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. 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 25th of November for the update of our strategic plan. Thank you, and now let me hand over to José Bogas.
Okay, thank you, Mara, 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, 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 instruments in accordance with the path set forward by the European 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 non-recurring, 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 GW in the beginning of the year, totaling now more than 61 GW. Moving now to slide number 3. As commented on in the previous slide, last October thirteenth, the European Commission published its toolbox to allow the member states 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 and 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 insurance against future price spikes. The European Commission has strongly emphasized that no interventionist measure distorting the electricity market should be adopted. The Spanish government deployed a set of regulatory proposals to counteract or soften 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 the urgent bill. This piece of regulation aims to remove renewable premiums from the access tariff and to establish a funding mechanism to share 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 till the end of the year. The much more controversial Royal Decree-Law 17/2021, in force since
September 16 and running till 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 17/2021 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 a 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 reform the regulated tariff in order to de-link 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 number four, 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 TWh estimated output for 2021, 120 TWh are sold through forward contract 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 reference below EUR 50 per MWh.
This production correspond mainly to hydro, nuclear, and non-regulated renewable power plants. Production sold at the spot prices is expected to amount to 123 TWh this year, mainly corresponding to regulated renewable cogeneration power plants known as RECORE, that represents around 80 TWh and the CCGTs. On the sales side, in addition to regulated customer, those liberalized industrial customer who have freely opted for indexed price contract are suffering from the price increase, too.
For the rest of the customers who opted for fixed prices and totaling about 184 TWh, 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 non-regulated renewables is not enough to cover fixed price sales.
Therefore, a significant portion of this sale must be acquired at the 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 customers, 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 1.5 times versus the same period of the previous year, reaching 78.5 EUR/MWh, 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 the 78.5 EUR per MWh, which compare with the around 32 EUR per MWh of the last year's same period, indeed affected by the COVID outbreak. Out of these 47 EUR per MWh spike, more than 80% of the attributable is attributable to the gas price rally.
Considering current forward for year end, the average market price could reach around 101 EUR per MWh in 2021, which would compare to 34 EUR per MWh 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 MWh. We believe that this trend will gradually revert during next year as a conjuncture 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 1/4, the growth path of renewable capacity remained almost flat, but addition will boost in the last 1/4. Our target is to reach 700 MW this year. Total mainland output reached 34.4 TWh, 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 represent just 15% of the total mainland production, mostly from CCGTs. Emission free production remain as 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 growth pipeline was further expanded to above 61 GW from 39 GW announced in full year 2020, maintaining a constant effort to fit our renewable project portfolio.
Out of this growth, figure, around 12% has TSO awarded connection points, and 2.5 gigawatt 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 a 0.4% increase in the liberalized sales, with significant improvement in the SME segment and international sales. By segment, both B2C and regulated customer 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-month 2021, we recorded the loss of just 67,000 liberalized and about 180,000 regulated customers, with total power customers decreased by 2% during 2021 as a result of the competitive intensity still dominating the sector. Customers would now be looking for more favorable conditions on the liberalized market due to the extraordinary high pool prices in the period.
This, coupled with the prices scenario, forecast pointing at sustained high prices in the coming month, easing 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 9M 2020.
Concerning our energy management on slide 10, electricity sales in the liberalized business remain flat versus the previous year. The unitary integrated margin affected by the current situation fell by 15% versus the 33.2 EUR/MWh of the 9M 2020. The unitary revenue rose to 74.5 EUR/MWh, reflecting both effects in indexed 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 in force since the first 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 cost offset by the absence of the COVID impact experienced last year. Finally, short position affected by the different evolution of prices in the 2 periods marked by the tough market context versus a very positive energy management in 2020.
The unitary integrated margin of 28.2 EUR per MWh includes EUR 85 million from rain and CO2 hedging, which hasn't been booked in non-mainland business. Regarding forward sales for 2021 and 2022, price-driven output has been closed at an OTC referent of around 50 EUR per MWh. We have hedged for 2021 100% of our estimated price-driven output at an all-in price of around 71 EUR per MWh.
For 2022, hedged volumes stand at over 88% at an all-in price of around 76 EUR per MWh. This implies that only 4.4 TWh of infra-marginal 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.
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 -3% year-on-year, reaching EUR 1.459 billion, -14% in net ordinary income level.
Funds from operations 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 sets of results have been driven by the market context previously commented, mitigated through several managerial actions, as well as positive non-recurrent gains booked in the period. Moving to the detail 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 million, +4% versus 9 months 2020.
