition, as we know, the market coordinator implemented a hydro reserve, which also impacted the hydro availability during this year. Since August, the hydro reserve was reduced thanks to rainfall and snow accumulation. It is, of course, positive for the rest of the current year. The main doubt will be until when in 2023 this improved hydrology will last, and what will be the new hydrologic scenario for the new period 2023, 2024. Second, coal prices continued to decrease during the last weeks. The graph is setting an average price of $350 per ton. As I mentioned before, the current coal API2 forward price for next 12 months is now slightly below $250 per ton, CIF.
This is positive for the system since coal is setting the spot price during most of the time. This impact would be mainly seen in 2023, since most generation companies will be burning the expensive coal before new inventories arrive at lower prices to the coal power plant. We need to consider that there is still volatility and prices could increase again under certain international market scenarios. Again, coal is very important, but we are experiencing a lot of volatility. Third, Argentine natural gas supply. It was key until April, and then it was initially expected to come back with relevant volumes since October of this year. The good news is that since July, Argentina is exporting relevant volumes to Chile through the central region.
There are committed injections of 6.5-8 million cubic meters per day for the period October 2022-April 2023. As I mentioned before, this is equivalent to 10%-15% of the Chilean electricity market. These volumes at the fair price are material for the system's operation. LNG supply, ETL faced a cancellation of one cargo between June and July. This means close to $50 million negative impact in ETL P&L, which was accrued half in June and half in July. The rest of the LNG cargos are coming from other terminals. This means the situation in Freeport is not impacting our view for the rest of the year. Efficient plant outages during the first half. IEM was limited and went through maintenance.
IEM is back since July at full capacity, and we expect to continue improving the availability during the second half of the year for the overall portfolio. PPA indexation, as I mentioned before, the regulated PPAs have an important lag in its indexation formula of approx six to eight months. This was not material when fuel prices were relatively stable, but given the current increase in coal and LNG prices, it has become a material element because the supply cost is recognized today, while the indexation formula will only reflect the higher fuel prices in six to eight months. This means part of the loss we are facing in 2022 would be recovered between the second half of this year and 2023.
For example, if we consider a total regulated demand of almost 5 TWh per year, each $10 that tariff increases, then this would represent a direct increase in revenues of around $50 million during the full year. Last, new solar PV power plants for 268 MW will be completing its commissioning during the upcoming weeks. Also we have in front of us the potential acquisition of a 101 MW wind farm in the south that will provide relief in 2023, together with the additional backup PPAs that will start at the beginning of next year. These seven main elements explain our current view for the rest of the year and provide some additional info on what could be expected for 2023.
Next year, we should also see an improvement in ECL overall position to the spot market. However, we need to consider that this view is taking into account coal prices, hydrology, thermal availability and natural gas to remain stable without material changes compared to the current situation, which is already complex.
Now, please turn to Page 15. Total net debt to last twelve months EBITDA ratio increased to 8x, given the lower EBITDA and the additional debt ECL raised to first finance its CapEx plan. ECL CapEx plan for 2022 is close to $370 million, including the acquisition of San Pedro Wind Farm. Second, to finance additional working capital needs coming from higher fuel prices and related inventories. This also came with higher receivables. Third, a very material impact coming from the regulated PPA tariff stabilization mechanism. The impact here would be-
Pardon me, ladies and gentlemen, it appears we have lost the connection to our speaker line. Please stand by while we reconnect. Thank you for your patience. Pardon me. This is the operator. We have reconnected the speaker, and we will continue. Please proceed.
Thank you. Sorry for this. We were explaining about Page 15. I was explaining that there was a third impact. It was a material impact that was coming from the regulated PPA tariff stabilization mechanism. The impact during 2022 for the whole year is expected to be around $250 million-$300 million that the company didn't collect. This comes with the need to implement a new monetization structure. Currently, we are working on the implementation of this new structure, and our objective is to implement this new structure as soon as possible and sell these receivables.
During the next year, ECL should return to the baseline that we defined to keep our leverage ratios not exceeding 3.5x on a structural and regular basis. As we explained before, we may face temporary increases in this ratio during the construction phase or during complex years like the current year, but this should be temporary considering renewals will rapidly generate an additional EBITDA. In this context, and while margins don't return to previous levels, we expect dividends will be kept at minimum ratios. Now, Bernardita will cover the following section to explain some additional elements on ECL performance, including the new regulated tariffs stabilization mechanism.
