Good morning, ladies and gentlemen, welcome to the nine-month 2022 results presentation, which will be hosted by our CEO, José Bogas, and the CFO, Luca Passa. Following the presentation, we will have the usual Q&A session open to those connected on the call and on the web. We kindly ask you to limit your questions to the financial and operational performance of the company during the period, and to wait until the 23rd of November for the update of the strategic plan. Thank you. Now let me hand over to José Bogas. Okay. Thank you, Mar. Good morning, everybody. Let's start with some key consideration for the period. First, the persistent volatility in the gas market and high electricity prices led both the European Union and the Spanish government to unveil new set of emergency measures in order to mitigate the consequences of the energy crisis, while discussing bolder proposal for the medium term. The deterioration of the macro context has shown no sign of recovery during the last quarter. The growing concerns on the main economies' performance and inflation exceeding all records in the Eurozone triggered a new round of corrective measure from central banks, including significant interest rate hikes. The sound performance of our liberalized business is clear evidence of our management-integrated strategy resiliency to overcome market headwinds. Like-for-like EBITDA, excluding sale of Endesa X Way to Enel, increased by 11%, while net ordinary income increased by 1%. Finally, an extraordinary shareholder meeting has been called on November the 17th to approve a set of preventive operational and financial measure within the usual related party transaction practice with our parent company. Its adoption will provide the company with greater operational and financial flexibility in the event of extraordinary energy market volatility occurring again in the near future. On the next slide, we will further elaborate on the dynamic of the market context. Nine-month cumulative mainland demand decreased by 1.4% compared to the previous year, showing a further leveling off in the negative trend seen during the year. In Endesa's mainland distribution area, figures were slightly better, as demand increased 0.5%, that is, -0.8% adjusted, relying on the service segment solid performance, offset by reduction in residential, -1.3%, and industrial, -4% segments. The latter being affected by the economy slowdown, mainly in the metallurgical and paper sector. The European energy crisis, also affected by the geopolitical tensions, resulted in a challenging market context, with record high prices during the summer. The European gas reference, the TTF index, reached the historical high of around EUR 316 per MWh on August the 26th, while the Spanish reference, MIBGAS or PVB, surpassed EUR 230 per MWh, additionally showing a relevant decoupling since June. Against this background, Iberian average full price reached EUR 186 per MWh in the period, up 137% year-on-year, and also affected by the cap on gas for electricity prices, limiting the implicit gas cost at EUR 40 per MWh since mid-June. So far, 2022 has been the most expensive year in the Spanish electricity market. In the absence of a similar gas cap as the Iberian exception, most European energy markets recorded average price around EUR 300 per MWh, driven by the gas record high and extreme volatility. Let's now focus specifically on the worsening of third quarter context on slide number five. While there is no doubt that 2022 is being characterized by record high gas prices, in particular, the third quarter has seen an extreme and unprecedented rise. For instance, MIBGAS PVB, which is the reference for the Iberian market, soared an average by more than 180% quarter on quarter to EUR 138 per MWh. This price level compares with the EUR 90 to EUR 100 per MWh range seen during the first half of the year. When it comes to the TTF, which currently is the leading European gas benchmark, declining gas export from Russia and the buying spree to top up winter reserves mean an average price of EUR 200 per MWh in the third quarter, which compare with the EUR 50 per MWh recorded in the same quarter of the last year. With these commodity prices increases, quarterly average power price also reached record high in all the markets, except in the Iberian market, where the price cap, in force since June the 15th, has allowed to keep pool prices under control compared to other European countries. Although, considering the thermal compensation, last quarter prices also represented an all-time record in Iberia. Power pool prices forward references for the last quarter point to similar levels, while natural gas futures linked to TTF and MIBGAS are trading around EUR 75 and EUR 70 per MWh respectively, close to level not seen since mid-June, and less than a third of their summer peak. Moreover, unusual warm weather, high flows of LNG, and strong storage build have eased some pressure on the gas market in the last two months. European storage is almost 94% full, and Germany has reached 98%. On slide number six, we can see a summary of the regulatory initiative unveiled during the last quarter and aimed at containing electricity prices and mitigating its social impact. At the European level, as a complement to the different packages approved to date, a new set of emergency measures to control energy prices was approved last September and will be applicable from December the 1st of this year to December the 31st, 2023. Among others, those include a reduction in electricity consumption, the introduction of a cap of EUR 180 per MWh for the marginal technologies, and a solidarity contribution tax for oil and gas companies. Moreover, the European Union reached a consensus to work on a gas purchase platform, an alternative reference in gas market, and a solidarity scheme to allocate gas between member states. Finally, an overall energy market reform debate carries on. In Spain, since August, the government has approved, through three different Royal Decree-Law, several cost reduction measures for the most vulnerable customers, such as implementing energy saving and efficiency measures, reducing energy dependence on natural gas while promoting electrification and deployment of renewable energies, lowering value-added tax back from 21% to 5% on supplies of natural gas, and increased