Good afternoon, everyone, and welcome to Engie Energia Chile's second quarter 2023 results conference call. If you need a copy of the press release issued on July 26th, it is available on the company's website at www.engie-energia.cl. Before we begin, I would like to remind you that this call is being recorded and that information discussed today may include forward-looking statements regarding the company's financial and operating performance. All projections are subject to risks and uncertainties, and actual results may differ materially. Please refer to the detailed note in the company's press release regarding forward-looking statements. We would like to advise participants that this call is dedicated to investors and market analysts, not for the press. We ask all journalists to contact Engie Energia Chile's P.R. department for details. I will now turn the call over to Mr. Eduardo Milligan. Please go ahead, sir. Thank you, Gary. Good afternoon. Today I'm here with Bernardita Infante, Alison Saffie, and Marcela Munoz, who will present ECL results for the first half of 2023. We will discuss our guidance for the rest of the year. We can start on page 4. On the left side of this page, we are highlighting some key elements to understand ECL's performance in the first half of the year, while on the right side, we will present the main drivers for the second half of 2023. Let's start on the left side. First, fuel prices fell in 2023 compared to the record prices of last year, while hydrology remained weak most of the first half of the year. On the revenue side, the higher fuel prices of 2022 negatively impacted ECL's average supply cost during last year. We need to consider that there is a lag in the indexation formula of our regulated PPAs. This means the higher costs were not automatically translated into higher PPA prices. As a consequence, in the first half of 2023, there is a mechanic positive impact in our energy margin since costs are slightly lower and PPA tariffs are higher. In simple words, this indexation lag created a lower margin in 2022, which was somehow partially recovered in 2023. As you know, this year, our LNG supplier didn't deliver a contractual volume of around 13 TBtu, and we were forced to replace these volumes with spot LNG at higher costs. We imported spot LNG, which has been key to partially mitigate the impact. It has been a difficult task, but our portfolio team, in coordination with the ENGIE Global Energy Management Division, managed very well this operations. Other key element in this first half of the year is the unavailability of thermal power plants. In our case, IEM Power Plant was out of service for approx 45 days. The plant came back into service early May, and now is fully available for the system. In this context, also, transmission bottlenecks continue to be an element to have in our radar for both potential increases in spot prices like in the south, and also in relation to curtailment for renewables in the north. Finally, as you know, liquidity was impacted by the delay in the monetization of receivables arising from the new Price Stabilization Law, known as PEC. As of June, ECL accumulated around $440 million in uncollected bills related to this mechanism. Now, the good news is that we are now very close to start the monetization program. The accumulation of these receivables in the investment context of ECL explain why ECL working capital and short-term debt needs increased in the last 12 months, but we took several measures in the first half of the year to improve our financing structure, including a credit line granted by our parent, ENGIE. Bernardita will explain in some minutes all these new developments. Now, on the right side of this page, we are highlighting other key elements to understand the future trajectory. In 2023, we have additional renewable generation and additional hedges or backup PPAs for additional 1.2 TWh during the whole year. As I explained before, there is a positive impact coming from lower fuel prices, and we were also able to source additional LNG for the system, which was key to partially keep spot prices under control and will be complementary during the rest of 2023 with the improved hydrology. In relation to hydrology then, as you have seen, we had recently some important rainfall events, and now we have better hydrology prospects for the rest of the year, which will be translated into lower spot prices during the rest of 2023. However, we need to be cautious since the snow accumulation is still in progress. This means the system will have a good performance in the short term. Between all these elements, ECL's short position would reduce from the 4 TWh we had in 2022 to less than 2.5 TWh in 2023, which should reduce volatility and risk in case spot prices increase again. Finally, we recently closed a 10-year, $400 million sustainable loan with IFC to refinance existing debts previously raised to fund our investment plan and to fund new investments in, in renewals. This is an interesting financing because it's green and linked also to sustainable KPIs, including gender parity. These KPIs will act as an enhancer in some economic conditions once ECL complies with their targets in the near future. The final good news: we are ready to execute the first monetization of PEC receivables. Target date for first monetization is end of August. We expect