Generation and supply EBITDA increased by 1% to EUR 1,406 million. Distribution EBITDA declined by 3% at EUR 1,432 million. Finally, non-main generation EBITDA increased to EUR 287 million, +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 million, 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 cost, and the positive impact of Brent and CO2 hedging that more than compensated the lower remuneration parameters and the absence of a positive revaluation booked 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% 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 others margins amounts to EUR 2.23 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 the results of a slightly lower unitary supply margins as a consequence of higher pool price and ancillary service cost, offset by the absence of the COVID-19 impact.
The short position affected by the difference 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-Law 17/2021, as we have 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 transaction. 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 1/2 results, once part of the derivatives negatives position booked as of June have been settled in the last 3 months. Moving now to the next slide, on the evolution of fixed cost. Total reported fixed cost have reached EUR 1,403 million, aligned to last year on a like-for-like basis.
Once deducted, no recurrent 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 account 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 in renewables and distribution, due to the investment effort carried out, and by the positive effect of the coal plants dismantling provision RECORE last year, partially compensated by -EUR 21 million of lower net debt.
Net financial results were positively impacted by the financial revenues from the interest for late payment in relation to Enel's right to be compensated for the 26 CO2 clawback and the 2013 hydraulic 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 worse 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 the recently enforced royal decree on access, tolls, and charges for more than EUR 400 million. The still non-cash items included in 9 months 2021 EBITDA, mainly from the CO2 and hydraulic 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 non-cash provisions. Due to the negative effects of Royal Decree-Law 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 amounted to -EUR 1,215 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, rising 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 19.
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 regular working capital remains slightly below last year figures at EUR 860 million.
Our leverage measures as net debt to EBITDA ratio increased to 2.4 times on a like-for-like basis. Our cost of debt reached extraordinarily 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. Now moving to slide 20, let me hand now over to Pepe for his final conclusions.
Okay, thank you, Luca. To close this presentation on slide number 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, based on non-recurrent items.
We are in a position to affirm 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 cost, and therefore, we continue to be open to dialogue with the administration to find the most efficient solution for this challenging context.
The integration of ESG values at the very core of our strategy has shaped the way we interact with all of our stakeholders, from the early adoption of more ambitious emission reduction targets in 2030, the increase of financial instruments for renewables, the contribution of the economic and social development of communities, to the electricity supply to vulnerable customers. Indeed, very recently we have been included in the AAA rating category, a notable achievement. Ladies and gentlemen, this concludes this 9-month 2021 results 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.
Ladies and gentlemen, the Q&A session has now begun. If you'd like to ask a question, please press star followed by one on your telephone keypad now. When preparing to ask your question, please ensure that your phone is unmuted locally. I will now hand the floor back over to Mrs. Mar Martínez.
Okay. First question comes from Harry Wyburd from Bank of America Merrill Lynch. The line is open. Harry, please go ahead.
Hi. Good evening, everyone, and thanks for taking my questions. I've got 2, and I'll keep it to 2. Firstly, just on the gas clawback changes in the 26th of October royal decree, can you just give us a sense for what you thought the impact of that gas clawback was gonna be before the modifications by the government, and then what you think the impact will be after, just to give us a sense of what that modification means financially?
Then an add-on to that would be, do you expect any further changes to the CO2 clawback tax, as well? Then the second one is just on commodities hedging. My perception from when you went through the slides is that it looks like you made some significant gains in the third quarter, specifically on commodities hedges.
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 how the cash flow relating to those hedges. Are they cash settled? Have they been reflected in your cash flow at the end of this 1/4? 'Cause obviously, you know, the FFOs come down quite significantly, so just trying to understand what those hedges mean for cash. Thank you.
Okay, thank you, George. I would say and then I will give the word to Luca Passa that yes, you're right. Really we have take into account the last Royal Decree in which it was withdraw the clawback of the gas increase yes because we have all our own production sold with one or 2 years before the delivery of this energy. 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. 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 level 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. For the future, according to notification, 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 a pool price floor.
You know that this bill is through urgent procedures in the parliament. There's been already 5 parties making amendments to this bill according to these changes. On 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.
The main effect on 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 10 months for about EUR 110 million.
Okay. Thank you, Harry. Next question comes from Alberto Gandolfi from Goldman Sachs.
Good evening, thank you. I'll stick to 2 questions. One was just asked by Harry. 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, you know, the European Union was not particularly keen on that. 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 and nuclear? The last question is on the one-offs.
Please, Luca, bear with me, but I have accounted for close to EUR 190 million for CO2. 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 2fold. One 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 question A would be, is that correct?
