Good afternoon, everyone, and welcome to Engie Energia Chile 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 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 Muñoz, Head of Investor Relations, Bernardita Infante, Head of Corporate Finance, and I are very pleased to be here with you and present ECL's results for the first nine months of this year. We will also discuss recent developments and answer as best as we can any questions you may have. To start, please go to page number six, just to remind you about three changes in our asset base, which we already discussed in our last call. First, last April, we acquired the solar plant, Los Loros and Andacollo, with combined peak capacity of 55 MW. Second, we disconnected the Tocopilla coal unit 12 and 13 with combined installed capacity of 171 MW, which was possible once the full interconnection of the Chilean system began operations at the end of May.
Third, IEM unit began operations last May. Now, let's jump directly to page number 10. On October 7, in a ceremony with the participation of the 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 during this year.
Also, as part of this agreement, we committed to participate every five 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 2050. Let's go back to the launching of our renewable projects. I just mentioned our acquisition of the Los Loros and Andacollo solar plants, which contributed 55 MW 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 three projects will add 362 MWp of renewable capacity 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 one gigawatt capacity, 1,000 megawatts, representing a total investment of about $1 billion. We will continue developing a 24/7 renewable 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 decide on construction and type of technology at the best time to market conditions. This will allow us to gradually 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 29th. This key milestone for the Chilean system is mainly contributing in three key aspects. First, the full interconnection reduced the volatility of the system's marginal cost.
Second, it helped to reduce a bit the marginal cost of the system. Third, we have seen after the interconnection a more frequent coupling of the marginal cost of 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 costs. 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. I am still on page 11.
I would like to inform you that we contracted up to 500,000 cubic meters per day or a total of 3.9 tera BTU of 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, our 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 nine months, we concluded the PPA renegotiations with Antucoya, part of the Antofagasta Minerals group, with Molycop, another client.
We also signed new contracts, mainly with B2B corporate names, all of which represent a total of more than 0.7 terawatt-hour of contracted demand per year. The concepts behind these renegotiations are the same applied to previous PPAs. An initial discount in the short term, further discount afterwards, together with a change in the indexation formula, moving to 100% inflation, and finally an extension of the PPA at latest market conditions. For our assets, we have three relevant events to report: the acquisition of two PV plants, the startup of the construction of the Calama wind farm and the [Tacornal solar plant], and the full commercial operation of IEM. In relation to our ratings, as discussed in our last call, we also have two positive updates.
Fitch reaffirmed our international BBB rating and changed the outlook from stable to positive, and our local rating was upgraded by Fitch 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 nine months of 2019. Now let's move to the key messages of these first nine months of 2019 on page 14. We left them unchanged from previous quarter, as they are still valid. First, [ISA] delivered another strong quarter, and we continue to make progress towards our objectives for this year. We can confirm that we may be in the upper limit or even beat the guidance we provided for this 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. Fourth, we have reached a sound and flexible capital structure with a strong cash generation that will allow [ISA] 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 nine months of 2018, we reached total sales of 8.3 terawatt-hours compared to 6.5 terawatt-hours 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.
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, we need to consider that we invested more than $1.1 billion in the IEM project, Puerto Andino, and our share in the 10 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 constructor due to the delay in the startup of the project 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 demands. In this slide, we can see that we are supplying most of our demand with three main sources. First, our lowest cost units, that is our renewable plants, IEM, CTA, and CTH. Second, energy purchases from both the spot market and contracts with other generation companies. Third, our combined cycle units using LNG, which are regularly dispatched to stabilize the marginal cost during peak hours. To optimize the use of our gas supply, at times, we have also contracted Gas Atacama to generate energy under a tolling agreement. As discussed in the previous quarter, the production coming from our coal-based units in Tocopilla is marginal, while CTM one and two continue to be required by the system, to a lesser extent than in previous quarters.
This means that these two 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. 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 % of our power supply so as to reduce our spot purchases and our exposure to spot price. The following pages, number 18, 19 and 20, are well-known by you and describe our main strength, the quality and duration of our portfolio, which currently reaches 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 PPAs. 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 behind this law is to freeze electricity prices to final customers for some time. In other words, the law seeks to annul a 9.2% increase in prices to consumers, while anticipating the benefit of the lower energy prices achieved in the more recent power auctions that will become effective starting 2021.
