Endesa, S.A. (ELE) Earnings Call Transcript & Summary

Good evening, ladies and gentlemen, and welcome to the 9-month 2021 Results Presentation, which will be hosted by our CEO, José Bogas; and the CFO, Luca Passa. [Operator Instructions] 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 25th of November for the update of our strategic plan. Thank you. And now let me hand over to José Bogas.

Okay. Thank you, Mar, and many thanks for being able to join us today. Let's start with the main highlights of the period. The adverse context in which we have operated during the first 9 months of the year has been earmarked by record high pool prices across all European countries, mainly driven by the imbalances in the gas market worldwide and to a lesser extent, to rising CO2 permit costs. In order to establish a common strategy to relieve customers from the exceptional electricity price increase, the European Union elaborated a toolbox, setting a series of guidance and available instrument in accordance with the path set forth by the Green deal. This year is proving to be one of the most complex in recent years in terms of adverse operational scenarios. Despite the uncertainty and thanks to the implementation of several managerial actions as well as a positive nonrecurring, we have managed to achieve an EBITDA of EUR 3.1 billion, in line with the previous year. More than ever, we are convinced that a strong and determined commitment to decarbonize our energy mix remains the key. Therefore, we have boosted our pipeline by an additional 22 gigawatts in the beginning of the year, totaling now more than 61 gigawatts. Moving now to Slide #3. As commented on in the previous slide, last October 13, the European Commission published its toolbox to allow the member state to address in accordance with European regulation, the immediate impact of the common problem of energy price increases. Main short-term measures to protect customers and industry are composed of tax exemption and reduction, the use of increase of CO2 revenues, subsidies to support intensive electricity consumption companies and direct aid to vulnerable families all of these under strong cooperation and European Union level monitoring. In the medium term, more structural measures will be adopted in order to boost market integration, empower consumers and uphold clean energy transition through Green deal as the best in insurance against future price spikes. The European Commission has strongly emphasized that no intervention measures distorting the electricity market should be adopted. The Spanish government deployed a set of regulatory proposal to counteract or shortened the rise in gas and therefore, its impact on electricity prices. Starting with the proposal of the national fund for the sustainability of the electricity system, one of the Spanish key measures to lower electricity prices and highly praised by the sector continues with the parliamentary approval process being treated now as an urgent bill. This piece of regulation aims to remove renewable premiums from the access tariff and to establish a funding mechanism to serve its cost among all energy consumers. A new draft bill on CO2 levy setting a permanent reduction of revenues affecting non-emitting facilities was sent for urgent parliamentary processing. We hope that the final bill will include some of the proposed amendments such as the exception of bilateral contract and the inclusion of a pool price floor. In this context of rising prices, a set of fiscal measures included in Royal Decree Law 12/2021 and 17/2021 have come into effect to alleviate customers' rising energy bills through some temporary fiscal reduction until the end of the year. The much more controversial Royal Decree Law 17 enforced on September 16 and running until end of March 2022 was finally modified through the Royal Decree Law 23/2021, recognizing the bilateral contract at fixed prices entered into prior to Royal Decree Law 17, and which therefore have not benefited from the price increase observed this year. Also with this new Royal Decree, protection of vulnerable customers has been improved, increasing the power bill discount. The social bonus will represent total contribution for Endesa of around EUR 75 million during this year on top of which we must add the effect of these new measures. Finally, we believe that the public consultation to report the regulated tariff in order to delink it from the volatility of spot prices is a step forward for this customer group that has been strongly impacted by the price increase. Let's move to Slide #4, in which we will briefly explain the composition of the Spanish electricity balance and how the high price scenario is affecting the different types of customers. On the production side, out of the 257 terawatt hour estimated output for 2021, 120 terawatt hour are sold through forward contracts at fixed prices between 1 and 2 years in advance of the energy delivery, not benefiting from price increase seen in the current context as they were sold at average referring below EUR 50 per megawatt hour. This production corresponds mainly to hydro, nuclear and nonregulated renewable power plants. Production sold at the spot prices is expected to amount to 123 terawatt hour this year, mainly corresponding to regulated renewable cogeneration power plants known as recovery that represents around 80 terawatt hour and the CCGT's. On the sales side, in addition to regulated customers, those liberalized industrial customers who have freely opted for index price contract are suffering from the price increase, too. For the rest of the customers who opted for fixed prices and totaling about 184 terawatt hour, not only are they not being affected by high prices, but they are also benefiting from the generalized lowering of tolls introduced by the Royal Decree 17. Therefore, clean baseload output from hydro, nuclear and nonregulated renewables is not enough to cover fixed price sales. Therefore, a significant portion of this sale must be acquired at a spot or OTC market prices. In the case of Endesa, all of our baseload generation, which is serving our fixed price contracts, both industrial and residential customer did not benefit from the current market context. Indeed, this contracting model will allow total estimated savings of EUR 3 billion to our customers throughout the year. On Slide #5, I would like to comment on the evolution of the scenario over the period, which has certainly been the main driver of this set of results. Over these 9 months of 2021, demand evolution in Spain started to show signs of recovery from the economic effects of the pandemic after the weak start of the year. Indeed, accumulated mainland power demand in the period increased by 3.4% or 3.5% if adjusted by calendar and temperature effects. Likewise, in Endesa's concession area, gross demand has