Edited Transcript of ECL.SN earnings conference call or presentation 30-Apr-20 4:00pm GMT

Thomson Reuters StreetEvents

Q1 2020 Engie Energia Chile SA Earnings Call

May 26, 2020 (Thomson StreetEvents) -- Edited Transcript of Engie Energia Chile SA earnings conference call or presentation Thursday, April 30, 2020 at 4:00:00pm GMT

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Corporate Participants

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* Bernardita Infante

Engie Energia Chile S.A. - Head of Corporate Finance

* Eduardo Martin Milligan Wenzel

Engie Energia Chile S.A. - Chief Financial & Shared Services Officer

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Conference Call Participants

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* Andrew J. McCarthy

Banchile Inversiones S.A., Research Division - Deputy Manager of Studies

* Murilo Riccini

Santander Investment Securities Inc., Research Division - Research Analyst

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Presentation

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Operator [1]

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Good afternoon, everyone, and welcome to the Engie Energia Chile's First 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.engieenergia.cl (sic) [www.engie-energia.cl]

Before we begin, I would like to remind you that this call is being recorded, and that 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 the 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 call over to Mr. Eduardo Milligan. Please go ahead, sir.

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Eduardo Martin Milligan Wenzel, Engie Energia Chile S.A. - Chief Financial & Shared Services Officer [2]

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Thank you. Good afternoon, and thank you for attending our first quarter results call. First of all, I hope you and your families are safe and doing well in these difficult times of the COVID-19 pandemic. So today, Bernardita Infante, Head of Corporate Finance; Marcela Munoz, Head of Investor Relations; and I are again very pleased to be once again with you to present our first quarter results. Just an important message for your logistical purposes, if during the call, you hear some kids screaming around, please don't panic. This is our first call, home office style.

Now on today's call, we will focus on the following 5 main relevant events or developments as they appear in the presentation. These 5 elements are: first, the agreement signed with Antofagasta Minerals regarding the renegotiation of the PPA with Centinela, which resulted in the extension of the 186-megawatt contract through December 2033. Including this agreement, we have already renegotiated more than 75% of our unregulated or free client portfolio and have extended the average remaining life of our PPA portfolio to 12 years.

Second, the progress of our renewable projects under construction, Calama and Capricornio, the Tamaya project, which is ready to start construction around midyear, and our transmission projects in construction are recently awarded.

Third, the actions carried out by the company in relation to the COVID-19 pandemic.

Fourth, the impact of COVID in our guidance for 2020 and some demand sensitivities that we want to share.

And the last point, the liability management transaction. By which, we issued a new 144-A bond for $500 million and fully repaid the $400 million bond maturing in January 2021. As well as the status of a couple of new financing facilities with the Inter-American Development Bank for a combined amount of approx $350 million.

Let's go over through the presentation to discuss these 5 developments in more detail. So please, let's move to Page #9. As discussed during our last call in 2019, we took different steps towards our decarbonization and transformation plan. We ended 2019 announcing the closure 6 coal units with an aggregate gross capacity of almost 0.8 gigawatts, exceeding our binding commitment with the Chilean government that we signed in June. We closed units 12 and 13 in Tocopilla in June '19, and we'll close the other 2 coal units in Tocopilla, units 14 and 15, by the end of next year. Finally, in December, during the COP 25 in Madrid, we announced together with the Ministry of Energy that we are ready to commit the closure of 2 additional units by 2024, which are units 1 and 2 in Mejillones. These closures represented impairments with after-tax impacts of around $53 million on our financial statements in 2018 and $134 million in 2019.

Now please see next, Page #10. We announced the execution of an ambition asset rotation plan, which involves the construction of approximately 1-gigawatt of renewals between solar and wind generation units. This plan will require an investment of approximately $1 billion or less if we continue to be successful in the procurement and sourcing of the equipment. We have already launched the execution of half of this plan. We acquired 2 PV plants, Loros and Andacollo, with a combined 55-megawatt; and started the construction of our first 3 renewable projects, which have a combined capacity of 362 megawatts. Hence, we're covering 417 of the 1-gigawatt already announced. At the same time, we're preparing the additional 600 megawatts to complete this first phase, or even more in case we capture additional demand over the next years. This means we are already committed a total investment of approx $326 million. In this slide, we can also see some pictures of our projects in construction. As of the end of March, GES, the civil works contractor for the Calama wind farm, has completed 28 out of the 36 foundations for the windmills. And the Capricornio solar PV plant reported a 53% state of advance in March. And finally, we delayed for a few weeks, the issue of the notice to proceed for the construction of the Tamaya solar plant -- PV plant given the current conditions. But everything is ready to start at the beginning of the third quarter with no delay expected for the commercial operation dates.

