ENGIE Energia Chile SA
SGO:ECL
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Good afternoon, everyone, and welcome to Engie Energia Chile's Third Quarter 2019 Results Conference Call. If you need a copy of the press release issued last week, it is available on the company's website at www.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. 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 would now like to turn the conference over to Mr. Eduardo Milligan. Mr. Milligan, please go ahead.
Thank you very much. Good afternoon, and thank you for attending this call. Today, Marcela Munoz, Head of Investor Relations; Bernardita Infante, Head of Corporate Finance, and I are very pleased to be here with you and present this year's results for the first 9 months of this year. We will also discuss recent developments and answer as best as we can any questions you may have.
So to start please go to Page #6. Just to remind you about 3 changes in our asset base, which we already discussed in our last call. First, last April, we acquired the solar plant Los Loros & Andacollo, we combined the capacity of 55 megawatts. Second, we disconnected the Tocopilla coal units 12 and 13, with combined installed capacity of 171 megawatts, which was possible once the full interconnection of the Chile system began operations at the end of May. And third, the IEM unit began operations last May.
Now let's jump directly to Page #10. On October 7, in a ceremony with the participation of the Ministry -- Minister of Energy, we publicly launched our renewables investment program. The first milestone in our transformation and growth story. This followed the decarbonization announcement, which took place last June, under which committed with the government to close the coal-based units 14 and 15 in Tocopilla. At that time, we requested the CNE's authorization to disconnect both units by the end of 2021. Once units 14 and 15 are closed, we will have closed 439 megawatts of coal-based capacity in our Tocopilla site.
We also booked impairments for almost $160 million in total, which were recognized part in 2018 and part in this year. Also, as part of this agreement, we committed to participate every 5 years in a roundtable with the authorities and generation companies to evaluate additional actions in line with the country's ambition and challenge to become carbon neutral by 2030.
But let's go back to the launching of our renewable projects. I just mentioned our acquisition of the Los Loros & Andacollo solar plants, which contributed 55 megawatts of renewable capacity. In terms of the upcoming new projects, the construction of our Calama wind farm and our Capricornio solar PV plant, both in the region of Antofagasta, already started. And we expect to begin construction of our Tamaya Solar plant in the first half of 2020. These 3 projects will add 362 megawatts peak of newer capacity to the commissioned -- to be commissioned in 2021 for a total investment of roughly $300 million. These are just the first projects of a program of at least 1 gigawatt capacity, 1,000 megawatts, representing a total investment of about $1 billion.
We will continue developing a 24/7 renewal portfolio by combining solar PV and wind technologies in different regions of the country, together with our existing gas capacity. Our idea is to keep several open options in parallel and deciding construction and type of technology at the best time to market conditions. This will allow us to globally replace aging coal plants.
Now let's go over some recent events and turn to Page 11, please. In our last call, we had already discussed about the full interconnection of the system, which was achieved on May 29. This key milestone for the Chilean system is mainly contributing in 3 key aspects. First, the full interconnection reduced the volatility of the systems and marginal costs. Second, it helped to reduce a bit the marginal cost of the system. And third, we have seen after the interconnection, a more frequent coupling of the marginal cost at both systems, which is also relevant to reduce differences between both systems, adding more competition, and therefore, benefiting the overall system's efficiency. The interconnection is not the only factor that explains the behavior of marginal cost. We also need to consider the lower coal prices, which are basically determining the system's marginal cost and the additional gas coming from Argentina in the central system.
And still on Page 11, I would like to inform you that we contracted up to 800,000 cubic meters per day for a total of 3.9 TBtu for gas supply from Argentina for the period between October of this year and April 2020. These volumes are to be delivered in a flexible manner with no take-or-pay or delivery or pay obligations for both counterparties. Imports will be made through ECS, a related gas distributor based in Argentina. The agreement will allow us to buy gas at a lower price that will permit a more continued dispatch of our combined cycle units, contributing to achieve slightly lower and more stable marginal costs.