protection for the most vulnerable energy consumers, particularly on natural gas. On the non-mainland proposed fuel auction, we welcome the recommendation of the CNMC report, which consider inadequate to use the Brent formula, and advocates market references such as MIBGAS. Concerning regulated tariff, a new draft for public consultation has been put forward, which consider longer-term market price references for the energy cost indexation. Lastly, the tax proposal on energy companies and banks required as a social contribution has started the allegation process in parliament. While the final outcome is still unclear, we reiterate our disagreement with the proposed taxation. The tax will not be levied on extraordinary results since it will be applied on consolidated tax revenues, clearly affected by the context of high prices as well as the associated energy costs, and most expressly excluding regulated businesses. Obviously, this tax goes against the spirit of the current European Union proposal. It must be highlighted that last year, our tax contribution represented more than EUR 3 billion, which places us as the fifth-largest taxpayer in the country. Now we turn to the evolution of the generation operating parameters on slide number seven. Over the last 12 months, we have continued to make progress in our decarbonization commitment, bringing into operation more than 700 megawatts of renewables. Mainland renewable capacity is 10% higher than in nine months 2021, while CO2-free sources now constitute 70% of our installed capacity on the mainland. Over this nine months of 2022, we connected 156 megawatts of new wind and solar capacity to the grid. In addition, on October the 21st, a new solar plant was commissioned in Seville with an installed capacity of 50 megawatts. All in all, 100% of this year's target additional capacity, one gigawatt, is on track. We expect it to be operational in the fourth quarter with no foreseen delays. As for the renewable pipeline, the 65% of the four gigawatts of new addition targeted for 2022 to 2024 are already addressed. While the rest is ensured with a gross pipeline of more than 80 gigawatts, the mature portion of which covers more than 16, that is 35% of four gigawatt, the residual target of new capacity. Total mainland output reached 39.9 TWh, +16% higher than previous year. Year-to-date output figure consolidates the lower hydro availability suffered mainly in the first semester. In that context, the increase in wind and solar production due to the entry of new capacity, together with the recovery of the thermal production, mainly CCGTs, more than offset the drop of hydro production. Finally, let me highlight the fact that Endesa was provisionally awarded the Andorra fair transition tender, obtaining the right to connect 953 megawatts and the option to step up to a total of 1,200 megawatts. This project reinforced the company commitment to future projects in areas affected by plant closure, creating value in the local communities. In power retail, we continue increasing the liberalized customer base, delivering on our successful commercial strategy, and we are now on slide number eight. The implementation of attractive offers in the current price context has resulted in a remarkable increase in our liberalized customer base during the last 12 months, adding around 1.2 million new clients. Customer acquisition runs well above what was in our plans and pushed sales in the liberalized market up 4% versus previous year. Sales to liberalized residential customer have more than offset the decrease in sales to B2B customers. Looking at Endesa X, both e-home contract and charging points associated with electric mobility are increasing significantly by 30% and 43% respectively. On slide number nine, the good evolution of our free power sales came together with a sound performance of the free power margin that reached EUR 38 per MWh, 35% above previous year, despite the complex and challenging market and price scenario resulting from unitary revenue that rose to EUR 161 per MWh, associated to an increase of index sales and higher pool price context, and increasing variable costs driven by lower purchase volume at high prices and fuel cost increases. Free power margin amounted to around EUR 2.2 billion, well above the previous year, and the main drivers being the following. The renewal of fixed price contract at the price of EUR 65, market in our bilateral contract, which is below the limit set in the regulation. This will provide stability to our customer, guaranteeing steady bills in the coming month, with prices well below the spot price. Better margins in thermal generation due to a higher CCGT production in a context of higher thermal output to compensate the low hydro production. Regarding forward sales, 100% of our 2022 price-driven output, 90% for 2023, and 46% in 2024 have already been hedged at EUR 65 per MWh base load price set in the bilateral contract between our generation and supply subsidiaries. Focusing on the gas business, we are on slide number 10. Total gas sales remain quite flat, increasing by around 1% to 75.4 TWh, with very strong sales to our CCGTs offsetting the lower conventional demand. Gas unitary margin, including wholesale, retail, and CCGT activity, recovered from EUR 0.9 per MWh in the first nine months of 2021 to EUR 3.7 per MWh in nine months 2022, driven by the wholesale business, with a significant improvement in the third quarter. This result reflects an overall context improvement compared to the previous year, clearly affected by the pandemic backdrop, by the American contract optionality, and the opportunities associated to high gas demand for CCGTs. To the contrary, retail business margin is slightly decreased, mainly driven by lower than expected gas demand. Volume hedge for 2022 is around 100% considering the expected sales to CCGTs in the fourth quarter. In the medium term, 60% and 29% of our sourcing contract are already hedged for 2023 and 2024 respectively. Our gas hedges are usually closed two or three years in advance, and we usually leave some Henry Hub volumes unhedged to exploit their full flexibility. Moving to operating achievement on networks, and I'm now on slide number 11. Distributed energy stood at 102 TWh, up by 3%. Our effort to improve quality and efficiency resulted in a drop in losses