On Page 11, we summarized the 2 recent important events on the financing side. In first place, last January, we launched a 10-year note tender offer to repurchase our existing $400 million bond with maturity in January 2021, which was subject to the issuance of a new bond. Almost half of bondholders participated in the tender. We then successfully placed a new 10-year $500 million bond with a 3.4% coupon. Right after the new issue, we launched a repurchase offer at a make-whole price for the remaining bonds that were not tendered, which was completed -- which completed the refinancing of the $400 million. We also prepaid our short-term bank debt, which amounted to 80 million. The effects of these transactions were that we improved our liquidity as we extended the average maturity of our debt to 7.7 years, and we lowered the average coupon rate of our debt to 3.85%. Because of the make-whole, we reported a $13.6 million one-shot loss affecting our first quarter financial results. We consider this nonrecurring, so it should not affect our dividend payment decisions. At the same time, we will report $5.5 million per year in interest expense savings.

In second place, during the COP 25, we signed a letter of intent with IDB to structure an innovative type of financing, encouraging the construction of renewable projects, which will allow the acceleration of decarbonization plans. This financing is for an indicative amount of $125 million and includes 2 tranches: one direct loan from IDB and another one funded by the Clean Technology Fund. The diligence process has been completed, and we are working in the credit approval and documentation processes to hopefully close the transaction in a couple of months.

Now please move to Slide 12 to discuss the price stabilization law approved by the Congress in November 2019, soon after the outburst of the social unrest in Chile. So on March 11, 2020, the National Energy Commission, also known as CNE, published the Exempt Resolution #72, setting the rules for the implementation of the temporary price stabilization mechanism for clients, subject to regulated tariffs. This price stabilization mechanism follows electricity tariffs at the levels prevailing in the first half of 2019 until year-end 2027, subject to certain adjustments from time to time as provided by the law. At the same time, the tariffs charged by generation companies to distribution companies continue to follow the indication formula set in the prevailing contracts among them. The mechanism will, therefore, produce a differential between the tariffs, but generation companies are entitled to charge according to the terms of their contracts with distribution companies and the tariffs actually collected from regulated end consumers. As a result of this price differential, generation companies have begun to build up an account receivable from distribution companies, which taken as a whole, gives birth to the so-called price stabilization fund.

According to law, this fund may increase until the first to occur between July 2023 or until it reaches a global amount of USD 1.35 billion. The authority expects that once lower-priced power supply agreements awarded in more recent auctions become effective, the average prices in the contracts between generation and distribution companies will begin to decrease gradually starting 2021. At the same point, contract prices will fall below the stabilized price that will be effective until December '27. When average contract tariffs fall below the stabilized price, distribution companies will begin repaying the accounts with the generation companies that form part of this fund. The main variable that will determine the size and recovery pace of the fund is by far the FX rates since the underlying exchange rate of the stabilized price is approximately CLP 640, while the FX rate is currently above CLP 830. As of December 2019, the size of this account receivable in our books was around $73.5 million. As of March, it had grown to $94 million. The resulting working capital financing costs will be borne by generation companies.

So here comes a third financing structure on which we are currently working. It consists of the monetization of these accounts receivable which the IDB, together with the 2 additional commercial banks, have a structure for all generation companies to improve our liquidity. We hope to announce the closing of this transaction before or around the date of our next quarterly call in case we end with an attractive structure.

Now continuing with other recent events, we certainly need to talk about COVID-19 pandemic. So let's go to Page 13. So the coronavirus, or COVID-19, was first detected in Chile on March 3. And as today, more than 16,000 cases have been confirmed. And unfortunately, more than 200 deaths have been reported. The country remains under constitutional state of catastrophe. The COVID-19 pandemic is deemed to be the worst sanitary and economic crisis in recent times. Economists estimates that the Chilean economy will contract into 2020 as a result of the pandemic. The electricity demand has decreased overall by approximately 7% since the second week of March, while the demand of -- from our unregulated clients have so far remained stable. This pandemic has posed several challenges, forcing us to adapt ourselves and to respond quickly along 3 lines of action: first, ensuring the safety and well-being of our teams; second, ensuring our company's operational continuity, which is essential to provide continued electricity supply; and finally, coordinating ourselves, as best as, possible with our stakeholders, including our customers, contractors, suppliers, shareholders and communities to keep an open, direct and collaborative dialogue. Since the beginning of this crisis, we established a Crisis Committee and have implemented several contingency plans adopting sanitary measures in our sites. And that's necessary to comply with the authority's instructions. Similarly, we have monitored the situation and actions taken by our suppliers and contractors, asking them to comply with the safety standards with their own staff. So at present, approximately 70% of our staff is working from home, while approx 300 direct employees and 400 contractors are working in shifts in 10 different sites to ensure the continuity of our operations.

