ENGIE Energia Chile SA

SGO:ECL

Earnings Call Transcript 2020-Q3

[Operator]

Good afternoon, everyone, and welcome to the Engie Energia Chile's Third Quarter 2020 Results Conference Call. If you need a copy of the press release issued yesterday, 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 the 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'd like to advise participants that this call is dedicated to investors and market analysts, not for the press. We ask that all journalists to contact Engie Energia Chile's PR department for details. I would now like to turn the conference call over to Mr. Eduardo Milligan. Please go ahead, sir.

[Eduardo Milligan Wenzel, executive]

Thank you. Good afternoon, everyone. Thank you for attending this call. I hope you and your families are safe and doing well. So today, Bernardita Infante, Head of Corporate Finance; Marcela Munoz, Head of Investor Relations; and I are very pleased to be once again with you to present our third quarter results. For this quarter, we have updated our corporate presentation. Hope you find interesting new information and additional elements on ECL transformation plan.

So today, we will focus first on the key messages for the third quarter. Second, we will go through the main operational events of the year then we will give you through -- a view of our projects under development. We will continue then on section 4 on the financial update to end with the main key takeaways we want to share today with you.

Now please turn directly to Page #7. On this page, we present the main key messages for this quarter. First, we are glad to mention that despite COVID, ECL has shown an operational resilience during the year that may allow us to probably reach the low end of the EBITDA guidance we gave for 2020. Indeed, we still have almost 2 months to go, but if the current market context remains stable, we may be able to reach our target, which is something very difficult in the current context.

Second, as you already know, in 2020, we completed the transformation of AMSA PPAs into green corporate PPAs. But in addition, we have signed new green PPAs with other clients like CAP, Parque Arauco, [ CCU RNX ] for additional 0.7 to 0.8 terawatts hour per year. This means we have added almost 2 terawatts hour per year of green corporate PPAs to ECL portfolio.

Third, we continued with the development and construction of renewals and transmission assets. I will go in detail over them in a few minutes, but I am also glad to mention that we will be completing in less than 12 months half of the 1 gigawatt we announced last year and that we are almost ready to launch a second group of renewal projects to complete this plan.

And fourth, in 2020 and during this crisis, ECL was upgraded to BBB+, which reflects the sound financial situation of the company and its ability to finance its transformation plan. So in this line, last Tuesday, ECL Board approved a provisory dividend of $67 million to be paid by the end of November, which represents 50% of ECL recurring net results as of September.

Let's continue to go through some details, and please move to Page #8. In this page, we show the path to transform ECL starting from the PPAs we converted together with our clients to the asset rotation plan, closing in this phase 0.8 gigawatts of coal units and replacing them with at least 1 gigawatt of renewables, of which 0.5 or 50% of this amount were acquired or are under construction and 0.5 gigawatts will come next. On the right hand, we can see some figures comparing 2020 9-month results with 2019 and 2018. Bernardita will explain the evolution of our financial results in some minutes.

On Page 9, we present a snapshot on ECL results comparing 2020 with 2019 for the same period. Total revenues reached almost $1 billion in the first 9 months of the year, down 11% from previous year despite the 3% increase in physical sales. This was because average prices decreased in turn due to the decrease in fuel prices, but costs also decreased. Our generation increased mainly due to the commissioning of IEM in May 2019. The increase in generation led to an increase in fuel costs despite the drop in fuel prices. However, our spot energy purchases decreased significantly from 4.3 terawatts hour to less than 3 terawatts hour or in other words, decreased 31% compared to previous year.

All in all, EBITDA is 21% lower compared to the previous year. This same impact was minus 29% for the first half of 2020. This means we have recovered some ground during the third quarter, of course, despite there is a COVID impact embedded in this result that could be around $15 million. The relevant decrease in comparison to 2019 is mainly explained by the $75 million LDs registered back in 2019, which were paid by IEM contractor due to the delay of startup. Excluding this impact, EBITDA in 2020 is almost in line with the EBITDA of previous year, which could be something to highlight in the current context.

Now I'm sure you're interested to see what we expect for the full year. I will be there in a couple of minutes to discuss our guidance and some sensitivities. In the same line, the recurring net income was $133 million, mainly explained by 2 effects. The LDs we received from IEM contractor is the first one. And the second one, higher interest expenses because interest expense ceased to be capitalized upon the completion of the IEM project around May 2019.

So in summary, physical energy sales had a positive performance considering the current context with an increase of 3% compared to previous year. However, we expected more than this when we prepared our guidance for 2020, and the lower-than-expected growth is explained by the lower regulated demand impacted by COVID. EBITDA fell in line with the average lower energy sales prices because of the indexation to fuel prices, but which were finally offset by lower costs of energy and fuel prices. Therefore, ECL margin after -- or excluding the LDs received in 2019 remained almost stable.

