ENGIE Energia Chile SA

SGO:ECL

Earnings Call Analysis

Earnings Call Transcript 2024-Q2

[Operator]

Good day, and welcome to the Engie Energia Second Quarter 2024 Results Conference Call. [Operator Instructions] Please note, this event is being recorded.

I would now like to turn the conference over to [indiscernible], CEO. Please go ahead.

[Eduardo Milligan Wenzel, executive]

Okay. Hello. Good afternoon, everyone. I'm here. I'm Eduardo Milligan from Engie Energia Chile, and I'm here today with Bernardita Infante, Alison Saffery and Marcela Munoz. So today, we will present Engie Energia Chile's results for the first half of 2024, and our view for the rest of 2024.

So we can start directly on Page #3. So in this page, we are highlighting the main drivers of our trajectory in 2024. So first, as we explained in previous quarters, we continue to see a positive evolution in fuel prices. which have remained stable, and this is positively impacting spot prices during this year.

Second, there is a positive effect coming from the new renewables, the contribution of batteries and the additional backup PPAs that we signed to hedge our exposure to the spot market risk.

A third element is related to tariffs, which decreased in line with lower fuel prices. This is why the average monomic price of our portfolio of PPAs in 2024 is around $30 megawatt hour below the average monomic price of the same period of 2023.

Then a fourth element is related to the lower dispatch of coal power plants, which is linked to the new renewables and improved hydro conditions. Then on PEC, we continue progressing and moving forward with the new structure to monetize these receivables. As of June 2024, we have accumulated receivables for around $329 million that are expected to be monetized in the second half of 2024.

We are, in this respect, intensely working on this project, knowing that these funds will be key to finance our future investment. Then we are also highlighting that we have accelerated the implementation of batteries to be installed in our existing operational sites.

So in 2024, we announced a new BESS project in Tocopilla site. And this means we will have close to 370 megawatts of batteries capacity. This last project is located in the same site in which we dismantled 2 coal power plants. And this comes with the additional objectives to provide continuity to the site.

And of course, our presence and relationship with the community. Then we also announced in 2024 that we have requested the disconnection of the last 2 coal power plants, named CTA and CTH by December 2025.

And finally, on the liability management side, we issued a 10-year $500 million green bond in the international capital market to fund the CapEx and to refinance short-term debt. In this line, our leverage or net debt to EBITDA ratio has decreased to 3.9x as of June 2024.

Now please let's continue on Page 4, which shows the evolution of ECL sales. There is a positive trend on both regulated and unrelated sales. Overall sales to customers increased 6% compared to previous year. The main variation is explained by sales to regulated customers that increased in approximately 11% as ECL is contributing with energy sales to a larger portion of the pool of regulated contracts.

On Page #5, we present the evolution of spot prices. The spot price decreased from average $87 megawatt hour in 2023 to an average of $62 in 2024. And this is, of course, positively impacted by the improved hydro availability, new renewals and also the lower fuel costs.

The historic evolution of hydro conditions then is shown on next Page 6 to make a link between these 2 pages. We are certainly glad to see a positive evolution for the market. So in terms of hydro generation as of June 2024, the accumulated probability of accidents is 53% and compared to the same date of last year, the current energy storage in reservoirs increased by approximately 1 terawatt hour.

Now we need to consider that during the first half of 2024, we were still benefiting from the good hydro conditions of the second half of 2023. Well, now for the rest of the year, we already know that July was a dry month, but spot prices were under control. And recently, we experienced heavy rainfall in the central region of Chile. So September and October will be key then to confirm hydro availability for the rest of 2024 and will give us some hints for the first half at least of 2025.

Then on Page 7, we present the evolution of coal prices, which in the last 9 months have remained on average at around $120 per ton. This is also positive since the production of -- the production cost, with coal will be again below $70 megawatt hour once the expensive coal stocks are fully consumed.

Next, Page 8 shows the evolution on the availability of coal power plants during the last 4 years. Other positive developments for the system is that the average availability has remained relatively stable in the last 2 years. at around 3.5 gigawatts. And we can also see, for the first time, a slight improvement during 2024.

Now we can continue on Page 9. The graph on top shows the evolution of International LNG prices, which have decreased in the last 9 months compared to the strong volatility experienced back in 2022 in the first half of 2023. This opens the possibility to buy LNG in the spot market and there to look for natural gas imports from Argentina. Again, other positive elements for the system since gas will continue to be key during the energy transition.