that improved 0.2 percentage point, while time of interruption improved by around 9%. These good efficiency figures have been achieved despite the extreme weather conditions, such as the record high temperatures during the summer or the Tropical Storm Hermine, an unprecedented meteorological phenomenon in the Canary Islands that affected the electricity grid. Now I will hand over to Luca, who will detail the financial results. Thank you, Pepe, and good morning to everybody. On the financial highlights, I am now on slide number 13. Reported EBITDA increased by 19%. EBITDA like-for-like increased by 11%, excluding the capital gain obtained from Endesa X Way transaction. Net ordinary income was up by 1% year-on-year, amounting to close to EUR 1.5 billion, not considering the net effect of the Endesa X Way transaction. Reported fund from operation figure, which amounted to EUR 0.6 billion, turned positive versus first half 2022. This figure was strongly affected by the increase in the regulatory working capital during the period of close to EUR 1.2 billion. Once stripped out of this impact, both years, FFO would have reached EUR 1.8 billion, more than doubling the adjusted FFO in nine months 2021. Moving to the detailed analysis of the period on slide 14, we invested approximately EUR 1.5 billion in the period, 20% more than the previous year, mostly allocated to the two main strategic pillars, networks and renewables. EBITDA like-for-like reached EUR 3,472 million, +11% versus nine month 2021. Generation and supply showed an improvement of 38%. Distribution EBITDA declined by 21% to EUR 1,132 million. While generation business benefited from the bilateral contract, customer business was impacted by the net increase of commercial sourcing cost. Moving now into a deeper analysis, slide 15, on generation and supply business. Despite the strong volatility, our liberalized business portfolio strategy has successfully overcome the headwind. EBITDA like-for-like reached EUR 2,340 million, +38% versus last year, including the following effects. Net effect of non-recurrent of -EUR 84 million. The free power margin has performed better than expected, showing an increase in absolute terms of EUR 724 million, mainly thanks to the generation margin increase, mainly to the new price reference and higher thermal output, with the lower volumes where the lower hydro is partially offset by the improvement in volumes of the rest of renewables and nuclear, and other minor effects. The supply margin was likewise affected by the net increase in sourcing cost, higher ancillary and shape cost, and customer mix effect. Finally, a positive effect on the short position for EUR 142 million. The positive contribution of Endesa X and other effects for +EUR 27 million, which includes: an improvement in the gas business and others for EUR 160 million, including EUR 209 in gas, thanks to the optionality of our contracts in a much better scenario versus the previous year, partially offset by other minor negative impacts of about EUR 50 million. A deterioration of non-mainland margin that decreased by EUR 133 million, resulting from the worsening of the fuel cost recognition due to the gas price, given that the current regulation does not yet allow the recovery of the actual cost incurred. Fixed cost increased by EUR 45 million, mainly due to the inflationary context and higher activity. Moving to slide 16, distribution EBITDA dropped by 21% to EUR 1.132 billion, mainly affected by lower gross margin impacted by the update of the regulatory remuneration for mainly 2017 to 2019, in accordance with the Ministerial Order issued in August by around EUR 180 million. Minus EUR 29 million of the previous year resettlements booked in the first half, and a marginal decrease of gross margin, mainly due to the impact of the two previous effects on the current year. Fixed cost increased by EUR 56 million, mainly due to the increase in the repairs and maintenance cost, the update of the workforce restructuring provision, and the recognition of recent sanctioning proceeding. We do not expect further non-recurrent effects for the last quarter of the year. Few more details on the evolution of fixed cost. We are now on slide 17. Total fixed cost reached EUR 1.510 billion, 8% higher than last year. Thanks to our digitalized asset base and platforms, we have continued to deliver efficiency across all businesses that soften the impact of the increasing inflation effect and rising inertial cost in the growing businesses. On the P&L evolution from EBITDA to net ordinary income, and I am now on slide 18, net ordinary income came at EUR 1.469 billion, up 1% year-on-year on the back of the dynamics commented at EBITDA level. D&A is up EUR 145 million year-on-year, with higher amortization for EUR 83 million based on investment increase, as well as activated customer acquisition cost, and higher bad debt accrual for EUR 62 million associated with the increase in billings volumes in the period, representing 0.4% of total revenues, slightly lower versus the historical trend. Overdue debt over 180 days sees a reduction of about 20% compared to nine months 2021. Net financial charges increased mainly as a result of the net effect of late interest payments for minus EUR 65 million, and the net exchange differences due to the evolution of the euro-USD rate during nine months 2022, and higher debt financing cost due to the increase of the average gross debt despite the lower cost of debt, mainly as a consequence of the increase in cash collaterals required in organized markets. This was more than offset by the update of the workforce reduction plans provision. Rises in taxes, mainly due to the higher results and the increase in the effective tax rate to 25.6% due to non-deductible tax provision. Minorities increased by EUR 36 million, in line with the trend shown in June, mostly due to better results of some wind farms with minorities participation. Moving to the cash flow on slide 19. Funds from operation evolution in the nine months came in at EUR 0.6 billion positive, improving for about EUR 0.8 billion versus the first half of 2022. Net working capital was equal to minus EUR 2.2 billion, strongly affected by the EUR 1.2 billion of regulatory working capital increase during the nine months of 2022, most of it in mainland business due to the regulatory