On Page 10, we present ECL's supply curve which, as every quarter, is very useful to understand our results. As you can see, IEM, CTA and CTH power plants continue to operate as baseload units for the system. Our 2 combined cycles units running with natural gas plus generation by Gas Atacama using our gas represented close to 22% of our energy supply, while the rest of ECL's coal units were less dispatched, as you can see in the table on top of this slide. Just a reminder, we already announced closure of units 14 and 15 in Tocopilla by the end of next year and for CTM1 and CTM2, around 2024 or even sooner if conditions are appropriate.

Finally, ECL bought almost 38% of its contracted demand between the spot market and the supply agreement with the other generation company. This means that we buy from the spot market at a lower cost than we can produce with our less efficient coal units, which still act as a physical hedge to limit the production costs at a certain level. Once the 3 renewal projects that are currently under construction reached commercial operation during next year, ECL purchases in the spot market should reduce to around 30%.

On Pages 11 and 12, we can see ECL main strength, which is its long-term portfolio of clients and PPAS. We show the evolution of ECL portfolio and how the average life of our portfolio is currently reaching 11 years.

If we move to Page #13, we can see how the green area in the graph has increased. This is explained by the new PPAs we signed during 2020, while we continue working in potential alternatives to transform the remaining coal-linked PPA with Codelco. The message behind this slide is that despite one of our main objectives was to transform the existing PPAS, an additional objective is to grow, capturing additional demand and clients in the upcoming years. So ECL structure and processes have evolved over the last 3 years to be prepared for this new phase.

As just mentioned, there is only one PPA in our free client portfolio that is still linked to coal. This means the transformation process we started 3 years ago to transform all PPAs into green corporate PPAs is almost concluded. Half of the renewals linked to this process are ready or under construction and that we can move forward towards a new phase of additional growth.

Now please turn to Page 14. For 2020, we have updated our CapEx forecast, and we expect $300 million mainly focused on our renewable and transmission projects as well as some maintenance. This quarter, we have also included our best estimate for 2021, which involves $361 million for renewables and transmission and $31 million for maintenance. As you know, we plan to finance these capital expenditures with a mix of internal cash generation and bank financing.

In this line, our net debt-to-EBITDA ratio should increase during 2020 to almost 2x following the additional debt we will raise to finance the portion of our CapEx needs. We intend to keep our leverage ratios not exceeding 2.5x on a structural and regular basis. We need to consider, however, that in 2020 and 2021, we will have most of the negative impact related to the regulated tariff stabilization mechanism which will need to be financed by ECL until these long-term receivables are collected in 5 to 7 years or until a monetization structure is implemented to sell these receivables.

Let's talk now about our guidance for 2020. Please turn to Page #15. Last quarter, we mentioned that we decided to keep this page unchanged, but adding a message that this guidance was under revision to be aligned with the current COVID context. Now 3 months later and considering we have only 2 months to go, I think we are ready to provide a better view on the best estimate for the full year. In this line, well, I'm glad to mention that ECL has shown an operational resilience during the year that will probably allow to reach the low end of the EBITDA guidance we gave for 2020. So if the current market conditions remain stable, we may be able to reach this target, something, as I said before, very difficult in these times and I'm sure will be appreciated by all shareholders.

For 2020, as we explained in previous quarters, we were expecting higher contracted demand compared to 2019 but a lower operational and recurring EBITDA during the year mainly explained by the termination of Zaldivar PPA during the second half of this year. Now what happened during the year?

First, our regulated demand increased in the first 9 months compared to previous year. Mining and other new clients, demand was higher and close to 0.2 terawatts hour compared to the same period of previous year. This increase is close to what we were expecting for 2020 guidance.

Second, the regulated demand slightly increased compared to 2019. But again, we were expecting a higher increase, and we are probably around 0.3 terawatts hour year-to-date, below our estimated regulated demand for 2020 or in other words, between 6% to 8% below the estimated demand pre-COVID. Therefore, the impact of the current situation of regulated demand has negatively impacted our results during the first 9 months of the year in around $15 million. If the current trend in consumption remains stable during the last 2 months of the year, we could expect a full year impact of approx $20 million.

Third, from a cost of supply perspective, the lower demand, lower fuel costs and consequently, lower spot prices helped to partially offset the negative impact in the regulated demand. And finally, operational expenses continued to be optimized, but these savings were negatively impacted by the additional expenses the company had to incur to adapt our operations to the current COVID context. But all in all, this is also a positive impact for our 2020 results.

