Engie Energia Chile S.A. (ECL) Earnings Call Transcript & Summary

Good afternoon, everyone, and welcome to Engie Energia Chile's Third Quarter 2023 Results Conference Call. If you need a copy of the press release issued on November 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.

Good afternoon. I'm here with Alison Saffery and Marcela Munoz. Today, we will present ECL results for the first 9 months of 2023. And we also intend to discuss our guidance for the rest of this year. And we can also provide some views on our business plan for next year. So we can start already on Page 4. On the left side of this page, we are highlighting the key elements to understand our performance as of September. While on the right side of this page, we will present the main drivers for the last quarter. So on the left side, first, fuel prices fell in 2023 compared to the record highs of last year. So we have all seen this during this year, and this is obviously positive. On the revenue side, we have a positive impact mainly during the first half of 2023, explained by the indexation lag in our regulated PPAs, while prices are starting to decrease since the third quarter, and this trend will continue in the fourth quarter of this year. As you know, this year, also, our LNG supplier didn't deliver a contractual volume of around 13 TBtu, and we were forced to replace these volumes with a spot LNG. But as you can imagine, at higher costs. We imported spot LNG for approx 14 TBtu. So it's slightly above the contractual volume that was not delivered. And these volumes have been key to partially mitigate the impact in our average supply cost or exposure to spot market. But as I said, at higher cost. Then on production and supply costs, we have different impacts were negative related to IEM and availability between February to May. And on the other hand. We have a positive impact related to an increased renewal generation, a larger volume of backup PPAs or hedges that are signed with other gencos and better hydrologic conditions and other market conditions that moved in the positive direction. Finally, one of the main impacts on liquidity was related to the PEC and MPC laws to stabilize regulated tariffs. We were able to monetize in the first 9 months of 2023, around $238 million, which provided some relief to improve our liquidity. Then as of September, we still have close to $300 million of accrued receivables, of which we will monetize around $40 million in the last quarter of 2023 and the remaining amount will be part of the [ amortization ] program for the future. Now on the right side of this page, we are highlighting the key elements that will help us to understand what can we expect for the last quarter. First, hydrology. There is a material improvement in hydrology for the 2023-2024 season. On the revenue side, as I said before, we expect lower regulated prices since tariffs are already reflecting the lower coal and gas prices in the indexation formulas. Other positive key milestone for us is that after more than 13 years, we were able to sign a contract to import gas on a firm basis from Argentina in the northern region of Chile. So these are, of course, good news for the northern Chilean system. Then transmission bottlenecks continue to be an issue for the systems efficiency. And finally, the improved operational results together with a $400 million sustainability-linked loan we signed with the IFC. And of course, the explicit and support with the credit line have allowed ECL to improve its debt maturity profile and also allow the rating agencies to confirm our BBB rating. Then let's move to next Page 5, in which we show the evolution on ECL's physical sales. Total sales are pretty stable, which, as you know, it's one of our main strengths. There is a specific decrease in regulated clients demand linked to a program maintenance on the mining side. While on the positive side, there is a 6% increase in regulated demand explained by our larger participation in the pool of regulated PPAs. And this is, of course, positive. On Page 6, we can see the spot price evolution and how the system switched from average $127 megawatt hour in 2022 to $102 megawatt hour as of September 2023. But bear in mind that the average in the first half of 2023 was $129 megawatt hour. So this means average spot prices in the second half of 2023 are far below the average prices over the last 12 months. Next, Page 7 presents the detailed evolution on hydrology, which shows a material improvement compared to all previous years. As of end of October, the accumulated probability of exceedance is 58% compared to 78% as of June and an average 95% in previous 2 years. So this improved hydrology together with new renewals and lower fuel prices are currently setting spot prices during solar hours close to 0 on spot prices during nonsolar hours to close to $80 a megawatt hour. And this is reflected in the current daily average spot price of around $40 megawatt hour. Then if we move to Page 8, we can see the positive evolution in coal prices. After hitting all-time highs in 2022, coal prices have returned to $140 per ton. At $140, the production costs with the coal power plants decreases to around $70 megawatt hour. So the coal futures have remained stable, and this will be positive for the overall cost of the system since we and of course, the other gencos have already sourced new inventories at these prices that will help to keep the spot price under control. This also means that the electricity produced with coal power plants is again cheaper than producing with spot LNG. Next, Page 9 shows the evolution of coal power plants availability for the overall system. Again, other positive element for the system is that coal power plants availability remains stable at around 3.5 gigawatts in 2023 and didn't continue worsen. Now let's go to next Page 10 to discuss about LNG and natural gas. The graph on top shows the evolution of international LNG prices. As you know, the evolution of JKM and TTF indexes allowed us after several efforts and action plans to import spot LNG in 2023 to partially mitigate the lack of LNG that was not delivered to us. But as I mentioned before, at higher cost. Then the graph below shows the LNG sourced through firm long-term contracts and the natural gas coming from Argentina. As I explained before, since October and until April of next year, we will also be importing gas from Argentina through our pipeline in the north of Chile, which will provide an additional source for the system that is positive since natural gas provides flexible generation, which will be and is key to a company renewals during the energy transition. On the LNG side, as we also explained in our last call, we have 2 long-term contracts with [ firm ] aggregated volume of 23 TBtu per year. In 2023, one of these contracts was confirmed by our supplier for about 10 TBtu. For the second contract with a volume of about 13 TBtu was not confirmed. And as I mentioned before, we sourced through spot purchases in the international market. Next, Page 11 shows an update on hedges or backup PPAs signed with other gencos. This page shows an additional volume of backup PPAs signed for 2023 and 2024 compared to previous years. And compared to the previous quarters also. In summary, we have average 3.3 terawatts hour of hedges contracted with other gencos for 2023 and 3.4, 3.5 terawatts hour per year for the 2024, 2026 period. So this will also provide us an additional hedge during the transition period in which we are implementing new renewals and start solutions for the portfolio. Page 12 shows a graph with the energy sources on average supply cost for the portfolio. Our main objective is to rebalance our portfolio as fast as possible to reduce risks and also the exposure to spot market volatility, mainly during nonsolar hours. The graph shows that the average supply costs materially increased between 2021 and the first half of 2023. While in the third quarter of 2023, there is a sharp decrease, which is driving the improved operational results. Next Page 13, we present the usual supply-demand curve for the overall portfolio. The average monomic price in the first half of 2023 reached $182, while the average monomic price as of September decreased to $171. This [ increase ] is mainly explained by what I mentioned before, the indexation lag on regulated PPAs, which are now reflecting the lower fuels that we have in the market. On the other hand, the average supply cost as of September 2023 reached $124 compared to $130 that we presented at the end of the first half of 2023. So this means despite the average price decreased in $11, the average supply cost decreased in $13 and this represents a margin of around $47 as of September, which we expect could remain relatively stable for the last quarter because the average PPA prices will decrease but the average supply cost should also decrease. We will see at the end of the year, if both variables decreased in the same proportion or not, but the difference should not be material. To give you further context, the $47 margin we are presenting as of September is similar to the average margin we had back in 2019 or 2020. So now we will continue with Alison, who will present the detailed financial results and related action plans to improve our leverage and liquidity.

