ENGIE Energia Chile SA
SGO:ECL
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Earnings Call Analysis
Q2-2023 Analysis
ENGIE Energia Chile SA
Engie Energia Chile's Second Quarter 2023 Earnings Call gave insight into both the past performance and future prospects of the company. Fuel prices fell in 2023 relative to the highs of 2022, which coupled with lagging indexation of regulated PPAs, led to a mechanical positive impact on the energy margin. Past due receivables accumulated from the new tariff stabilization law were set to be monetized starting the end of August, which was expected to collect around $200 million to repay debt and enhance leverage ratios.
Spot prices have followed a volatile trend, spiking to $129 per megawatt hour in the first half of 2023 from an average of $52 in the 2017-2020 period. Hydrology showed improvement in June, offering better prospects for the rest of the year with hydroelectric production potentially reducing spot prices. However, preparations for 2024 are necessary to account for uncertainties in rainfall and snow accumulation.
Coal prices, having spiked to all-time highs in 2022, decreased substantially in the first half of 2023, with coal becoming cheaper than LNG and positively affecting system costs. However, overall coal plant availability for the system has seen a downturn. Specifically, Engie Energia Chile's IM coal power plant faced a service outage early in the year, but resumed operations in May.
Despite the non-delivery of contracted LNG volumes by a supplier, spot LNG was secured to mitigate the impact. Through long-term contracts and imports from Argentina, the company maintains a steady supply of natural gas, though at higher costs. Engie Energia Chile also hedged an average of 3.3-3.4 terawatt hours with other GenCos for the period from 2023 to 2027, to balance the portfolio and reduce exposure to spot market volatility.
The average supply cost of energy sources increased from 2021 to 2023. The company's strategy aimed to include more renewables, gas, and contracted volumes, thus decreasing purchases in the spot market. EBITDA more than tripled from last year, reaching $189 million in the first half, matching the full year of 2022. Net results turned around from a $40 million net loss to a $27 million profit. Moreover, despite high CapEx and PEC receivable accumulation, net debt only rose by $75 million to reach $1.7 billion.
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Good Afternoon, everyone, and welcome to Engie Energia Chile's Second Quarter 2023 Results Conference Call. If you need a copy of the press release issued on July 26, 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 a detailed note in the company's press release regarding forward-looking statements.
We would like to advise participants that this call is dedicated to investors and market analysts, not for the press. We ask all journalists to contact Engie Energia Chile's PR Department for details.
I will now turn the call over to Mr. Eduardo Milligan. Please go ahead, sir.
Thank you, Gary. Good afternoon. Today, I'm here with Bernardita Infante, Alison Saffery, Marcela Munoz. We will present ECL results for the first half of 2023, and we will discuss our guidance for the rest of the year.
We can start then on Page #4. On the left side of this page, we are highlighting some key elements to understand ECL's performance in the first half of the year. While on the right side, we will present the main drivers for the second half of 2023. Let's start on the left side. First, fuel prices fell in 2023 compared to the record prices of last year while hydrology remained weak, most of the first half of the year.
On the revenue side, the higher fuel prices of 2022 negatively impacted ECL's average supply cost during last year. We need to consider that there is a lag in the indexation formula of our regulated PPAs. So this means higher costs were not automatically translated into higher PPA prices. And then as a consequence, in the first half of 2023, there is a mechanic positive impact in our energy margin since costs are slightly lower and PPA tariffs are higher. So in simple words, this indexation lag created a lower margin in 2022, which was somehow partially recovered in 2023.
As you know, this year, our LNG supplier didn't deliver a contractual volume of around 13 Tbtu and we were forced to replace these volumes with the spot LNG at higher costs. We reported spot LNG which has been keep to partially mitigate the impact. It has been a difficult task, but our portfolio team in coordination with the Engie's Global Energy Management division, managed very well these operations.
Other key element in this first half of the year is the unavailability of thermal power plants. In our case, IEM power plant was out of service for approx 45 days. The plant came back into service early May and now is fully available for the system. So in this context, also transmission bottlenecks continue to be an element to have in our radar for both potential increases in spot prices like in the South and also in relation to curtailment for renewables in the North.
Finally, as you know, liquidity was impacted by the delay in the monetization of receivables arising from the new tariff stabilization law known as PEC as of June. ECL accumulated around $440 million uncollected deals related to this mechanism. Now the good news is that we are now very close to start the monetization program.
