ENGIE Energia Chile SA
SGO:ECL
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Good afternoon, everyone, and welcome to the Engie Energia Chile's First Quarter 2024 Results Conference Call. If you need a copy of the press release issued on May 2, 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 or contact Investor Relations Officer, Marcela Munoz.
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. I'm here with Bernardita Infante, Alison Saffery and Marcela Munoz. Today, we will present this year results for the first quarter of 2024 and of course, our view for the rest of the year.
So we can start directly on Page 3. In this page, we are highlighting the main elements and drivers we will discuss today. So first, the positive evolution on fuel prices, which have remained stable in the first quarter of this year. As we will explain in some minutes. Second, the positive impact on our portfolio of increased renewable generation, batteries and additional backup PPAs. Then we also need to consider that with lower fuel prices, we will see lower PPA tariffs. Then that given the improved hydro conditions, we also had lower dispatch of coal power plants during this first quarter.
On PEC, we continue progressing and moving forward with the new structure to monetize the receivables coming from the tariff stabilization law, also known as PEC. As of March 2024, we have accumulated receivables for $333 million, which are expected to be monetized in the second half of this year. Then we have accelerated the implementation of batteries, known as BESS, in our existing sites. In this line, we recently announced the construction of an additional project in Tocopilla site in the north of Chile. And this means we will have close to 371 megawatts of BESS capacity with this additional project.
What is also interesting is that we are building this new BESS project in the same site and in the same square meters in which we had 2 coal power plants that have been recently disconnected and dismantled. So this is key because we are also giving continuity to an existing site like Tocopilla.
Then we recently announced that we are ready to disconnect and [indiscernible] our coal power plants, CTA and CTH. This will occur by December 2025. And finally, we executed recently a successful liability management, issuing a 10-year $500 million bond in international capital markets to fund our future CapEx needs and refinance our short-term debt.
Now let's continue on Page 4 that shows the evolution in sales -- physical sales. There is a positive evolution on regulated sales, which increased in 10% compared to previous year. This positive evolution confirms the trend we had in 2023, where regulated sales increased 6% compared to previous year. While on the unregulated side, sales also increased in 5% compared to the same period of previous year.
On Page 5, we can see the evolution of spot prices. The spot price decreased from average $87 per megawatt hour in 2023 to average $58 per megawatt hour in the first quarter of 2024, positively impacted by improved hydro availability and reaching almost the average spot prices of the 2017-2021 period.
We see the detailed trends on hydro conditions in next Page #6. As we can see in the graph, the improved hydro conditions of 2023 are clearly reflected in the hydroelectric generation during the first quarter of 2024, it was materially better than in the last 5 years. In fact, as of the end of March, the energy start in reservoirs was around 2.5 terawatt hour more than the energy store at the end of the same quarter of previous year. And this is, of course, providing additional support during April and May of the current year.
Then on Page 7, we present the evolution of coal prices, which in the last 6 months have remained between $100 and $110 per ton. We need to remember that $100 per ton, the production cost with coal power plants decreases to around $50 per megawatt hour. And as we mentioned in our previous call, this also means that electricity produced with coal is again cheaper than with LNG, but of course, coal power plants are not flexible and need to be running permanently, which brings other issues to the system.
Then on next Page 8, this page shows the evolution of coal power plants availability in the last 4 years. Other positive element for the system is that the average availability of coal power plants in the last 2 years remains stable at around 3.5 gigawatts after a difficult period post pandemic.
Now let's continue on Page 9. The graph on top show the evolution of international LNG prices, which have remained relatively stable in the last 6 months. Changes are mainly linked to their usual seasonal behavior. And then the graph below shows the LNG sourced by Engie and other generation companies through long-term through contracts and the natural gas coming from Argentina, which in our case was imported through ECL's gas pipeline in the north of Chile, providing an additional and alternative source of natural gas for our combined cycle power plants.
Next page, 10 shows an update on the hedges or backup PPA signed with other gencos. In summary, we will have 3.6 terawatts hour for 2024 and average 3.5 terawatt hour between 2025 and 2026. We haven't signed new PPAs in the last 3 months. But this instrument will continue to be opportunistic and interesting for us and there are certain market conditions.
Then Page 11 shows a graph with the energy sources and the average supply cost for the portfolio. The main message in this page is related to the average cost of energy to supply our portfolio of PPAs. These costs decreased in 40% compared to the first quarter of 2023, mainly explained by new renewables, lower fuel costs and better hydrologic conditions.