to collect around $200 million in the first process. Proceeds will be used to repay debt and improve our leverage ratios. We will still have approx $250 million more to be monetized on the next process, which should be triggered once the regulated tariff, applicable since January 2023, is confirmed by the regulatory bodies. Let's move to next, page 5, shows the evolution on ECL's physical sales. Total sales grew in 1%, mainly explained by higher sales to regulated customers, which increased in 7%. This is positive for ECL and a potential upside in the future, considering the regulated PPA we have in the center to south regions, has an average consumption of less than 75%, vis-a-vis the fixed 4.5 TWh contracted volume. This means the positive trend in our regulated PPA's load factor is confirmed. That is, mainly explained by a larger participation of ECL in the pool of regulated contracts and the return of free clients to the regulated scheme, too. On page 6, we can see the spot price evolution over the last 7 years, and how the Chilean system moved from an average of $52 MWh in 2017-2020 period, to $127 MWh in 2022, and $129 MWh in the first half of 2023. The trend is not smooth. The system will continue to be under pressure in this transition period. Since June and until early August, we have seen much lower spot prices, given the improved hydro conditions in the system. Looking forward, will depend on additional rainfall and snow accumulation. This means hydroelectric production could be very positive in the short term, but we need to be prepared for 2024. Next, page seven, shows the detailed evolution on hydrology, which had a material improvement in June compared to previous years. As of the end of July, the accumulated probability of exceedance is 73% compared to previous two years, in which we were in the mid-90s, approx. As I mentioned before, we have additional energy accumulated in the reservoirs, which is approx twice the volume we had one year ago, and we need to see how these levels and the snow accumulation evolve in the next weeks. On page eight, we can see the unprecedented evolution in coal prices. As you know, coal hit all-times highs in 2022. The average price per ton in 2022 reached $314, which can be translated into a production cost of around $130 MWh. As we explained in our. In the last quarter, this trend reverted in 2023. The average coal price in the first half of 2023 decreased to $154 per ton, which is less than half the price of previous year. In the second quarter of this year, the average coal price decreased further to around $125 per ton. At $125 per ton, the production cost with coal power plants should decrease to around $60-$70 MWh. The coal futures have remained stable in current levels, and this will be positive for the overall cost of the system. In summary, what we have seen recently is that coal is again cheaper than LNG. Page 9 shows the evolution on coal power plants availability for the overall system. The message in this page is clear. Coal plant availability for the system has declined in the recent years. In the first quarter of 2023, in our specific case, IEM coal power plant had a failure in its transformer and was out of service between February and April. To mitigate this situation, its planned maintenance was rescheduled from August to March, and now the plant is again in service since early May. Let's go to next page 10, and discuss about the natural gas. The graph on top shows the evolution of international LNG prices. We can see the all-time highs, same as with coal in 2022, explained by the Russia-Ukraine conflict and its impact in the supply-demand balance worldwide. LNG reached $40 million BTU, which made it impossible to buy LNG in the spot market, because, as you know, at $40 million BTU, the production cost with a combined cycle using natural gas would be close to $300 per MWh The positive evolution on JKM index allowed us to import spot LNG in 2023, and mitigate the lack of LNG that was not delivered by our supplier. The graph below shows the LNG sourced through firm long-term contracts and the natural gas coming from Argentina. We have seen in the recent years, stable volumes imported from Argentina during the summer, and increasing during the winter, as we can see in the graph, in which the green area represents the volumes imported from Argentina and their increased importance for the system. On the LNG side, as we explained in our last calls, we have two long-term contracts for an aggregate volume of 23 TBtu per year. One of these contract was confirmed by our supplier for about 10 TBtu, while the second contract with a volume of about 13 TBtu was not confirmed, and therefore, we were not able to ask to add this LNG volume to the annual delivery program in the regasification terminal. To partially mitigate this situation, we have secured around 14 TBtu replacement LNG in the ordinary course of business, but as it's obvious, at higher costs. Page 11 shows an update on the hedges or backup PPAs signed with other gencos. This page shows an additional volume of backup PPAs signed for 2023 and 2024. In summary, we have an average of, 3.3TWh, 3.4 TWh of hedges contracted with other gencos, between 2023 and 2027, the period in which we will be adding additional renewables to our portfolio of assets. Page 12 shows a graph with the energy sources and average