Thank you, Eduardo. Good afternoon to everyone. Let's start on Slide 14 for a closer look of third quarter results. Our EBITDA almost tripled compared to last year. Actually, for the first 9 months, EBITDA reached $312 million, 165% higher than the same period in 2022. Total revenues increased by 23% as a result of the recovery in the demand from regulated customers as well as a high average monomic prices. Physical sales decreased by 1%, with an increase in sales to regulated customers and a decrease in sales to free clients that Eduardo mentioned earlier. Gas sales also increased significantly as in the first half of 2023, the company bought enough LNG volumes to generate electricity. At its own plant and through a tolling agreement that we have with Keller that we currently have with Keller as well as to sell gas to other companies. Our generation costs remained high as the fuel used in generation came from high-priced stocks built up in 2022. Despite marginal costs decreasing during the third quarter of 2023 due to a higher hydro generation, which has remained -- they will improve hydrology in that period. However, sales prices increased further, explaining the margin widening. To meet our sales commitments, we bought 25% of total volumes from the spot market down from 37% in the first 9 months of last year, in line with our strategy of reducing our exposure to spot prices. Energy sourced through backup PPAs represented 25% of our total volumes sold, up from 16% in the first 9 months of 2022. Renewables accounted for 27%, up from 16%. Gas production, including energy generated at our own plants and through the tolling agreement with Keller increased to represent 54% compared to 24% last year. This was possible thanks to spot LNG purchases, which allowed us to secure LNG supply volumes despite the fulfillment of one of the 2 long-term gas supply agreements by our main LNG supplier. In short, greater renewables and gas production plus the backup PPA volumes are allowing us to close the gap between our sales commitments and our generation so as to reduce our exposure to the spot market. Net results reached $70 million -- sorry, I have a gap here in the presentation. Net results reached $70 million at turnaround from the $58 million net loss reported in the first 9 months of last year. We note that one-off items were bigger this year as the company reported $12.6 million in financial expenses related to the sale of accounts receivable from distribution companies affected by the price stabilization law the so-called PEC 1. In 2023, we sold a nominal amount of $51 million of account receivables, which represented the lost sales of PEC 1 mechanism, while overall, since the PEC 1 monetization started in January 2021, the company sold accounts receivables totaling $273 million. It received $196 million in cash proceeds and accounted for financial expenses of $77 million under this first program. Additionally, in August 2023, we sold an equivalent of $200 million of accounts receivable related to the second price stabilization law called MPC or so-called PEC 2 mechanism. In this case, the government of Chile issued certificates of payment guaranteed by the state thus representing a nonrecourse to sale, which also generated a payment of interest for approximately $10 million for the first monetization exercise. After this monetization, further sales certificate will occur every 2 months for accounts receivable accumulated from July 2023 onwards. Actually, we received -- we did the second monetization in October, where we received approximately $10 million. And we will probably receive further amounts that will help us total around $40 million for what's remaining in the year. Our net debt, excluding IFRS 16 leases increased significantly throughout 2022 as we had to finance capital expenditures as well as the heavier working capital needs due to the steep increase in fuel prices, while the price stabilization law compressed our liquidity. Net debt reached $1.65 billion in year-end 2022. Through the first 9 months of 2023, we have been focusing on reducing our leverage ratio while extending the average maturity profile of our debt. So in spite of the continued CapEx required for our transformation program, our net debt as of the end of September continues to be only slightly higher as the level reported in the end of 2022. If we go to Slide 15, it shows the reasons behind the EBITDA recovery. Clearly, average realized prices captured the increase in fuel prices and inflation observed in previous months. Net energy purchases decreased in volume, and they were made at lower prices in the third quarter of this year. The increase in physical sales were explained by higher demand from regulated clients, which compensated for the decrease in free clients. On the other hand, net capacity purchases increased as well as OpEx and SG&A, mainly related to the addition of new operations and renewables. There was also a lower margin for the gas business. All of these effects could not offset the higher