Then our operations are functioning normally, and we believe we can continue doing so under even stricter sanitary requirements. Our reconversion strategy and our asset rotation plan remains unchanged. We continue working hard to ensure the construction of our renewables and transmission projects. So the projects can be completed as timely as possible within the required quality and performance standards.

Now let's turn please to Page 14 to talk about one of the main highlights of the quarter, I refer to closing of the PPA renegotiation with one of our largest clients. On March, we signed a commercial agreement with Minera Centinela, an affiliate of Antofagasta Minerals. In first place, the agreement comprises the amendment of the existing energy supply contracts between our subsidiary, Hornitos, or CTH, and Minera Centinela, considering its Esperanza and Tesoro mines for an aggregate volume of 186 megawatts. So this amendment considers the application of a price discount during 2020 and 2021 and a change in the contract maturity date to December '21. In addition, the agreement includes a new 186-megawatt power supply contract. This time between EECL and Minera Centinela for the period between January '22 and December '33, with prices indexed to CPI. There will be one tariff applicable for the period between '22 and '28 and the lower tariff for the period running between '29 and '33. So this is pretty in line with the previous renegotiations that we have implemented since 2018.

Finally, the agreement, and this is something new because of the current structure that we have for CTH or Hornitos subsidiary. Considering the amendment of the shareholders' agreement, ruling the ownership and corporate governance of Inversiones Hornitos. This includes an agreement not to distribute any dividends until Hornitos' debt with EECL has been repaid in full and to use any excess cash to repay this debt, and the transfer to EECL by the December '21 of 40% of Inversiones Hornitos' shares which belongs to Inversiones Punta de Rieles, an affiliate of Antofagasta Minerals. Under IFRS rules, EECL will take control of 100% of Inversiones Hornitos. And as a result, we are no longer reporting minority interest in our financial statements starting March 31, 2020. So this new contract and its price scheme will allow us to continue our reconversion to renewables while extending the average life of our contracts with Minera Centinela by 7.5 years. In addition, it will help our clients to fulfill its own transformation by gradually replacing conventional power supply with renewable energy. We consider this renegotiation a significant achievement as we have already renegotiated more than 75% of our free client portfolio. So we are now ready to focus our efforts on renegotiating the 150 megawatts Codelco contract with our subsidiary, CTA, to complete this process.

Now let's move to Slide 15 to summarize some company developments. In relation to our clients, after the completion of the [long-term] renegotiation, we report an expected demand averaging over 5.2 terawatt hour per year under our renegotiated and new PPAs with the free clients. This represents around 78% of free client demand. The concept behind these renegotiations are initial discount in the short term, a further discount afterwards, together with the change in the indexation formula moving to 100% inflation; and finally, an extension of the PPA at the latest market conditions.

In relation to our assets, we have 3 relevant events to report: the acquisition of 2 PV plants; the construction of Calama wind farm and Capricornio solar plant; and the Tamaya Solar PV plant that will start construction in the third quarter.

In relation to our ratings, Fitch and S&P, reaffirmed our international BBB rating last January, and our local rating was upgraded by Feller to AA-.

And finally, during 2019, we paid $112 million in dividends, including $22 million paid on account of 2018's profits and $90 million on account of 2019's net profits.

We will continue from now on with the key messages. Please move to Page 17. The first message is that our results for the first quarter were in line with the expectations. However, we are now in a completely different context, facing the effects and the uncertainty surrounding the COVID-19 pandemic.

Then let's go to Page 18. As you know, our contracted portfolio has grown to approximately 12 terawatt hour per year, mainly driven by the full ramp-up of the regulated PPA, which started in January 2018. In the box at the right of the slide, you may see that our total volume sales in the first quarter of 2020 increased when compared to the first quarter of 2019 despite the outburst of COVID in Chile in early March. This was because of 2 main reasons. First, the demand from mining companies in the north of Chile recovered from a tough Altiplanic winter, which affected mines in the first quarter of last year. And second, the demand from regulated companies in the peak increased because our pro rata share, the regulated demand increased as some contracts from other generation companies came due at the end of 2019.

Now please see Page 19. Total revenues reached $335 million in the first quarter, down 2% from the first quarter of last year despite increase in physical sales. This was because average prices decreased in turn due to the decrease in fuel prices, but costs also decreased. Our own generation almost doubled compared to the same period of last year, mainly due to the commissioning of IEM in May 2019. This means IEM was not included in the first quarter results of previous year. The increasing generation led to an increase in fuel costs despite the drop in fuel prices. However, our spot energy purchases decreased significantly, offsetting the increase in fuel costs. This allowed us to report a 3% increase in EBITDA to $99 million in the first quarter. Net income was $25.6 million, 40% below the net result of the first quarter of 2019. This was basically because of higher interest expenses, first because interest expense is to be capitalized upon the completion of the IEM project in May '19; and second because interest expenses included $13.6 million spent in the premium paid to bondholders, which as I said before, we consider to be nonrecurring.