settlements at historical fuel cost, far below the current market. Excluding this impact, FFO would have reached around EUR 1.8 billion. Apart from this effect, net working capital amounts to minus EUR 1.1 billion, almost all of it expected to be temporary and corresponds to minus EUR 1.1 due to the gas cap mechanism pending to cash in from customers, minus EUR 0.1 billion higher mandatory stock on gas required by the government to face the energy crisis, and plus EUR 0.2 billion net energy system charge impacted by the government measures both in 2021 and 2022. The increase of net balance of receivables and payable accounts associated with the external energy market environment is offset by different actions implemented to improve working capital, such as cash collection, commercial factoring, and others. We expect the above effects impacting working capital to normalize over the year, assuming a stabilization and normalization of the energy context and no further regulatory measures. I will now move on debt evolution on slide number 20. Net debt amounts to EUR 11.1 billion, EUR 2.3 billion higher than the full year 2021. This increase is clearly affected by EUR 1.6 billion cash-based CapEx, EUR 1.5 billion of the total dividend corresponding to 2021 results. All of the above was partially offset by the EUR 0.6 billion of positive FFO generated during the year. Regular working capital, as previously commented, was close to EUR 2 billion with a EUR 1.2 billion higher respect of full year 2021, mainly due to the increase in the pending compensation on mainland, of which we are expecting to cash in at least EUR 400 million by year-end. Our leverage measure as net debt to EBITDA ratio was 2.3 times, and the cost of debt is still very competitive at 1.1% level. Gross debt has notably increased as a result of the material rise of financial guarantees, commonly known as margin collateral requirements, required for the commodity financial hedging contracts, which has spiked in the third quarter due to extremely volatile context, as Pepe mentioned before. Let me specify that these commodity financial hedging contracts are used to hedge our margins for our native portfolio in both power and gas and are absolutely not speculative. Collateral requirements are temporary. In fact, at the end of October, the figure has dropped, reaching EUR 8.6 billion due to the gradual decline in commodity prices after the third quarter peak. Moreover, we expect these volumes to notably reduce as derivative mature, starting at year-end with an expectation of EUR 8 billion and a rate of about EUR 400 million per month in the 2023 year, assuming the current forward price. Regarding the estimate of net debt by year-end, with no further regulatory intervention and a stabilization of the market scenario, we expect net debt to be in the range of EUR 10 billion to EUR 10.5 billion, slightly above same year expectation, mainly due to the expected increase in regulatory working capital, as commented before. Moving to liquidity, I am on slide 21. At the end of September, liquidity amount to EUR 4.4 billion. This figure consider unconditional credit lines amounting to EUR 5.8 billion, out of which EUR 3.8 billion are available. The adjustment in liquidity is a consequence of the strong increase in collateral in the third quarter, which is affecting all energy operators across Europe and the sector liquidity needs, together with a slower than expected recovery of operation cash flows and the payment of the final dividend in July. The increase in margining has been financed mainly with short-term instruments. Once deducted the funding of energy markets cash collaterals, the resulting ratio of fixed rate gross debt is 62%, adequate to address the current path of rate normalization in the Euro area. Pending the European energy market stabilization, we are actively managing the current situation through a number of financial initiatives, strengthening the liquidity position and providing the necessary backup in case of a new extreme volatility spikes. We have already put in place facilities amounting to EUR 4.5 billion that, once considered, results in a coverage of 11 months of debt maturities, in particular, EUR 3 billion in a 12-month credit line with Enel Finance International, pending EGM approval the next November 17th, EUR 1.3 billion renegotiation of loan extension from March 2022 to July 2024 with the relationship banks already executed, and EUR 250 million new sustainability-linked European Investment Bank loan for 15 years signed yesterday. We are working on additional measures that will provide a material increase in the liquidity position in the short term, reaching levels that we find sufficiently comfortable. Let me now hand over to Pepe for his final remarks. Thank you, Luca. To close this presentation on slide number 22, I would like to share some final remarks on the main achievement of the period. First of all, the resiliency of our long-proven integrated business model has allowed us to successfully overcome one of the most challenging contexts in recent years, both in terms of market volatility and regulatory intervention. We continue to attract new customer, leveraging on a successful commercial strategy based on range of products and services, providing stability to their energy bills. In renewables, we continue to deliver on capacity addition and are on track to deliver the full year target. We remind you that on the 17th of November, an extraordinary general shareholders meeting will be held to approve a set of operation to reinforce our position on international gas market, as well as to strengthen our liquidity, providing a solid backup in case of new extreme volatile spikes. To wrap up, despite the many headwinds encountered during the period, the nine months results reached in nine months support the achievement of the net ordinary income target set for the year. Even considering prudently the proposal of taxing utilities for about EUR 400 million. Ladies and gentlemen, this concludes our nine-month 2022 result presentation. Thank you very much for your attention, and we are ready to take some questions. Okay. Thank you, Pepe. We start now with the Q&A session, and open to take all the questions you may have. Thank you. If you would like to ask a question, please press star one on your