supply costs for the portfolio. Our main objective is to rebalance our portfolio as fast as possible to reduce risks and exposure to spot market volatility. As we can see in the graph, the average supply cost materially increased between 2021 and 2023. In the first half of 2023, we can see how sources are moving in the right direction, more renewables, more gas, more hedges or, or contracted volumes with other gencos, and as a consequence, less purchases in the spot market, represented by the light blue area in this graph. On next, page 13, we present the usual supply-demand curve for the overall portfolio. The average monomic price in the first half of 2023 reached $182 MWh, which was stable during both quarters, compared to $134 in the first half of 2022, or $146 for the full 2022. This means an increase of $48. Sorry, of $48 compared to the same period of previous year, or an increase in $36 compared to the average monomic price of the whole 2022. This increase, as I explained before, is mainly explained by the indexation on PPAs to coal, LNG, and U.S. inflation. On the other hand, the average supply cost reached $137, again, stable in the first 2 quarters of 2023, compared to $118 in 2022. The broader relative spread between sales and costs is explained by the indexation lag in our regulated PPAs, together with relative lower supply costs, given the actions explained before on LNG, backup PPAs, higher generation from renewables, and spot purchases at lower costs. In the first half of this year, we can also see how the generation coming from renewables and LNG with our own CCGTs and a tolling agreement with Kelar, plus the additional backup PPAs, are replacing spot purchases, which reached 1.4 TWh, compared to 2.1 TWh during the same period of previous year. Now, we will continue with Bernardita, with the detailed financial results and related action plans to improve ENGIE Energia Chile's liquidity and capital structure. Okay, thank you, Eduardo, and good afternoon to everyone. Hold on just a second, please. Okay. If we can go to slide 14 for a closer look at first half results. EBITDA more than tripled compared to last year. Actually, first half, EBITDA reached $189 million, equaling the figure reported for the whole year in 2022. Revenues increased mainly due to the 36% increase in energy prices, which captured the extremely high fuel prices and inflation observed in the second half of 2022, due to the lag with which price indexation in our PPAs reflect fuel price increases. Physical sales decreased by 1%, with an increase in sales to regulated customers and a decrease in sales to free clients. Gas sales also increased significantly, as in the first half of 2023, the company bought enough LNG volumes to generate electricity at its own plants, and through a tolling agreement with Kelar, as well as to sell gas to other companies. Generation costs remain high, as the fuel used in generation came from high price stocks built up in 2022, and marginal costs remained affected by poor hydro generation through most of the period. However, sales prices increased further, explaining the margin widening. To meet our sales commitments, we bought 23% of total volumes from the spot market, down from 33% in the first half of the year, in line with our strategy of reducing our exposure to spot prices. Energy sourced through backup PPAs represented 25% of total volume sold, up from 16% in the first half of 2022. Renewables accounted for 13%, up from 7%. Notably, gas production, including energy generated at our own plants and through a tolling agreement with Kelar, increased to represent 28%, compared to 14% last year. This was possible thanks to spot LNG purchases, which allowed us to secure LNG supply volumes, despite the unfulfillment of one of the two long-term gas supply agreements by our main LNG supplier. In short, greater renewables and gas production and backup PPA volumes are allowing us to close the gap between our sales commitments and our own generation, so as to reduce our exposure to the spot market. Net results reached $27 million, a turnaround from the $40 million net loss reported in the first half of last year. We note that one-off items were bigger this year, as the company reported $12.6 million in financial expenses related to the sale of accounts receivable from distribution companies affected by the Price Stabilization Law, the so-called PEC 1. In May 2023, we sold a nominal amount of $51 million of accounts receivable, which represented the last sale under the PEC 1 mechanism. Overall, since the PEC 1 monetization started in January 2021, the company sold accounts receivable totaling $273 million. It received $196 million in cash proceeds and accounted for financial expenses of $77 million. Our net debt, excluding IFRS 16 leases, increased significantly throughout 2022, as we had to finance CapEx as well as heavier working capital needs due to the steep increase in fuel prices, while the Price Stabilization Law compressed our liquidity. Net debt reached $1.65 billion at year-end 2022. Through the first half of 2023, we have been focusing on reducing our leverage ratio while extending the average maturity profile of our debt. In spite of the continued CapEx required for our transformation program, our net debt at the end of June was only slightly higher than the level reported at the end of 2022. Slide 