On Page 20, we present EECL's supply curve, which is very useful to understand our thoughts. As you can see, IEM, the most efficient unit in our portfolio after the renewals, increased its contribution. CTA and CTH continued to operate at base growth units, while they reported some limitations in production. Our 2 combined cycle units running natural gas, coal generation by Gas Atacama and using our gas represented almost 20% of our energy supply. While the rest of EECL coal units were less dispatched, as you can see in the table on top of this slide.

Finally, EECL booked almost 40% of its contracted demand between the spot market and the supply agreement with another generation company. This means that we buy from the spot market at lower cost than we can produce with our less efficient coal units, which still acts as a physical hedge to limit the production cost at a certain level.

On Page 21, the good news is the one we already talked about before, the renegotiation of the PPA with AMSA. It allowed us to maintain the average remaining life of our contracted portfolio at 12 years. We will continue our constructive conversations with the client who still have co-linked PPAs. Meanwhile, our intention is to offer them a solution that should create value for both.

On Page 22, more details on our PPA renegotiations, particularly the most recent one with AMSA showing that we have already renegotiated PPAs for a total of 0.7 gigawatts, which is equivalent to more than 75% of our unregulated portfolio.

Page 23 gives a snapshot of our PPA portfolio runoff through 2030. We can see the demand under our contracts, which is almost 12-gigawatt hour per year, although we assume that some effect from the COVID-19 in 2020. Also beginning in 2020, the green portion, representing our renegotiated and decarbonized PPAs as well as new PPAs, increases due mainly to the [uncertain state]. The gray bar, representing the contracts still need [to call], basically the Codelco contract with our PPA subsidiary. It will remain to be renegotiated. This is where our commercial efforts will be focused.

Now let's talk about our projects and their status, which is 1 of the 5 highlights of the quarter. On Page 24, we present a summary of the first stage of our asset rotation plan, which includes the acquisition of 2 solar PV plants; the construction of Calama wind farm and Capricornio PV plant; and finally, the Tamaya PV plant.

Regarding Tamaya, the notice to proceed has been delayed until the beginning of the third quarter due to the COVID-19. Although the construction schedule has been accommodated, so the commercial operation date is not delayed. The 3 projects, Calama, Capricornio and Tamaya will represent combined capital expenditures of approx $290 million between '19 and '21. Of which, $63 million has already been paid as of March 2020.

I would like to go to the next slide, Page 25. So you can see the progress of the Calama wind farm. This 150-megawatt wind farm considers 36 mills, each with a 4.2-megawatt capacity. At the end of March, construction showed 38% of advance, while the overall progress rate was 15%. The concrete foundations for 28 out of the 36 have been completed at that date. The main contractors are Siemens Gamesa for the turbines and GES for the civil works. COD, as suggested by the effects of the COVID-19, is scheduled for the third quarter of 2021.

On Page 26, you can see the progress of our almost 95-megawatt Capricornio solar PV plant, which as of the end of March, represented a global state of advance of 53%. More than 11,000 drill holes have been made with almost 6,000 steel piles installed. The tracker and the solar model assembly had begun and the connection process with the coordinator have begun -- have been started. The main contractors are GES, TrinaPro and Sungrow. The schedule COD after considering the effects also of COVID-19 on procurement activities is the second quarter of 2021.

I am now on Page 27. First, on transmission. We continue with the construction of 4 national or zonal projects awarded back in 2018 with a total investment of approximately $43 million. This includes El Rosal, Algarrobal and the Capricornio section and substations and Nueva Chuquicamata substation and transmission line. As you can see in the pictures, the construction of these projects is also making progress.

On Page 28, we give an overview of the national transmission projects corresponding to the auction conducted in October 2019. These projects, include [Antofagasta By Pass] and the La Negra substation and transmission line, representing an overall investment of approximate $28 million.