telephone keypad. If you change your mind, star two on your telephone keypad. To ask a question, please ensure your telephone is unmuted locally. Ms. Mar Martínez, Head of Investor Relations, please go ahead. Okay. The first question comes from Alberto Gandolfi from Goldman Sachs. Please, Alberto, go ahead. No. Probably Alberto has some technical issues. We can move to the next analyst, that is Javier Garrido from J.P. Morgan. Good morning, everyone. I have a few questions. First one guidance. Did I understand correctly that you are including up to a potential impact of up to EUR 400 million from the Spanish energy tax that would be included in your reiteration of the ordinary net income for 2022? That's the first question. Second question, you can quantify or at least give some approximate figures about how much of the EUR 724 million increase in the gross margin in the first nine months in the free markets is due to the repricing of contracts, and how much is due to higher profits from CCGTs? The third question is, I've noticed the continuation and acceleration in the increase in index sales in your portfolio. Is this increase sustainable, and is it a strategic decision to reduce the economic exposure to a short energy position in the future? Thank you. Okay. Thank you, Javier. Let me say, you are absolutely right. We have prudently, as I have said, include this taxation of EUR 400 million in the net ordinary income. That means that we will maintain our net ordinary guidance, net income ordinary guidance, even with this taxation. With regard to the last question, in the sense of the index sales, well, let me say that this is not a strategy to increase or decrease our index sales. It's a consequence of the market and the dynamic of this market. There are many customer, many clients that they prefer, in the future, just to be index because they are expecting a minimal reduction in the prices. We try to advocate them in the sense to give them the best alternative for their supply. Well, from time to time, we have different strategies. One of them trying to give clues just to fix prices or to continue in the indexation. It depend on the kind of client and the way in which they would like to go ahead. On your second question, Javier, regarding the impacts on the EUR 724 million of increase in our liberalized margin. As far as the generation part, basically, we have obviously the positive effect of The bilateral contracts, which impact for EUR 440 million in generation, in particular, when it comes to the CCGTs, here, obviously for the increase in volume, we have a positive effect of about EUR 200 million. On the supply side, you have the negative effect on generation still for EUR 440 million regarding the bilateral contract, and the net effect there of EUR 60 million, assuming that obviously repricing for the full nine months is giving us in the region of EUR 350 million. Okay. I think that we have now Alberto Gandolfi from Goldman Sachs. Please, Alberto, go ahead. Mar, thank you, and good morning. I also have three questions, please. The first one is continuing on margins in the liberalized business. If I observe on your slide 15, it looks like the non-mainland will normalize at some stage when fuel somehow settle. What I'm trying to understand is how much of these benefits from gas contracts, CCGT spreads are going to also repeat in 2023. Can you tell us maybe how much of these EUR 2.3 billion EBITDA in the generation and supply is function of the gas contract and/or export to France, that when the nukes restart may no longer be there? I'm trying to understand the sustainability of this profitability, which admittedly is extremely strong, into next year. If you keep that plus the normalization in mainland, it would be really strong numbers. I'm just trying to figure out that. The second question is on interest expenses. You've been really good at keeping costs at 1.1%. I wonder how sustainable is that, considering half of your debt is variable and considering that we are seeing refinancing rates being something like 300, 350 basis points higher than what you are paying right now. How much of a headwind is this going to be on the accounts going forward? Last question, I'm not going to ask about CapEx and the revenue tax, I think that's going to be addressed in the next couple of weeks. Maybe the last question, I'm a bit surprised that you are booking 0.4% bad debt, which is less than average. I would have expected with bills going up, you would be booking a higher percentage. I know the absolute amount is going up anyway because your revenues are growing. What's the rationale for booking a lower ratio of bad debts in a moment where energy bills are going up, are doubling, basically? Thank you so much. Okay, Alberto, I will hand over to Luca to answer. Let me say something with regard to the fuel cost for the island, or the remuneration of the island. Let me say that the fuel remuneration, in regulated fuel remuneration, must be based on the pass-through rule that we used to have always in this regulated business. It is clear that the current, I would say, customs fuel cost is not working now. Having said that, the CNMC on its report, last report of September, published a report on the proposed fuel remuneration in the island. The CNMC recommends using indexes that reflect market quotation in a better way, explicitly mentioning the MIBGAS. We are currently waiting for a new draft Ministerial Order aligned to the CNMC recommendations. Luca? Sure. Just adding on this first question, obviously the gas business has had a very good performance in this period. We are expecting this to be sustained towards the end. For 2023, let me not comment until we get to our Capital Markets Day in about two weeks. When it comes to interest expense, I can give you basically how the evolution towards the end. We currently have 1.1% cost of debt. We are expecting to reach 1.5% at the end of the year. That is based on an assumption of the fixed rate component just over 2%, at around 2.3%, and the variable rate component at 90 basis points in terms of cost of funding. Obviously, in the future years, again, we will comment at the CMD, we will have an increase in interest expense as all other operators are basically experiencing, given the normalization of interest rates across Europe. The third question was