Okay. Thank you, Eduardo Milligan, and good afternoon to everyone. If you please turn to Slide 18. When we look at the evolution of EBITDA, we can observe that the variations are quite similar to what we showed in the last quarter. Although most effects clearly improved in the last two months of the period. EBITDA reached $118 million, down 51% from the first nine months of last year. Average realized prices increased significantly since higher coal and gas prices, as well as U.S. inflation, began to be reflected in prices, given the delay with which cost variations are captured in tariffs, particularly in the regulated segment.
Also, our spot sales increased due to the generation surplus reported by Eólica Monte Redondo as one of its PPAs with CTE for 175 GWh came due at the end of 2021. The Los Loros PV plants and PPA sold power to the spot market in the first two months, and starting March 2022, they have both been selling their energy production to ECS. We note an increase in physical sales to free clients, which offset a decline in sales to distribution companies due to a lower PRASA in the pool of regulated contracts and the maturity of the Eólica Monte Redondo PPA with CTE. Our gas margin increased by $29 million, a turnaround from the loss reported last year.
This was because 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 for such event. We can see a $142 million negative impact from fuel costs, purely explained by higher prices as our own thermal generation decreased by approximately 40%. Our LNG generation fell due to the maintenance of our combined cycle units and the Freeport incident affecting generation in June and July. Coal generation dropped basically due to the IEM overhaul and subsequent maintenance schedules at CTA and CTH. This was partly offset by renewable generation, which climbed by 4 times due to the Calama Wind Farm and Tamaya Solar Plant operations.
The Capricornio and Coya PV plants started injecting energy into the grid with a combined contribution of 45 GWh. Energy purchase volume doubled compared to last year. While 55% of this volume increase came from regular spot purchases, 45% is explained by contracted purchases from other generation companies, which increased by 4x to almost 1.5 TWh in the first nine months of this year. There was a $79 million negative effect from an increase in spot prices, in turn explained by high fuel prices, the drought, and transmission congestion in certain nodes, especially in the Puerto Montt area, where marginal costs have remained at averages above $200 per MWh through the first nine months of the year.
Finally, we had no insurance compensation this year, while we did report a $5 million payment in 2021. Operating and maintenance costs also reported an increase which caused a $26 million contraction in EBITDA. Now, let's move to Slide 19 to see the evolution of net results, which went from a $39 million net profit last year to a $58 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. Letting out this effect, we would have reported a $75 million profit in the first nine months of last year.
In the first nine months of 2022, we reported a $105 million after-tax reduction in EBITDA, which added to other smaller negative effects in terms of financial expenses, and insurance recoveries, resulted in a $47 million net loss before one-offs. This year, we also reported an $11 million after-tax impact on financial expenses related to the sale of accounts receivable originated by the PEC law, which led us to report a $58 million net loss in the first nine months of 2022. Just for you to know, we still have approximately $43 million in accounts receivable left to be sold under the PEC 1 mechanism. So far, we have sold $222 million and have booked a $64 million financial cost related to PEC 1.
Please turn to Page 20 to talk about cash flow and net debt. The main cash outflows included $405 million used in operations. Let's take a closer look here. We can say that about half of these operating cash needs correspond to higher costs, mainly higher prices for coal, gas, and energy purchases. We also built up coal inventory to reduce risk. The other half is explained by the effects of the price stabilization law in effect since late 2019. This means that we have been unable to collect more than $220 million corresponding to the difference between the contractual tariff and the stabilized tariff we are actually charging to regulated consumers.
We will discuss this in more detail in a few minutes, but the conclusion is that once we are able to monetize these accounts, our operating cash flow will be restored in this respect. We invested $143 million in capital expenditures, mainly in PV plants, wind farms, and substations. We paid $37 million in CO2 and income taxes, and almost $42 million in interest expenses. IFRS 16 leases decreased by $19 million, mainly due to non-cash effects adjustments, as the liability is denominated in Chilean pesos, which depreciated against the U.S. dollar through the first nine months of the year. Finally, we received $39 million in profits from the true sale of long-term receivables from distribution companies through Chile Electricity PEC.
Since we financed this cash needs with new debt for a total of $480 million and with $147 million of cash reduction, cash that we had available at year-end 2021, our net debt increased to $1.6 billion at the end of September. On Page 21, we see the sharp increase in net debt to EBITDA, mostly due to the decrease in last twelve months EBITDA, which reached only $189 million, compared to $361 million reported in the last twelve months ended September 2021.
Also, as just explained, our net debt increased by $569 million from year-end 2021, including primarily $230 million in one-year loans, a $250 million five-year loan with Scotiabank, and a $147 million reduction in cash balances. Our credit rating remained unchanged as of the end of September, but we must note that on October 28, Fitch downgraded EPS rating to BBB with stable outlook. According to Fitch, the downgrade reflects Engie Chile's higher leverage, deteriorated liquidity position weakened by expected negative Free Cash Flow due to its renewable expansion. Further, approximately 30% of the company's contracted position has been covered with spot energy purchases in a market currently with high marginal costs. Now, we explain the effects of the price stabilization law.