On Page 99 (sic) [Page 29], we show that in 2019, we completed the construction of IEM, which marked the end of a CapEx-intensive phase, even considering our asset rotation plan with a significant investing activity in renewals, CapEx levels are lower than those of 2016 and 2017, while our cash flow generation capacity has increased. For 2020, we are projecting total capital expenditures of $290 million, focus our renewal and transmission projects as well as maintenance. In the first quarter, we already paid $50 million of this amount. We plan to finance these capital expenditures with a mix of internal cash generation and bank financing, like the $125 million we are currently structuring with IDB. In this line, our net debt-to-EBITDA ratio should increase during 2020, following the additional debt we will raise to finance a portion of our CapEx mix. We intend to keep our leverage ratios under control. That is not exceeding 2.5x on a regular basis. We need to consider, however, that in 2020, we will have most of the negative impact related to the regulated tariff stabilization mechanism, which will need to be financed by EECL until these long-term receivables are collected in the future or until a monetization structure is put in place.

Let's talk some minutes about our guidance for 2020. Please turn to Page 30. We kept this slide unchanged, although we know that the COVID-19 may affect our results in ways that are difficult to predict. EECL delivered solid results in the last 2 years, reaching the high end to 2018 guidance and exceeding guidance for 2019. For 2020, we were expecting a slightly higher contracted demand compared to 2019, but a lower operational and recurring EBITDA during the year, mainly explained by the termination of the Zaldivar PPA in the second half of the year, and we were also considering a more conservative average spot price for this guidance. Also, when we compare the operational results of 2019 with our guidance for 2020, we need to consider that, in 2019, we received the IEM EPC contractor a $75 million compensation for delay on startup, which corresponded to an operational loss of profit. But almost $35 million were related to the portion of revenues IEM was not able to generate in 2018, while the difference corresponds to 2019. This means the adjusted EBITDA for 2019 without the positive recognition of 2018 loss of profit could be around $500 million. The lower EBITDA in our guidance for 2020 is related to the variables I mentioned before. Then in 2021, EECL should be able to share recovery in EBITDA once the 3 renewable projects are in operation since EECL will replace spot purchases at spot market prices by producing at almost 0 cost. However, COVID-19 will have the effect of delaying in some weeks the COD of these projects, so we need to also consider that impact for next year.

To the left side of this slide, we show the main variables that may impact our results depending on their behavior. Of course, we have added COVID-19 as a negative factor. Regulatory changes, such as green taxes or changes in ancillary services can always impact results. We also need to consider that the higher penetration of renewables in the system will meet some future changes in the market design. Our own transformation is aligned with this trend, and we will closely work with the system on the required changes, of course.

Considering the uncertainty surrounding the development of COVID-19 and its effects, we have added Slide 31 to this presentation. On the upper part of the slide, we show a comparison of our actual physical sales to regulated and unregulated clients in the first quarter of 2020 and 2019. Despite the effects of COVID on power demand in the second half of March, we note demand increases in both segments. Regulated sales remained even in March of this year compared with March of last year. As discussed at the beginning of this call, the demand from free clients had suffered the effects of a tough Altiplanic winter in the first quarter of 2019. So the increase in the first quarter of 2020 is a return to normality. The demand from regulated clients increased due to an increase in EECL's pro rata share of the universe of contracts between generation and distribution companies because of the expiration of older contracts from other players in the market.

On the bottom part of the slide, we present a couple what-if exercises. What if demand falls by 5% in April, 20% in the May, June period and then remain flat in the rest of the year? If these assumptions are applied to our entire PPA portfolio, then EBITDA could be impacted by 18% (sic) [$18 million]. If these assumptions are applied to our regulated portfolio only, then EBITDA could drop by roughly $10 million. We also show another scenario with a softer tough, longer demand decreases. Demand decreases will certainly affect the results, although the negative effects are partly offset by few cost savings and lower energy purchase costs. So what we intend to show in this slide are basically some sensitivities. All the assumptions behind are not specific assumptions on specific clients or the specific operation of our clients. The intention of this slide was to give everyone a sense -- a high-level sense of what could happen if demand decreases in some percentages over the year.

So now we will move to the next section, Bernardita will give us more details on our financial results.

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Bernardita Infante, Engie Energia Chile S.A. - Head of Corporate Finance [3]

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Okay. Thank you. Thank you very much, Eduardo. Hello, everyone. So we are now on Slide 33. Our EBITDA advanced 3% to $99 million in the first quarter, and this was mainly a result of lower energy purchases, combined with increased volume sales to both free clients and distribution companies. On the negative side, the main impact was the drop in average realized prices. This is primarily explained by the drop in the fuel prices used in our PPA tariff formula and, to a lesser extent, by the PPA renegotiation. Therefore, our average realized monomic price fell from $119 per megawatt hour in the first quarter of last year to $103 per megawatt hour in the first quarter of 2020. We also reported higher fuel costs due to the increase in our own generation. The decrease in fuel prices was not enough to offset the increase in the quantities of fuel purchase.