We do know that COVID-19 will affect our results in ways that are difficult to predict. But for 2021, if demand continue recovering at current pace -- and we are optimistic ECL should be able to see a recovery in EBITDA once also the 3 renewal projects are in operations since ECL will replace spot purchases at spot market prices, let's say, between $30 to $40 by [ provisioning ] with our renewals at almost 0 cost.

On next page, 16, we present an estimated COVID impact during the first 9 months of the year. As I mentioned before, it's $15 million, on the left, which already materialized in our P&L. Then we present in this page 2 simple scenarios as sensitivities, 5% and 10%, affecting only regulated or both regulated and unregulated demand. I hope these sensitivities will provide some guidance. If we assume a moderate case that is very similar to what we have seen so far of minus 5% affecting only regulated demand, then we will be close to minus $20 million for the full year considering the additional minus $5 million impact for the last quarter of the year.

Therefore, if current market conditions remain stable and we don't see an important change in demand for the last 2 months of the year, we could expect the full year EBITDA closer to the low end of the guidance we provided for 2020. Next quarter, we will, of course, come back with a new guidance range for 2021 to give you more elements than the ones we have already discussed during this call.

Now on Page 17, we are summarizing again where we are with the transformation plan. And following this snapshot, please turn to Page 18. This new page shows an updated view of the asset rotation plan. First, at the bottom, we can see the 6 coal units we already committed to close between 2019 and 2024. Second, on the top, we present the different renewals that we will replace -- that will be replacing, let's say, those coal units on the bottom.

In summary, we have committed a 1 gigawatt plan, and we are preparing an additional set of renewal projects for an additional 1 gigawatt. As I mentioned before, half of the first gigawatt is already committed between the plants we acquired during 2019 and 2020 and the 3 projects that are currently under construction and that will reach operation next year. The other half will be coming soon.

If we turn to Page '19, we can see a snapshot of how ECL portfolio will evolve between 2018 and 2022. In 2018, coal power plants represented 58% of ECL total installed capacity, and renewables represented only 1%. By 2022, only 4 years after, renewals will represent at least 40% to 42% of ECL's installed capacity.

Now let's move to next section and go through some specific events impacting our operational results during the year. I'm now on Page 21.

We explained during our last 2 calls, the COVID pandemic has created several challenges to adapt our processes and operations and to respond very fast, ensuring the safety of our teams and also the operational continuity and finally, the way we do business and work together with our clients and other important stakeholders. So we continue running our business through different committees that, in practice, have become part of our day-to-day operation and processes and have implemented different contingency plans in our sites to keep and to ensure the operational continuity of our power plants. We will know that we need to continue alert and do not relax the controls and safety measures until we can return to normality.

Now on Page 22, we can see the main terms and conditions of the agreement signed with Antofagasta Minerals during the first quarter of 2020. As I explained before, this agreement, together with the new green corporate PPAs that we present in next page, 23, represent almost 2 terawatts hour per year of green PPAs for our longer-term portfolio.

On Page 24, we can see the main conditions for the recent acquisition of Eolica Monte Redondo. So maybe, what will be the contribution of this acquisition to ECL in terms of EBITDA? Around $7 million in 2020 for half of the year, around $15 million in 2021 and around $10 million between 2022 and 2023. Well, afterwards, it will depend on the marginal costs. But it doesn't matter because afterwards, these 2 plants will become uncontracted and will contribute its energy yield to ECL portfolio and its 11-year average life portfolio of PPAS.

Now please move to Page #25 to discuss where we are in relation to the price stabilization mechanism. In the past 3 calls, we have already explained in detail how this law and mechanism works. So the main 2 variables that will determine the size and recovery pace of the fund is the demand, the regulated demand, of course, and the peso-dollar exchange rate, since the underlying exchange rate of the price is approximately CLP 640 per dollar, while the FX rate is currently close to CLP 780 per dollar. As of September 2020, the size of this account receivable in our books was $131 million and represents an increase of $19 million versus the previous quarter. This represents an around $6 million monthly increase for ECL. As we explained before, to improve our cash flow position, we are evaluating different alternatives to monetize these receivables. Once we are ready, we'll be able to communicate the preferred option.

An important question you may have is when we expect the fund will be fully consumed. Well, this will depend on the demand and FX evolution. It's very -- the FX evolution will basically determine when the fund will be consumed. But if we use the current FX rate ranges and expected regulated demand, it could happen during 2022. An appreciation of the Chilean peso will benefit the duration of the fund and vice versa.