Now let's turn please to Page 12. Other important recent events of our business. From our clients, in these 9 months, we concluded the PPA renegotiations with the Antucoya, part of the Antafagasta Minerals Group, with Molycop and other clients. And we also signed new contracts, mainly with B2B corporate names. All of which represent a total of more than 0.7 TWh of contracted demand per year. The concepts behind these renegotiations are the same applied to previous PPA: An initial discount in the short term, further discount afterwards; together with the change in indexation formula, moving to 100% inflation; and finally, an extension of the PPA at the latest market conditions.
For our assets. We have 2 relevant events to report; the decision of 2 PV plants, the startup of the construction of the Calama Wind farm and the Capricornio solar plant and the full commercial operation of IEM.
In relation to our ratings, as discussed in our last call, we also have 2 positive updates, which we affirmed our international BBB rating and changed the outlook from stable to positive, and our local rating was upgraded by further to AA-.
Finally, during the first half of 2019, we distributed the final dividend for 2018 and also distributed a provisional dividend for the present year. In total, we distributed $72 million during the first 9 months of 2019.
Now let's move to the key messages of the first -- of the first 9 months of 2019 on Page 14. We left them unchanged from previous quarter as they are still valid. First, ECL delivered another strong quarter and we continue to make progress towards our objective for this year. We can confirm that we may be in the upper limit or even beat the guidance we provided for the year. Second and third, we continue building a strong portfolio of clients, and at the same time, leveraging on our contracts to transform our portfolio of generation assets. And fourth, we have reached a sound and flexible capital structure with a strong cash generation that will allow ECL to benefit from attractive conditions to finance our existing debt, finance our transformation plan and yield positive returns for our shareholders.
I'm now on Page 15 to discuss our performance. As you may see in the first 9 months of 2019, we reached total sales of 8.3 TWh compared to 6.5 TWh back in 2018. This means a 28% growth in physical hedge, which is mainly explained by the new regulated PPA, which triggered the construction of IEM. And then as a consequence, our EBITDA more than doubled between 2017 and 2019, while the net recurring income increased from $61 million to $207 million. These figures are impressive, but we need to consider that we invested more than $1.1 billion in the IEM project Puerto Andino port and our share in the TEN transmission projects.
On Page 16, we can see the variation between 2019 and 2018. Our revenues increased by 17%, EBITDA by 54% and recurring net income by 66%, while our physical energy sales increased 13%. The EBITDA increase is mainly explained by higher regulated sales with distribution companies in the south central region. There is also a positive impact coming from the recognition of liquidated damages paid by the IEM project, EPC contractor, due to the delay in the start-up of the project that will be -- that we will discuss in more detail in a few minutes.
Let's move to Page 17, please. In this graph, we are showing how we supplied our contracted demand. In this slide, we can see that we are supplying most of our demand with 3 main sources: First, our lowest cost units. That is our renewal plant, IEM, CTA and CTH. Second, energy purchases from both the spot market and contracts with other generation companies. And third, our combined cycle units used in LNG, which are regularly dispatched to stabilize the marginal costs during peak hours. To optimize the use of our gas supply, at times, we have -- we have also contracted Gas Atacama to generate energy from their tolling agreement. As discussed in the previous quarter, the production coming from our coal-based units into Tocopilla's marginal was CTM 1 and 2 continue to be required by the system, but to a lesser extent than in previous quarters. This means that these 2 units may follow the same path in the future like units 12 to 15, something we will continue to analyze and come back in the future.
We need to consider that IEM did not begin commercial operation until May, and it also had some outages. So this is why we did not see a clear reduction in spot purchases during this period. We hope that in the following quarters, IEM will present a larger percentage of our power supply, so as to reduce our spot purchases and our exposure to spot price.