You can find more details in Slides 66 and 67 of our presentation. As you know, the first price stabilization fund, which we call PEC 1, reached its $1.35 billion cap in mid-January of this year. Last August, a new law was approved to deal with the differences generated by the contractual tariffs and the stabilized tariffs, which have been accruing since the PEC 1 mechanism was exhausted last January. The new law differs from the previous one in the following main matters. First, it includes differentiated tariffs depending on consumption level. This is geared to protect the most vulnerable consumers.
Second, generation companies will receive certificates of payment issued by the Chilean Treasury for the difference between the contractual and the stabilized tariffs, as opposed to accumulating accounts receivable from distribution companies. The certificates of payment will be transferable, and their amount will be grossed up for financial expenses.
IDB Invest has been working with the government and different stakeholders to structure a mechanism by which generation companies will be able to monetize these certificates without bearing the financial burden, which was the case under PEC 1. In simple words, once the new mechanism is implemented, generation companies will be able to sell the certificates and restore their liquidity. We estimate that Engie alone will have accrued approximately $250 million through December of this year after the end of PEC 1.
This amount could be recovered as soon as the mechanism is in place and the first certificates are issued. Now let's move to Page 22, where we show no changes. No dividend payments in 2022 and a 16% drop in ECL's share price, which is relatively aligned with the industry, which has been affected by fuel prices, the drought, and geopolitical, economic, and regulatory uncertainty. I'll leave you with Eduardo for an update on the transformation plan and final remarks.
Thank you, Bernardita Infante. On Page 24, Capricornio PV is ready, 100% energized, and just completing the process for its formal COD. On Page 25, Coya PV reached an overall advance of 97%. It's already injected to the grid and has started the final phase to receive its formal COD too. Within these two projects, [inaudible] will add 268 MW to its renewable portfolio. On Page 26, we can see the description of the two land concessions that have a combined capacity to build 1.5 GW between PV, wind, and batteries. We are finalizing the development phase to add additional projects to construction phase.
Finally, on the development of new renewables, you can see on Page 27. Other projects that recently received their environmental approval or that have recently requested an environmental approval. As you can see, we are also developing storage projects that could be added to the existing PV solar plants in the north of Chile. In addition, we need to consider the acquisition, the potential acquisition of the 100 MW in the south region of Chile that will be added to the 268 MW that will be completed and that will be ready for next year. Finally, on transmission, last quarter, we added this section to better describe this business. 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 generation assets. 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, ECL has annual regulated revenues of approx $23 million. Approx 80%-85% of these revenues contribute to ECL's EBITDA.
In addition, as we can see on Page 38, ECL is developing other transmission projects that are detailed on Pages 32 and 33, with a total investment of $150 million that are expected to contribute additional $10 million annually, 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 following the 80%-85% ratio, an approx EBITDA of $26 million-$28 million. On top of that, as you know, ECL has a 50% participation in TEN transmission line, which is described on Pages 34 and 35.
TEN has an estimated average annual EBITDA during the next four years of approximately $60 million-$65 million, while the company has a total debt of around $600 million. As you know also, TEN is not consolidated, and ECL owns 50% of this company. That means 50% of its net result is accounted as EBITDA in ECL, and that is approximately $8 million-$9 million per year. Now to end this presentation, we are summarizing the main key takeaways on page 36. As we also mentioned in our previous two calls, considering the extraordinary international context triggered by the conflict in Europe, ECL faced a very complex first half in 2022.
In fact, this context continued until July, to be precise, and which was probably the worst month during this year. Since August, ECL performance had a turning point, explained by controllable and non-controllable elements. On the controllable elements, the availability of ECL thermal power plants improved materially compared to previous quarters. In addition, the operations team managed a better mix of fuels to reduce the average supply cost.
While on the development side, ECL completed two additional PV projects and reached an agreement to acquire an uncontracted wind farm of 101 MW in the southern region. On non-controllable elements, we are well aware that market conditions improved on hydrology, natural gas from Argentina, and recently on fuel prices. We have seen an important improvement.
The market will continue to be under stress, but as we mentioned in our previous call, there are elements that are moving in the positive direction, including also a new tariff stabilization mechanism to provide some certainty on regulated revenues. Now the challenge is to monetize as fast as possible those renewables. In this context, and as we mentioned before, it will be key to accelerate the development and construction of renewables and keep a high availability of our own thermal power plants, while at the same time secure our funding needs for these projects. Thank you, and now we are ready for any questions you may have for us. Sorry for the lost connection a couple of times.