On the other hand, the average monomic price of our portfolio of PPAs also decreased, as we can see next, Page 12, where we present the supply-demand curve for the overall portfolio of PPAs. And the related supply sources. The average monomic price of our portfolio of PPAs in this page is shown at $123 in the first quarter of 2024. As you have seen each quarter, downstream prices declined gradually, and this decrease is mainly explained by the indexation of lower fuel prices. So this is a mechanic evolution.
On the other hand, the average supply cost reached $71 compared to the $118 of the first quarter of 2023. This means both PPA prices and the average supply cost materially decreased, but the reduction in the average supply cost was greater. This is why our energy margin increased from $47 megawatt hour in the first quarter of 2023 to the $52 megawatt hour, we are showing in this page during the first quarter of 2024.
Now we will continue with Bernardita. Bernardita will present the detailed financial results for this quarter.
Yes. Thank you, Eduardo, and good afternoon to everyone. Let's go to Slide 13 for a look at financial highlights. So EBITDA increased by 35% compared to the first quarter of last year and reached $138 million. Total revenues dropped 25% to $443 million, mainly as a result of a 29% decrease in average realized prices to $123 per megawatt hour, reflecting the return of fuel prices to more normal levels.
On the contrary, physical energy sales increased 7% to 3.1 terawatt hour with growth driven by both free clients and regulated clients demand, but more evidently in the regulated space as a result of natural growth and an increase in our pro rata share of regulated supply.
As we will clearly see in the next slide, our EBITDA margin recovered to 35% due to significant cost reductions, mainly explained by the drop in fuel prices and lower spot energy prices resulting from better hydrologic conditions, lower fuel prices and greater availability of natural gas, including Argentina.
In the first quarter, we reported a 33% increase in energy purchases, although we have reduced our exposure to the spot market during non-sun-hours. Energy purchases from the spot market declined 44% to 0.9 terawatt hour, while purchases under backup PPAs increased 33% to almost 1 terawatt hour. These purchases were done at much lower average prices. Indeed, the average realized price of our energy purchases was $68 per megawatt hour, almost half the price reported in the first quarter of 2023.
Our own generation decreased. On the one hand, coal generation increased 41% to 0.5 terawatt hours because of the failure of the IEM plant in the first quarter of last year. And on the other, gas generation fell 51% to 0.4 terawatt hour due to lower availability of our combined cycle [indiscernible].
Our renewable generation, including the output of our new BESS Coya storage plant decreased by 3% to 0.4 terawatt hour, accounting for approximately 30% of our own generation. Our net income reached $46 million, a significant improvement compared to the first quarter of last year. And the good news is that the improvement is primarily explained by recurring operating results.
Now moving to Slide 14. This shows the main reasons behind the EBITDA recovery, lower fuel costs with the lower average price of our energy purchases and the increase in physical sales. These positive factors offset the decrease in average realized prices and the increase in energy purchase volumes. This explains the $36 million increase in EBITDA to $138 million, which is in line with the high end or exceed the high end of our EBITDA guidance for the full year.
In Slide 15, we can see that net income more than doubled compared with the first quarter of 2023, reaching $46 million. This was mainly due to the strong EBITDA recovery, a reduction in depreciation expenses explained by the impairments made in the last quarter of last year in anticipation to the future discontinuation of coal production and the decrease in other provisions. These positive factors were only partially offset by an increase in net interest expense, explained by the increase in debt at higher interest rates, the absence of insurance recoveries in this quarter and the negative exchange rates.
In Slide 16, we see the status of our net debt, which increased by only $50 million to almost $1.9 billion after financing CapEx of $90 million and $44 million buildup of accounts receivable resulting from price stabilization loss. This moderate increase in net debt compared to the investing activity was possible due to the strong operating cash flow generation, which reached $123 million, plus $10 million in proceeds from the sale of PEC-2 receivables in January 2024.
In Slide 17, we are showing a summary of cash flows resulting from the price stabilization loss. Over the 3-year period ended December 2023, the company accumulated accounts receivable for a total amount of $650 million on top of the $142 million initial balance reported at year-end 2020. All this represented sales revenue that could not be collected because of the enactment of price stabilization for regulated consumers.