Then the graph below shows the LNG sourced by Engie and others through long-term contracts and the natural gas coming from Argentina, which, in our case, was imported to our pipeline in the North of Chile. And this is providing an additional an alternative source of natural gas for our gas power plants in the North. We didn't buy gas from Argentina in the first half of 2024. Since there were no signals on market needs [ nor ] prices. But this, of course, could change in the future.

Next, Page 10 shows the hedges or backup PPAs signed with other gencos. We didn't find additional hedges in the first half of 2024. We have 3.6 terawatts for '24, an average between 2025 and 2026. Now signing additional contracts will be always in this scenario opportunistic if we -- if we find a good match for the portfolio of PPAs.

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. This cost decreased 34% compared to the first half of 2023, given all the elements we explained before. And in addition, we can see a clear trend on how cogeneration is being gradually replaced by other sources.

On the other hand, the average monomic price of our current portfolio of PPAs also decreased, as we can see on next Page 12. Sorry, operator, I think your line is open. Also decreased, as we can see, yes, what I was mentioning now, we can move to Page 12, where we present the supply-demand curves for the overall portfolio of PPAs. We can see in this page that the average monomic price of our portfolio of PPAs reached $128 in the first half of 2024.

As you have seen each quarter, downstream prices or PPA prices declined gradually, and this decrease is mainly explained by the indexation or lower fuel prices. So this is just an mechanic impact on our portfolio of PPAs. And as I was explaining at the beginning of this call, this means a sharp decrease in prices of around $30 compared to the first half of 2023.

However, on the other hand, the average supply cost reached $73 compared to the $111 we faced during the first half of 2023. So this means both PPA prices and the average supply costs materially decreased. But the decrease in the average supply costs continue to be greater, and this is why our energy margin increased from $46 in the first half of 2023 to $55 megawatt hour in the first half of 2024. If you multiply the 55x energy we sold to our regulated and unregulated, you will find our S minus B margin or energy margin during the first half of the year.

Now to move forward, we will continue with Alison, who will present the detailed financial results for the first half of the year.

[Alison May Saffery Gubbins, executive]

Hello, everyone. I'm Alison Saffery, Head of Corporate Finance here in Engie. Welcome, everybody, to this call, and I'm continuing with Slide 13. Let's take a look at our financial highlights.

Our EBITDA increased by 56% compared to the first half of last year, and reached $294 million. Our total revenues, on the other hand, dropped by 22% to $934 million, mainly as a result of an 18% decrease in average realized prices to $128 per megawatt hour, reflecting the return of fuel prices to more normal levels.

On the contrary, physical energy sales increased as Eduardo said, by 6% to 6.3 terawatt hour, with growth driven by both fee clients and regulated clients, especially, but more evidently in the regulated space as a result of the natural growth and the increase in our pro rata share of regulated supply.

As we will clearly see in the next slide, our EBITDA margin recovered to 32% due to significant cost reductions, mainly explained by the drop in fuel prices and lower spot energy prices resulting from better hydrological conditions, lower fuel prices and greater availability of natural gas. In the first half, we reported a 17% increase in the energy purchases although we have reduced our exposure to the spot market during non-sun hours.

Energy purchases from the spot market climbed 59% to 2 terawatt hour. While purchases under backup PPAs increased 17% to 1.88 terawatt hour. These purchases were made at much lower average prices. Indeed, the average realized price of our energy purchases was almost half the price reported in the first half of 2023.

On our -- sorry, our own generation decreased. On the one hand, coal generation increased 40% to 1 terawatt hour because of the failure of our IEM plant in the first half of last year. And on the other hand, our gas generation fell 49% to 0.9 terawatt hour due to the fact that last year, we had tolling agreement with Keller, which hasn't been in place in the first half of this year.

Our renewable generation, including the output of our BESS Coya storage plant decreased by 4% to 0.78 terawatt hour, accounting for approximately 30% of our own generation. Our net income increased -- sorry, our net income reached $151 million, a significant improvement compared to the first half of 2023.

Slide 14 shows the main reasons behind the EBITDA recovery, lower fuel costs, the lower average price of our energy purchases and the increase in physical sales. These positive factors were offset by the decrease in average realized prices -- sorry, these positive factors offset the decrease in average realized prices. This explains the $105 million increase in EBITDA to $294 million, which is in line with the high end of our EBITDA guidance for the full year.