The following pages, #18, 19 and 20, are well known by you and describe our main strength, the quality and duration of our portfolio, which currently -- which is 12 years and probably presents one of the longest in the market while we continue adding new clients and contracts.
Please stay in Slide 20 and give a closer look to the dark and light blue segments of our PPA portfolio, which represents our regulated PPA. A little less than 50% of our contracts.
This time, I cannot go on with this presentation without discussing the recent events in our country and the recently approved electricity price stabilization law affecting the blue areas in Slide 20. As you might have heard the idea within this law is to freeze electricity prices to final customers for some time. In other words, the law takes to a new, a 9.2% increase in prices to consumers, while anticipating the benefit of the lower energy prices achieved in the more recent power options that will become effective starting 2021.
The recent riots in Chile, which caused significant damage to infrastructure, particularly the Santiago metro will yield social unrest with numerous demand from the populations related to inequality, insufficient pensions and the distress caused by the rising cost of basic services, such as public transportation and electricity deals among others. In response to this demand, the government quickly passed an electricity price stabilization deal, which was approved very fast by the congress.
I will briefly explain the mechanism and then try to give an idea of the potential effects for ECL. But first, let me explain how the regular invoicing from generation companies to distribution companies work, even before talking about the stabilization mechanism. In our -- in working to distribution companies, there exists 2 dimensions. The first one corresponds to the price included in the contract that we were awarded in public auctions. This price is calculated twice a year according to the formula included in the contract, which is impacted by CPI and fuel price. The price is set in dollars, and is then converted to pesos at the average exchange rate of the month prior to the month of the invoice. This price is called [Foreign Language]. It is the price that we are legally entitled to charge and is what we reflect in our income statement. But this price is not immediately passed through to final consumer. We have to wait until the CNE publishes what is called the [Foreign Language] which is sort of a way to average of the prices of each of the PPA between generation companies and distribution companies. At that moment, distribution companies can start charging these price to final consumers.
So only after the [Foreign Language] is published, distribution companies are able to pay the PPA price to generation companies. The CNE normally publishes this [Foreign Language] with months of delay. What happens is that the revenues recognized in the income statement, which correspond to the PPA prices are different from the cash flow actually received from distribution companies at each point in time. The difference may be against or in favor of the final consumer. Unfortunately, in the last 2 periods, the difference has been against the final consumer mainly because of the depreciating trend of the Chilean peso. So generation companies have begun to build up an account receivable that is supposed to be repaid through reliquidations in the consumers' electricity bill.
Now the stabilization mechanism is similar to what exists already with the following difference. The tariff to be charged to the final consumer will be frozen and will receive the name of [Foreign Language] or PEC. The PEC will remain fixed in Chilean pesos until January 1, 2021. This tariff is the same one as that was prevailing in the first half of 2019. So this means that our cash flow from regulated contracts in Chilean pesos should remain at similar levels to those already reported in the first 9 months of 2019. We know that the inherent exchange rate of this tariff was approximately CLP 640 per U.S. dollar while the FX rate is now very close to CLP 750 per U.S. dollar. So exchange rates represent one of the main factors that will explain the size and evolution of this stabilization fund.
The stabilization fund is nothing else than an account receivable that will accrue because of the difference between the PPA price and the PEC. So again, the PPA price will continue being used to calculate our revenues in the income statement, whereas the PEC will determine our cash flows. The difference at the end of 2021 will accrue and generate an account receivable.
Second, the year in 2021, the CNE is expecting this account receivable to begin to decrease as new lower-priced PPAs awarded in more recent options become effective. So starting 2021, the price to be charged to final consumers will be equal to the calculated [ P&P ]. With a cap equivalent to PEC plus inflation, which is called adjusted PEC. So if the [ P&P ] is greater than the adjusted PEC, the fund will continue increasing. Otherwise, if the [ P&P ] is lower than the adjusted PEC, the price charged to final consumers will be adjusted upwards to equal the adjusted PEC. The difference will be used to reduce the fund. The CNE then will calculate the invoicing differences and will include in its semi-annual tariff decrease the detail of the accrued balance of the fund in U.S. dollars for each contract. Then the stabilization fund balance for the entire industry will increase only until July 2023 or until it reaches a total of USD 1.35 billion. If this happens, the CNE will have to make the necessary adjustments to the price charged to final consumer to avoid any further increase in the fund.