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 or any time. If at any point your question is answered, you may remove yourself from the queue by pressing star two. Questions will be taken in the order they are received. We do ask that when you ask your question, that you pick up your handset to provide optimum sound quality. Please hold while we poll for questions. Again, to ask a question, you may press star then one. The first question today comes from Alejandra Andrade with J.P. Morgan. Please go ahead.
Hi. Good morning. Thank you for answering my question. I just wanted to ask, obviously, there are a lot of positive drivers for results in the fourth quarter and into 2023, but I was wondering, in case anything disappoints or if you don't get to the leverage level that is more normal to NG, what are you considering in terms of other options to lower leverage faster? Thanks.
Sorry, we lost the connection again. Thank you for your question, Alejandra. Basically, what we expect for the short term or for next year is that ECL balance sheet should be sufficient to finance the new projects that we have in our pipeline. We expect to be ready with probably one or two additional renewal projects in the next months. Considering the view that we have for 2023 and 2024, right now we are not contemplating right now any additional, let's say, structure to finance these projects.
I think conceptually, if at some point, and probably, if I understood correctly, you mentioned, if things get worse in the future, it is obvious that probably ECL balance sheet is not going to be sufficient to finance additional projects in the future, and we will need to contemplate other alternatives, like subordinated debt or an equity increase or any other innovative structure, indeed.
Thank you.
The next question comes from Andrew McCarthy with Credicorp Capital. Please go ahead.
Good afternoon, Eduardo, Bernardita, Marcela, and everyone on the call. Many thanks for the presentation and taking my questions. I just was wondering if we could maybe just go a bit deeper into, you know, what you are seeing in terms of the sort of the capital that you need for next year. I don't know if there's any sort of guidance you can already provide as in terms of the CapEx for 2023. You mentioned there, Eduardo, you know, maybe one or two renewables projects you might be starting to look at investing in next year.
You know, I understandably, dividends should be fairly low given the sort of net income outlook for 2022. You've also got, obviously, this, you know, $280 million of debt that needs to be refinanced in first half 2023. Just trying to put all the pieces together and part of that is obviously understanding a bit better, you know, what that sort of CapEx outlook is for 2023 to the extent you can provide that.
Hello, Andrew. Thank you. Let me start with one of those pieces. In terms of debt, we do have some short-term maturities next year. Currently we are working on different structures in parallel to increase the duration of our debt. This is something that is currently under implementation. On the CapEx side, the committed CapEx for next year so far is not material, the committed CapEx that we have as of today. On the other hand, we do have projects that are reaching a ready-to-build phase.
That means that, if those projects are approved, we may have additional CapEx for next year, which could be close to $200 million or $300 million. It will depend on when those projects are approved and when we start construction. The projects that are currently reaching a ready-to-build phase are mainly a wind farm, and we are also analyzing storage options to add them to our existing PV solar plants. This means that for next year, we may have a additional, let's say, CapEx of $200 million-$300 million if we are successful to reach the construction phase as soon as possible.
We also need to consider that next year we should monetize around, I will use a ballpark figure, $300 million long-term receivables coming from the Energy Price Stabilization Law. This $300 million is or are the receivables that we haven't collected during 2022. We expect to monetize these receivables and increase our liquidity position when these receivables are monetized. This should happen as soon as possible during the next three, four, five, six months.
Great. Thanks, Eduardo. Is there any color you can provide? I know you're talking now with TotalEnergies about, you know, the cargo that didn't arrive in June. You mentioned, I think during the call that the impact on the EBITDA margin was something in the order of $50 million. Is there anything you can provide us there in terms of, you know, what you might be expecting in terms of eventual compensation?
So far we are still discussing this specific case. As you know, the LNG market is currently very difficult. What we mentioned is that the impact on ECL P&L during this year was probably between $40 million-$50 million. Because basically we didn't produce with that LNG. In addition, there was an impact in the overall system, a direct impact without that LNG that was expected between June and July. We are still discussing what will be the remedies and alternatives that we can obtain from our supplier.
That's great. Thanks. The last one for me. Just in terms of I know the lag in the indexation and the regulated PPAs, the prices you mentioned sort of six to eight months. You also made interesting point there during your presentation about the, you know, even though the forward prices on coal have already come down to 250 or slightly lower per ton.
The inventory effect means that you're still sort of seeing $350 per ton for the fourth quarter. Just wondering if you could give a bit more color in terms of how that lag effect works in terms of the-- On the cost side, if that's sort of a one or two or three or four, I don't know how long that sort of inventory lag effect is on the cost side. That'd be great. Thanks.