In Slide 15, we can see that net income more than tripled compared to the first half of 2023, reaching $150 million. This was mainly due to a 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 our coal production and an increase in net financial income. These positive factors were only partially offset by the negative exchange difference.

In Slide 16, we see the status of our net debt which increased by $158 million to $2.0 billion. After financing CapEx of $231 million and $78 million buildup of accounts receivable, resulting from price stabilization laws. This moderate increase in net debt compared to the investing activity was possible due to the strong operating cash flow generation, which reached $181 million, plus $49 million in proceeds from the sale of PEC-2 receivables in the first half of 2024, sorry.

On Slide 17, we're showing a summary of cash flows resulting from the price stabilization laws. 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 in 2020. All this represented sales revenues that could not be collected because of an enactment of price stabilization for regulated customers.

Thanks to 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 it had to bear a financing cost, 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 -- sorry, $11 million of interest income, which alleviated liquidity pressures in 2023. In the first half of 2024, the account receivable buildup amounted to $78 million. That is an average of almost $13 million per month, which we expect to decrease over the rest of the year as the gap between PPA tariffs and the stabilized prices should narrow.

In the first half of 2024, we completed the fourth and fifth sales of certificates of payments issued under PEC-2 and an aggregate amount of approximately $48 million. The last sale on under PEC-2 for $9.5 million took place on [ August 9, ] 2024. And in this way, the PEC-2 program ended after the 1.8 billion caps stipulated in the law was reached in March 2024.

At the end of June, the accounts receivable balance amounted to almost $329 million, plus $69 million corresponding to inflation and interest adjustments. The IDB and Goldman Sachs are working with the relevant government regulatory and rating agencies and the generation companies in the structuring of the PEC-3 program, which is similar to PEC-2 with an additional cap of $2.3 billion and partial sovereign guarantee.

Some steps required for the PEC-3 monetization have been met, including the publication of the Exempt Resolution setting the guidance for the laws implementation. Pending milestones include the stabilization fund regulation, [indiscernible] degree and the approval by the country controller. As soon as these milestones are met, the first sale of the certificates of payment could be [ before ] perfected, which we expect to happen during the fourth quarter of 2024. We expect to sell over $300 million certificates under the first PEC-3 sale. These funds will allow us to strengthen liquidity and finance our investment in renewable projects.

Now let's move to Slide 18. Our BBB stable outlook rating has been confirmed both by Fitch and Standard & Poor's. Net financial debt reached $2 billion at the end of June with net debt to EBITDA down to 3.9x. 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 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 the curtailment and intermittence associated with renewables. And third, to extend the maturity profile of our debt.

In April, we issued our first Green 144A/RegS bond in the amount of $ 500 million, which allowed us to redeem $250 million of our notes maturing in January 2025. And to fund our capital expenditures in renewables and best 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 June, which shows a significant reduction of our refinancing risk. As of the end of June, the average coupon rate of our debt was 5.6% and the average remaining life of our debt was extended to 5.1 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 of the action plans.

[Eduardo Milligan Wenzel, executive]

Thank you, Alison. So now we can continue on Page 19, where we are highlighting the actions taken to continue rebalancing our portfolio.

So first, we secured additional backup PPAs for 2024 and until 2026. Second, in 2024, we will have more than 1 terawatt hour of renewable generation, while in 2025, we will add an additional terawatt coming from wind Lomas de Taltal, our 342-megawatt wind project, which already started its energization and, of course, the new batteries that are currently under construction. As we highlight in this respect, we are adding additional batteries to our portfolio, and the idea is to reach at this stage, total capacity of around 370 megawatts, and we will evaluate additional projects for the future, of course.

Now this capacity will be key during non-solar hours, and as we mentioned at the bottom of this page, our total exposure not covered with our own assets during nonsolar hours could be closer to 1 terawatt hour compared to the 2.5 terawatts we had back in 2022. Now to clarify this figure, real purchases in the spot market could be above the 1 terawatt hour to nonsolar hours. But would become an upside, and this could be explained, for example, because of better hydro conditions.

But when we mentioned that the 1 terawatt hour is the exposure we have during nonsolar hour it means the exposure that is at risk basically or not covered with our own generation assets. As we explained in previous quarters, the exposure in nonsolar hours is the main risk we need to manage as part of our rebalancing strategy, and this is why we are investing in batteries.