prices and lower net energy purchases mentioned. Therefore, EBITDA reached $312 million, 165% increase compared as for -- as to the first 9 months of 2020 -- '22. In Slide 16 we show the evolution of our net results. The turnaround is mainly explained by the EBITDA recovery. Also, insurance recoveries and depreciation ForEx exchange difference also contributed to mitigate the $32 million increase in interest expenses. As a result of the above, net income before one-offs increased from $47 million loss to an $89 million profit in the first 9 months of 2023. In terms of one-offs, while the first 9 months of 2022, we reported $11 million in interest expenses related to the sale of PEC receivables, in 2023, we reported a $9 million after-tax effect in the last sale of PEC 1 receivables and a $10 million impairment. These impairments are mainly related to impairments of assets such as, for example, the return of an onerous concession on the Pampa Yolanda site. As a result, net income was $70 million in the first 9 months of the year. On Slide 17 -- let's go to Slide 17 to discuss the evolution of the net debt. This shows that despite capital expenditures of $375 million and accumulation of PEC accounts receivable for $210 million, our net debt increased by just $59 million to $1.7 billion, given the recovery of our operating cash flow as well as the proceeds from the sales of PEC 1 and PEC 2 receivables. The debt figures exclude $104 million of financial leases related to very long-term and land lease contracts. Our cash from operations before the effect of the PEC receivables buildup reached $449 million in the first 9 months of the year. And we also reported $38 million in cash proceeds from the last sale of PEC 1 receivables and $208 million from PEC 2 receivables. In Slide 18, we see that the status of our debt as of the end of September. Gross tax, excluding financial leases reached $1.9 billion, Net debt to EBITDA reached 4.4x, a significant improvement compared to the record high 8.7x at year-end 2022. We have continued to make progress in reaching our 3 main objectives related to our debt profile. First, to reduce our net debt to EBITDA through EBITDA recovery by maintaining net debt relatively flat despite the financing of our capital expenditures in renewables and transmission projects. Second, to secure funding for the construction of the Lomas de Taltal wind farm, BESS Coya and BESS Tamaya storage projects, whose objectives are to reduce our costs, our exposure to the spot market and curtailment and intermittence and risks associated to the PV plants. And third, to extend the maturity profile of our debt. On the bottom left corner of the slide, we show the maturity schedule of our debt as of the end of September. I will ask you to jump to Page 23 for a moment for an update on recent events. The first state of the monetization of receivables related to the price of the station law that we call PEC 2 structured by [indiscernible] with the participation of Goldman Sachs, JPMorgan and the [indiscernible] bank concluded successfully with the 144 A and 4a2 issuances in August. From the proceeds of the bond, we received approximately $200 million in cash funds plus interest, corresponding to the first sale of certificates of payment issued by the Chilean treasury. After this first sale, as mentioned before, we have continued to, with by monthly sales of certificates of payment with the first of this these occurring in October for approximately $10 million. We expect to receive a third monetization in December for amounts accumulated between August and October 2023. As we have previously shared with you, on June 20, we signed a $400 million 10-year loan with the IFC and the German Bank DEG. On June -- sorry, on July 28, we made a first disbursement under these facilities for a total amount of $200 million, and we closed an interest rate swap to reduce the exposure to interest rate risk. We expect to complete a second disbursement under the facility before the end of the year. These 2 transactions have helped us reprofile our short-term debt and to finance our CapEx needs for the 2023 and 2024 period. Indeed, in the first week of August, we repaid short-term debt for $125 million, including the $75 million loan from related company [indiscernible]. On our credit ratings have been conferred by at BBB, both by Fitch and Standard & Poor's. As discussed in the past call, last March, Standard & Poor's placed our rating in credit watch negative due to liquidity pressures. In September, S&P lifted the credit watch negative, confirming Engie Chile's rating as BBB with a stable outlook, considering that both liquidity and leverage has been strengthened. This trend has been confirmed in the third quarter in terms of liquidity. We still have mentioned -- the mentioned undrawn amount of $200 million of the IFC and DEG loans. We have registered local bond lines, which we might use to reduce debt. Now I'll leave you with Eduardo, who will brief us on the recent events and action plans for 2024.