Finally, on Page 26, we wanted to share the main regulatory topics that will be in the agenda for the medium and long term. I'm sure these topics are of your interest.

Before we discuss some of them, first, I want to highlight that -- the recent results of the plebiscite that took place last Sunday in which by majority was approved the initiative to draft the new constitution. So in this line, it was also approved that the new constitution will be drafted on a constitutional convention, meaning the convention will be comprised entirely of 155 members elected by the public. The convention will begin drafting the new constitution in June 2021, and we'll have until May 2022 to finalize this new constitution, which would be subject to another plebiscite.

Now moving directly to some regulatory topics. Maybe today, in addition to the stabilization fund status I recently explained, we can tackle 2 additional topics that were recently in the news, and that we may be able to highlight and explain during this call.

So first, I can summarize the recent proposal on electric portability. Well, this project was officially presented by the Ministry of Energy and the National Energy Commission. Some of the main objectives of this new framework are to provide each client the right and possibility to choose their electricity supplier to increase competition and to promote innovation.

So this new scheme will differentiate electricity consumers in 3 groups: small consumers with demand below 20 kilowatts, mainly residential consumers; medium-sized consumers, between 20 kilowatts and up to 5 megawatts; and finally, large consumers with a demand above 5 megawatts. Under the future new scheme, every consumer will have access to the free market, but only those consumers with a demand below 20 kilowatts will have the option to remain with their existing electricity supplier. Who are those demanding less than 20 kilowatts? Well, mainly residential consumers. If part of these consumers does not want to change supplier, then their demand will still need to be supplied through regulated auctions.

We expect this new scheme to be implemented on a gradual basis and without affecting the existing demand and related contracts. So we should not expect a negative impact or that the existing contracts will be at risk. The Ministry objective, with a gradual implementation, is to respect existing contracts and related investments.

Second, maybe we can clarify some recent news related to the potential accelerated decarbonization of the Chilean generation matrix by 2025 that has been discussed recently. In this line, I can mention what the ministry and energy commission concluded and shared recently that this initiative can be executed in this time frame. The process to approve this initiative still needs to go through different stages in Congress and technical commissions.

We expect the technical elements will be clarified and will help to better plan a future decarbonization that will consider all impacts and consequences for the overall system, like the cost of this initiative or the systems reliability, not to mention impacts on workforce, and as I mentioned before, loss of competitiveness when replacing coal units with diesel or gas power plants. Well, we can expect this process can continue with the renewables, but not as fast as for 2025. The message is that this initiative goes in the good direction, but needs further planification.

Now let's move to next section and discuss where we are with projects under construction. On Pages 28 and 29, we can see the full picture of the current plan to develop renewables: the 2 acquisitions in 2019 and 2020 of Los Loros and Monte Redondo totaling 137 megawatts, the 3 projects under construction for 362 megawatts, additional wind and PV projects for 539 megawatts that are getting closer to its implementation phase and other projects under development for 1 gigawatt. The last row shows the estimated total CapEx for the -- to complete the first gigawatt of renewals with a total investment of $851 million. This amount is below the initial estimated CapEx of $1 billion for 1 gigawatt.

Next pages, 30 to 34, show the detailed status of each renewable and transmission project under construction. In summary, wind Calama on Page 30 has a global advance of almost 50%, and we maintain its commercial operation date target for the third quarter of next year. Capricornio solar plant has a global advance of 75%, as you can see on Page 31, and we expect its full commercial operation date during the second quarter of next year. Tamara solar plant has a global advance of 61%, and we expect a full commercial operation date by the end of the second quarter of 2021.

Then for transmission projects, the first 4 projects described on Page 33 with a total investment of $53 million will be ready in the upcoming 6 months, on budget and also on scale, while the 2 additional projects awarded this year described on Page 34 should start construction soon once the decree is issued by the authority. Both will require a total investment of $28 million and have an estimated commercial operation date for 2023.

Now we can move to the final section. So I will invite Bernardita, and Bernardita will give us more details on our financial results.

[Bernardita Infante, executive]

Well, thank you, Eduardo. Hello, everyone. I'm on Slide 36. Our EBITDA decreased by $91 million to $338 million in the first 9 months of this year. So leaving aside the effects of the pandemic for one moment, we can see that the $75 million of the EBITDA decrease can be attributed to the liquidated damages that we received last year from the main contractor for the IEM power plant to compensate for the delayed start-up of the project.