increased by 2.2% or 2.3% in adjusted terms. These figures are driven by the solid recovery of the service and industrial segments. In 9 months 2021, average pool prices increased by around 1.5x versus the same period of the previous year, reaching EUR 78.5 per megawatt hour, mainly driven by the increase in the average gas prices and the high average CO2 prices in Europe. These conditions are not exclusive to the Spanish market. Gas is the marginal fuel in most European countries, so the impact in the electricity prices has been similar. Wholesale power prices increased above the Spanish pool price since the beginning of the year in many European markets. It is important to underline that we are not benefiting from these high prices. Moving to Slide #6. As commented on before in the last 12 months, the electricity price in Spain increased by 146% to EUR 78.5 per megawatt hour, which compared with around EUR 32 per megawatt hour of the last year's same period, indeed affected by the COVID outbreak. Out of this EUR 47 per megawatt hour spike, more than 80% of the attributable -- is attributable to the gas price rally. Considering current forwards for year-end, the average market price could reach around EUR 101 per megawatt hour in 2021, which would compare to EUR 34 per megawatt hour average price seen in 2020. The expected evolution of the commodities scenario suggests that price will remain high for the next few months. As a matter of fact, forward prices for 2022 stand at EUR 111 per megawatt hour. We believe that this trend will gradually rebound during next year as conjunctural situation is affecting current forwards. Now we turn to the evolution of the operating parameters for the period on Slide #7, where thanks to our continued effort in decarbonization, mainland renewable capacity now represents around 45% of the total, well on track to reach the 62 target set out in our business plan. Likewise, CO2-free sources constitute 64% of our installed capacity on the Peninsula. During this quarter, the growth path of renewable capacity remained almost flat. But addition will boost in the last quarter. Our target is to reach 700 megawatts this year. Total mainland output reached 34.4 terawatt hour aligned to last year. The year-on-year increase in wind and solar capacity together with the higher nuclear output of the period makes up for the lower hydro output. As a consequence of the coal phase out, today, thermal generation represents just 15% of the total mainland production, mostly from CCGT's. Emission-free production remained at 85% of the mainland total output close to reaching the 89% target set for 2023. On Page #8, let's have a look at the current situation of our pipeline, which will allow us to reach our commitment in renewable growth as well as accelerate it, if appropriate. Our gross pipeline was further expanded to above 61 gigawatt from 39 gigawatt announced in full year 2020, maintaining a constant effort to fit our renewable project portfolio. Out of this gross figure, around 12% has TSO-awarded connection points and 2.5 gigawatts are under execution, while solar technology represents the majority of this project. Based on our policy of developing storage jointly with the deployment of renewable capacity, we aim to gradually incorporate them into newly installed renewable capacity once regulation guarantees the competitiveness of these facilities. When it comes to retail on Slide #9, Endesa's total sales remain mostly flat at 66.3 terawatt hour, including a 3% drop in the regulated sales and 0.4% increase in the liberalized sales with significant improvement in the SME segment and international sales. By segment, both B2C and regulated customers experienced a decrease in sales. This was mostly compensated by B2B, increasing by 2%. Advertising campaigns put in place since the end of the last year for the B2B and B2C sector are starting to bear fruit. We have managed to reverse the downward trend in liberalized customers, which showed a positive balance of new contracts in this segment around 55,000 in the third quarter 2021. As of 9 months 2021, we recorded the loss of gas 67,000 liberalized and about 180,000 regulated customers with total power customer decrease by 2% during 2021 as a result of the competitive intensities is still dominating the sector. Customer would now be looking for more favorable condition on the liberalized market due to the extraordinary high pool prices in the period. This, coupled with the price scenario forecast pointing at sustained high prices in the coming months, using customer transfer between regulated and liberalized market make us confident to be able to sustain this trend going forward. Finally, churn rate amounted to 17.3%, reflecting competitive process still at a very high level when compared to the 10.9% level in 9 months 2020. Concerning our energy management on Slide #10, electricity sales in the liberalized business remained flat versus the previous year. The unitary integrated margin affected by the current situation, fell by 15% versus the EUR 33.2 per megawatt hour of the 9-month 2020. The unitary revenue rose to EUR 74.5 per megawatt hour, reflecting both effects in index sales, pool price increase, and higher volumes versus the previous year. The evolution of the integrated margin has been clearly affected by the unfavorable market situation being the main factor behind this margin decrease. First of all, the lower generation margin, mainly due to the weaker OTC references, lower income from thermal output and the new Catalan Tax enforced since the 1st of July 2020, partially offset by the suspension of 7% tax in the third quarter. Lower supply margin compared to the previous year, mainly as a result of a slightly lower unitary supply margin as a consequence of a higher pool price and ancillary services costs offset by the absence of the COVID impact experienced last year. And finally, short position affected by the different evolution of prices in the 2 period marked by the tough market context versus a very positive energy management in 2020. The unitary integrated margin of EUR 28.2 per megawatt hour includes EUR 85 million from blend and CO2 hedging, which has been booked in non-Mainland business. Regarding forward sales for 2021 and 2022, price-driven output has been closed at an OTC referral of around EUR 50 per megawatt hour. We have hedged for 2021, 100% of our estimated price-driven output at an all-in price of around EUR 71 per megawatt hour. For 2022, hedge volumes stand at over 88% at an all-in price of around EUR 76 per megawatt hour. This implies that only 4.4 terawatt hour of inframarginal generation are pending to be hedged. For 2023, we have hedged around 30% of our estimated price-driven output at a price slightly higher than 2022. And now let me hand over to Luca Passa, who will detail the financial results.