15 shows the reasons behind the EBITDA recovery. Clearly, average realized prices captured the increase in fuel prices and inflation observed in previous months. Spot sales also increased as the sales through the tolling agreement with Kelar are reflected in this account. The increase in physical sales was explained by higher demand from regulated clients. Spot purchases decreased in volume, although they were made at higher prices than in the first half of last year. Fuel costs continued reflecting the use of inventory acquired at higher prices, prices increased more than costs. EBITDA reached $189 million, a 212% increase compared to the first half of last year. Slide 16 shows the evolution of our net results. The turnaround is mainly explained by the EBITDA recovery. Insurance recoveries also contributed to mitigate a $21 million increase in interest expense. In such way, net income before one-offs increased from a $38 million loss to a $46 million profit in the first half of 2023. In terms of one-offs, while in the first half of last year, we reported $3 million in interest expenses related to the sale of PEC receivables. In 2023, we reported a $9 million after-tax effect on the last sale of PEC 1 receivables and a $10 million impairment. These are mainly related to impairments of assets, such as, for example, the return of the onerous concession on the Pampa Yolanda site. As a result, net income was $27 million in the first half of the year. Now, let's go to page 17 to discuss the evolution of net debt. This shows that despite capital expenditures of $178 million in the first half of the year, and accumulation of PEC accounts receivable of $176 million, our net debt increased by just $75 million - $1.7 billion, given the recovery of our operating cash flow. The debt figures exclude $174 million of financial leases related to very long-term land lease contracts. Cash from operations before the effect of PEC receivables build-up, reached $320 million in the first half of the year. We also reported $38 million in cash proceeds from the last sale of PEC 1 receivables. In slide 18, we see the status of our debt as of the end of June. Gross debt, excluding financial leases, reached $1.85 billion. Net debt to EBITDA reached 5 times, a significant improvement compared to the record high 8.7 times at year-end 2022. We have been making progress in reaching our 3 main objectives related to our debt profile. First, to reduce net debt to EBITDA through EBITDA recovery, and by maintaining relatively flat net debt, despite the financing of our capital expenditures in renewable and transmission projects. Second, to secure funding for the construction of the Lomas de Taltal wind farm and the BESS Coya storage projects, whose objectives are to reduce our costs, our exposure to the spot market, and curtailment and intermittence risks associated to PV plants. Third, to extend the maturity profile of our debt. On the bottom left corner of the slide, we show the maturity schedule of our debt as of the end of June. We have news to share with you, part of which Eduardo has already anticipated, I'll ask you to please jump to page 23 for a moment. The monetization of receivables related to the Price Stabilization Law, PEC II, a program structured by the IDB with the participation of Goldman Sachs, JP Morgan, and, has been progressing. Today, the roadshow for the related 144A and 42 issuances was launched, we expect to receive approximately $200 million in cash funds by the end of August, corresponding to the first sale of certificates of payments issued by the Chilean Treasury. After this first sale, we expect to perform bimonthly sales of certificates of payment, starting October 2023, including a larger sale, which is contingent upon the publication of the average node price decree for the six-month period starting January 2023. On June 20, we signed a $400 million, 10-year loan with the IFC and the German bank DEG. On July 28, we made the first disbursement under these facilities for a total amount of $200 million, and we closed an interest rate swap to reduce our exposure to interest rate risk. These two transactions are helping us to reprofile our short-term debt and to finance the CapEx needs for the 2023, 2024 period. Indeed, in the first week of August, we repaid short-term debt by $125 million, including a $75 million loan from the related company, ENGIE Austral. Our credit ratings have been confirmed at BBB by both Fitch and Standard & Poor's. As discussed in the past call, last March, Standard & Poor's placed a rating in CreditWatch Negative due to liquidity pressures. S&P has not lifted the CreditWatch Negative at this date. However, both liquidity and leverage have been strengthened, and we expect this trend to be confirmed in the following months. In terms of liquidity, we still have an undrawn amount of $200 million under the IFC and DEG loans, and we have registered local bond lines, which we might use to refinance debt. Now I'll leave you with Eduardo, who will brief us on the recent events and action plans for 2023. Thank you, Bernardita. The actions mentioned on page 19 are driving our improved operational performance. First, we secured the 24 TBtu of LNG for 2023 together with a tolling agreement with the Kelar CCGT. We rescaled IEM maintenance and implemented a fast track to recover the plant, and now it's operational