Another $22 million of the EBITDA decrease is explained by the drop in our electricity margin. And why did the electricity margin decrease? The main reason was electricity prices, which fell because the indices to which our tariffs are linked, that is, coal prices, Henry Hub and CPI, fell significantly compared to last year. In addition, last March, we signed a very important PPA renegotiation with Minera Centinela controlled by Antofagasta Minerals. This renegotiation not only involves the commercial terms of the PPA, but also the transfer of control of Inversiones Hornitos.

Under the agreement, the PPA has a bigger price discount in 2020. Through this bigger discount every month, Engie is paying for the acquisition of a 40% stake in Inversiones Hornitos. So the tariff decrease affected our electricity margin, but it was countered by the income related to the acquisition, which amounted to $23.7 million in the first 9 months of 2020. Therefore, its effect on EBITDA was almost neutral.

Now the increasing fuel costs, despite the drop in their prices, is explained by the increase in our coal and gas generation mainly due to the start-up of IEM in May 2019 and increased availability of LNG to run our combined cycle units. As our generation increased, we had to buy less energy from the spot market, and this leads us to a $75 million positive impact on EBITDA because the decrease in electricity purchase volumes was coupled with lower spot prices, which averaged $40 per megawatt hour at the Crucero node in the first 9 months of 2020, down from $49 per megawatt hour compared to the same period of 2019.

And now, what happened with our physical sales in the context of the pandemic? The demand from our free clients increased 5% because our mining clients continued operating while last year, they were affected by a hard Altiplanic Winter, temporary stoppages for the upgrade of emission reduction systems and the strike at the Chuquicamata mine. In the third quarter, however, the demand from our free clients decreased 7% compared to the third quarter of 2019 mainly due to the end of the Zaldivar PPA last July.

Now in terms of sales to regulated clients, we can see a 2% increase in the first 9 months of the year. In the first quarter, before the pandemic outbreak in Chile, physical sales to distribution companies increased. Please remember that beginning 2020 and this pro rata share of the PPA with distribution companies in the south center segment of the SEN increased as older PPAs from other generation companies came due.

So the COVID effect on power demand did not begin to show until the end of the first quarter. It was the second quarter, the one reflecting the most the COVID impact. In the second quarter, physical sales to distribution companies decreased by 5% when compared to the same quarter of 2019 but by 13% when compared to the first quarter, which already included the pro rata increase.

So in the third quarter, demand from distribution companies began to recover given the gradual relaxation in lockdowns. So please note that our third quarter regulated sales include 50 gigawatt hour of Eolica Monte Redondo sales under its PPAs with [ CTE ]. So overall, for the first 9 months of the year, we can say that the COVID effect was completely offset by the increased pro rata of the pool of contracts with distribution companies.

Now please turn to Slide 37 to discuss the evolution of net income. In the first 9 months of 2019, we reported net income of $143 million. But this result was affected by the impairment of units 14 and 15 in Tocopilla which will be closed by year-end 2021. If we discount this $64 million nonrecurring impact, we would have reported $207 million recurring net income in the first 9 months of last year. This result is shown in the box at the center of the slide.

The bars inside the box show the evolution of net recurring income, which went down from $207 million to $133 million in the first 9 months of 2020. The main reasons for the decrease were the one-off income from the liquidated damages paid by the IEM contractor, which had a positive $55 million after-tax impact in 2019. Other effects included increased depreciation costs as a result of the start-up of IEM and higher financial expenses given the decrease in capitalized interest.

But we also reported a nonrecurring effect in 2020 with a negative $10 million after-tax impact. This was due to the make-whole paid to bondholders in a liability management transaction in the first quarter by which we issued a $500 million bond to repay an old one. This transaction allowed us to raise $100 million in additional debt while at the same time, saving $5.5 million per year in interest expenses and extending our average debt maturity to 7.7 years.

Finally, we can see that the minority interest disappeared. As according to IFRS rules, ECL took full control of CTH upon execution of the agreement with AMSA at the end of March.

Now we go to Slide 38. We can observe an increase in net debt as a result of the following cash flows in the first 9 months of the year. In terms of uses of cash, the first 2 bars show capital expenditures and the acquisition of Eolica Monte Redondo, which taken together amounted to $192 million. Capital expenditures were primarily related to investments in our renewable and transmission projects.

In the following bar, we show the $14 million paid -- premium paid to bondholders. The next 2 bars correspond to factors that had a direct effect on debt balances but no effect on cash. The first bar includes accrued interest and mark-to-market variations, and the second one includes an increase in land and vehicle leases classified as financial leases pursuant to IFRS 16. These leases have increased mainly due to land leases for the development of our renewable project pipeline.

Now income -- CO2 and stamp tax payments amounted to $73 million. Our cash sources, shown in the red bars with negative numbers as they lead to net debt reductions, included a $7.5 million cash payment from TEN at the beginning of the year and $200 million in operating cash flow.