on the rationale? Percentage. The rationale on the percentage of bad debt. We always had a percentage that was ranging between 0.3%-0.5%, so 0.4 is more or less in line with the past. We have an increase in basically billings volumes of about 60% in these last months, which is a huge number. The usage of this percentage is in the average of our past periods. Therefore, this is also based on expected evolution for the future, because obviously not all the increase in billing will basically come down as bad debt, given what we are spending currently in basically payments by our customers. Therefore, we deem appropriate using the 0.4 percentage point given the higher increase in billing that we're seeing basically this year. Many thanks, Alberto. Next questions come from Antonella Bianchessi from Citi. Yes, a very quick question on your CapEx. You reported EUR 1.6 billion. Your plan is talking the EUR 2.6 billion for the current year. Are you on track on that, or you think some of the CapEx will flow into the next few years? I noticed that the demand is coming down a lot, and therefore how this can change the position of Endesa, going forward, particularly on its ambition on the renewable growth. Okay, Antonella. Well, Luca will explain deeper. We are on track on our CapEx, and we don't see any change in the future. We feel comfortable with what we are doing, and we will reach this CapEx. With regard to the second question, if demand going down is going just to reduce our long-term position in generation. Well, it is clear, if demand is reduced, our long-term position will be reduced also. We feel comfortable in the way in which our, as I have said, strategy is working, and we feel comfortable continuing with this strategy. Luca? No, just confirming again the CapEx expectation for the full year at EUR 2.6. Regarding the demand decrease in our development in renewables, I confirm the 1 gigawatt of additions expected for this year. We are already over or in and around 250. The rest of the capacity will come online in these last two months of the year, as we experienced also in the previous two years. While for basically the evolution going forward, again, let's wait for the CMD in a couple of weeks. Thank you. We move to the following questions that comes from Jorge Guimarães from JB Capital. Good morning. I have two questions. The first one is, if you can go back to the liberalized margin, in Q3, an electricity margin close to EUR 50 a MWh. If you can help us to understand how did you achieve such a high margin, and how sustainable it is going forward? The second one, it's not directly related to the results, but I can't help but ask it. Do you have any opinion about the news last week in Spanish press about the inclusion or not of CPI adjustment clawback exemption? Thank you very much. Okay, Jorge, thank you for the question. Again, Luca will explain better. We think that it is not easy as to obtain this kind of margins. It is the consequence of a very good job, trying just to, first of all, to give a very good price to our customer base in the infra-marginal cap that we have of 67, you know, our price is 65. Managing all the rest of the cost, the ancillary costs, the shape of the customer, et cetera. It is not easy. I think we are doing a very good job. With regard to the second question, first of all, that is in relation with what we call the responsible declaration that we do, yes, to the CNMC, taking into account our infra-marginal generation and the fixed prices to our customer. I should say that I think that there is not any problem, or at least material problem, with respect to our declaration. As I have said, we have done some kind of repricing of contracts to levels consistent, as I have said, with the 67 EUR per MWh clawback. I think that this repricing will have a sustainable positive impact. We are not going to be penalized because of any clawback. Just on the liberalized margin again, basically the effect and the sustainability of this result in the months is based on the fact that we are repricing our generation at the level of 65, starting from previous years where we were ranging in the 45 to 50 area. Again, respecting also the regulation of the 67 EUR clawback imposed by the regulator. I think it is part of the evolution, our generation and supply margins together, as I commented before, with the impact of the bilateral contract for EUR 440 million positive in generation and negative in supply, obviously the improvement when it comes to thermal output, given the higher volumes in generation. We have now Manuel Palomo from Exane BNP. Hello. Good morning, and thanks for taking my questions. I will stick to two. One is just a confirmation to make sure that the up EUR 2.4 billion impact is in net profit and not in EBITDA. That will be the first one. Second one is, whether you could please explain the rationale why you have materially increased the number of clients in the liberalized market, 21% if I'm not wrong, while volumes have gone only up by 4%? Is this the trend that you will expect going forward? Thank you very much. Okay. Thank you, Manuel. First of all, you are right. It is clear that this increase in the net ordinary results will be supported by an increase in the EBITDA that Luca will explain later. The second question is with regard to Okay, Luca. I'll take it, Pepe. The first one is up to EUR 400 million of, let's say, prudently tax provision on the new proposal taxation is at the net income level, so confirmed. On the second question, 4% volumes versus 20% increase in clients. First of all, volumes are affected by demand. You've seen the evolution of demand. I think we commented by sectors, but basically you have an increase in demand only on services, while both residential and in particular industrial are down in terms of demand, given the high prices scenario. The evolution of demand obviously will depend also on the macroeconomic evolution and basically GDP evolution for next year. You know GDP evolution for this year and for next year have been lowered several times during the last months. Basically, volumes are affected by macro and sectors evolution, while customers, notwithstanding the increase or the inversion in trend that we experience in the last nine months, obviously, the flows is lowing, because also customers acquisition in liberalized