Now please turn to Slide 34. At the center of the slide, we can see each of the after-tax variations in net recurring income, which decreased from $43 million in the first quarter of last year to $36 million in the first quarter of this year. The drop is primarily explained by interest expense because no interest was capitalized in the first quarter of 2020. While in 2019, we capitalized $37 million. Another effect is that minority interest disappeared as according to IFRS rules. EECL took full control of CTH upon the execution of the agreement with AMSA at the end of March.

If we look outside the box to analyze nonrecurring impacts, we see that net income was impacted in the first quarter of 2020 by $13.6 million in premiums paid on the early redemption of the $400 million, 144-A bond. And this had an after-tax impact of almost $10 million on the first quarter net income.

In Slide 35, we can observe an increase in net debt as a result of the following cash flows or movements in the debt account in the first quarter. In terms of uses of cash, capital expenditures amounted to $50 million, mainly in the renewable and the transmission projects. In the next bar, we show the payment of premium to bondholders. The next 2 bars are noncash, they correspond to factors that had a direct effect on debt balances. The first bar includes accrued interest and mark-to-market variations, 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 $18 million in income and stamp taxes. Now our cash sources included in the gray bars with negative numbers -- sorry, orange bars, as they led to a reduction in net debt included a $7.5 million cash payment from TEN and $29 million in operating cash flow.

Now let's move to Slide 36 that provides detail of our liquidity and debt structure. And the main changes are the following: As EBITDA increased slightly in the 12-month period ending March 2020, while net debt increased mainly due to a reduction in cash balances, the net debt-to-EBITDA rate to increase slightly but was still very comfortable 1.4x. Our gross debt increased by $20 million, basically due to the new $500 million bond issue, which was used to repay the $400 million bond and $80 million of short-term debt. International rating agencies have confirmed our BBB flat international rating and local agencies confirmed our AA- rating.

On Slide 37 -- sorry, yes. We can see that in 2019, our dividends increased with marked increase in dividend yield. However, our market cap and share price evolution have been significantly affected by the COVID-19 driven recession. We note, however, that our stock performed better than the market in the last 12 months in relative terms. While the EECL stock price fell 28%, the IPSA index fell 34%.

Well, this is all on my side, and I'll leave you with Eduardo for the final remarks.

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Eduardo Martin Milligan Wenzel, Engie Energia Chile S.A. - Chief Financial & Shared Services Officer [4]

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Thanks, Bernardita. Before we move to Q&A, we would like to end with some final messages. So first, on the current crisis, we need to continue preparing our organization to manage any potential future risks. Our main objective, as I mentioned before, during this phase, will be to implement several measures to protect and keep our employees and contractors safe, while at the same time, continue running our operations at high standards.

Second, today, we presented some sensitivities on demand and potential impacts on EBITDA for 2020. In this context, we need to implement a conservative cash planning, and that's why we decided not to distribute an additional dividend for 2019. This situation may change in the upcoming months if the current situation evolves positively.

And third, as you know, we entered into an important transformation and implementation phase, and we continue to develop our renewable portfolio. Our strategy remains the same. We may see some weeks of delay in CODs, but nothing material at this stage. We continue developing an important portfolio of renewables to bring them to a ready-to-build stage, and we will also evaluate to continue participating in future transmission options.

So well, with these final messages, we're finalizing our first quarter 2020 presentation. We hope, as always, this presentation is helpful for you and wish you the best in these difficult times.

So thank you for your participation, and we are ready, with Bernardita and Marcela, for any questions you may have.

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Questions and Answers

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Operator [1]

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(Operator Instructions) Our first question will come from Murilo Riccini with Banco Santander.

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Murilo Riccini, Santander Investment Securities Inc., Research Division - Research Analyst [2]

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I have a couple of questions for you, guys. The first one, could you provide us an update on the CapEx deployment expected for 2020. Is there possibility of -- defer part of this to 2021 due to some delays in any project construction or even in order to preserve liquidity?

And the other one is that just to be sure, I don't know if I heard correctly, but do you have a credit facility with the IBD for $350 million or $125 million? I don't know -- I think I heard $350 million, but just to confirm this information.

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Eduardo Martin Milligan Wenzel, Engie Energia Chile S.A. - Chief Financial & Shared Services Officer [3]

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You're very welcome. Yes, of course. Well, in terms of CapEx deployment, the answer is no. We continue to invest what we have in our plan. The CapEx plan for 2020 involves the construction of the 3 renewable projects that we have currently under construction. As I explained before, we delayed a couple of months the notice to proceed for Tamaya. But the impact in the CapEx plan would not be material compared to the overall CapEx plan for the year.