The recent riots in Chile, which caused significant damage to infrastructure, particularly the Santiago Metro, revealed social unrest with numerous demands 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 bills, among others. In response to these demands, the government quickly passed an electricity price stabilization bill, 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. First, let me explain how the regular invoicing from generation companies to distribution companies works, even before talking about the stabilization mechanism. In our invoicing to distribution companies, there exist two 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 prices. 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 Precio de Nudo de Largo Plazo. It is the price that we are legally entitled to charge, and is what we reflect in our income statement. This price is not immediately passed through to final consumer. We have to wait until the CNE publishes what is called the Precio de Nudo Promedio, which is sort of a weighted average of the prices of each of the PPAs between generation companies and Distribution Companies. At that moment, Distribution Companies can start charging this price to final consumers.
Only after the Precio de Nudo Promedio is published, distribution companies are able to pay the PPA price to generation companies. The CNE normally publishes this Precio de Nudo Promedio with months of delay. What happens is that the revenues we recognize 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 two periods, the difference has been against the final consumer, mainly because of the depreciating trend of the Chilean peso. generation companies have begun to build up an account receivable that is supposed to be paid through reliquidations in the consumer's 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 Precio Estabilizado al Cliente Regulado or PEC. The PEC will remain fixed in CLP until January 1st, 2021. This tariff is the same one that was prevailing in the first half of 2019. This means that our cash flow from regulated contracts in CLP should remain at similar levels to those already reported in the first nine months of 2019. We know that the inherent exchange rate of this tariff was approximately CLP 640 per US dollar, while the FX rate is now very close to CLP 750 per US dollar. 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. 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 least until 2021, will accrue and generate an account receivable. Second, beginning 2021, the CNE is expecting this account receivable to begin to decrease as new lower price PPAs awarded in more recent auctions become effective. Starting 2021, the price to be charged to final consumers will be equal to the calculated PNP, with a cap equivalent to PEC plus inflation, which is called adjusted PEC. If the PNP is greater than the adjusted PEC, the fund will continue increasing.
Otherwise, if the PNP 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 will calculate the invoicing differences and will include in its semi-annual tariff decrease, the details of the accrued balance of the fund in US dollars for each contract. The stabilization fund balance for the entire industry may increase only until July 2023, or until it reaches a total of $1.35 billion. If this happens, the CNE will have to make the necessary adjustments to the price charged to final consumers to avoid any further increase in the fund. 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 31st, 2027.
If during the period between 2025 and 2027, the CNE sees that the balances will not be extinguished, then the CNE will adjust the PEC to permit the full repayment of the fund balance by December 31st, 2027. The account receivable or stabilization fund will not accrue interest before 2027. Beginning January 1st, 2026, it will accrue interest on the outstanding balance, if any, at a rate of six-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 through a specific component to be added by the CNE to the distribution pool. Repayment of the stabilization fund will be made to each generator in proportion to its share of the accrued fund balance. What are the expected effects for Enel?
Well, the effect will be on cash flows more than on revenues and profits. We will have to bear the cost of financing an account receivable, which will draw no interest until 2026. How much will this financial cost be? Well, it is difficult to tell at this point. First, because the CNE still needs to define the specific rules to implement the mechanism. Second, because the size of the account receivable and the rhythm of this reduction beyond 2021 will mostly depend on the behavior of exchange rates, which is impossible to predict. Third, because we need to confirm the accounting treatment to be given to the mechanism.
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. 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 three renewal projects and bringing other projects in our portfolio to be ready to build stage. I already talked about our acquisition of Los Vilos and Andacollo, which contributed 55 megawatts. We have started also the construction of two of the three greenfield projects that will come next.