Thank you, Pepe, and good evening, ladies and gentlemen. I'm on Slide #12. Reported EBITDA stood at EUR 3.125 billion, almost flat on a like-for-like basis, once netted from last year personnel provision effect, the EBITDA would have increased by 4%. Net income dropped by minus 3% year-on-year, reaching EUR 1.459 billion, minus 14% and net ordinary income level. Funds from operation reached EUR 862 million, 56% down versus last year, mainly due to the bill collection delays related to the new regulations and other conjunctural items, as I will comment later on. Finally, net debt increased to EUR 10 billion, up by 45% versus full year 2020. These set of results have been driven by the market context that previously commented, mitigated through several managerial actions as well as positive nonrecurrent events booked in the period. Moving to the detailed analysis. On the like-for-like EBITDA on Slide 13, let me now briefly set out the main drivers. Like-for-like EBITDA stood at EUR 3.125 billion, plus 4% versus 9-month 2020. Generation and supply EBITDA increased by 1% to EUR 1.406 billion. Distribution EBITDA declined by 3% at EUR 1.432 billion. Finally, non-mainland generation EBITDA increased to EUR 287 million, plus 117%. Moving into a deeper analysis. We are on Slide 14 on the regulated business. Like-for-like EBITDA increased by 7% to EUR 1.719 billion, with a higher gross margin and a reduction of 7% in the fixed cost. Distribution margin decreased by 3%, mainly due to the application of the new remuneration parameters of the second regulatory period. The non-mainland generation gross margin increased by 39%, thanks to the normalization of the negative margins in 2020, driven by the mismatch between the fuel cost reference for regulated revenues and effective fuel costs and the positive impact of Brent and CO2 hedging that more than compensated the lower remuneration parameters and the absence of a positive realization book in 2020. Fixed costs were EUR 40 million lower once deducted the net provision release effect of last year, mainly due to lower maintenance costs in both businesses. On the liberalized business, I'm on Slide #15. EBITDA reached EUR 1.406 billion, 1% increase with 2% of higher gross margin and 5% increase in fixed cost on a like-for-like basis, mainly as a consequence of the positive update of the workforce provision booked last year. The liberalized electricity and other margins amounts to EUR 2.230 billion, negatively affected by the market context amounting to about EUR 350 million, mainly due to weaker OTC references, lower income from thermal output, lower supply margins compared to the previous years, mainly as a result of a slightly lower unitary supply margins as a consequence of higher pool price and ancillary service costs offset by the absence of the COVID-19 impact. The short position affected by the different evolution of prices in the 2 periods marked by a tough market context versus a very positive energy management in 2020. These numbers do not take into account any gas levy impact by Royal Decree 17 of 2021 as we filed a responsible declaration confirming our net selling position. All of the above was partially offset with the recognition to Endesa of the right to be compensated for the CO2 clawback in 2006 for EUR 188 million booked in 2021 by the ruling of the Supreme Court on the hydraulic canon law for EUR 48 million and the positive mark-to-market arising from the net positions of several commodity derivatives transactions. These positive mark-to-market effects are expected to reduce by year-end as the contracts are settled. Enel Green Power gross margin evolution has been affected by higher production volumes more than offset by lower OTC references and the regulatory adjustments that was negative in the period. Gas gross margin declined EUR 131 million in 9 months 2021 to