Then the mechanism will remain in place until the earlier of, first, the date on which all the balances due to generation companies are fully repaid, or second, December 31, 2027. If during the period between 2025 and 2027, the CNE sees that the balance sheet will not be extinguished, then the CNE will adjust the PEC to permit the full repayment of the fund balance by December 31, 2027.
The accounts receivable or stabilization fund will not accrue interest before 2027. Beginning January 1, 2026, it will accrue interest on the outstanding balance, if any, at the rate of 6-month LIBOR plus the country risk spread at that time. Those final consumers who decide to migrate from the regulated to the free segment from now on will have to contribute to the repayment of the stabilization fund, to a specific company, sorry, to specific components to be added by the CNE to the distribution [ talk ]. Repayment of the stabilization fund will be made to each generator in proportion to its share of the accrued fund balance.
And what we are expected -- and what are we expected -- what are the expected effect for ECL. Well, the effect will be on cash flows, more than on revenues and profits. We will have to bear the cost of financing and accounts receivable, which will draw no interest until 2026. And how much will this financial costs be? Well, it's difficult to tell at this point. First, because the CNE still needs to define the specific rules to implement the mechanisms. Second, because the size of the accounts receivable and the reason of this reduction beyond 2021 will mostly depend on the behavior of exchange rates, which is impossible to predict. And third, because we need to confirm the accounting treatment to be given to the mechanism. But as I said earlier, our cash flow should remain relatively unchanged in Chilean pesos from what it has been during 2019. While our revenues as reported in the income statement should be similar to our budget, except probably for the temporary drop in demand caused by the recent riots.
Now let's go back to talk about our projects under development, and where we are with them. Let's go to Page 21. Our development and project teams continue to be very busy focused on the 3 renewal projects and bringing other projects in our portfolio to be ready to build stage. I already talked about our acquisition of Los Loros & Andacollo which contributed 55 megawatts. We have started also the construction of 2 of the 3 greenfield projects that will come next. First, Calama wind farm will have 36 turbines, each with a 4.2 megawatts capacity, which means a total of 151 megawatts. To give you an idea, the height of its turbine is close to 90 meters, and the radius is close to 145 meters. The main contractors are Spanish companies, Siemens Gamesa, which will provide the wind turbines and generators and Spanish company, Global Energy Services for the balance of plant. Commercial operation should begin around the second quarter of 2021.
Second, we also began the construction of the Capricornio PV project, which will have 250,000 high-efficiency panels to reach a total capacity of 97 megawatts. The design includes trackers. The main contractors are: Chinese, Trina, for the PV panels; a Chinese Spanish company, Nclave, for the trackers; and a Chinese company, Sungrow, for the inverter. And finally, Spanish GES, Global Energy Services, for the balance of plant. The plan is to reach commercial operation date during the first half of 2021.
Finally, for the Tamaya PV project, with a 114 megawatts capacity, we'll probably have further news and details on the design and dates in which we will start construction during the next quarter.
So these 3 projects will bring 362 megawatts of renewals to our portfolio and will require a total investment of about $300 million, which will be financed inside our balance sheet.
In addition on Page 22, we show 3 new transmission projects awarded in 2018, which are under construction. They will require around 2 years for construction and the AVI will be close to $1.5 million per year. And as we mentioned before, these are strategic projects and very interesting for us because are located in areas in which we have synergies or are located close to our renewals to be developed nearby.