Now thanks to the PEC-1 monetization program, the company could collect cash proceeds amounting to $193 million between the first quarter of 2021 and the second quarter of 2023 and had to bear financing costs of $79 million because these receivables were sold at a discount.
PEC-2 notes began to be sold in 2023. Under this program, we collected $221 million in cash plus $11 million of interest income which contributed to elevated liquidity pressures in 2023. In the first quarter of this year, the account receivable build up amounted to $44 million. That is an average of almost $15 million per month, which we expect to decrease over the rest of the year as the gap between PPA tariffs and stabilized prices should begin to narrow.
In January, we completed the fourth sale of certificates of payments issued under PEC-2 in an amount of approximately $10 million. We expect to complete the fifth sale in an amount of $38 million on May 30 and the final sixth sale of approximately $10 million in June 2024. The PEC-2 program reached already the $1.8 billion [indiscernible] stipulated by law in March 2024. At the end of March, the accounts receivable balance amounted to almost $333 million. The IDB and Goldman Sachs are working with the relevant government and regulatory agencies, under generation companies in the structuring of the PEC-3 program, which is similar to PEC-2 with an additional cap of $2.3 billion. The PEC-3 monetization program is expected to be enacted during 2024, and it should allow us to sell a significant portion of our balance of PEC receivables, contributing to strengthening our liquidity and financing our investment in renewable projects.
Now let's move to Slide 18. Our BBB stable outlook ratings have been confirmed by both Fitch and Standard & Poor's. Net financial debt reached $1.9 billion at the end of March with net debt-to-EBITDA down to 4.3x. We have made progress in our debt profile objectives. First, to reduce net debt to EBITDA through EBITDA recovery. Second, to fund the construction of the Lomas de Taltal wind farm and BESS Coya projects -- sorry, the BESS storage projects, the subjectives are to reduce our costs, our exposure to the spot market and the curtailment and intermittence associated to renewables. And third, to expand the maturity profile of our debt.
As Eduardo mentioned, in April, we issued our first green, a 144A/RegS bond in an amount of $500 million, which allowed us to redeem $215 million of our notes maturing in January 2025 and to fund our capital expenditures in renewable and BESS projects. The annual coupon rate is 6.375%.
On the bottom left corner of the slide, you can see the maturity schedule of our debt as of the end of April after the new bond placement, which shows a significant reduction of our refinancing risk. As of the end of April, the average coupon rate of our debt was 5.63%, and the average remaining life of our debt was extended to 5.2 years from 3.6 years at the end of March.
Now I'll leave you with Eduardo, who will brief us on the recent events and action plans.
Thank you, Bernardita. So on Page 19, now, we are highlighting some actions that are key to reduce ECL's exposure to the spot market. So these actions are crucial to reduce our activity on operational results and also to bring stable margins.
So first, we secured additional backup PPAs for 2024, 2025 and 2026. Today, these hedges represent around 25% to 30% of our total contracted volume. Second, in 2024, we will have more than 1 terawatt hour of renewable generation. More to come in to 2025, of course. And in parallel, we are adding batteries or BESS to our portfolio of assets. In 2023, we completed the construction of BESS Coya, which is now, or as of today, the largest storage system Latin America. And in addition, we have 3 other projects under construction. And together with these 4, we will reach a total capacity of 371 megawatts for 5 hours. So this capacity, as you know, will be key during nonsolar hours.
And as we mentioned at the bottom of this page, ECL's total exposure during nonsolar hours will be close to 1 terawatt hour in 2024 compared to the 2.5 terawatt hour that we had back in 2022. So this means we are progressing very well on reducing this risk for our portfolio. As we explained in previous quarters, we are highlighting the exposure during nonsolar hours because this is when spot prices could be out of control and this is the risk we need to manage as part of our rebalancing strategy.
Then on Page 20, we are presenting the evolution of our investment plan and the committed CapEx for 2024 and 2025. Once we complete the now 4 projects under construction, that are wind Taltal and the BESS projects, Tamaya, Capricornio and the newly announced BESS Tocopilla, we will reach 1.5 gigawatts of renewals plus batteries, and we expect to reach -- are ready to build status for other projects very soon. On top of these developments, we also confirmed the conversion of IEM power plant to natural gas. And this conversion will be implemented during 2026.