EUR 67 million due to the worsening of the wholesale context partially compensated by the booking of the positive delta in the gas mark-to-market resulting from the derivative contracts. The mark-to-market figures have reversed from a negative delta of EUR 102 million registered in the first half results, once part of the derivatives negative position booked as of June have been settled in the last 3 months. Moving now to the next slide on the evolution of fixed costs. Total reported fixed costs have reached EUR 1.403 billion, aligned to last year on a like-for-like basis. Once deducted nonrecurrent effects as the workforce provision restructuring plans update and the COVID-19 public responsibility plan, fixed costs would have decreased by 2%. This is mainly due to the several efficiency plans crystallizing in a reduction of the average headcount by almost 5% in 9 months 2021 versus last year to a low historical record. Now moving to Slide #17, on the P&L evolution from EBITDA to net ordinary income. D&A increased by 7%, explained by the higher amortization, mainly renewables and distribution due to the investment effort carried out and by the positive effect of the coal plants dismantling provision recorded last year, partially compensated by minus EUR 21 million of lower bad debt. Net financial results were positively impacted by the financial revenues from the interest for late payment in relation to ENDESA's right to be compensated for the 26 CO2 clawback and the 2013 hydro canon. The effective tax rate resulted in 23.9%, stable compared to 9 months 2020. All in all, net ordinary income decreased by 14% over the period. Moving to the cash flow on Slide 18. Funds from operations decreased by 56% year-on-year, reaching EUR 862 million due to the following effects: higher EBITDA after provisions paid and net provision release of around EUR 70 million; working capital and others was materially, mainly due to the increase of net balance receivables and payables accounts for more than EUR 700 million as a consequence of collection delays related to recently enforced Royal Decree on access tools and charges for more than EUR 400 million; the still noncash items included in 9 months 2021 EBITDA mainly from the CO2 and hydro canon sentence in total more than EUR 200 million and higher inventories for about EUR 150 million. The evolution of derivative mark-to-market and CO2 rights, partially offset by lower other noncash provisions. Due to the negative effects of Royal Decree 17/2021 and the commodity scenario evolution on working capital, we expect FFO to worsen by year-end and then to recover in the following months as the vast majority of these effects are temporary. Income tax paid amount to minus EUR 215 million versus EUR 164 million in the previous year mainly due to the EUR 73 million corporate tax refund in 2020 corresponding to fiscal year 2018. Cash-based CapEx, raising to a sound 22% versus 9 months 2020 led the free cash flow to negative EUR 719 million. Let's now take a look at net debt on Slide 10 -- 19, sorry. Net debt amounts to EUR 10 billion, EUR 3.1 billion higher than full year 2020. The increase is clearly affected by the payment of dividends against 2020 results paid this year and the negative free cash flow explained before. The regulatory working capital remained slightly below last year's figures at EUR 860 million. Our leverage measures as net debt-to-EBITDA ratio increased to 2.4x on a like-for-like basis. Our cost of debt reached extraordinary low levels, maintaining its reduction path to 1.5%, still marking historical minimum and the most competitive financing cost of European integrated utilities. Sustainable finance accounts for 57% of total gross financial debt, a significant progress from 45% in full year 2020. And now moving to Slide 20. Let me now hand over to Pepe for his final conclusions.