Then on Page 20, we are presenting the evolution on our investment plan and the committed CapEx for 2024 and 2025. We are fully on track to reach 1.5 gigawatts of renewables plus batteries, and we expect to reach a ready-to-build status for other renewables and batteries very soon. So on top of these developments, we also confirm the conversion of IEM power plants to natural gas, which will be executed -- the work will be executed, in fact, during the first half of 2026. So this means the first half of 2026, IEM will not be available and will be converted from coal mode to natural gas.

Page 21 presents the detailed CapEx by type of business. We will be investing around $650 million in 2024 between renewables, batteries and transmission. As we know, these investments will contribute with an additional margin since each megawatt hour produced will be replacing energy purchases in the spot market. Now the figures we present in this graph are only considering the committed CapEx. So this means the figures for 2025 could increase once we approve additional projects.

Now in Page 22, we are updating our guidance, considering year-to-date results and our best estimate for the rest of the year. We are upgrading the guidance to the $475 million, $525 million range. On the left side, we described the main driver. So fuel prices are expected to remain stable, which together with current hydro conditions will continue to be positive for the market and the average supply cost of our portfolio.

On top of those market conditions, we will see during the ramp-up of our 342-megawatt wind project Lomas de Taltal that is expected to reach a full energization by the end of the current year. So this is a 342-megawatt wind farm that required a total investment of $468 million, and that will certainly be very welcome for our portfolio in 2025.

On the liquidity side, the monetization of PEC receivables is progressing, and we are targeting to monetize these receivables before the end of 2024. So this action is key, given its material impact to continue improving our leverage and will allow EECL to apply this cash for new investments in renewables and batteries.

Now next Page 23 shows the detailed evolution of EECL's EBITDA, CapEx and leverage. Liquidity and leverage should continue improving under this scenario.

And then finally, to end our presentation on Page 24, we shared some structural messages. So first, reducing exposure to spot is key in our rebalancing strategy; second, accelerated investment in renewables and batteries will enable us to do better balanced. This is why we will come back soon with additional projects. Third, we need to continue developing more renewables and batteries to be prepared for the next phase of growth. So this means on top of rebalancing the portfolio, prepare new investments if market conditions allow us. And fourth, we need to secure, in this process, the liquidity and financing of BESS market conditions while keeping an excellent track record and access to the international market.

well, we can end our presentation, and we are ready for your questions and comments. So thank you very much for your interest and participation with us today.

Operator, I think we can [indiscernible].

[Operator]

[Operator Instructions] Our first question comes from Martin Arancet with Balanz Capital.

[Martin Arancet, analyst]

Can you hear me?

[Eduardo Milligan Wenzel, executive]

Yes. Operator, I think there is an open line, which is not ours. If you can help us with that, it would be great.

Martin, I think we can continue with your questions.

[Martin Arancet, analyst]

Okay. I have 2 questions. First, well, you already mentioned something about it but it will be great to clarify how much do you have still on receivables under each of the 3 PECs and when we expect to collect that? I mean you already mentioned something about $300 million in the first monetization of PEC-3 but I guess that the PEC-1 and PEC-2 have different timings. I don't know if you have some of those.

And then my second question is from what we know about the batteries. You decide when to charge them as if you were a consumer but the cardinal determines when they discharge -- when to discharge those batteries. I was wondering how this works in terms of profitability for you guys since if it gets this chart dispatched according to the merit of the marginal cost. The marginal cost will be the charging price. So I was wondering how that works and what is the IRR that you are aiming with those projects, if you can disclose this?

[Eduardo Milligan Wenzel, executive]

Okay. Thank you, Martin. First, in relation to PEC. So PEC-1, we already sold all those receivables. And basically, as you can remember, we have seen the financial costs in that case. So for every dollar, we only collected around $0.80. So that means the financial cost was assumed by generation companies during PEC-1. In PEC-2, we already sold 100% of those receivables, the last receivables were sold last week, and we collected the last $10 million last Friday. So that means PEC-1 and PEC-2 have been already monetized.

While what we have accumulated as of June 30 in relation to PEC-3 in terms of receivables is $329 million, which we can see on Page 17. And on top of the receivables, we will also have the right to collect around $69 million, which is related to the interest adjustment because of the delay on the collection of those receivables, plus an inflation adjustment on those receivables because of when those decrease should have been published.