On Pages 23 and 24, we describe the main characteristics of IEM and the port. IEM began commercial operations in May, and the project was within budget, although it has reported some outages due to repairs needed in the pulverizing systems, IEM has allowed us to reduce our regeneration with the oldest coal plants, replaced part of our spot purchases and also lower our average energy supply costs. This is because IEM is today one of the most cost-efficient base load plants in the system.
Now please turn to Page 25, where we show that our CapEx financing needs have decreased, releasing balance sheet financing capacity for our asset rotation plan. We will be able to finance our investment in renewal capacity through a mix of operating cash flow and additional debt while keeping our leverage ratios under control.
In terms of guidance, please move to Page 26. Here, what we can mention is that ECL delivered solid results in 2018, which in the high end of our guidance for 2019, which is the second year of our important ramp-up period for us. We are basically maintaining the guidance. If you analyze the 9-month EBITDA, it seems that we will beat by far the guidance. However, you need to consider the one-shot impact related to the penalties the contractor of IEM paid in the first half of 2019, which includes a portion of the revenues that the IEM project was unable to generate in 2018. We will explain this in a few minutes.
We do believe that we may be able to reach the high end of the guidance, and we could eventually beat this limit due to the completion of the southern segment of the inter Chilean transmission line and also due to lower coal prices that should contribute to lower spot energy prices in the system.
We will now move to the financial update section. So I will leave you with Bernardita.
Thank you, Eduardo. Hello, everyone. I'm on slide 28. Our EBITDA advanced 54% to $429 million in the first 9 months of 2019. As we will see, this was mainly a result of increased volume sales to distribution companies and other operating income. So to give a closer look to the bars of this chart. We'll start with the green bars, representing positive EBITDA variation. In first place, sales under the new PPA with distribution companies, which had a ramp-up beginning 2019 reached almost 2.4 TWh and $309 million in the first 9 months of the year. Physical sales under this contract grew by 88% compared to the first 9 months of 2018 and had a positive $118 million impact on revenue.
Second, we reported lower fuel costs. This was because of too many reasons. One is that our generation decreased 6% due, among other reasons, to the increased penetration of renewables in the system, plant maintenance schedule, the frequent use such as coal plants at lower load factors and an increase in gas supply. Coal generation, in particular, dropped by 28% as compared to last year, and it was affected by the delayed startup of the IEM project. In contrast, gas generation increased by 61% due to an increase in gas supply, particularly in June and July. And because gas generation is better suited than coal to cope with the intermittency of renewable generation. The second reason for the $47 million decrease in fuel costs is the drop in international coal prices through the first 9 months of 2019.
Our fuel costs could have decreased even further had it not been for the number of plant startups to cope with the system intermittency, which requires high consumption of diesel. We would like to note the 75% increase in renewable generation, following the acquisition of the Los Loros & Andacollo PV plants in April.
In third place, we had a $20 million positive impact on EBITDA from several items, including an increase in spot sales from the recently acquired solar PV plants. But more importantly, because of an increase in transmission revenue, primarily resulting from realisation from last year.
Fourth, we reported $5 million from lower operating maintenance and administration costs. And last but not least, among the positive factors, please note the $72 million impact, primarily explained by liquidated damages paid by the IEM project EPC contractor. As you know, the IEM project whose construction was committed to supply distribution companies, was initially expected to begin commercial operations in July 2018, but it did not start until May 16, 2019. On the one hand, this meant that IEM failed to receive capacity payments over such period, and on the other, ECL's energy supply costs were higher than those it would have reported had IEM been in operations. This is because IEM is the lowest cost plant of our thermal fleet. The delay triggered the collection of liquidated damages as provided in the construction contract and delayed liquidity damages are intended to compensate for lost income similar to the concept of business interruption used in the insurance industry. In this specific case, $74.9 million of the liquidated damages went to our income statement. We recognized this amount in one shot in the second quarter of 2019, while we should have recognized roughly $30 million in the second half of 2018 and $45 million in the first 4 months of 2019 had the plant been in operations as originally planned.