First, Calama Wind Farm will have 36 turbines, each with a 4.2 MW capacity, which means a total of 151 MW. To give you an idea, the hub height of each turbine is close to 90 m, and the radius is close to 145 m. The main contractors are a Spanish company, 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 MW. The design includes trackers. The main contractors are Chinese Trina for the PV panels, the Chinese-Spanish company Nclave for the trackers, and the Chinese company Sungrow for the inverters. 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. For the Tamaya PV project, with a 114 MW capacity, we'll probably have further news and details on the design and dates in which we will start construction during the next quarter. These three projects will bring 362 MW of renewables 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 three new transmission projects awarded in 2018, which are under construction. They will require around two years for construction, and the AVI will be close to $1.5 million per year.
As we mentioned before, these are strategic projects and are interesting for us because they are located in areas in which we have synergies or are located close to our renewables 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 generation with the oldest coal plants, replace part of our spot purchases, and also lower our average energy supply cost. This is because IEM is today one of the most cost-efficient baseload plants in the system. Now please turn to page 25, where we show that our CapEx financing needs have decreased, releasing on-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, reaching 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 nine-month EBITDA, it seems that we will beat, by far, this guidance. 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 InterChile 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.
Yeah. Thank you, Eduardo. Hello, everyone. I'm on slide 28. Our EBITDA advanced 54% to $429 million in the first nine months of 2019. As we will see, this was mainly a result of increased volume sales to distribution companies and other operating income. To give a closer look to the bars of this chart, we'll start with the green bars representing positive EBITDA variations. In first place, sales under the new PPA with distribution companies, which had a ramp-up beginning 2019, reached almost 2.4 terawatt hour and $309 million in the first nine months of the year. Physical sales under this contract grew by 88% compared to the first nine months of 2018 and had a positive $118 million impact on revenue. Second, we reported lower fuel costs. This was because of two main reasons.
One is that our generation decreased 6%, due, among other reasons, to the increased penetration of renewables in the system, plant maintenance schedules, the frequent dispatch of 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 start-up 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 nine months of 2019.
Our fuel costs could have decreased even further had it not been for the number of plant start-ups to cope with the system's intermittency, which requires higher consumption of diesel. We would like to note the 75% increase in renewable generation following the acquisition of the Rio Flores and 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 reliquidations from past periods. Fourth, we reported $5 million from lower operating maintenance and administration costs. 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 that period, and on the other, ECL's energy supply costs were higher than those it would have reported had IEM been in operation. 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 delay liquidated 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 recognize 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 in the first four months of 2019, had the plant been in operations as originally planned. In this same bar, we also included the variation in other insurance compensations for business interruption, which resulted in a $3 million reduction in EBITDA. The $75 million in liquidated damages, plus the negative variation in insurance compensation, resulting in the $72 million net positive impact on EBITDA. We will now comment on the gray bars, which corresponds to the effects that put our electricity margin under pressure.
First of all, given the 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 the sufficiency capacity provision had a $34 million impact on EBITDA. Third, despite the heavier weight of the higher price regulated PPA with distribution companies in the southern segment of the CEN 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 64%, mainly because of an increase in volume sold, the liquidated damages paid by the IEM EPC contractor, and the lower energy procurement cost per megawatt hour sold.
Please turn to slide 29. At the center of the slide, we can see each of the after-tax variations in net recurring income, which increased by 67% to almost $207 million in the first nine 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 non-operating 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, this is just because interest ceased to be capitalized following the completion of the IEM project.
If we look outside the box to analyze non-recurring impacts, we see that net income was significantly impacted in both periods by the impairments 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 uses of cash, capital expenditures amounted to $107 million, excluding capitalized interest, most of which correspond to the final payments to the IEM project EPC contractor.
In the next bar, we show the acquisition of the Los Loros and 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 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 CPH. The next two bars correspond to factors that had a direct effect on debt balances but had no effect on cash. 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 CLP 68 million in income taxes and CO2 taxes in the first nine months of the year. Our cash sources, included in the gray bars with negative numbers, as they led to a reduction in net debt, included a CLP 22 million cash payment from CEN and CLP 423 million in operating cash flow. This last number includes CLP 80 million cash payment corresponding to liquidated damages paid by the IEM EPC contractor. Of the CLP 80 million, as we explained earlier, almost CLP 75 went to the income statement, and the remaining five went to the balance sheet as a deduction from the fixed asset account. In slide 31, provides details of our liquidity and debt structure, the main changes here are the following.