Thank you, Alison. So the actions are described on Page 19 are driving our improved operational performance in 2023. So first, as we mentioned before, we secured 24 TBtu of LNG for this year. And we also implemented a tolling agreement with the Keller CCGT. In some minutes, I will explain our view for 2024. Then as you know, I'm -- came back in operation after having an important failure at the beginning of this year. Third, we secured additional backup PPAs for this year and we have been signing additional ones until 2026. Fourth, in 2023, we have additional 0.9 terawatts hour from renewable generation. And finally, on the development and construction side, but there is -- are underway. So BESS Coya is very close to COD. In fact, the commissioning phase already started and some batteries are already injecting electricity during nonsolar hours. While in parallel, we launched the construction of a second storage project as an add-on to solar plant Tamaya. So between both start systems, we will have more than 1 gigawatt hour per day to support the system and our portfolio during nonsolar hours. As a result, as we highlight below the spot exposure during nonsolar hours is expected to be close to 1.5 terawatts hour in 2023, which, as you can see, is materially below the 2.5 terawatts hour we had in 2022. And this position will continue to improve in 2024. As you can also see, we are highlighting the exposure during nonsolar hours because this is when spot prices could be out of control and there are certain circumstances like the ones the system experience in 2022. So our main goal is to reduce this exposure during nonsolar hours. On Page 20, we are presenting the evolution and our investment plan and the committed CapEx for 2023 and 2024. Once we complete the now 3 projects under construction, we will have reached 1.4 gigawatts of renewable storage and we expect to reach a ready-to-build status for other projects very soon. So this means that since we started our transformation plan, we have already -- or we are already implementing 1.4 gigawatts of new capacity for Engie Energia Chile. Then Page 21 presents the detailed CapEx by type of business. On top of the $700 million we are investing in renewables and storage between 2023 and 2024, we are also investing $190 million in transmission projects. This is also why our leverage is not declining at a faster pace because we are investing an important amount in new CapEx, which once ready, of course, will contribute with higher operational results. Now in Page 22, we are showing an upgraded guidance for 2023, in which our view for the last quarter of 2023 is positive and market conditions could remain relatively stable even during part of the first quarter of 2024. Most of the impacts on the left side of this page are in green, which are reflected in the upgraded guidance, that is shown in the graph on your right. And now we are presenting a midpoint for the 2023 guidance of around $400 million. The graph also shows the expected CapEx and net debt EBITDA evolution considering the updated fuel price and the actions we explained before. And in this line liquidity and leverage should also improve in this new context and following our updated business plan. For 2024, we are certainly in a better position from an operational and risk perspective, considering the additional renewables, the additional storage with batteries, the additional backup PPAs, the new contract to import gas from Argentina. And also because we have recently confirmed to the GNL MEJILLONES terminal that in 2024, our LNG supplier will be delivering the full LNG volumes contracted with the ECL. So this means the full 23 TBtu. On top of that, we also sourced additional 2 TBtu from the local market for 2024. So this means we will have around 25 TBtu of LNG in 2024. In terms of electricity, to give you a more articulation 25 TBtu will be equivalent to 3, 3.3 terawatts hour per year, which, of course, will be key to reduce our exposure during nonsolar hours. So in this context, we expect to have a short exposure during nonsolar hours of less than 1 terawatts hour in 2024. Compared to what we mentioned before, we had around 1.5 in 2023 and 2.5 in 2022. So this will, of course, is positive because we reduce risks and volatility for our operational results. So finally, to end our presentation with some key messages. Please let's move to Page 24. So in summary, we are on track to rebalance the portfolio. Our batteries project, BESS Coya will be ready very soon and BESS Tamaya is expected to be ready in 2024. Both will contribute with more than 1 gigawatt hour per day. While total 343 megawatt wind farm, we'll continue its construction during the whole 2024 to continued in 2025 with new renewable generation for the portfolio. And in between, we expect to launch the construction of additional projects between batteries and wind. Also, in this context to reduce volatility and risk, we also secured a additional hedges for June '23, as we mentioned before, but also for the 2024, 2026 period, which will also provide us more stability on our average supply cost. And in summary, all actions, together with better market conditions have allowed us to improve our operational results, also have allowed us to upgrade our guidance for the year. While the updated scenario for 2024 seems to be positive with a less volatile market context with improved hydro conditions at least during the first quarter of 2024 [Technical Difficulty].