The accumulation of these receivables in the investment context of ECL explaining why ECL working capital and short-term debt mix increased in the last 12 months, but we took several measures in the first half of the year to improve our financing structure, including a credit line granted by our parent engine. Bernardita will explain in some minutes all these new developments.
On the right side of this page, we are highlighting other key elements to understand the future trajectory. In 2023, we have additional renewal generation and additional hedges or backup PPAs for additional 1.2 terawatts hour during the whole year. Then as I explained before, there is a positive impact coming from lower fuel prices, and we were also able to source additional LNG for the system which was key to partially keep spot prices under control and will be complementary during the rest of 2023 with the improved hydrology. In relation to hydrology then as you have seen, we had recently some important rainfall events and now we have better hydrology prospects for the rest of the year, which will be translated into lower spot prices during the rest of 2023.
However, we need to be cautious since the snow accumulation is still in progress. So this means the system will have a good performance in the short term. Between all these elements, ECL's share position would reduce from the 4 terawatts hour we had in 2022 to less than 2.5 terawatt hour in 2023 which should reduce volatility and risk in case spot prices increase again.
Finally, we recently closed a 10-year $400 million sustainable loan with IFC to refinance existing debt previously raised to fund our investment plan and to fund new investments in renewals. This is an interesting financing because it's green and linked also to sustainable KPIs, including gender parity. These KPIs will act as an enhancer in some economic conditions once ECL complies with their targets in the near future.
The final good news, we are ready to execute the first monetization of tech receivables. Target date for first monetization is the end of August we expect to collect around $200 million in the first process. Proceeds will be used to repay debt and improve our leverage ratios. We will still have approx $250 million more to be monetized on the next process, which should be triggered once the regulated tariff applicable since January 2023 is confirmed by the regulatory bodies.
Then let's move to next page 5. Shows the evolution on ECL's physical sales. Total sales grew in 1%, mainly explained by higher sales to regulated customers which increased in 7%, and this is positive for ECL and a potential upside in the future, considering the regulated PPA we have in the center to South regions has an average consumption of less than 75% vis-a-vis the fixed 4.5 terawatts hour contracted volume. This means the positive trend in our regulated PPA load factor is confirmed that is mainly explained by a larger participation of ECL in the pool of regulated contracts and the return of free clients to the regulated scheme too.
On Page 6, we can see the spot price evolution over the last 7 years on how the Chilean system moved from an average of $52 megawatt hour into '17 to '20 period to $127 megawatt hour in 2022 and $129 megawatt hour in the first half of 2023. The trend is not smooth. The system will continue to be under pressure in this transition period. Since June and until early August, we have seen much lower spot prices given the improved hydro conditions in the system. Looking forward, we will depend on additional rainfall and snow accumulation. This means hydroelectric production could be very positive in the short term, but we need to be prepared for 2024.
Next, Page 7 shows the detailed evolution of hydrology, which had a material improvement in June compared to previous years. As of the end of July, the accumulated probability of exceedance is 73% compared to previous 2 years in which we were in the mid-90s approx. As I mentioned before, we have additional energy accumulated in the reservoirs, which is approx twice the volume we had 1 year ago, and we need to see how these levels and this new accumulation evolve in the next weeks.
On Page 8, we can see the unprecedent evolution on coal prices. As you know, coal hit all times high since 2022. The average price per ton in 2022 reached $314, which can be translated into a production cost of around $130 megawatt hour. As we explained in our -- in the last quarter, trend reverted in 2023. The average coal price in the first half of 2023 decreased to $154 per ton, which is less than half the price of previous year.
In the second quarter of this year, the average coal price decreased further to around $125 per ton then at $125 per ton, the production cost with coal power plants should decrease to around $60, $70 megawatt hour. The coal futures have remained stable in current levels, and this will be positive for the overall cost of the system.
So in summary, what we have seen recently is that coal is again cheaper than LNG.
Next, Page 9 shows the evolution of coal power plant's availability for the overall system. The message in this page is clear, coal plant availability for the system has declined in the recent years. In the first quarter of 2023 in our specific case, IM coal power plant had a failure in its transformer and was out of service between February and April. Now to mitigate this situation, plant's maintenance was rescheduled from August to March, and now the plant is again in service since early May.