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? Thank you so much for your patience.
Okay, Alberto, let me say to you regarding the second question, the long term and the hydro and nuclear, as we have commented on in other presentations, what we have said is that the operational cost of the nuclear is something around 45-47 EUR per MWh. If we take into account the investment and reasonable remuneration of the capital, then we will reach something around 57-58 EUR per MWh. With regard to the hydro, we are talking about 60 EUR per MWh. Let me say that around 22 EUR per MWh are taxes included in these costs.
Luca, if you want just to answer the rest of the question, please.
Yes. When it comes to question 2, Alberto, you're right. At gross margin level, the non-recurring positive effects is 188 for CO2, EUR 48 million for hydro, and this 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.
This is basically where we are as of the closing of September. As I said, the mark-to-market basically will come to zero as all the positions are netted towards the year-end. That is an effect that you won't see basically in the fourth 1/4 or will revert in the fourth 1/4.
When it comes to non-mainland, the evolution 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, thank you. Next question comes from Enrico Bartoli from Stephens.
Thanks for taking my questions. First of all, the first one is related. I would like to go back to the CO2 clawback. 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. 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 of the details that you gave during the presentation.
If you can elaborate on the evolution that you expect in the fourth 1/4 and maybe a guidance for the net debt that you expect for the end of the year. 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 1/4, and then the EUR 4 billion EBITDA target for the year is still on track. Thank you.
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 these 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, it's just because you know the adverse context in which we are operating.
Within it not easy, we are very proud about what we have reached in the third quarter. We are aware that the adverse condition will continue in the future. As we have done in this 9 month, we will continue with managerial actions. Some of them are well on track, and others we will continue looking for.
We are confident in reaching these guideline. Then, Luca, if you want to answer the rest of the question.
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 parliamentary proceeding, and the modification could be material as we see on Royal Decree 17. I don't think it's worthwhile really to basically give any 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 the introduction of a pool price floor. 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. Basically, this is affected in terms of FFO, the working capital specifically, by the increase of the net balance of receivables and payable 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. The still non-cash items related to the CO2 and hydro canon, there is more than EUR 200 million in terms of the impact on working capital, and higher inventories for about EUR 150 million.
The evolution of derivatives mark-to-market and CO2 rights, which amount to approximately EUR 500 million in working capital at the end of September, partially offset by lower other non-cash provisions for about EUR 150 million. These are the effects that are affecting our working capital and others in the end of this period at the end 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. At the moment, what I can say in terms of net debt estimation for year-end, that we're gonna be approaching 11 billion EUR on net debt at year-end.
Obviously, this worsening of the working capital will be recovered in the first months of 2022.
Okay, many thanks. We move to the next question from Javier Suárez from Mediobanca.
Thank you, Mar Martínez, and thank you for the presentation as well. Three questions remaining. The first one is one more on the guidance. The latest guidance of the company is net ordinary income of EUR 1.7 billion. You have said that the beat by end-September 2021 has a contribution of some one-off. 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 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 your lack of, you know, 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? The 1/3 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 costs. What would be Endesa's position on that proposal? Many thanks.
Okay. Thank you, Javier, for the question. Let me try to answer the second and perhaps the 1/3 one. With regard to the political and regulatory discussion and our non-participation 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 plants to offer the energy to our customer 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 clientes, 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 next 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 80-90 terawatt-hours linked to the spot price, then you have 30%-35% customers prices linked to these very high pool prices.
What we think is that if this is a regulated, I'm talking about the RECORE, the renewable cogeneration and waste, regulated production, you know that these production have the guarantee just to obtain the 77.4%, 71% regulated remuneration. It should be adjusted in the year 2023. 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 these of this generation and dedicating it to these regulated customers and industrial customers.
Having said that, we don't know exactly what's going on within that just because what we have here about is gonna be a solution or it's possible just to obtain this, the 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.
For the first questions, the guidance obviously includes the non-recurring positive one-off, both at EBITDA level as well as below EBITDA, i.e., the EUR 70 million at financial expenses charge.
Now we have Jorge Guimarães from JB Capital. Please, J`orge, go ahead.G No, I think that we have lost Jorge Guimarães. Probably we can skip to the following one. That is Javier Garrido from JP Morgan. 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?
Javier, the line is open. I don't know what is happening, but we can't hear you, Javier. Probably if we try with the following one, Antonella. Antonella Bianchessi from Citi? I'm very sorry, but we can't hear you. Probably after the conference call, we will contact you and try to address all the question you may have. I have received some question from the web, if you allow me.