Then Page 21 presents the detailed CapEx by type of business. We have divided these investments between renewables and BESS, to highlight the importance, the relevance of this new technology in our portfolio. We continue to invest around $550 million per year in renewables, BESS and transmission projects. As you know, each megawatt hour that is produced by the new renewables and BESS, we'll be replacing the energy purchases in the spot market and hence, increasing ECL's energy margin.
Now on Page 22, we are highlighting the main drivers for our guidance. On the left side, we described these elements. We expect first fuel prices for coal and gas to remain stable and a normal supply of gas from Argentina and/or the LNG spot market. As a consequence, we expect lower average spot prices. And even if hydrology in the second half of 2024 is not expected to be as good as 2023. On top of that, we will see, during the second half of 2024, the ramp-up of our 342-megawatt wind project, Lomas de Taltal. So this means that we will have additional renewal generation this year.
And then on the liquidity side, the monetization of PEC receivables is progressing well, and we expect to be ready in the second half of 2024. And finally, we already executed the liability management to improve the duration of ECL's debt, where we continue working on other potential transactions for the future. So considering all these elements, we continue to expect to be, in 2024, within the $450 million to $500 million EBITDA range.
Next, Page 23 shows the detailed evolution of ECL's EBITDA, CapEx and leverage ratio, liquidity and leverage should improve under this new scenario. Then for 2024, we are in better position from an operational and risk perspective, considering the additional renewables, backup TPAs, the new contract to import gas from Argentina and the LNG availability. Then in 2025, we will have the full contribution of the new 342-megawatt wind farm Taltal and the full contribution of 3 storage systems or BESS with a combined capacity of 255 megawatts. While in 2026, we will have the full contribution of an additional BESS project, the one that is called BESS Tocopilla, with 116 megawatts more. This means, in this context, we expect a gradual improvement in ECL operational results.
And finally, to end our presentation on Page 24, we would like to share with you some structural messages. So first, reducing exposure to spot is key in our rebalancing strategy. Second, accelerating investments in renewals and BESS will enable us to better balance or to better be balanced since 2026 onwards. Third, we need to continue developing more renewable storage projects to be prepared for the next phase of growth. And fourth, we need to secure in this process, the liquidity and financing the best market conditions and keeping an excellent track record and access to the international capital market.
So with these final messages, we end our presentation, and we are now ready for your questions. So thank you very much for your participation and being with us today.
[Operator Instructions] The first question comes from Florencia Mayorga with MetLife.
Congratulation on the results. I have 4 questions. One is regarding if you can provide more color regarding any time frame regarding the PEC-3 monetization. The second one is perhaps -- more -- it's regarding -- do you believe that these PECs fee should be the end of the tariff stabilization? And the third one is regarding your thoughts on potential regulatory changes. There were some headlines about the Minister of Energy was thinking about to change the way on how the spot market currently works? And the other one is regarding how do you see -- even though you don't -- you didn't participate in the regulated auction, what's your sort of the regulated price?
Hello, Florencia, thank you for that. So first, on PEC-3. The schedule that we have today could take us to the third quarter of this year. So that's probably the best estimate that we have today. There are still several actions and milestones that need to be completed. But so far, everything is progressing very well, and all milestones were completed on time. So our best estimate today is the third quarter of this year. Now if this will be the end of this mechanism, well, this is the objective. The objective of the new regulation is to have a permanent mechanism, to end with the existing debt. And that's what we see today.
In relation to market design. Your third question was related to a potential change in how the system works today. Well, today, we are operating in marginalist system. And one of the alternatives that we could see in the future is to move to a different type of market, an auction market, like in other regions of the world like Europe, for example.
And this is part of the market design for the country and something that is going to be evaluated during the next years by authorities and the rest of the industry. And this is the result of how a system like Chile is evolving from a main thermal, let's say, market combined with hydro to a new system that will combine renewables with natural gas in the future. So that's why there is this task force and initiative to evaluate what could be the market design for the future. This will take some time, of course.
And the last one in relation to the regulated auction, well, what we have seen in this last auction is that prices are probably now reflecting the, let's say, trends that we have seen in the levelized cost of energy of new renewables. So that's why in this latest action, we see prices in the 50s range or in the 50s to 60s, which seems to be, in at least my personal opinion, more reasonable than the prices that we saw in the past or in the recent years, before this last auction.
The next question comes from Martin Arancet with Balanz Capital.