Now let's go to next Page 10 and discuss about the natural gas. The graph on top shows the evolution of international LNG prices. We can see the all-time highs, same as with coal in 2022 explained by the Russia-Ukraine conflict and it's impacting the supply-demand balance worldwide. LNG reached $40 million Btu, which made impossible to buy LNG in the spot market because as you know, at $40 million Btu, the production cost with the combined cycle using natural gas will be close to $300 per megawatt hour.
The positive evolution on JKM index then allowed us to import spot LNG in 2023 and mitigate the lag of LNG that was not delivered by our supplier. Then the graph below shows the LNG sourced through long-term contracts and the natural gas coming from Argentina. We have seen in the recent years, stable volumes imported from Argentina during the summer and increasing during the winter, as we can see in the graph, in which the green area represents the volumes imported from Argentina and their increased importance for the system.
Then on the LNG side, as we explained in our last call, we have 2 long-term contracts for our natural gas volume of 23 TBtu per year. One of this contract was confirmed by our supplier for about 10 TBtu while the second contract with the volume of about 13 TBtu was not confirmed, and therefore, we were not able to add this LNG volume to the annual delivery program in the regasification terminal. To partially mitigate the situation, we have secured around 14 TBtu replacement LNG in the ordinary course of business, but it's obvious at higher costs.
Next, Page 11 shows an update on the hedges of back-up PPA signed with other GenCos. This page shows an additional volume of backup PPAs signed for 2023 and 2024. In summary, we have an average of 3.3, 3.4 terawatts hour of hedges contracted with other GenCos between 2023 and 2027, the period in which we will be adding additional renewals to our portfolio of assets.
Page 12 shows a graph with the energy sources and average supply cost for the portfolio. Our main objective is to rebalance our portfolio as fast as possible to reduce risk and exposure to spot market volatility. As we can see in the graph, the average supply cost material increased between 2021 and 2023. Now in the first half of 2023, we can see how sources are moving in the right direction, more renewables, more gas, more hedges or contracted volumes with other GenCos. And as a consequence, less purchases in the spot market represented by the light blue area in this graph.
On 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 megawatt hour, which was stable during both quarters compared to $134 in the first half of 2022 or $146 for the full 2022, this means an increase of 80 -- sorry, of $48 compared to the same period of previous year or an increase in $36 compared to the average monomic price of the whole 2022. This increase, as I explained before, is mainly explained by the indexation from PPAs to coal, LNG and U.S. inflation.
On the other hand, the average supply cost reached $137, again, stable in the first 2 quarters of 2023 compared to $118 in 2022. Now the broader relative spread between sales and costs is explained by the indexation lag in our regulated PPAs together with relatively lower supply costs, given the actions explained before on LNG, backup PPAs, higher generation from renewables and spot purchases at lower cost.
In the first half of this year, we can also see how the generation coming from renewables and LNG with our own CCGT and our tolling agreement with Keller plus the additional backup PPAs are replacing spot purchases, which reached 1.4 terawatt hour compared to 2.1 terawatt hour during the same period of previous year.
So now we will continue with Bernardita with a detailed financial results and related action plans to improve ECL's liquidity and capital structure.
Okay. Thank you Eduardo, and good afternoon to everyone. Hold on for a second, please. Okay. So we can go to Slide 14 for a closer look at first half results. So EBITDA more than tripled compared to last year. Actually, first half EBITDA reached $189 million, equaling the figure reported for the whole year in 2022. Revenues increased mainly due to the 36% increase in energy prices, which captured the extremely high fuel prices and inflation observed in the second half of 2022 due to the lag with which price indexation in our PPAs reflect fuel price increases.
Physical sales decreased by 1% with an increase in sales to regulated customers and a decrease in sales to free clients. Gas sales also increased significantly as in the first half of 2023, the company bought enough LNG volumes to generate electricity at its own plants and through a tolling agreement with Keller as well as to sell gas to other companies.
Generation costs remain high as the fuel used in generation came from high-priced stocks built up in 2022 and marginal costs remained affected by poor hydro generation through most of the period. However, sales prices increased further, explaining the margin widening. To meet our sales commitments, we bought 23% of total volumes from the spot market, down from 33% in the first half of the year, in line with our strategy of reducing our exposure to spot prices. Energy sourced through backup PPAs represented 25% of total volumes sold, up from 16% in the first half of 2022. Renewables accounted for 13%, up from 7%.