In Slide 39, we give some details of our financing activity. We have already talked about the issue of a new $500 million 144A/RegS bond mainly used to refinance the old $400 million bond with original maturity in January 2021. Another transaction that we expect to close really soon is $125 million innovative type of financing from the IDB, which seeks to finance the construction of renewable projects in combination with an incentive to accelerate the closure of coal-based plants.

In Slide 40, we provide details of our liquidity and debt structure. The main changes are the following. The net debt-to-EBITDA ratio is at 1.8x. EBITDA for the last 12-month period ending September 2020 was $443 million, while net debt reached $809 million. Our gross debt increased by $74 million to $996 million. This is compared to year-end 2019 basically due to the $100 million increase in our bonds and a $26 million increase in IFRS 16 leases. A $30 million net reduction in our short-term debt partially offset the gross debt increase. As discussed earlier, Fitch ratings upgraded our international rating to BBB+ and our local rating to AA both with stable outlook.

Now on Slide 41, we can highlight 2 things. First, that after a prudent decision of not making -- of not paying dividends last May in light of the uncertainties brought about by the pandemic, last Tuesday, our Board approved a provisional dividend on account of 2020's earnings to be paid on November 30. The amount is $67 million approximately, which corresponds to 50% of the net recurring income reported in the first 9 months of the year.

The second point we can highlight is that despite our good results in this difficult environment, our stock price has fallen 24% in the last 12 months, performing only slightly better than the market. We trust that our resilience and long-term strengths from our PPA re-profiling and decarbonization strategies will be recognized and reflected in our market value going forward.

And now I will leave you with Eduardo for the final remarks.

[Eduardo Milligan Wenzel, executive]

Thank you, Bernardita. Well, to conclude this presentation, I want to summarize the main key takeaways we present on Page 42.

So first, despite this year negative effects, ECL has shown an operational resilience during the year that may allow the company to reach the low end of the EBITDA guidance we gave for 2020. Second, we continue signing new green corporate PPAS, adding more than 0.7 terawatts hour in 2020. Our new business structure and organization is ready to continue expanding our strong base of customers with additional long-term PPAs and other energy solutions.

Third, we continued with the development and construction of renewables and transmission assets. We are glad to mention that we will be completing in less than 12 months half of the 1 gigawatt we announced last year and that we are almost ready to launch the construction of a second group of renewables to complete this plan. And fourth, the recent rating upgrade to BBB+ reflects the responsible and sound financial situation of the company that is key to finance our transformation plan and at the same time, keep an adequate dividend policy.

So well, with these final messages, we are finalizing our third quarter presentation. We hope the presentation is helpful and wish all of you the best in these difficult times. Thank you, and we are ready for any questions you may have.

[Operator]

[Operator Instructions] And our first question today comes from Murilo Riccini from Banco Santander.

[Murilo Riccini, analyst]

I have a couple of questions for you guys. Talking about the portability bill that is being discussed in the Lower House, in the case this bill is approved in 2021 or '22, how are you seeing the valuation movement going forward? And what levels of demand do you expect for your regulated PPAs in the coming years? Like, how could be the pro forma of this level of demand? And which kind of mechanism could be implemented in order to ensure the financial balance and stability of these current regulated contracts in the case you see this possibility?

And regarding the bill that prohibits the coal plants by 2025, what are the alternatives related to the existing assets, especially those -- the new plants like IEM that you have? And what are the criteria are you evaluating to move forward with the second step of the investment plan, this additional 1 gigawatt of renewables?

[Eduardo Milligan Wenzel, executive]

Murilo, thank you for the questions. So the first one [ in relation ] to portability, I think it's very important to clarify that the intention of this new scheme is to basically provide this flexibility and to cover the, let's say, regulated demand that will not be supplied by the existing contracts. So what we are not seeing here is that if the current contracts or the existing contracts will reduce their expected demand but that after 2025, 2026 when new demand comes to the market or when some contracts end, then this new scheme should replace the contracts that will mature within this period.

That's why I mentioned that the intention of the ministry and the CNE is basically to do this on a gradual basis, to implement some pilots within this period because the intention, again, is to respect the current contracts and investments that are related to the plants that several companies built over the last years following the existing mechanism of regulated auctions. So this is something that should be gradual and that should capture the growth in demand that we will see in the future or the demand that will be maturing after 2025. That's the first one.