Okay. Thank you, Luca. To close this presentation, on Slide #20, I would like to share some final remarks on our performance during these 9 months 2021. Despite the complexity of the scenarios in this year, in terms of adverse operational context, we have managed to achieve an EBITDA of EUR 3.1 billion impact on nonrecurring items. We are in a position to feel that we are on track to achieve the target set for 2021 based on further managerial efforts. We are aware of the difficulties that many customers are facing due to the high energy costs. And therefore, we continue to be open to deal with the administration to find the most efficient solution for this conjunctural context. The integration of ESG values at the very core of our strategy has saved the way we are -- we interact with all of our stakeholder from the early adoption of more ambitious emission reduction target in 2030, the increase of financial instrument of renewables, the contribution of the economic and social development of communities to the electricity supplied to vulnerable customers. Indeed, we -- very recently we have been included in the AAA rating category, a notable achievement. And ladies and gentlemen, this concludes this 9-month 2021 result presentation. Thank you very much for your attention, and we are ready to take some questions.

Okay. Thank you, Pepe. Thank you, Luca. We are now open to answer all the questions you may have.

[Operator Instructions] I will now hand the floor back over to Ms. Mar Martinez.

Okay. First question comes from Harry Wyburd from Bank of America, Merrill Lynch.

I've got 2, and I'll keep it to 2. So firstly, just on the gas clawback changes in the 26 of October Royal Decree. And can you just give us a sense for what you thought the impact of that gas clawback was going to be before the modifications for the government? And then what you think the impact will be after just to give us a sense of what that modification means financially? And then an add-on to that would be, do you expect any further changes to the CO2 clawback tax as well? And then the second one is just on policy hedging. So my perception from when you went through the slide is that it looks like you made some significant gains in the third quarter, specifically on commodities hedges. So I wondered if you could just give us exactly how much contribution from those hedges came in, in Q3? And then just help us a bit to understand about the cash flow relating to those hedges. Are they -- Are they cash settled? Have they been reflected in your cash flow at the end of this quarter because obviously, the FFO has come down quite significantly. So just trying to understand what those hedges mean for cash.

Okay. Thank you, Harry. I would say, and then I will give the word to Luca Passa that yes, you're right, really, we have taken into account the last Royal Decree, which it was withdraw the drawback of the gas increase just because we have our -- all our own production sold with 1 or 2 years before the delivery of this energy. And you are right, we have improved something around EUR 110 million. And also, we have some mark-to-market due to our hedge in the commodities mainly Brent and CO2. But could you, Luca, explain a little bit?

Sure. Thank you, Pepe. Regarding the gas clawback, let me say, if there were no modification, the impact for us at gross margin there would have been EUR 110 million in the 9 months of this year. So for the 2 weeks of September in which that we will have applied. And for the future, according to modification, we do not expect any impact from this measure. Regarding the second part of this question, further changes expected on the CO2 clawback. As mentioned by Pepe in the presentation, we basically expect a similar, I would say, treatment of this clawback or levy on CO2, where exemptions comes when you have fixed-price contracts with customers as well as the introduction of pool price floor. And you know that this basically bill is through urgently basically procedures in the parliament. And there's been already 5 parties making amendments to this bill according basically to these changes. On -- basically, the second question, the impact of mark-to-market on commodities hedging. Let me remind you that this commodities hedging is part of how we hedge the short position basically throughout the year. So our long position on Brent, CO2 and some other commodities references, the impact for the full 9 months is positive on power for about EUR 300 million. And obviously, this plays negatively in the working capital evolution. So when I refer to the mark-to-market negative in the working capital evolution was the mark-to-market on power as well as the mark-to-market on gas, which has been positive in these 9 months for about EUR 110 million.

Thank you, Harry. Next question comes from Alberto Gandolfi from Goldman Sachs.

I'll stick to my question -- I'll stick to 2 questions. One was just asked by Harry. So the first one is I'm a bit intrigued by this pool price floor because France has been trying to achieve that for a couple of years and the European Union was not particularly keen on that. So I was wondering, one, how would you estimate that? And part of the same question. There has been a discussion about long-term contracts from hydro and nuclear. Can you tell us, please, where do we stand on this debate? Is it still a viable option? And what price should we be thinking about in terms of signing long-term contracts from hydro, nuclear? The last question is on the one-offs. So please Luca bear with me, but I have accounted for the 180 -- so let's say, close to EUR 190 million for CO2, close to EUR 50 million for the hydro levy, which were already disclosed in the H1, nearly EUR 300 million derivatives. So you have about EUR 530 million positives. I guess my question is twofold. One is, is there anything -- any negative I should think about here? Or this is it. Then there is a little bit more in the financial expenses, another EUR 80-something million. And so the question, A, would be, is that correct? And question B would be the EUR 127 million in the non-mainland, is it a one-off recovery for last year mismatch? Or is what you reported from mainland right now a proper run rate on that division?

Okay, Alberto, let me say you -- regarding the second question, the long term on the hydro and nuclear. As we have commented on in others presentation, what we have said is that the operation -- operational cost of the nuclear is something around EUR 47 -- EUR 45, EUR 47 per megawatt hour. And if we take into account the investment and a reasonable remuneration of the capital then we will reach something around EUR 57, EUR 58 per megawatt hour. With regard to the hydro, we are talking about EUR 60 per megawatt hour. Let me say that around EUR 22 per megawatt hour are taxes included in these cost. And then, Luca, if you want just to answer the rest of the question, please?