Notably, gas production, including energy generated at our own plants through a tolling agreement with Keller, increased to represent 28% compared to 14% last year. This was possible, thanks to spot LNG purchases, which allowed us to secure LNG supply volumes despite the unfulfillment of 1 of the 2 long-term gas supply agreements by our main LNG supplier. In short, greater renewables and gas production and backup PPA volumes are allowing us to close the gap between our sales commitments and our own generation, so as to reduce our exposure to the spot market.
Net results reached 27 million, a turnaround from the 40 million net loss reported in the first half 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 May 2023, we sold a nominal amount of 51 million of accounts receivable, which represented the last sale under the PEC-1 mechanism. Overall, since the PEC-1 monetization started in January 2021, the company sold accounts receivable totaling 273 million. It received $196 million in cash proceeds and accounted for financial expenses of $77 million.
Our net debt, excluding IFRS 16 leases, increased significantly throughout 2022 as we had to finance capital expenditures as well as heavier working capital needs to the steep increase in fuel prices, while the price stabilization law compressed our liquidity.
Net debt reached $1.65 billion at year-end 2022. Through the first half 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 at the end of June was only slightly higher than the level reported at the end of 2022.
Slide 15 shows the reasons behind the EBITDA recovery. Clearly, average realized prices captured the increase in fuel prices and inflation observed in previous months. Spot sales also increased as the sales through the tolling agreement with Keller are reflected in this account.
The increase in physical sales was explained by higher demand from regulated clients. Spot purchases decreased in volume, although they were made at higher prices than in the first half of last year. Fuel costs continued reflecting the use of inventory acquired at higher prices, but prices increased more than costs. Therefore, EBITDA reached $189 million, a 212% increase compared to the first half of last year.
Slide 16 shows the evolution of our net results. The turnaround is mainly explained by the EBITDA recovery. Insurance recoveries also contributed to mitigate a $21 million increase in interest expense. In such way, net income before one-offs increased from a $38 million loss to a $46 million profit in the first half of 2023.
In terms of one-offs, while in the first half of last year, we reported $3 million in interest expenses related to the sale of PEC receivables. In 2023, we reported a $9 million after-tax effect on the last sale of PEC-1 receivables and $10 million impairment. These are mainly related to impairments of assets such as, for example, the return of the onerous concession on the Pampa Yolanda site. As a result, net income was $27 million in the first half of the year.
Now let's go to Page 17 to discuss the evolution of net debt. This shows that despite capital expenditures of $178 million in the first half of the year and accumulation of PEC accounts receivable of $176 million, our net debt increased by just $75 million to $1.7 billion, given the recovery of our operating cash flow.
The debt figures exclude $174 million of financial leases related to very long-term land lease contracts.
Cash from operations before the effect of PEC receivables, buildup reached $320 million in the first half of the year. We also reported $38 million in cash proceeds from the last sale of PEC-1 receivables.
In Slide 18, we see the status of our debt as of the end of June. Gross debt, excluding financial leases, reached $1.85 billion. Net debt-to-EBITDA reached 5x a significant improvement compared to the record high 8.7x at year-end 2022. We have been making progress in reaching our 3 main objectives related to our debt profile. First, to reduce net debt-to-EBITDA, through EBITDA recovery and by maintaining relatively flat net debt despite the financing of our capital expenditures in renewable and transmission projects.
Second, to secure funding for the construction of the Lomas de Taltal wind farm and the BESS Coya storage projects whose objectives are to reduce our costs, our exposure to the spot market and curtailment and intermittent risks associated to PV plants; 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 June.
We have news to share with you part of which Eduardo has already anticipated. So I'll ask you to please jump to Page 23 for a moment. The monetization of receivables related to stabilization law PEC-2, a program structured by the IDB with the participation of Goldman Sachs, JPMorgan and Itau has been progressing. Today, the roadshow for the related 144a and 4a2 issuances was launched and we expect to receive approximately $200 million in cash funds by the end of August, corresponding to the first sale of certificates of payments issued by the Chilean treasury.
After this first sale, we expect to perform bimonthly sales of certificates of payment starting October 2023, including a larger sale which is contingent upon the publication of the average note price decree for the 6-month period starting January 2023.
On June 20, we signed a $400 million, 10-year loan with the IFC and the German bank deck. On July 28, we made the first disbursement under these facilities for a total amount of $200 million, and we closed an interest rate swap to reduce our exposure to interest rate risk.