Then in relation to 2025, basically, as you know, we already announced closure of 6 coal units of the 9 that we have. So we will close 0.8 gigawatts between 2019 and 2024, while the 3 remaining coal units that we have, CTA, CTH and IEM, these 3 units have less than 10 years or around -- or in average, let's say, 7 years in operation and IEM recently started commercial operation. So these are units that today are baseload units for the system. We do believe that in the future, there could be some alternatives for them. As you know, and this is something that we have seen in other countries, this type of coal units could be converted to other technologies. But this is something that needs to be very well clarified also from a system reliability standpoint and also from a technical point of view.

So we are not ready yet to say that this is possible or not. But from our side, at least, this is something that we have been analyzing over the last years. And once we have more information, we will be very glad to share what options we could have for these units in the upcoming years or in the long term, considering that the 3 of them still have some years to go until the end of their economic life.

And the third one, what could trigger the additional 1 gigawatt that we mentioned that are currently under development, so basically, new demand could be one option. An additional option could be if we see that the spot prices go up very fast. As you know, we are net buyers in the spot market since we have a contracted portfolio with an average life of 11 years. So today, we are buying 38% of our needs in the spot market. In the future, this should go down to around 30% with the 3 projects that next year will come into operation. With the other projects to complete the first gigawatt, it should go down again in another 10%.

And then as you know, there is some intermittency with the portfolio of renewables, so we will always need to buy some energy in the spot market. But to launch an additional set of projects would depend on new demand and the portfolio needs. So what is important is to have these projects ready, to have them ready to be launched in case our portfolio determines that it's better than being exposed for 10% or 20% of our needs in the spot market.

[Murilo Riccini, analyst]

Great. And a follow-up question, if I may. How are you seeing the level of competition in the industry mainly after this movement that we have seen in the social and political side related to the sector and also the country in general? Are you seeing the same level of competition in terms of renewing the PPAs and also award of new PPAs?

[Eduardo Milligan Wenzel, executive]

Yes. Certainly. I think we are positive on the future. We're positive on the future of the economy, on the future of new mining projects that could trigger additional demand and that could trigger additional investments in the market. Well, as you know, there are still some PPAs in the market that are currently covered with the thermal generation that will need to be converted in the future to other generation sources or to green corporate PPAs. So we do believe that there are good opportunities to continue investing, and if we see these, I'm sure others, too.

[Operator]

Our next question comes from Andrew McCarthy from CrediCorp Capital.

[Andrew McCarthy, analyst]

My first question is on Page 14 of the presentation. I see that you have kind of EBITDA of -- just looking at the green -- the bold green line, you have EBITDA of about $450 million for 2020 and then around $480 million for 2021. So just to understand that, so effectively, the increase year-on-year in 2021 should primarily be led by the start-up of the new renewable plants basically in the second half of next year, which means you'll have to make less spot purchases because of that, and also some positive impact from -- in the first half from the Monte Redondo PPAs. Is that the right way to think about it?

[Eduardo Milligan Wenzel, executive]

Andrew, sure. I think you answered -- your answer is very good to your question. I completely agree with your analysis. I think both impacts will probably create a slightly increase in the EBITDA for next year. But of course, there could be other, let's say, positive or even negative impacts that we need to consider in relation to spot prices, for example, for regulated demand or unregulated demand. But if we consider that the current context remains stable for next year, you will see the positive impact next year, as you said. We will have a full year with Monte Redondo. Second, we will see the positive contribution of the renewables coming online next year replacing spot purchases at $30, $40 by producing [ normal ] fuel.

[Andrew McCarthy, analyst]

Okay. Got it. And just to understand it, so what are the biggest risks you would say there are to that $480 million target? What are maybe the 1 or 2 factors that you'd be most concerned about as at today?

[Eduardo Milligan Wenzel, executive]

I would say any impact on our overall demand. As you can see, a 6% to 8% decrease in the regulated demand over 2020 represented almost $20 million of lower EBITDA. So -- and this is only for regulated demand. So in my view, if we see a complicated 2021 in terms of demand or if the economic conditions get worse during next year, then we can see a lower EBITDA coming from lower demand basically. I think demand will become the most important parameter for next year. We can say that spot prices, too. But considering the current demand and the entry of renewables and the fuel prices that we are currently seeing for next year, maybe it's in the second line. The first and more important probably is the overall demand.

[Andrew McCarthy, analyst]

Got it. Very clear. Just one further question, if I may. You mentioned the -- in terms of the renegotiations of the PPAs, the big one outstanding is with Codelco. I was just wondering if you could provide any color on what needs to happen there to get that renegotiation done. And if once that is done, would that trigger the possibility of you being able to then take out CTA or withdraw that from -- eventually and move you closer to that finally taking all the coal -- all of your 9 coal units out?