Pardon me. This is the conference operator. We seem to have lost the connection with Eduardo. [Operator Instructions] Pardon me, this is the conference operator. The speaker lines have reconnected. Mr. Milligan, you may continue.

Sure. We are ready for questions. So maybe we can continue with the Q&A.

[Operator Instructions] Our first question today is from Martín Arancet with Balanz Capital.

Well, first, congratulations on the results. I have 2 questions. I would like to run them one by one, if that's okay. First, what options for LNG procurement are you thinking about for 2024? And how is the arbitration for the 2022 LNG volume with Total going?

Sorry, Martin, can you please repeat the question?

Yes. Can you hear me?

Yes, I can hear you now.

Okay. Yes, I was wondering what options for LNG procurement are you thinking about for 2024? And how is the arbitration for the 2022 LNG volumes with Total going?

Okay. Martin, so first, what we were explaining is that for 2024, Total has confirmed us that the full volume related to Contract 1 and to Contract 2 will be delivered to ECL in Chile. So this means that we do not need to source additional LNG in the spot market.

Okay. Great. Second question then the new gas swap contract with Argentina producers. Could you comment a little bit more on how that works regarding the production in the South and the delivery in the North? And also, should we think about 0.4 million cubic meters per day size on a year-round basis or only up to 0.5 million cubic meter per days on certain moments of the year?

Sure. So the contract we signed with Argentinian producers, it's basically with 2 of them to deliver up to 0.4 million, as you said, in the north of Chile, between October and April, and this is on a firm basis. So this means it's a take-or-pay, let's say, and the obligation of deliver this gas in the north. So during this period. So basically, you know during the summer. Now we expect at some point in time that there could be in the future the possibility to increase exports from Argentina, our imports from Chile, if, let's say, there is available gas in Argentina. So the good news behind this is that -- this is the first time after 13 years that gas is being exported through the northern region. And as we saw in the center, this could be something that could be increased in the future, if possible and if the price is, let's say, giving a good signal for import gas from Argentina in general compared to the other sources that we can have in the north of Chile, of course.

[Operator Instructions] You next question is from Fernan Gonzalez with BTG Pactual.