since early May. We also secured additional backup PPAs for this year, increasing the total hedges to 3.3 TWh-3.4 TWh between 2023 and 2027. Fourth, as you know, in 2023, we have additional 0.9 TWh coming from our renewables. Finally, we are already implementing two additional projects, 342 MW wind farm in the north, and 638 MWh storage solution to be added to our existing solar plant, Coya, also in the north. As a result, as we highlight below, the spot exposure is expected to be close to 2.5 TWh in 2023, which is slightly higher than the 2 TWh we mentioned in our previous call. This increase is explained by additional spot purchases in the market because of the lower spot prices. This is somehow positive. On page 20, we are presenting the evolution on our investment plan and the committed CapEx for 2023 and 2024. Once we complete the 2 projects currently under construction, we will have reached 1.3 GW of renewables, and we expect to reach a ready-to-build status for other projects very soon to complete our 2 GW plan. Page 21 presents the detailed CapEx by type of business. On top of the $600 million, we are investing in renewables, we are also investing $190 million in transmission projects, which contribute with the stable and regulated cash flow. The $600 million renewables include the 2 projects we have currently under construction, which are Lomas de Taltal and the storage solution we are adding to Coya Solar Plant. Now, in page 22, we show the guidance we gave for this year. It's good to, to see that most of the impacts on the left side of this page are green, which means we are on track to reach the guidance. If current conditions remain stable for the rest of 2023, and we do not experience extraordinary events like in 2022, the high end of the initial guidance should become the new lower limit for 2023. The graph also shows the expected EBITDA, CapEx, and net debt EBITDA evolution, considering the updated fuel prices and the actions we explained before. Liquidity and leverage should also improve with implementation of the financing with IFC and the monetization of PEC receivables, together with other actions our corporate finance team implemented during 2023. Finally, to end our presentation, we are summarizing the main key takeaways of this first half on page 24. First, we continue to be on track to rebalance our, our portfolio as fast as possible, adding additional renewables, signing hedges through backup PPAs, and optimizing our flexible generation by sourcing additional LNG in the international market. These actions have allowed ECL to improve its energy margins during 2023, and we are well on track to reach the guidance for 2023. In fact, as I mentioned before, we could expect even better results under the current scenario. In this line, we are also on track on the construction of 2 additional projects, and we expect to announce soon the construction of additional storage and wind projects, which will complement the 1.3 GW we have already implemented or, or have under construction, to reach at least 2 GW of renewables. Finally, in 2023, we implemented several measures to improve ECL's liquidity and leverage. In this line, as Bernardita recently explained, on June 20, we signed a $400 million 10-year loan with IFC and the German bank DEG, and we made, during July, the first disbursement of $200 million. And finally, on the monetization of PEC receivables, we made a lot of progress, and we expect to receive approximately $200 million by the end of August, which will correspond to the first sale of certificates of payment issued by the Chilean Treasury. Well, with this summary, we end our presentation, and we are ready for your comments and questions. Thank you very much for your participation today. Thank you. Thank you. The floor is now open for questions. If you have a question, please press star one on your touch tone phone at this or any time. If at any point your question is answered, you may remove yourself from the queue by pressing star two. Questions will be taken in the order they are received. We do ask that when you pose your question, that you pick up your handset to provide optimum sound quality. Please hold while we poll for questions. Our first question comes from Florencia Maiorca with MetLife. Please go ahead. Hey, Eduardo, everyone. Thanks for taking my question, congratulations on the results. I have a couple of questions. Regarding the monetization of PEC, regarding the second tranche, do you have any update as when you are expecting to collect them, or just for now, only the $200 million by the end of August? My second question is regarding the CapEx plan. After this $200 million in PEC, the $200 million in the wind farm, and the better performance, are you expecting to accelerate the renewable transformation? Additionally, are you facing any issues regarding cross-transportation, or are you seeing that it's taking more time than the value of the project, something that we heard from some peers? Thank you. Hello, Florencia. Thank you for your question. First, on, on monetization, we expect to monetize. As, as I mentioned, at the beginning of the presentation, we have around $440 million as of June, of accrued receivables in our balance sheet. We expect to monetize a first tranche, which in our case, will be equivalent to around $200 million. We should collect by the end of