These 2 transactions are helping us to reprofile our short-term debt and to finance the CapEx needs for the 2023, '24 period. Indeed, in the first week of August, we repaid short-term debt by $125 million, including a $75 million loan from the related company Engie Austral.
Our credit ratings have been confirmed at BBB by both Fitch and Standard & Poors. As discussed in the past call, last March, Standard & Poor's placed our a rating in credit watch negative due to liquidity pressures. S&P has not lifted the credit watch negative at this date, however, both liquidity and leverage has been strengthened, and we expect this trend to be confirmed in the following months.
In terms of liquidity, we still have an undrawn amount of $200 million under the IFC and DEG loans, and we have registered local bond lines, which we might use to refinance debt.
Now I'll leave you with Eduardo, who will brief us on the recent events and action plans for 2023.
Thank you, Bernardita. The actions mentioned on Page 19, are driving our improved operational performance. First, we secured the 24 TBtu of LNG for 2023, together with the tolling agreement with Keller CCGT. Then we rescheduled IEM maintenance and implemented a fast track to recover the plant, and now it's operational since early May. We also secured additional backup PPAs for this year, increasing the total hedges to 3.3, 3.4 terawatts hour between 2023 and [ 2027 ].
Fourth, as you know, in 2023, we have additional 0.9 terawatt hour coming from our renewal. And finally, we are already implementing 2 additional projects, 342 megawatts wind farm in the north and 638-megawatt hour storage solution to be added to our existing solar plant, Coya, also in the North.
As a result, as we highlight below, the spot exposure is expected to be close to 2.5 terawatts hour in 2023, which is slightly higher than the 2 terawatts hour we mentioned in our previous call, but this increase is explained by additional spot purchases in the market because of the lower spot prices. So this is how positive.
On Page 20, we are presenting the evolution on our investment plan and the committed CapEx for 2023 and 2024 once we get the 2 projects currently under construction, we will have reached 1.3 gigawatts of renewables, and we expect to reach a ready-to-build status for other projects very soon to complete our 2-gigawatt plan.
Page 21 presents the detailed CapEx by type of business on top of the $600 million, we're investing in renewals. We are also investing $190 million in transmission projects, which contribute with the stable and regulated cash flow. The $600 million in renewals include the 2 projects we have currently under construction which are Lomas de Taltal and the storage solution, we are adding to Coya solar plant.
Now in Page 22, we show the guidance we gave for this year. It's good to see that most of the impact on the left side of this page are green, which means we are on track to reach the guidance. And if current conditions remain stable for the rest of 2023, and we do not experience extraordinary events like in 2022, the high end of the initial guidance should become the new lower limit for 2023.
The graph also shows the expected EBITDA, CapEx and net debt-to-EBITDA evolution considering the updated fuel prices and the actions we explained before. Liquidity and leverage should also improve with implementation of the financing with IFC and the monetization of PEC receivables, together with other actions, our corporate finance team implemented during 2023.
Finally, to end our presentation, we are summarizing the main key takeaways of this first half on Page 24. First, we continue to be on track to rebalance our portfolio as fast as possible, adding additional renewables, signing hedges through backup PPAs and optimizing our flexible generation by sourcing additional LNG in the international market. So these actions have allowed ECL to improve its energy margins during 2023, and we are well on track to reach the guidance for 2023. And in fact, as I mentioned before, we could expect even better results under the current scenario.
In this slide, we are also on track on the construction of 2 additional projects, and we expect to announce soon the construction of additional storage and wind projects, which will complement the 1.3 gigawatts we have already implemented or have under construction to reach at least 2 gigawatts of renewables.
And finally, in 2023, we implemented several measures to improve ECL's liquidity and leverage in this line. As Bernardita recently explained, on June 20, we signed a $400 million, 10-year loan with IFC and the German bank, DEG. And we made during July, the first disbursement of 200 million.
And finally, on the monetization of PEC receivables, we made a lot of progress, and we expect to receive approximately $200 million by the end of August, which will correspond to the first sale of certificates of payment issued by the Chilean treasury.
So well this summary, we end our presentation, and we are ready for your comments and questions. Thank you very much for your participation today.
[Operator Instructions] Our first question comes from Florencia Mayorga with MetLife.
Congratulations on the results. I have a couple of question. So regarding the monetization of PEC, regarding the second chance, do you have any update that when you are expecting to collect them or just for now only the $200 million by the end of August?