I have 2 questions. First, do you expect any cap savings by reusing the Tocopilla? And if so, how much? And my second question related to curtailment, as you mentioned, there has been some renewable energy losses in the system and the tendency seems to be to increase those losses. I was wondering what's your expectation on that topic? And if you think that, I don't know, batteries probably could be a quick solution for that or if the -- this problem is going to get worse in the next couple of quarters?
Martin, just to confirm your first question was related to cap savings?
Yes. CapEx savings.
Yes, indeed. Now clear. So yes, I mean one of the reasons why we are building storage BESS in our existing sites is that, of course, there are synergies and our synergies because we have the site. Usually, we have the permits, we have the connection we have a relationship with, let's say, the communities and the authorities around, and we have the expertise in the area. So that's why today, we are building best first in all our existing sites. That's why the first one was added in an existing PV solar plant.
And I will make the link with us -- with your second question because the curtailment is exactly why adding batteries in this type of PV solar plants makes sense because the capture price that we are seeing during the day, with our PV solar plants is very low. If you see the spot price in the north of Chile during the day, during several periods of time is almost 0. And this is, in fact, because there is an oversupply of renewable capacity, but they're also -- because there is some curtailment because this excess of production can be transported to other regions.
And that's why adding batteries in this context makes a lot of sense because we are able to charge these batteries during the day and to use them during the night, during nonsolar hours, when spot prices are not any more set by renewables, but are set by thermal power plants like natural gas or coal.
So that's why we do expect that curtailment will continue in the system, and this should be relieved or solved, hopefully, with the new transmission line, the HDVC transmission line, that will increase the transport capacity between the North and the center. But this is expected to be ready by the end of this decade basically.
The next question is from Fernan Gonzalez with BTG Pactual.
Hi, Eduardo, Bernardita, Marcela, I have 4 questions. The first one is that, on Slide 29, you mentioned that the CTA and CTH units will stop being based on coal in 2026. But there's no explicit mention to the biomass reconversion. Will this materialize? Or are you analyzing different alternatives for those assets?
My second question is on the best projects. And if you could share what the levelized cost of storage is for this type of projects, the ones that you're assuming at least?
And my third question is that you mentioned the additional capacity that you plan to add between '25 and '27, which is for almost 600 megawatts $900 million in CapEx. Will this project be built in the south part of the country? And how comfortable are you with the balance sheet to finance this?
We have 3 questions or 4? Sorry. 3, Okay.
The third one is sort of 3 and 4.
Okay. So let's start with the conversion to biomass. Indeed, so the initial plan for CTA and CTH when we announced their disconnection by December 2025 was to convert them to biomass. That was around 2019. Now the biomass market is not sufficiently developed to reconvert both units to biomass now. And this is why what we have today in our pipeline is to disconnect them in coal mode and to continue evaluating other alternatives for them.
So this means that we might keep them in multiple, multiple means that we will continue keeping them under let's say, maintenance with a limited CapEx per year until we find other options for them, which could be other conversion to other technology which could be to provide ancillary services to the system or if we don't find alternatives for them after some years, we will completely disconnected. But the biomass alternative, as of today, is not viable for CTA and CTH.
Then on the LCOE of BESS -- LCOS in this case, of BESS. I would say that this is in the $100, $120 range. based on public information coming from different sources. So those are the ranges that we have today for this type of technology. We know that exactly like with the other technologies that have been evolving in the last 15 years, we see a declining trend in this LCOS. So this could positively evolve in the next years. And as I was explaining before, having some synergies with existing operations will also be key.
And your third question was related were we plan to build a real wind capacity. So indeed, one of the main objectives that we have is to increase our presence in the center to South region because it is where we have less generation capacity. And part of our strategy is to have generation capacity in different regions and not to be only concentrated in the north of Chile.
And how comfortable are you with the balance sheet given this CapEx and the ongoing [indiscernible] that you also have?
Yes, with -- for the additional projects that we haven't yet committed to build. We still have enough balance sheet capacity to complete the plan. You can see that our net debt to EBITDA is around 4.3 in the first quarter, while our EBITDA and operational results will continue to increase this year and the next 2. And this will bring us additional balance sheet capacity to finance the rest of the plan, basically.
On top of that, don't forget that we have $333 million of PEC receivables that we need to monetize and that we are planning to monetize. So the net debt that we have today, which is close to $1.9 billion, this directly impacted in $333 million by the PEC. And that's why PEC is so relevant for us, and it's so relevant to find a solution for this mechanism that will be permanent to allow us to continue investing. This is the main message that we have.