market in the third quarter is much lower than what we experienced in the first two quarters. I expect the customer trend to slow again in the future quarters, while volumes will depend on demand on each of the sector, and industrial, I think, will be impacted in the next few quarters in that respect by the energy context. Okay. Next question is coming from Javier Suárez from Mediobanca. Hi, good morning, and thank you for the presentation. Three follow-up questions also on my side. The question for you is, when and how are you expecting the recovery of this working capital? Which should be the amount of working capital that we should see by the year-end? How confident you see on the positive evolution and reduction on this regulatory working capital? A related question is on the level of cash collaterals that you are expected by the year-end, and implication that this may have on your capital going forward. Third question is on the guidance. The company has confirmed this morning the net ordinary net income for 2022. Can you please elaborate on latest guidance for EBITDA and then payout policy, and therefore implicit dividend yield in 2022? The final question is, if you can update us on your contribution to the ongoing debate on how the European Union should face the structural reform of the European electricity market, through both short-term and then medium-term measures. Thank you. Okay, Javier. I will try just to give you some coloring on the last question, the debate in the European Union around these changes. Well, in my opinion, it is absolutely clear that we have realized that with an extreme, unpredictable, volatile context like the one that we are suffering now, the marginal system pricing that we have, I would say doesn't work correctly in the sense that the combined cycles are fixing very high prices, that it has no sense for the infra-marginal technologies. Another question is, what should be this price for the infra-marginal technologies? As you could see, in Spain, the regulator had decided he has to cap with EUR 67 per MWh, and in Europe, this figure is EUR 180 per MWh. In any case, what I think is that it should be different between the signal price and the remuneration price for the different technologies. I think if we go back to a normal situation again, there is any problem, and this marginal price has been working during a long period of time and during the last years. I think that very efficiently, because it allocate the resources in the right way. We have obtained a lot of cost reduction, in the sense of the European Union cost of energy. As I have said, we should think how to change this. In any case, if you think in the future, in a mix in which we will have only renewables, then the marginal cost will be zero, close to zero, and it has no sense. This remuneration system should change in the future, just because of this extreme context, or just because we are going just to have marginal technologies with marginal costs close to zero, and you should pay, in any case, the capital cost or the fixed cost. We are really open to this change and while it is not easy, but it is normal and reasonable just to think about a new remuneration system for the future. Thanks, José. On the first questions regarding working capital reabsorption, as I said, regarding working capital, we expected to basically lower it to the stock that we are registering of EUR 2 billion at the nine months by EUR 400 million by year-end, and hopefully something more if it comes. When it comes to the, let me say, the ordinary evolution of working capital, which has a negative effect of about EUR 1 billion in nine months, we are expected to recover almost all of it, because obviously the impact of EUR 1.1 billion of the cap on gas will be reabsorbed quite substantially towards the fourth quarter, given the evolution in price and the fact that in certain recent days, the cap on gas do not apply. Therefore, we will not have an impact on demand. As you might recall, these measures basically is settled on generation on a weekly basis in the system, and then is transferred or financed through bills to final customers. We have basically a delay in terms of timing of when the settlement goes into the bill, and when actually we are basically getting the money, basically from the final customers. On cash collateral, expectation for year-end, given the current prices, is EUR 8 billion gross for year-end 2022. As I said, for 2023, we are expecting a decrease of about EUR 400 million per month. In terms of, let me say, EBITDA evolution in the fourth quarter, we are expecting basically an EBITDA evolution similar of what we had in the third quarter, driven by obviously the absence, as I mentioned, of a negative one-off in distribution that we already recorded in this third quarter. The recovery of mainland generation, slightly below the guidance, in and around EUR 400 million in terms of margins. Stable free power margin also for the fourth quarter, which has been quite strong, as discussed before, for the third quarter. Some worsening on the gas wholesale mark-to-markets for about EUR 300 million. That's basically what we are guiding for in terms of EBITDA evolution for the fourth quarter. We gave formally a guidance on net ordinary income, net of basically the provisions for the split-up ETF proposal, as that is the base for dividend payment. Okay, thank you. We have now Fernando Garcia from RBC. Please, Fernando, go ahead. Good morning, thank you for taking my questions. I have two. First one is on the, if you can expand the explanation on the EUR 180 million in the distribution update. I think this is related to an inventory. My question here is if you think this inventory in the case of Endesa was correctly. The second one is a follow-up question on the previous question of Javier Suárez, on the guidance of net debt on to EUR 10.5 billion. I assume here that you are including EUR 1 billion recovery for the cap of gas, then EUR 0.4 billion as well on regulatory working capital. I am correct here? Thank you. Thank you, Fernando. Let me try to answer the first one, the one regarding to the distribution remuneration. First of all, I should say that it is a negative impact not only for Endesa, but for all the sector. This figure comes from the inventory, that is the asset, also for the operational