It's a complex, let's say, mechanism, but let's try to make it simple. Let's assume that during the first eight months of the year, we bought coal and LNG at a higher price. After six, eight months, we will see this additional cost increase in the indexation formula of the regulated PPAs. This happened last August. In August, there was an extraordinary adjustment in the PPA tariff because there is an extraordinary adjustment when the tariff increases above 10%. In October and on April, we have the regular adjustment in the indexation formula.
That's why I was saying that there is a six to eight month delay on the PPA tariff. On the cost side, it is true, and you have seen that our coal inventories increased during the first nine months of this year because of price, because of volume, because we are trying also to have more reliability on coal inventories. In this complex context, we need to be sure that our plants will have enough coal. The average price of those inventories is much higher than the current forward price for the next 12 months of $250.
What we should expect is that we should continue burning this expensive coal during the next two, three months. Since December, January, we should see a reduction in the production cost of coal power plants overall, not only in ours, but in the system, if the coal price remains at current levels during the next three months. The impact of a lower coal price is not going to be something that we will see this year. It's something that we could expect for next year.
Very clear. Thanks very much, Eduardo.
Thank you.
The next question comes from Juan Carlos Petersen with Chufquen. Please go ahead.
Hi. Good afternoon, Eduardo. Can you hear me well?
Yes. Hi.
Hi. I have three or four questions. The first one is related to what Andrew was just pointing out. In terms of price, if you assume that the current conditions faced, the current ones at market, what should be the peak of the energy price you could foresee for the next, let's say, six months? Given that you have a lag, you expect the increase in four months, but normally tend to assume in the last.
Sorry, Juan Carlos. We can't hear you very well.
Hello?
Is it better now?
No, now it's better. Yeah.
I was saying, Eduardo, I was asking you what would be the peak price or the maximum price that the company could have in the next six months, given the lack of the readjustments, given the cost that the companies have to incur in the current year. That's the first question.
Okay.
The second question is related to market opportunities. We have seen a couple of defaults from some renewable generation companies in the Chilean market. Could this be an opportunity for Engie to have a look? What are you doing about? Third question is related to EBITDA for next year. As you have explained very well the CapEx, the range, the possible ranges on CapEx. Under the current conditions, what should be or what could be the EBITDA for next year given the price adjustments and the current conditions on inputs? Thank you.
Thank you, Juan Carlos. Okay, if I understood correctly, the first one is related to what is our view on the PPA price or the average price for the next let's say six to 12 months. This is unrelated to the indexation lag that we have in the regulated PPA. I'm going to answer in relation to the regulated PPA. If the average price of the regulated PPA was around $150, what we could expect for next year is that the average price could be close to $200. This is explained by the higher fuel prices that would be factored in the indexation formula.
This is probably a view for the next eight to 10 months, and then it will depend for the next, let's say, variation. It will depend on how fuel prices evolve. On the second question, opportunities, yes, we are always analyzing opportunities or assets in the local market that could be a good fit to our own portfolio of PPA contracts. Always it's important to take into account that we are highly contracted, so we are interested in merchant power plants or power plants that are not contracted. We always depend on the nodes, on the region in which those plants are also injecting based on our own portfolio.
Yes, we are always seeing this type of opportunities in the local market. The problem is that it's not always easy to match our own needs with the assets that could be in the market on sale, let's say. The EBITDA for next year. I think the EBITDA for next year under the current context and I need to add 10 disclaimers is that that should be very similar to the EBITDA that we were expecting for this year before the crisis in Europe started. Why?
Because if the average supply cost of the portfolio remains stable during next year, we should, on the revenue side, see an increase in revenues that should compensate the material increase on the average supply costs that we have seen during this year. The math is pretty simple, and it's basically related to the regulated PPA and the tariff that should increase for next year, compared to the average supply cost that we expect for next year, which should also be lower than the average supply cost of this year, considering that we will have close to 370 MW of additional renewables in our portfolio.
Considering that we will have also additional 0.7 TWh per year of additional backup PPAs signed with other generation companies. Both elements will certainly reduce our average supply cost, but we will not be able to close all the gap or the short position in the spot market. There is still a risk related to the market price at which we will buy the remaining portion in the spot market.
Thank you. Very clear. That's all from me.
Thank you.
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.
Thank you. That's all from our side. If you have additional question, comments, we'll be happy to address them in the coming days, weeks. If not, see you soon or during our next conference call.
Okay. Thank you, all, and best regards. Hope you have a nice day.
Thank you. This concludes today's presentation. You may disconnect your line at this time and have a nice day.