August. There will be a bi-monthly monetization for smaller amounts during the rest of the year. Finally, once the tariff decree number seven, which corresponds to the regulated tariff starting January 2023, is approved by, finally, the national controller, then we will be able to monetize another tranche, another material tranche, of probably around $200 million-$250 million. When we expect? We are all working together with the authorities, the banks, the gencos, to have this ready by year-end. This is the target. If not by year-end, it should be possible during the first quarter of next year. This is our intention and the will of all parties involved in this transaction. On the CapEx plan, your second question: Yes, today we are investing in 2 projects. We are investing in Lomas de Taltal and Pesqueira. We are planning to continue investing in additional renewables to reach the 2 GW that we have in our plan. Because the 2 projects that we have today under construction, we will reach 1.3 GW. We need to add around 700 MW of additional capacity to our portfolio, which should come through storage and wind projects. We should launch in the next 6 months-12 months and to build them between 2024 and 2026. Perfect. Thank you. I have an additional question regarding the rebalancing portfolio, that you mentioned that additionally, to reduce your current exposure to the spot market in the near term, and you are looking for to become culturally long by 20%, and part of your strategy was to reduce the regulated contract. How was the progress on that front? Well, on the, on the, let's say, strategy or at portfolio level, indeed, our, our plan is to be balanced in the, in the medium term. This is why we are investing in, in renewables during, during the next years. When we should be completely balanced, should be in the next 3 years, when, when we will have completed the 2 GW of additional capacity. We don't have any, let's say, actions on the, on the demand side. With the plan that we have for renewables, we should reach balance in, in some, in, in the, in the next years. Perfect. Thank you so much. You're welcome. The next question is from Peter Boley, with Bank of America. Please go ahead. Hi, Edward team. Thank you for the call and the opportunity for a question. On the status of the redress or arbitration regarding the LNG supply contract, can you confirm the amount that's being demanded, and if there's been any developments in terms of timing of a potential future award? Thank you. Hi, Peter. Based on the confidentiality obligations under the SPA, we cannot disclose any specific details regarding the legal proceeding that is ongoing between ENGIE and our supplier. Once we are able to disclose any information, we will do it. Thank you. Again. You're welcome. Again, if you have a question, please press star then one. The next question is from Martín Arancet with Balanz Capital. Please go ahead. Hi. Well, first of all, thank you for taking my questions and for the materials. I have two questions. I would like to run them one by one, if that's okay. The first one, regarding gas. This year, you were able to replace the gas cargos that TotalEnergies did not deliver. Do you think it is possible that the situation repeats again next year, and what kind of measures do you have in mind, if that's the case? Hello, Martin. Indeed, it is possible. We still don't have full confirmation of one situation or the other, but we are well prepared to continue sourcing LNG in the international market, if we need to, and if the volumes related to the same contract are not delivered in 2024, including the tolling agreement that we have with with Kelar. Okay. My final question then, the government has sent, a lot to Congress regarding the energy transition that looks quite ample and lacking some specifics, in our view. I was wondering, what, what, items in the new bill are you eyeing with more attention? As, as you say, today, the future market design is under analysis. I would say that my... Something that, it's worth to have in mind, will be, what will be the role of the natural gas in the future? It's, that's key. As you probably have seen, there is also, a potential or is coming, a potential option for storage in the future, which is also something that makes sense. This is something that, I think it's obvious today. It was not so obvious 4 years or 5 years ago, but I think that we and the system, we have all learned, how, the system could evolve in these years, and, storage makes sense. Will need to be analyzed, what will be the best way to implement this capacity in the system. This is still under discussion. Acceleration of renewables, of course, will be key. We have seen some delays in some projects, this could also impact the system in the short term. I would say that those three, in, in, in line with the volatile evolution of hydrology, should be key for the future. Thank you. Very helpful. That's all on my side. Thank you. This concludes the question and answer section. At this time, I would like to turn the floor back to ENGIE Energia Chile, for any closing remarks. Thank you. Thank you very much, everyone, for, for your participation. I hope, you had a, a good time with us, and, looking forward for our next, meeting in, three months. Thank you. Thank you. This concludes today's presentation. You may disconnect your line at this time.