And in relation to the second question, yes, I think we didn't clarify that during the presentation. But we are working in 2 facilities. So the first one is the $125 million bilateral loan, which has a subjective to promote the reduction of CO2 emissions by providing some special funding for building renewables and closing coal plants. This is the facility that we announced last December during COP 25 in Madrid. That's the first one. That's a bilateral facility. The second one is related to the stabilization fund. The IDB is currently working with the whole industry, not only with us and with 2 additional commercial banks, to structure a facility that has a subjective to acquire the credit rights coming from these long-term receivables. So when we said $350 million, it's because between the $125 million and the total funds we expect to have in our balance sheet that could be sold in this some kind of factoring facility, we can reach around $350 million. That's because we expect to have between $150 million and $200 million of long-term receivables related to the tariff stabilization fund.

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Murilo Riccini, Santander Investment Securities Inc., Research Division - Research Analyst [4]

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Perfect. And just a follow-up question about the CapEx deployment. You already had expensed $50 million during the first quarter. And how do you expect to spend for the rest of the year?

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Eduardo Martin Milligan Wenzel, Engie Energia Chile S.A. - Chief Financial & Shared Services Officer [5]

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For the rest of the year, I think, proportionally, until we get to around $300 million. I think it's also included on Page 29.

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Operator [6]

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Our next question will come from Andrew McCarthy with Banchile Inversiones.

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Andrew J. McCarthy, Banchile Inversiones S.A., Research Division - Deputy Manager of Studies [7]

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First question, just wanted to make sure I understood the amounts on the loans. So it's $150 million to $200 million potentially for the stabilization -- tariff stabilization mechanism. And then $125 million for the bilateral loan. Did -- so that gets us to approximately $350 million. Did I get that right?

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Eduardo Martin Milligan Wenzel, Engie Energia Chile S.A. - Chief Financial & Shared Services Officer [8]

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Yes. That's right. The $125 million, $200 million, the $125 million could be a bit higher, so it's not fixed yet. So between both, we estimate around $350 million.

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Andrew J. McCarthy, Banchile Inversiones S.A., Research Division - Deputy Manager of Studies [9]

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Perfect. Just a sort of more conceptual question. I just wanted to understand why with the stabilization mechanism sort of factoring fund you're looking to do. Why are you doing that as an industry? Why you don't do that sort of individually, given that maybe individually, you could get different terms, et cetera? Just to understand from that perspective.

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Eduardo Martin Milligan Wenzel, Engie Energia Chile S.A. - Chief Financial & Shared Services Officer [10]

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Well, I think there are 2 parts there. The first is because the structure that needs to be implemented is complex. It also requires involvement from the authorities, from the ministry, from the CNE. And that's why IDB has also been involved in this structure. So to make this structure bankable, there were some changes that were needed in the law. And that's why we're moving in that direction with IDB. And not working, let's say, on a pure commercial structure.

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Andrew J. McCarthy, Banchile Inversiones S.A., Research Division - Deputy Manager of Studies [11]

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Got it. Perfect. And then finally, just wanted to go back to the very helpful sensitivity analysis you included on the potential impact of demand -- or demand impact from COVID-19. Just firstly, on the -- is there, you show for May, June, in the moderate case, minus 20%. And in the downside case, only minus 10%. Just wanted to understand that. What drives those difference -- the difference there?

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Eduardo Martin Milligan Wenzel, Engie Energia Chile S.A. - Chief Financial & Shared Services Officer [12]

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Yes. The difference was, let's say, to have a V or a U turn, right? The moderate case could be, okay, let's have something fast, and we go back to normality very fast in July. The downside case is, okay, this will have a more severe impact, more permanent. And this will reduce our demand over more than 6 months or over the next 6 months in the year. It's just a V compared to a U.

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Andrew J. McCarthy, Banchile Inversiones S.A., Research Division - Deputy Manager of Studies [13]

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Got it. Yes, that makes sense.

And then finally, on the other assumptions there, do you make any assumption for lower marginal costs or spot prices because of the lower demand? Or is that -- the change is just purely on -- in your modeling there just on lower volumes of energy purchases?

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Eduardo Martin Milligan Wenzel, Engie Energia Chile S.A. - Chief Financial & Shared Services Officer [14]

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Right. It's a good point. Everything is included in the blender. I think when we are reducing demand, we are also considering lower spot prices. We are also considering lower fuel curves affecting our PPAs and affecting also our production costs. So everything is included in the blender, not only, let's say, an isolated sensitivity on demand.

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Andrew J. McCarthy, Banchile Inversiones S.A., Research Division - Deputy Manager of Studies [15]

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Okay. Got it. And can you give any kind of idea there on sort of percentage lower spot prices or fuel cost curve that you're considering?