The next question comes from Juan Carlos Petersen with Inversiones Chufquen.
Well, first of all, congratulations for the results for management, its a very significant improvement. I have 3 questions, please. The first one is related to the auction prices that we saw a few days ago, and that [indiscernible]. Given that do you foresee a positive impact on ECL's margins for '25, '26 and '27 for instance. Given -- and also given that we have that -- this public information now, would you be able to provide the guidance for a longer term, for instance, example, 3 years?
Second question or third question is regarding the likelihood of receiving a legal compensation linked to the gas supply issue last year. What is the legal process and its current status. I've seen some reports that you may receive a legal compensation, a significant legal compensation, but it's just -- I don't know if it is gossip or there is some substance on that.
And last question is based on the current results, which are very good and company is back on generating good cash and electric -- electricity margin that you show with -- I think it was 41%. It's a very strong one. In view of that, should the frame agreement for dividend distribution that was agreed a couple of years ago in an AGM will be well executed. This means distribution -- distributions in August '24, November '24 and in May as a final dividend for the 2024 results.
Thank you, Juan Carlos. Good question. So in terms of impact in ECL margin, there is no direct impact in ECL margin related to the recent regulated auction results. However, we do believe and we do expect that the pro rata share of ECL in the whole universe of regulated contracts will increase. So that's why we have seen a 10% increase in our regulated demand during the first quarter of 2024. Probably 1/3 of this increase is related to real, let's say, increase in regulated demand, but probably impacted by seasonality in January and February since we have seen more consumption during those months every year.
But the rest, the other 2/3 are directly linked to the fact that our PPAs will have greater load factor during the next years. Why? Because our PPAs were supposed to have greater load factor in the past 2, 3 years. But because demand didn't grow because there was some migration and because the growth in demand was probably overestimated at some point in time, our PPAs were having lower load factors. So we do expect that the load factor of our PPAs will increase over time. And this will bring, of course, a positive impact in our margin.
Then on your second question and in relation to the 4 LNG cargoes that were -- didn't deliver. What I can say, because as I explained before, following the confidentiality obligations in the contract, we cannot disclose any specific details is that there is an ongoing process and that we expect to have some results on that by 2025, not before. So this is an ongoing process. And once we have something to share, we will be able to share is the information once the process is finalized, but not before because this is a confidential process.
And in relation to dividends, we are coming from a difficult '22, we improved in '23, we are stabilizing our balance sheet in '24. In '24, of course, we expect better results than in '23. But since we still -- and we are still planning to invest in additional projects, I don't think that at this stage we will propose at least to increase dividends in the short term. And we will need to analyze this on an annual basis based on the balance sheet capacity and the final results. But we still have some milestones to complete in order to be fully rebalanced. So that's why in the short term, at least, I don't see an excess of liquidity to propose additional dividends.
Thank you, Eduardo, very clear. With regards to the first question regarding the guidance, would you consider to provide a guidance for, let's say, 2/3 years possible for the next management quarter call, would have been that possible given that now we have this new auction prices?
Let us see. Challenge accepted. We will see if we can come back with an additional guidance. Now that we are, let's say, in a more stable context. However, we have been always to -- let's say, bring the guidance for the next 2 years at the beginning of each year. But we can provide probably are some elements to be considered in 2026, for example, for our portfolio. We do know that '24, '25 and '26 are years that should not have a material change in terms of revenues. And then our main or the key elements to forecast the energy margin will come from the average supply costs for our portfolio of PPAs. And since we are adding more and more renewals and more batteries the supply costs should continue decreasing and this will bring additional operational results.
Sorry, Eduardo. We have another question from the webcast from Martin [indiscernible] from Fundamental Capital. He's saying, how should we expect contract prices to behave going forward on a consolidated level?
Okay. For 2024, the best estimate that we have, as of today, considering the fuel prices and the indexation formula of our regulated PPAs is that the monomic price of our regulated PPA portfolio should be in the 138 to 140 range. That's on the regulated side. While the unregulated should be the 100 to 110 range basically.
This concludes the question and session. At this time, I would like to turn the floor back to management for any closing remarks.
Well, thank you very much for your participation, and your questions, and see you soon or in the next quarterly call.
Thank you. Thank you very much for participating. Have a nice day.
Thank you. This does conclude today's presentation. You may disconnect your line at this time, and have a nice day.