Thanks to the EBITDA growth and the lower net debt, the net debt to EBITDA ratio has continued decreasing, and it is now at 1.4 times. Our gross debt remains flat because the addition of 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. Also, we had also discussed this last quarter, Fitch Ratings confirmed our triple B flat international rating and changed the outlook to positive. On slide 32, we can see that in 2019, we have increased the dividend paid, including a $50 million provisional dividend in June, to recognize 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 that ECL's share price increased by 8%, whereas the IPSA fell by 4.2%. This is all on my side, and I'll leave you with Eduardo for the final remarks.
Well, thank you very much, Bernardita. I think it was another good quarter for ECL. We expect to reach the high end or even beat our guidance for this year. Now we're ready for any questions that you may have.
Thank you. The floor is now open for questions. If you have a question, please press star then one on your touch-tone phone at this or any time. If at any point your question is answered, you may remove yourself from the queue by pressing star then two. Questions will be taken in order they are received. We do ask that when you pose your question that you pick up your handset to provide optimum sound quality. Please hold while we poll for questions. The first question today comes from Ezequiel Fernandez with Credicorp Capital. Please go ahead.
Hi, good day. Thank you for the materials and the presentation. I have two basic questions related to the quarterly results. The first one is related to the ingresos por peaje, or transmission revenues. This quarter, they amounted to $40 million. By the way, I got disconnected the call. Maybe you commented on this, I don't know. Again, transmission revenues were $40 million this quarter. That's roughly $20 million higher than usual. I wanted to know if there is any reclassification or any recalculation of transmission tolls that took place.
Ezequiel, that is because of.
Yes
re-liquidations, essentially. The $20 million
Okay.
It's hard to explain.
No, I know it's a tricky calculation, but that the regulator does it, so that's good. Thank you. My second question is related to the EML contract, the smaller regulated contract that you had for a while. Regulated 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. Anyway, 7% down year-over-year is a lot less than what we're seeing on the other regulated contracts from other generating companies, which are falling maybe 15%-20% year-on-year. I wanted to know if there is a specific reason why EML should not drop as much. Also, what is your expectations on overall changes in regulated volumes for next year? Thank you.
Hi, Ezequiel. Well, basically, in the specific case of EML contract, I think it's a specific situation in the region in which our distribution companies related to this contract are located.
The universe of potential clients to migrate is smaller than in other regions. 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.
That's super clear.
Yep. The second is basically what we have been trying to explain before, considering that today clients with a maximum or with a demand of 0.5 MW or more can migrate. We believe that the universe of regulated customers with this possibility almost already migrated. We believe that in the future, the demand in our, let's say, central DisCos PPA should remain stable at current levels. That's at least our best view on the future. Later on, it could have an increase after 2024, 2025.
That's all from my side. Thank you very much.
If you have a question, please press star then one. The next question comes from Macarena Auzua with Credicorp Capital. Please go ahead.
Good afternoon. Thanks for the presentation. I have two questions. The first one is regarding the stabilization mechanism. Are you thinking that this will affect your dividend policy for 2020? My second question is about your gas mix during this quarter. I would like to know if there was some gas coming from Argentina.
Hello, Macarena. Well, in relation to the gas from Argentina, we signed the contract. We are ready. We haven't yet imported any gas. 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. Your first question?
Dividend.
The dividend policy. Okay. In relation to the dividend policy, well, basically, I think this mechanism or this system is probably not going to be as relevant as the speed and the possibilities that we may have in accelerating our CapEx program or finding any acquisitions in the next year. We do believe that there will be an impact in cash flow, of course. There will be a working capital impact. The reason behind a change in the dividend policy or paying more or less dividends shouldn't be materially affected by this working capital need. More relevant will be our business plan and growth plan for the future.
Okay. That's all. Thank you very much.
The next question is a follow-up from Ezequiel Fernandez with Credicorp Capital. Please go ahead.
Sorry, guys. It's been answered, so thank you.
Again, if you have a question, please press star then one. Since 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.
Yes. 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.