It comes from Antonella Bianchessi from Citi, and she was asking about the. During the conference, we have confirmed the 700 MW renewable capacity addition for this year. The question is about the 1.4 GW 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 MW, it's confirmed. This is all capacity that will come due between now and year-end for this year. For 2021, this is basically the target. For 2022, let me say that first of all, we have in total 2.5 GW of pipeline in construction currently, in execution currently, of which 700 MW 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 until the 25 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 it's in relation to the mark-to-market effect, if we are expecting to entirely expire by year-end.
Thank you, Mar. Antonella, yes, as I said, we expect this mark-to-market to basically goes to zero as all the derivatives come into effect. We might have some minor positive impact, but nothing in comparison to what we had actually in this period that we just presented.
Well, we have still 2 analysts that are pending to ask. I will try again. Manuel Palomo from Exane BNP Paribas, can you hear me?
I can hear you well, Mar. Can you hear me?
Yeah. Thank you. Go ahead, please.
Okay, I'm going. Yeah, it's only one question, and it's regarding the 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.
I wonder whether you are expecting any other one-off that you will consider as recurring in the fourth 1/4 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 1/4 that, given the current market scenario, seems maybe a bit too challenging.
Thank you, Manuel. This is Luca. As I said, we are expecting the mark-to-market reversal in the last 1/4 that I mentioned before. We are expecting a fourth 1/4 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 TWh in sales, which is lower than what we expected. Let's say, an overall margin for the full year, close to 30 EUR/MWh in terms of integrated margin, which points to a fourth 1/4 in the region of 34 EUR/MWh in terms of integrated margin.
That's basically the expectation for the full year, which will obviously bring us to EUR 4 billion in terms of EBITDA, which includes the positive non-recurring, as I mentioned before.
Following questions from Jorge Guimarães from JB Capital.
Hi. Good afternoon, and 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 the old amounts paid until now. 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? This would be my question. Thank you very much.
Let me say only, Jorge, that well, there are 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 will depend on the different hydro confederaciones in which we need just to arrive to the last approval just to receive that. In any case, be sure that we will receive all this amount, and we will see if it's gonna be in this year or will be in the next year. Luca, could you explain a little bit more?
Sure. To be completely clear, we do not assume in our guidance any recovery of further hydro canon 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.
When it comes to the unconstitutionality of the retroactivity, i.e., 2013 and 2014, as we mentioned, we already booked 2013. We think that 2014, a tranche, which is in the region of EUR 50 million, will probably come in 2022, as every Hydrographic Confederation has to basically be positive on this recovery.
When it come 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. Please, Antonella, go ahead.
Yes. A very last question from me. In my calculation, in Q3, you sold forward power at 90 EUR. Will this be subject to the gas clawback in 2022? You know, if I look at, you know, 2022 forward sales. Or you think it's gonna be fine?
Thank you, Antonella. This is Luca Passa. 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 customer, therefore all our own generation, inframarginal generation. In order to be sure, we have filed basically the requested under the new royal decree that is also being basically appraised by a 1/3 party. Therefore, we are net seller in that sense, and we do not expect to be applied any gas levy in 2022.
Okay, this was the last question of the conference. We have received some question from Jorge Alonso from Société Générale. 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 costs. The question is, if these contracts are mandatory in exchange of the recent Royal Decree-Law. The last question is in relation to the long position for 2022, if we are hedged or not fully hedged. Thank you.
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 what we are seeing now is with these very high pool prices, it is very difficult for many of the companies 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.
What I have seen is that the different companies are taking care about how to do or to go ahead in the future. We will see what happen. In my opinion, the supply market will be with high intensity, as always, but not as we have seen in the last month. 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 7teen went into force.
All the new contracts signed with, for more than one year and at a fixed price would be okay in the sense that it's not going to be applied any clawback coming from the gas. 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 have said, we have almost 100%, indeed 88%, if I remember well, hedged of our production at reasonable prices. When I say reasonable prices, is because you know that we hedged 1 or 2 years in advance to the delivery of the energy.
That means that we have prices around EUR 50 per MWh. We don't think we are not obliged. We have hedged, and we have this contract signed before. We are not being affected by the clawback.
When it comes to the 1/3, I mean, are we entering 2022? I mean, regarding our production, as Pepe pointed out, we still have basically to hedge 4.4 TWh. Regarding our, let me say, short position, we are going into the year fairly balanced in 2022.
Okay. At this stage, there are no more questions. Our team will contact you to try to address all the pending questions that we couldn't tackle during the conference. Thank you for participating, and see you the next CMD, November fifteenth. Thank you very much.