Yes. So when it comes to question 2, Alberto, so you're right. At the gross margin level, the nonrecurring positive effect is EUR 188 for CO2, EUR 48 million for hydro and is at gross margin level, then below EBITDA on the financial expenses line we have EUR 70 million for both of them. It's about EUR 10 million for the hydro and the rest is almost EUR 60 million for the CO2. You are right regarding the positive mark-to-market, it's about EUR 300 million. So this is basically where we are as of the closing of September. As I said, the mark-to-market basically will come to 0 as all the positions are netted towards year-end. So that is an effect that you won't see basically in the fourth quarter or will revert in the fourth quarter. And then when it comes to non-mainland, the evolution is actually includes, as I said, about EUR 85 million of Brent and CO2 hedging that actually are against our electric short position for EUR 85 million. Therefore, you need to basically detract this EUR 85 million at least in the 9 months in order to have a recurring gross margin evolution when it comes for the island.

Okay. Next question comes from Enrico Bartoli from Stifel.

First of all, the first one is related, I would like to go back to the CO2 clawback. So you commented that possible amendment will be discussed. But if you can give us a figure on the impact that can be expected in 2022 from the measure of how it is proposed by the government in the last version? And yes, some comments on how this could be modified would be definitely welcome. Second question is related to the evolution of working capital. If you can give us a bit back the details that you gave during the presentation. And if you can elaborate on the evolution that you expect in the fourth quarter? And maybe a guidance for the net debt that you expect for the end of the year. And last one is on the closing remarks. You say you are on track to achieve the 2021 target. That means that you think that also some managerial action would manage to offset the difficult market environment in the fourth quarter and then the EUR 4 billion EBITDA target for the year is still on track.

Enrico, let me say, trying to answer the last one. What we have said is that we are in a condition to affirm that we will reach this -- our guidance, that is the EUR 4 billion EBITDA and the EUR 1.7 billion net income. When we have said that we will continue with some managerial action is that because we know the best context in which we are operating. And within it, not easy. We are very proud about what we have reached in the third quarter. But we are aware that the best condition will continue in the future. And then as we have done in these 9 months, we will continue with managerial actions. Some of them are well on track and others we will continue looking for. And we are confident in reaching this guideline. And then Luca, if you want to answer the rest?

Sure. When it comes to the CO2 clawback estimation, Enrico, let me basically say that we would like to avoid to give any estimation given there is still basically through a parliamentary proceeding and the modification could be material as we see on Royal Decree 17. So I don't think it's worthwhile really to basically give an estimation there. Let me say that the modification that we are expecting regarding this potential new bill relates to the exemption of fixed price contracts with final customers similar to what has been already basically modified for the gas levy as well as an introduction of a pool price floor. And let me say that there have been, as I said, 5 parties already basically putting forward written amendments to this draft bill. When it comes to the evolution of working capital, basically, let me restate the impacts that I mentioned on Slide 18. So basically, this is affected in terms of FFO, the working capital specifically, by the increase of the net balance of receivables in payroll accounts for more than EUR 700 million as a consequence of collection delays related to the recently enforced Royal Decree on access tolls and charges, which came into force in June. This only affects for more than EUR 400 million and this impact should be recovered by year-end. There's still noncash items related to the CO2 and hydro canon that is more than EUR 200 million in terms of the impact on working capital and higher inventories for about EUR 150 million. Also the evolution of derivatives mark-to-market and C02 rights, which amount to approximately EUR 500 million in working capital at the closing of September, partially offset by lower other noncash provisions for about EUR 150 million. So these are the effects that are affecting our working capital and others in the closing of this period at 30th of September. Now the evolution, as I mentioned, especially for Royal Decree 17 will be worse, i.e., we will be basically being affected by the lowering of tolls and basically the fiscal measures that have been introduced by Royal Decree 17 between now and the end of the year. So at the moment, what I can say in terms of net debt estimation for year-end that we're going to be approaching EUR 11 billion of net debt at year-end. And obviously, this worsening of the working capital will be recovered in the first months of 2022.

Okay. We move to the next question from Javier Suarez from Mediobanca.

3 questions remaining. The first one is more on the guidance. So the latest guidance of the company is net ordinary income of EUR 1.7 billion. And you have said that the EBITDA by end September is -- had the contribution of some one-offs. So can you clarify that this EUR 1.7 billion of net ordinary income that you are guiding for does not include this one-off that you have been accounted for until end September 2021? That would be the first question. The other 2 questions are related to the scenario and also political and regulatory discussion. The first question is on the -- your lack of no participation in the last renewable energy auction in Spain. If you can clarify or share with us the reason for that. What do you intend to be the strategy for the next auctions, renewable energy auctions in Spain? And the third question is on the publication by the local press that the government may approve next week a new decree linking regulated and industrial tariff to renewable energy cost, what would be Endesa's position on that proposal.