[Eduardo Milligan Wenzel, executive]

Sure. Well, with Codelco, we are not there yet, and this is not because we have difference and -- or other reason. It's just because we are both still preparing some alternatives to make the deal happen. So as you know, we started this process in 2018. Codelco was, in fact, the first client with which we renegotiated our first group of PPAs. So we know each other. We have a very good relationship, and we are -- I'm sure our commercial team will find a win-win solution with Codelco.

Now what will happen then with the CTA? Well, again, CTA for me, it's not a dedicated asset in this line. It's part of the overall portfolio. And afterwards, it should provide a physical hedge to the overall portfolio. And as I explained before, in parallel, we will see what alternatives we can implement for this type of plants if in the future are not needed for the system.

[Operator]

[Operator Instructions] Our next question comes from Juan Carlos Petersen from Inversiones Chufquen.

[Juan Carlos Petersen, analyst]

Can you hear me well?

[Eduardo Milligan Wenzel, executive]

Yes.

[Juan Carlos Petersen, analyst]

Three questions. Again, thanks for the presentation. It's very well prepared and very clear. The first question is related to Page #26, again, regarding the electric portability. Just would like to confirm that, if I heard you correctly, that you did say that you do not expect a financial impact on the regulated contracts that ECL has given the portability initiative? That's my first question, especially on those long-term contracts that are due to 2026, I think, and 2030 or 2032. Second question is related to the monetization explained on Page 25. The question is, Eduardo, what would you expect as defined as a successful monetization and competitive monetization in terms of cost impact on P&L and for when?

And my last question is related to the dividend. Thanks for the announcement done yesterday. It's a very strong signal, the 50% distribution. What would you expect for early 2021 in terms of dividend -- further dividend, additional dividend, given the healthy balance sheet and good results shown this year? And lastly, sorry, I forgot my fourth question related to financial structure. You did mention that you are expecting [ 2 ] new finances, new debt. What would you expect in terms of conditions? Should they be better than those executed early in 2019 related to the USD 500 million that you did announce at that time? Those are my 4 questions.

[Eduardo Milligan Wenzel, executive]

Thank you, Juan Carlos. So I will start with the first one, and the answer to your question is yes. And what I was saying is that we do not expect the financial impact because the purpose of this new scheme is a gradual implementation, and this gradual implementation should capture the additional demand or the demand that becomes uncontracted in the future, after 2025, 2026. So this is why from our perspective, we don't expect an impact on existing contracts.

Then for the second one in relation to the monetization, difficult to tell you right now what costs we expect because we are currently working day and night on this one. So that could give you a hint on the when. So the when, as I said, early, could be during the next call. At least my personal objective would be to be able to communicate some good news on any type of structure during the next quarterly call. But right now, we are not ready yet.

The third one in relation to the dividend policy, what could we expect for 2021. So first, we need to consider that our current policy is to keep a minimum of 30%. So that's the regular standard policy. Now we need to consider that in 2021 and 2022, we will have also an important amount of CapEx to be implemented. So this is why we are not, let's say, ready to fix an amount or to fix a dividend payout ratio for the future, and this will depend, of course, on different developments. And what could we expect for 2021? Maybe something similar to the range that we applied this quarter if conditions allow us to maintain the current payout ratio. But it is something that will be discussed later and will depend on the evolution of our cash flow.

And finally, in terms of our financial structure, your fourth question. So what can we expect in terms of financing conditions? As you may recall, we restructured -- we refinanced $400 million early this year. During January, we issued a $500 million corporate bond with a 10-year tenor. And the rate -- the coupon is around 3.4%. Today, we believe that conditions have improved a bit. So basically, we can be some dips below this previous cost. And any financing coming from the capital market for a bank financing today could be structured in better conditions. So this is something that we need to take into account, but this is something that, of course, depends on the market evolution and market interest rates. But today -- as of today, we can see an improvement in the overall cost.

[Operator]

And ladies and gentlemen, in showing no additional questions, we'll end today's question-and-answer session. At this time, I'd like to turn the floor back to Engie Energia Chile for any closing remarks.

[Eduardo Milligan Wenzel, executive]

Thank you. Well, from our side, I think this is all. Thank you very much for your patience and to be connected with us this quarter, and we'll see you soon during our next quarter.

[Bernardita Infante, executive]

Yes. Well, yes, on my side, I would like to thank you all, and goodbye and to hear you again in our next call. Thank you very much.

[Eduardo Milligan Wenzel, executive]

Thank you. Bye.

[Operator]

Ladies and gentlemen, this concludes today's conference call. We thank you for attending. You may now disconnect your lines.