maintenance concept. Well, we don't agree with this resolution because of many things, we have appealed. We will intend just to explain, because I think there are some mistakes in this regulation, not only for Endesa, for all the sector. The main negative impact is not in the value of the asset, but in the recognition of the operational maintenance. Thank you, Pepe. On the second question, the assumption of net debt at year-end at EUR 10 billion-EUR 10.5 billion is based on FFO generation of EUR 2 billion and regulatory working capital at EUR 1.7 billion. It is a recovery of EUR 400 million in regulatory working capital, and let's say ordinary working capital recovery of about EUR 1 billion, which is obviously the cap on gas plus other recoveries. Okay. Next question comes from Robert Pulleyn from Morgan Stanley. Hi, good morning. Thank you. At this stage, I will limit it to one question, given that lots of others have already been answered. Can I just revisit for clarification, this renewables capacity for delivery in 4Q? You have said it twice, that you aim to still hit your one gig target. Could I ask the status of those projects? Are all the components just awaiting installation and commissioning, or are there any pending delays in delivery, especially in solar? As a follow-up, very quickly on a previous question, as you referred to cost of financing, would you be willing to say where you expect your leading-edge borrowing costs to go for those refinancings due in 2023 and 2024? Thank you very much. Okay. Thank you for the question. With regard to the first one on the renewable delivery, as usual, we used to deliver at the end of the year. As we have said, if you take into account the last 12 months, we have put in operation 700 MW. In this year, taking into account what we did in October, we have now a little bit more than 200 MW. We do not expect any material delay. We will reach, or we feel comfortable just to reach our target of one gigawatt at the end of the year. Let me add, Pepe, that this was the same performance in terms of capacity additions that we had both for 2021 and 2020. Therefore, lots of the capacity coming basically online in the last two months. Construction is almost basically finished for the major of the projects that we have. As far as cost of financing, Rob, I can comment for the evolution up until this year-end, and then for 2023 and 2024 refinancing, I'm sorry, but you need to wait a couple of weeks. Clearly, you can expect an increase given the interest rates, basically normalization that we are seeing in Europe. Next question comes from Jorge Alonso from Societe Generale. Hi. Good morning. A couple of questions, please. You have hedged 90% of the energy for 2023. I just wanted to know on what hydro output, if you are assuming a full normalization or which is your assumption for 2023, just in order to be sure that you're not going over hedging again. The second one is related to the gas procurement cost. If you expect that your procurement cost for gas next year would increase materially or would stay more or less at the same level that you have seen this year. The last one is about the distribution business. If you can give us some more color about the underlying performance of the business, not considering the one-off, if it is recovering or is it still a little bit weak, and what are the reasons for that? Thank you very much. Okay, Jorge. Let me say that we always consider an average year in hydro, but in this case, I think what we have considered is a little bit lower than the average for the rest of the year. With regard to the second question, the gas cost procurement, while it is clear that these costs are more or less aligned with certain indexes like Brent, Henry Hub or even the indexes of MIBGAS, et cetera. It would depend on the evolution of these indexes. Nevertheless, what we see is that if these indexes increase and the reference that we have increased, our aim is, yes, to try to maintain the margins that we have today. With regard to the distribution, we don't expect any more negative news in terms of the regulation. We think that the evolution in the future should be or will be, if you take into account what happened in this year, 2022, without this negative regulation impact is similar to other years. Luca, could you? Yes. When it comes to the last one on distribution, as we said, we have allocated this amount that has been requested. Therefore, if our allocation goes through, we might have some recovery of that amount. Now, I cannot comment on the amount specifically, but clearly this is basically something that we are trying to recover. When it comes to the second one on the gas procurement cost, there has been and there will be, as always, some repricing in contracts. Let me say that the repricing, it's all in the money vis-à-vis the current market scenario. Clearly, I cannot comment on the level at which we are basically striking repricing with our sourcing counterparts. Now I think Antonella Bianchessi from Citi is back with some additional questions. Please, Antonella, go ahead. Yes, a very quick one. I noticed that in your CapEx, you have materially increased the CapEx related to the customer base. Is this capitalization of losses of new customer or it's marketing cost? What is this, and which is going to be the evolution over the next few years? Yes, Antonella, we increase, obviously, activation for customer acquisition, which is basically the component that then also has an effect in D&A, as I commented before. The impact on D&A for these nine months is only EUR 24 million. The evolution will depend on how much customer we will continue to attract given our strategy. Now, as I said, we will comment the evolution for 2023 and onwards in a couple of weeks. For this year, we do not expect further acquisition cost that will affect basically D&A. In terms of cost of acquisition of customers, we are ranging in the EUR 65-EUR 75 per customers, in terms of the cost at which we are acquiring customers currently. Okay, this was the last question of the call, and all the questions received by email has been addressed in the conference call. Thank you very much for participating. As always, IR team is available to help you in case you have further questions. That's all. See you next 23rd of November in our CMD. Have a nice day. Thank you.