Okay. Thank you, Javier, for the question. Let me try to answer the second and perhaps the third one. With regard to the political and regulatory discussion and our no participation in the renewable -- in the last renewable auction, I have to say that the only reason we did not participate in that is that we have decided to focus our strategy towards the promotion of our own generation used to supply our customers in the long term given our current short position. Instead of going to auctions with our project, our plan is to build new renewable plans to offer the energy to our customers through PPAs. Our decision was not due to any question of legal uncertainty, but because we need to aim our resources to serve as I have said our clients. We consider the natural hedge of our renewable development with our supply activities as one of the key ways of growing and creating value. With regard to the link between the regulated tariff and also the index for the industrial consumers, I should say that, well, we don't know what is going on. But this is one of the proposals that we gave to the government, just because, as we have explained, if you take into account that in the production side, we have something around 80 to 90 terawatt hour link to the spot price, then you have 30% to 35% customers' prices linked to these very high pool prices. Then what we think is that if this is regulated -- I'm talking about the renewable generation and waste regulated production. You know that these production have the guarantee just to obtain the 7.4, 7.1 regulated remuneration. So it should be adjusted in the year 2023. So we think that in this exceptional situation, it would be helpful for all without any pain to anyone just to advance this regulation and then to use more normal, let's say, prices maintaining the profitability of this generation and dedicating it to these regulated customers and industrial customers. But having said that, we don't know exactly what's going on. We think that, yes, because what we have here about it's going to be a solution, this is possible, just to obtain this solution for the future. And exceptionally, let me say, perhaps for the year 2022, which is the most difficult, tough year that we are focusing.

And for the first question, the guidance obviously includes nonrecurring positive one-off, both at EBITDA level as well as below EBITDA, i.e. the EUR 70 million at financial expenses charge.

And now we have Jorge Guimarães from JB Capital. I think that we have lost Jorge Guimarães. Probably, we can skip to the following one. That is Javier Garrido from JPMorgan. Javier, can you hear me? Sorry, I think we have some technical issues, please, if you can stay on the line. Just one second. Javier, can you hear me, please? I don't know what is happening, but we cannot hear you, Javier. Probably, if we try with the following one, Antonella. Antonella Bianchessi from Citi. I'm very sorry, but we cannot hear you, probably after the conference call we will contact you and try to address all the questions you may have. I have received some questions from the web, if you allow me, comes from Antonella Bianchessi from Citi, and she was asking about the -- during the conference, we have confirmed the 700-megawatt renewable capacity addition for this year. And the question is about the 1.4 gigawatt target for the next year, for 2022. Is this still valid considering that construction has not yet started?

Thank you, Mar. Antonella, regarding the 700 megawatts, it's confirmed, this is all capacity that will come due between now and year-end for this year. So for 2021, this is basically the target. Then for 2022, let me say that first of all, we have, in total, 2.5 gigawatt of pipeline in construction currently, in execution currently, of which 700 megawatt relates to this year and you have more than 1.8, 1.9 for the following years. For the target, let me ask you to wait up until the 25th of November because obviously this will be part of the new plan.

Okay. We have just one question left also from Antonella Bianchessi from Citi and is in relation to the mark-to-market effect if we are expecting it to entirely expire by year-end?

Thank you, Mar. Antonella, as I said, we expect this mark-to-market to basically goes to 0 as all the derivatives coming to effect. We might have some minor positive impact, but nothing in comparison to what we had actually in this period of -- that we just presented.

Well, we have still 2 analysts that on the -- are pending to be -- to ask. I will try again, Manuel Palomo from Exane BNP Paribas. Can you hear me?

Can hear you well, Mar. Can you hear me?

Yes.

Okay. Yes, it's only one question, is regarding the EBITDA guidance that you gave for the full year, you're talking about EUR 4 billion. However, on the other side, you're talking about a reversal of this close to EUR 300 million positive impact of the mark-to-market of the derivative hedging. So I wonder whether you are expecting any other one-off that you will consider as recurring in the fourth quarter in order to reach the guidance. Otherwise, if my numbers are correct, you would have to do around or even above EUR 1.2 billion in the last quarter given the current market scenario seems maybe a bit too challenging.

Thank you, Manuel. This is Luca. So as I said, we are expecting basically the mark-to-market reversal in the last quarter that I mentioned before, we are expecting a fourth quarter in the region of EUR 800 million in terms of EBITDA. And this is based on the evolution of the liberalized market with about 75 terawatt hours in sales, which is lower than what we expected. For, let me say, an overall margin for the full year, close to EUR 30 megawatt hour in terms of integrated margin, which points to a fourth quarter in the region of EUR 34 megawatt hour in terms of integrated margin. So that's basically the expectation for the full year, which will obviously bring us to the EUR 4 billion in terms of EBITDA, which includes the positive nonrecurring, as I mentioned before.