So all in all, we still need to collect close to $400 million related to PEC-3. Around $337 million should be monetized in the PEC-1. That's what we expect to collect before year-end. And the difference should be collected in the first quarter of 2025. So that's the first one.

And in terms of BESS today, battery are -- we can decide when to charge our batteries and we are also, at this stage, deciding when to discharge them. So it's not at this stage, the market coordinator who is defining when you can discharge these batteries. The operation behind installing batteries in Chile and in other markets, which have a similar situation like Chile, is to charge them during the day when spot prices are very low and discharge them during nonsolar hours to replace other expenses generation coming from coal, coming from natural gas or coming from diesel.

So this means charging them at the lower cost possible, probably between $0 and $10 during solar hours and discharging them, for example, during the first half of this year at around $70 or $80 per megawatt hour. So the arbitrage can from this difference. And on top of that, there is a capacity remuneration recognition for this type of battery, which probably brings the all in to around $100. So this is the $100 that batteries, for example, in the first half of 2024, are capturing in relation to BESS Coya, and we have around 100 gigawatts hours that were injected by these batteries during nonsolar hours over the first half of 2024.

[Operator]

And the next question comes from Fernan Gonzalez with BTG Pactual.

[Fernan Gonzalez, analyst]

Eduardo, you had mentioned in earlier calls that you wouldn't compete for new PPAs until 2028, 2029 when your portfolio would be more balanced. Has that changed? Because you mentioned here that you are now accelerating the development of renewables and storage. So are there any updates related to your medium- to longer-term commercial strategy or not?

[Eduardo Milligan Wenzel, executive]

Fernan, very good question. Yes, as we become, let's say, more balanced over time and that we have more visibility on how the market is evolving. First, we need to see how we're going to contract our portfolio of assets because, as you know, the average life of our portfolio goes until 2033 on average, let's say, for the next 10 years. However, we need to start contracting our portfolio and the assets that today we are building before that. So this means that our commercial activity could be around the corner on that side.

And besides that, today, our market share is around 15%. We have sales for around 12 terawatt hour per year. So this means also that we need to clarify, and this is part of the strategy that we need to define once we are rebalanced and once we start recontracting our portfolio, that would be, of course, a target market share, which will, of course, come with additional investments or could come with additional investments in the future. So this means that right now, we are not only fully focused on being rebalanced but also in analyzing further opportunities to capture, let's say, additional PPAs for the medium and long term. So the answer is yes. It's not a full switch but it's part of the activities that we need to start implementing once we are more balanced.

[Fernan Gonzalez, analyst]

Great. Just to follow up here. I mean it doesn't sound like it's imminent but the idea would be to perhaps maintain the 15% market share by 2030. Is that something that you're analyzing perhaps?

[Eduardo Milligan Wenzel, executive]

It's -- yes, it's something that we are, of course, analyzing and what would be the, let's say, the market participation that we would like to target. This will, of course, depend on several factors in the new market design and business opportunity and regulations. But of course, we are interested in continue investing in Chile.

[Fernan Gonzalez, analyst]

Just my final question on this topic is, what would be the strategy for that additional energy sales? Would it be sourced with new developments of renewable assets in storage? Or would you consider also adding more backup PPAs?

[Eduardo Milligan Wenzel, executive]

We have been always, let's say, seen the backup PPAs as an additional source of supply for the portfolio. Sometimes are opportunistic and sometimes are to reduce risk. Our main intention, of course, is to supply new PPAs and the PPAs that we will contract with our own generation and using all the sources that you mentioned. And on top of that, if there is a possibility to let's say, add backup PPAs or hedges like the ones that you can see in other markets in which you have forward electricity prices, here, we don't have them but what we have is this possibility. This could be complementary. But our main objective, of course, is as of an industrial company to supply PPAs with our own assets.

[Operator]

And the next question comes from Andrew McCarthy with LarrainVial.

[Andrew McCarthy, analyst]

Eduardo and the team, my first question, I was wondering there was some news recently about the shipment of LNG from your supplier that didn't -- that won't be delivered. I was wondering if you could shed light of that comment on gas supply in the second half of this year. And also whether you're seeing any -- given also how -- what you commented about the positive hydrology, whether you're seeing any opportunities for maybe some commercialization of natural gas later this year?