Eduardo, I have 3 questions. The first is that you said that the recontracting activities postponed until you rebalance your portfolio which you expect in 2028. But do you have an interest in participating in the upcoming regulated auction in December as the supply of that contract starts around 2028? Or do you completely rule out this possibility too? And the second and third questions are related to the LNG supply for next year. It's good that you managed to confirm the deliveries from Total, but due to the drought that the Panama Canal has been facing and the restrictions being implemented on transit that will actually get worse over the coming months, and we have no idea how those would be from the second quarter onwards. What's the scenarios that you foresee that could happen because most of the LNG that is imported into Chile goes through that canal. And it seems it might be a problem next year. Do you have a plan B in case this happens? What are the conditions that Total may have? If you can comment a little bit about that? And the second part related to the LNG is the additional 2 TBtus that you acquired or you committed in the local market, is that because the tolling agreement with Keller will continue next year as well?

Thank you, Fernan. So let's go one by one. So in terms of -- we're balancing the portfolio. Indeed, our objective is to rebalance as fast as possible our portfolio between 2026 to 2027. The new regulated option is still programmed for -- by the end of this year. So far, we believe that these actions will take place every year. So indeed, right now, we are fully concentrated on basically rebalancing our portfolio and not to add additional commitments in the future even if they start in 2028. As you know, we will become -- we will start to become uncontracted, and we will have some room starting 2033. So we have some time -- we still have some time to prepare our participation in future actions. Then on the LNG, it is indeed an issue in the Panama Canal. We have seen that the number of vessels per day have been restricted and will be restricted in the next months. But on the LNG side, there is a priority because of...

Refrigerated -- sorry, Alison here, certainly, I come from Panama. So I know a lot about the Panama Canal. I used to do trading. So refrigerated vessels have priority usually. It's a big problem for example, other vessels like diesel or gasoline or those. But usually, refrigerated have priority. Still, it is an issue. We buy delivered. So it should be an issue for the supplier and they have to source from somewhere else if they have issues in that sense or make sure that the vessels are on time at the side of the Panama Canal before crossing. So in my experience, and I had a lot of it, I must say, it should be less of a problem because refrigerated vessels have priority.

And then on the third one, in terms of LNG supply and what we plan for next year. Indeed, we have the 23 TBtu coming from the 2 contracts with Total. On top of that, we have additional 2 TBtu we sourced in the local market. On top of that, we have the Argentinian gas. So indeed, we are working with Keller to see if there is a common ground to have a new tolling agreement or commercial agreement for next year.

The next question is from Juan Carlos Petersen Widmer with Inversiones Chufquen.

Can you hear me well?

Yes.

First of all, congratulations for the improvement and the recovery in cash generation. I have 2 questions. What are the assumptions for 2024 in terms of marginal cost in the Chilean market for that guidance of USD 450 million EBITDA? And my last question is regarding dividends. 2 or 3 years ago in an AGM, it was discussed that the company should be distributing 2 dividends in -- ideally in August and November and in May after the confirmation of final results. What do you foresee on that context, given the current results?

Thank you, Juan Carlos. Well, in the guidance we did for -- we gave for 2024, of course, we have average spot prices that are probably in the 60s to 70s range or around 60. And this will evolve in the next months. We all know that in the first 2 months of the year, the first 3 months of the year, we will still have some water in the system. So it will be positive. On the other hand, we have seen that coal prices remain stable at $140. With the natural gas and with the Henry Hub prices, still a question mark how this will evolve. We need to consider that we continue to be exposed to the international market volatility. So all in all, we could expect better spot prices than the one, of course, I'm mentioning, but let's see how the system evolves so far. And then on the dividend side, before I think talking about dividends, we need to first reduce our leverage. We need to consider where we're coming from. We're coming from a very complex 2022. We still have to finance new projects in the future. So it is our objective to protect, of course, the rating and to continue having access to the international capital market to continue having access to investors and to banks. And for that purpose, it would be better if we keep, let's say, leverage under control and continue decreasing it in the next 12 months. I hope this answer a little bit what is our view on that side.

This concludes the question-and-answer session. At this time, I would like to turn the floor back to Engie Energia Chile for any closing remarks.

Well, thank you very much for your participation. And of course, we remain available for any further questions you may have. And if not, see you in 3 more months for our full year 2023 results. And hopefully, we will continue delivering positive operational results for the future. Thank you very much.

Thank you, Eduardo. We appreciate you connecting and we'll be available for any questions, Marcela and our team, okay? Thank you, all.

Thank you. This concludes today's presentation. You may disconnect your line at this time, and have a nice day.