Following questions from Jorge Guimarães from JB Capital.

I'm sorry if my question was answered in the meantime. This is related to the hydro canon recovery. Other players seem to be more advanced than you on this recovery. Some of them are speaking about recovering 2016 and effectively recovering all amounts paid until now. So should we expect Endesa to recover all the hydro canon paid until now? And going forward, how do you expect this tax to be treated? Will it be eliminated since it was considered unconstitutional? So this will be my question.

Let me say only Jorge that, well, there are different, different things. I should say that we will recover all but we don't have -- or we don't know exactly the timing. We will recover this tax because it would depend on the different hydro confederations in which we need just to arrive to the last approval, yet to receive that. But in any case, be sure that we will receive all this amount. And we will see if it's going to be in this year or will be in the next year, but Luca, could you explain a little bit more.

Sure. Let me just before -- just to be completely clear, we do not assume in our guidance any recovery of further hydro canon, let me say, payments between now and year-end. The reason being is that, obviously, as Pepe pointed out, we are in different levels of the basically judicial proceeding for each of the years of this hydro canon, therefore, our expectation that this might come actually in the following year rather than this year. And when it comes to, let me say, the unconstitutionality of the retroactivity, i.e., 2013 and 2014. As we mentioned, we already booked 2013. We think that 2014 tranche, which is in the region of EUR 50 million, will probably come in 2022 as every hydro confederation has to basically be positive on this recovery. And when it comes to the 2015 to 2020 and 2021, basically, there we are in different levels of proceeding vis-a-vis some of our peers. Therefore, again, we don't have any firm sentence in order to basically start recovering this money as of now.

We have now Antonella Bianchessi from Citi.

Yes. A very last question for me. And in my calculation, in Q3, you sold forward power at EUR 90, will this be subject to the gas clawback in 2022? And as I look at 2022 forward sales or you think it's going to be fine.

Thank you, Antonella, this is Luca. I mean, as I said, we do not expect basically any impact from the gas levy also for 2022 as we have already contracted at fixed price, basically all our customers, therefore, all of our own generation inframarginal generation. And in order to be sure we have filed basically the requested under the new Royal Decree that has also been basically appraised by a third party. Therefore, we are a net seller in that sense, and we do not expect to be apply any gas levy in 2022.

Okay. This was the last question of the conference. But we have received some questions from Jorge Alonso from Societe. The first one is in relation to the supply market expectation for the next year for 2022. The second one is in relation to those contracts that has to be signed at low cost. And the question is, if these contracts are mandatory in exchange of the recent Royal Decree Law. And the last question is in relation to the loan position for 2022, if we are hedged or not fully hedged.

Regarding the supply market, I would say that at least, in my opinion, we will see a less intensive competitive market in the year 2022. The reason why I have said this is that, well, what we are seeing now is with these very high pool prices, it is very difficult for many of the companies just to offer prices if they need to buy this electricity in the pool prices. As I have said, we are expecting some kind of regulation, extraordinary, I would say, but I don't know, but extraordinary regulation for the year 2022, in which we will -- or the administration, the regulator will look how to reduce this pool price. But what I have seen is that different companies are taking care about how to do or to go ahead in the future. So we will see what happens. But in my opinion, the supply market will be with high intensity as always, but not as we have seen in the last month. And with regard to the long-term contract, if we are going to be obliged, no, the only thing -- as far as I understand, is that all the contracts signed before the Royal Decree 17 went into force. And all the new conference contracts signed with -- for more than one year and at fixed price would be okay in the sense that is not going to be applied any clawback coming from the gas. And we hope -- or we think that also will be the same with the clawback of the CO2, but there is no mandatory. The only thing, and we have, as Luca has said, we have almost 100% indeed, 88%, if I remember well, hedged of our production as reasonable prices, and when I say reasonable prices is just because you know that we hedge 1 or 2 years in advance to the delivery of the energy. And then that means that we are -- we have prices around EUR 50 per megawatt hour. So we don't think -- we have lot of right. We have hedged and we have this contract signed before. And then we are not being affected by the clawback.

And when it comes to the third, I mean, we enter in 2022. I mean in regards to our production, as Pepe pointed out, we still have basically to hedge 4.4 terawatt hours. Regarding our, let me say, short position, we are going into the year fairly balanced in 2022.

Okay. There are normal questions, our team will contact you to try to address all the pending questions that we couldn't tackle during the conference. And thank you for participating, and see you in the next CMD, November 15. Thank you very much.