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Eduardo Martin Milligan Wenzel, Engie Energia Chile S.A. - Chief Financial & Shared Services Officer [16]

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Maybe. To give you some idea, probably around $3 to $5 lower than probably our previous view or the view that we used for the guidance or the previous guidance that we gave.

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Andrew J. McCarthy, Banchile Inversiones S.A., Research Division - Deputy Manager of Studies [17]

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Okay. And that goes for both the moderate and the downside case?

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Eduardo Martin Milligan Wenzel, Engie Energia Chile S.A. - Chief Financial & Shared Services Officer [18]

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Sorry, I didn't get the last one.

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Andrew J. McCarthy, Banchile Inversiones S.A., Research Division - Deputy Manager of Studies [19]

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Sorry, Eduardo. I just wanted to clarify. And that goes for both the moderate and the downside cases?

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Eduardo Martin Milligan Wenzel, Engie Energia Chile S.A. - Chief Financial & Shared Services Officer [20]

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Yes, yes, yes.

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Operator [21]

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(Operator Instructions) Your next question comes from [Juan Carlos Peterson with Inversiones Groflin].

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Unidentified Analyst, [22]

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So a question for Eduardo. Related to Page 31, congratulations. It's a very helpful and very well prepared information. I think I heard -- I hear Eduardo saying 18%. Maybe I was wrong. But I just would like to confirm that we are talking impact on U.S. dollars, millions of U.S. dollars. That means $18 million or $25 million, not 25%, right?

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Eduardo Martin Milligan Wenzel, Engie Energia Chile S.A. - Chief Financial & Shared Services Officer [23]

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Right. You're correct. If I said 18%, my fault, but it's in million, $18 million, $25 million, $10 million and $18 million.

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Unidentified Analyst, [24]

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Very clear. Thank you.

Second question, I have 4 questions, by the way. Second question. Regarding -- or considering this scenario, what would be the net recurring income for full year 2020 expected, considering the downside or moderate?

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Eduardo Martin Milligan Wenzel, Engie Energia Chile S.A. - Chief Financial & Shared Services Officer [25]

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I don't have that number right now. But I think all the other variables should remain stable in terms of interest expenses, taxes. So we could assume that this pretax effect should also be translated into the previous page on Page 30. We can see the guidance for 2020. The net income was -- the net result around $160 million to $180 million. So we should consider this direct impact of, let's say, the $18 million pretax on the net income that we previously gave as a guidance for 2020.

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Unidentified Analyst, [26]

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Third question. And just to reinforce the point that Andrew just asked. You did say, Eduardo, that the marginal cost -- the lower marginal cost for spot prices, energy purchase, could be reduced by $3 or $5. Just would like to confirm it though if that's upside that could help?

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Eduardo Martin Milligan Wenzel, Engie Energia Chile S.A. - Chief Financial & Shared Services Officer [27]

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Yes. That's an upside. That's correct.

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Unidentified Analyst, [28]

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The number that's now highlighted on 31 -- on Page 31? Or is that included already?

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Eduardo Martin Milligan Wenzel, Engie Energia Chile S.A. - Chief Financial & Shared Services Officer [29]

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No, that's included already. That's -- when Andrew made -- asked if -- what we included in this analysis, everything is included in the blender. So the lower spot price is compensating at some point, the reduction in the demand.

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Unidentified Analyst, [30]

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Perfect. And last question, regarding the fund, the receivable fund, do you have any FX risk? Or -- and how are you hedging, covering that?

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Eduardo Martin Milligan Wenzel, Engie Energia Chile S.A. - Chief Financial & Shared Services Officer [31]

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There is no FX risk because the tariff is still indexed in dollars. What we have with this stabilization fund is just a long-term receivable. But there will not be impacts related to changes in the FX. That's in case we keep these receivables, and we don't implement any type of monetization fund or factoring. Once you implement this type of factoring or monetization fund or you sell these credit rights, you forget about these receivables in the future.

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Operator [32]

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

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Eduardo Martin Milligan Wenzel, Engie Energia Chile S.A. - Chief Financial & Shared Services Officer [33]

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Well, thank you very much for your participation. I hope next quarter, we will be back with you with probably better news and hope that all of you stay safe during the next months.

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Bernardita Infante, Engie Energia Chile S.A. - Head of Corporate Finance [34]

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On my side, well, thank you very much for participating, and hope you're all well. And for those of you who are in Chile, have a nice long weekend.

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Eduardo Martin Milligan Wenzel, Engie Energia Chile S.A. - Chief Financial & Shared Services Officer [35]

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Thank you. Bye-bye.

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Bernardita Infante, Engie Energia Chile S.A. - Head of Corporate Finance [36]

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Bye-bye.

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Operator [37]

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

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