And my second question is regarding the CapEx plan. So after this $200 million impact, the $200 million in the green loan and the better performance, are you expecting to accelerate the renewable transformation? And additionally, are you facing any issues regarding transportation? Or are you seeing that taking more time [indiscernible] of the project, something that [indiscernible]?
Florencia, thank you for your questions. So first, on monetization. We expect to monetize. As I mentioned at the beginning of the presentation, we have around $440 million as of June of accrued receivables in our balance sheet. We expect to monetize a first tranche which, in our case, will be equivalent to around $200 million, we should collect by the end of August.
Then there will be a bimonthly monetization for smaller amounts during the rest of the year. And finally, once the tariff decree number 7, which corresponds to the regulated tariff starting January 2023 is approved by finally the National Controller then we will be able to monetize another tranche -- another material tranche of probably around $200 million to $150 million. When we expect -- well, we are all working together with the authorities, the banks, the GenCos to have this ready by year-end. This is, let's say, the target if not by year-end, it should be possible during the first quarter of next year. This is our intention and the will of all parties involved in this transaction.
Then on the CapEx plan, your second question. So yes, today, we are investing in 2 projects. We're in investing in Lomas de Taltal and BESS Coya, but then we are planning to continue investing in additional renewables to reach the 2 gigawatts that we have in our plan because the 2 projects that we have today under construction, we will reach 1.3. So we need to add around 700 megawatts of additional capacity to our portfolio, which should come through storage and wind projects, we should launch in the next 6 to 12 months and to build them between 2024 and 2026.
I have a additional question regarding the rebalancing portfolio that you mentioned that additionally to review your current exposure to the spot market in the midterm, and you are looking for to [indiscernible] by 20%, what are your strategy was to reduce the regulated contracts. How was the progress on that front?
Well, on the, let's say, strategy or our portfolio level, indeed, our plan is to be balanced in the medium term. And this is why we are investing in renewables during the next years. When we should be completely balanced, should be in the next 3 years when we will have completed the 2 gigawatts of additional capacity, but we don't have any, let's say, actions on the demand side with a plan that we have for renewables, we should reach balance in some -- in the next years.
The next question is from Peter Bowley with Bank of America.
On the status of the redress or arbitration regarding the LNG supply contract. Can you confirm the amount that's being demanded and if there's been any developments in terms of timing of a potential future award?
Peter. Based on the confidentiality obligations under the SPA, we cannot disclose any specific details regarding the proceeding that is ongoing between Engie and our supplier. So once we are able to disclose an information, we will do it.
[Operator Instructions] The next question is from Martin [indiscernible] with Balance Capital.
Well, first of all, thank you for taking my questions for materials. I have 2 questions. I would like to run them one by one, if that's okay. The first one regarding gas. This year, you were able to replace the gas cargoes that total did not deliver. Do you think it is possible that the situation repeats again next year? And what kind of measures do you have in mind if that's the case?
Martin. Indeed, it is possible. We still don't have a full confirmation of one situation or the other. But we are well prepared to continue sourcing LNG in the international market if we need to and if the volumes related to the same contract are not delivered in 2024, including the tolling agreement that we have with Keller.
Okay. And my final question, the government has sent a lot of congress regarding the energy transition that looks quite ample and lacking some specifics in our view. I was wondering what items in the new [indiscernible] you eyeing with more attention?
As you say, today, the future market design is under analysis. I would say that my -- something that it's worth to have in mind will be -- what will be the role of the natural gas in the future. It's -- that's key. As you probably have seen, there is also a potential or it's becoming a potential option for storage in the future, which is also something that makes sense, and this is something that I think it's obvious today.
It was not so obvious 4 or 5 years ago, but I think that we and the system, we have all learned how the system could evolve in these years and storage makes sense. We'll need to be analyzed what will be the best way to implement this capacity in the system. So this is still under discussion.
And then acceleration of renewals, of course, will be key. We have seen some delays in some projects, and this could also impact the system in the short term. So I would say that those 3 in line with the volatile evolution of hydrology should be key for the future.
Very helpful. That's all on my side.
Thank you.
This concludes the question-and-answer section. At this time, I would like to turn the floor back to Engie Energia Chile for any closing remarks.
Thanks you all. Thank you very much, everyone, for your participation. I hope you had a good time with us and looking forward for our next meeting in 3 months.
Thank you. This concludes today's presentation. You may disconnect your line at this time, and have a nice day.