In the same bar, we also included the variation in other insurance compensation for business interruption, which resulted in a $3 million reduction in EBITDA. So the $75 million in liquidated damages plus the negative variation in insurance compensation resulted in the $72 million net profit impact on EBITDA.
We will now comment on the grey bars, which corresponds to the effects that put our electricity margin under pressure. First of all, given significant sales increase, which coincided with a decrease in our own generation. We reported higher physical energy purchases, which represented a $58 million cost increase. Second, the contracted sales increase also required higher capacity purchases. The increase in this efficiency capacity provision had a $34 million impact on EBITDA. Third, despite the heavier weight of the high price regulated PPA with distribution companies in the southern segment of the SEN starting 2019, we reported a decrease in average realized prices mainly due to lower fuel prices when compared to 2018 when coal and oil prices reached very high levels. Lower average realized prices had a $20 million negative impact on EBITDA.
In sum, EBITDA increased by 54%, mainly because of an increase in volumes sold, the liquidated damages paid by the IEM, EPC contractors and the lower energy procurement costs per MWh sold.
Now please turn to Slide 29. At the center of the slide, we can see it to be after tax variations in net recurring income, which increased by 67% to almost $207 million in the first 9 months of the year. The good news is that the main variation is pure operations, is the $110 million after-tax increase in EBITDA, which we just explained. Other nonoperating items, mainly the variation in insurance compensations for property damage and depreciation had a $12 million net negative impact. We also reported a $13 million increase in interest expense, but this is just because interest ceased to be capitalized following the completion of the IEM project.
If we look outside the box to analyze nonrecurring impacts, we see that net income was significantly impacted in both periods by the impairment of the coal-fired units that we have already closed or will close in the coming years. In 2018, we booked the impairment of units 12 and 13 with a $52 million after-tax impact. While in 2019, we reported the impairment of units 14 and 15 with a $64 million after-tax impact.
Now in Slide 30, we can appreciate $109 million net debt reduction. In terms of use of the cash, capital expenditures amounted to $107 million, excluding capitalized interest, most of which corresponds to the final payments to the IEM project EPC contractor.
In the next bar, we show the acquisition of the Los Loros & Andacollo solar PV plants, for which we paid $35 million, but we are presenting it here net of the cash available in those companies at the time of the purchase. In next place, we paid $79 million in dividends. This includes $22 million final dividend from 2018 earnings that we paid last May, a $50 million provisional dividend on account of 2019 earnings paid in June, and $8 million in dividends paid to our partner in CTH.
The next 2 bars correspond to factors that had a direct effect on debt balances, but had no effect on cash. So the first bar includes accrued interest and mark-to-market variation. And the second one includes land and vehicle leases that were classified as financial leases as a result of the implementation of IFRS 16. Finally, we paid $68 million in income taxes and CO2 taxes in the first 9 months of the year.
Now our cash sources included in the grey bars with negative numbers as they led to a reduction in net debt included a $22 million cash payment from TEN and $423 million in operating cash flow. This last numbers includes $80 million cash payment corresponding to liquidated damages paid by the IEM, EPC contractor. Of the $80 million as we explained earlier, almost $75 million went to the income statement and the remaining $5 million went to the balance sheet as a deduction from the fixed asset account.
Now on Slide 31, provides details of our liquidity and debt structure. And the main changes here are the following. Thanks to the EBITDA growth and the lower net debt, the net debt-to-EBITDA ratios continued decreasing, and it is now at 1.4x. Our gross debt remained flat because the additional financial leases following the application of IFRS 16 was offset by a $10 million reduction in our short-term bank debt that went from $90 million at the end of 2018 to the current $80 million. And also, we had also discussed this last quarter, Fitch ratings confirmed our BBB flat international rating and changed the outlook to positive.