And my second question, just wondering if you're providing any net income guidance for this year, 2024? And particularly there, are you seeing any possibility of any more write-offs in particular related to the coal-fired plants? I know you mentioned during the presentation, Eduardo, that I think the first half of 2026, you're going to be doing the conversion of IEM but just wondering, related to the coal plants, if there are any more write-offs that could occur this year and therefore, impact the potential for the payment of dividends on 2024 net income?

And then finally, I just wanted to touch on the new CapEx forecast for this year and next year. I noticed they moved up even though there aren't sort of any more specific announcements on new projects. So just wondering if you could help us bridge -- understand the bridge between the old figures for 2024 and the new ones -- old figures for 2024 and 2025, and the new ones, that would be really helpful?

[Eduardo Milligan Wenzel, executive]

Andrew, sure. Well, first question in relation to LNG. So indeed, 1 LNG cargo was not loaded, and this is unfortunately explained because of Hurricane Barry, the last one, which impacted Freeport. And unfortunately, we didn't receive this additional cargo. Now considering spot prices this year, and where LNG spot prices are, the impact this time is not as big as it was back in 2023.

And this also can -- in relation to your second question on how a better hydrology could open opportunities in the gas side, indeed, there could be a possibility not only to import gas from Argentina. This will, of course, will depend on the gas price. We didn't import any gas during the first half of this year because of the price at which we could have imported the natural gas, it made no sense for us. Now if the gas price changes in the future, then this could be an opportunity on the import side. But this also opens a possibility on the export side because we can try to export the LNG from time to time, and maybe during the winter to Argentina when we have better hydro conditions. As you have seen in the past in Chile where some generation companies, let's say, diverted or resell some of the natural gas of their portfolios. And in relation to -- so this is an open, let's say, possibility and we will see if we find the commercial ground for this type of exchange. The good news is that the window is open also to import or to export. And this will, of course, bring the opportunities in the future.

And in relation to net result, I think, as you know, the net result in the first half is impacted by a one-off of around $50 million, which is the recognition, Alison, explained related to PEC. So there is around $50 million. And the other $100 million, it's related to our, let's say, recurrent business. So we can probably see something in that line. We do expect the second half to be similar to probably the last months as we have moved forward with a good July. So we could expect a good second half also. And you can try to extrapolate that recurrent results of the first half, probably to the second.

In terms of write-offs, we do not have any plan on write-offs. We did most of them or all of them last year or during the last 2 years. So in our plan, we do not have, let's say, any view on that but we will need to follow the impairment test process every year, and then we will see. However, given the current results and what we already impaired in the last 2 years, we already impaired all of them. And in the case of IEM, which will be the only coal power plant that will remain after 2026. It has also been partially impaired during the last 2 years, where all the others have been fully impaired. So this means that it's not something we should expect.

And in terms of CapEx. Yes, in terms of CapEx, we adjusted the CapEx because instead of paying some of this CapEx in 2026, we expect to pay it in -- sorry, in 2025, we expect to pay this in 2024. And this is because the batteries project are well on track, the same with Total. So initially, we were forecasting that some CapEx could be delayed. But now we are being, let's say, more conservative on the CapEx for this year because projects are progressing very well on that side.

[Operator]

And the next question comes from Florencia Mayorga with MetLife.

[Florencia Mayorga, analyst]

Eduardo, Congratulations on results. And just a question regarding the leverage of 4x. So this figure already [indiscernible] the monetization of receivables for this year. And a follow-up on that is regarding assuming that the company decides to maintain the market share, what's the leverage target that you have going forward?

[Eduardo Milligan Wenzel, executive]

Florencia, well, the leverage as of June, it's only including the monetization of PEC-2. So the forecast includes the monetization of PEC-3. And considering our operating cash flow [Technical Difficulty] future EBITDA that we expect during an intense, let's say, CapEx phase is to be in the 4%, 4.5% range as I think it was also mentioned by rating agencies recently.

[Florencia Mayorga, analyst]

Okay. And just a follow-up regarding CapEx. So the increase on the amount that you are expecting to invest this year is only regarding acceleration on the battery side but there is some inflation cost on that or only the new project?

[Eduardo Milligan Wenzel, executive]

No. It's only the new projects and the projects that are already committed in our pipeline.

[Operator]

This concludes our question-and-answer session. I would like to turn the conference back over to Eduardo Milligan for any closing remarks.

[Eduardo Milligan Wenzel, executive]

Well, so that's all from our side. So thank you, everyone, for your participation today, and see you soon, see you around, see you in the next quarterly call. Thank you very much again.

[Operator]

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.