On Slide 32, you can see that in 2019, we have increased the dividend paid, including a $50 million provisional dividend in June to recognize the improved recurring income and the conclusion of a CapEx-intensive phase. We are now positioning ourselves to finance the next investment phase, which will allow us to invest in renewables as we embark on our asset rotation plan. Our stock price evolution over the last 12 months ended September 30 shows steady sales share price increased by 8%, whereas the EBITDA fell by 4.2%.
Well, this is all on my side, and I'll leave you with Eduardo for the final remarks.
Well, thank you very much, Bernardita. And I think it was another good quarter for ECL. We expect to reach the high end or even beat our guidance for this year. But now we're ready for any questions that you may have.
[Operator Instructions] The first question today comes from Ezequiel Fernandez with CrédiCorp.
Thank you for the materials and the presentation. I have 2 basic questions related to the quarterly results. The first one is related to the [Foreign Language] or transmission revenues this quarter, they amounted to $40 million. And by the way, I got disconnected in the call. So maybe you just commented on this. I don't know. But again, transmission revenues were $40 million this quarter. And that's roughly $20 million higher than as usual. I wanted to know if there is any reclassification or any recalculation of transmission policy that took place?
Ezequiel, that is because reliquidations, essentially, the $20 million. It's hard to explain.
Okay. I know it's a tricky calculation, but the [indiscernible] that's good. And my second question is related to the [ ML ] contract, the smaller regulated contract that you had. Related volumes of that contract are dropping 7% year-on-year, roughly this year. I guess that because of client migrations and also because of the over-auctioning effect. But anyway, 7% down year-over-year is a lot less than what we are seeing on the other rated contracts, which are from other generation companies, which are falling maybe 15%, 20% year-on-year. I wanted to know if there's a specific reason why [ ML ] should not drop as much? And also what is your expectations on overall change in regulated volumes for next year?
Ezequiel, well, basically, in the specific case of [ ML ] contract, I think it's a specific situation in the region in which our distribution companies related to these contracts are located. The universe of potential clients to migrate is smaller than in other regions. And that's why we have seen that the impact in this PPA has been lower or is lower than in other regions or in other PPAs. That's the first part. And the second -- yes, and the second is basically what we have been trying to explain before, considering that today clients with the maximum or with a demand of 0.5 megawatts or more can migrate. We believe that the universe of regulated customers with this possibility almost already migrated. So we believe that in the future, the demand in our, let's say, central [ list ] of PPA should remain stable at current levels. That's at least our best view in the future. And later on, it could -- we could have an increase after '24, '25.
[Operator Instructions] The next question comes from Macarena Arce with CrediCorp.
I have 2 questions. The first one is regarding the stabilization mechanism. Are you thinking that this will affect your dividend policy for 2020? And my second question is about your gas mix during this quarter. I would like to know if there were some gas coming from Argentina?
Well, in relation to the gas from Argentina, we signed the contract, we already. But we haven't yet imported any gas. So we will continue monitoring the situation in the market to see if it could be possible in the coming months. That's your second question. And your first question the dividend policy, okay. And in relation to the dividend policy, well, basically, I think this mechanism or this system is probably not going to be as relevant as this peak, the possibility that we may have in accelerating our CapEx program or finding any acquisitions in the next years. We do believe that there will be an impact in cash flow, of course, there will be a working capital impact. But the reason behind changing the dividend policy or paying more or less dividends shouldn't be materially affected by this working capital need, but more relevant will be our business plan and growth plan for the future.
The next question is a follow-up from Ezequiel Fernández with CrédiCorp.
Sorry, guys, it's been answered.
[Operator Instructions] As there appears to be no further questions. This will conclude our question-and-answer section. At this time, I would like to turn the floor back over to Engie Energia Chile's management for any closing remarks.
Well, nothing else from our side. Thank you very much for attending the call and see you later.
Thank you all and goodbye. Have a nice day.
Thank you. This concludes today's presentation. You may disconnect your line at this time, and have a nice day.