EDP, S.A. (EDP) Earnings Call Transcript & Summary

Ladies and gentlemen, thank you for standing by, and welcome to the EDP's 9M Results Presentation. [Operator Instructions] As a reminder, today's conference call is being recorded. I would like to now turn the call over to Mr. Miguel Viana to begin, Head of Investor Relations. Please go ahead, sir.

Good morning, ladies and gentlemen. Thanks for attending EDP's First 9 Months 2021 Results Conference Call. We have today with us our CEO, Miguel Stilwell de Andrade; and our CFO, Rui Teixeira, which will present to you the main highlights of 9 months 2021 financial performance and an update on strategy execution. We'll then move to the Q&A session, in which we will be taking your questions both by phone or written questions that you can insert from now onwards at our web page. This call should last close to 60 minutes. I'll give now the floor to our CEO, Miguel Stilwell de Andrade.

Thank you, Miguel. Good morning, everyone, and thank you for participating. So I'm sure it's been a long week for all of you with a lot of results calls this week. So we'll try and do just a brief presentation and then turn it over for Q&A. If we go to Slide 3. So what we can see is that in the first 9 months of the year, we continue to accelerate the growth. We had the growth investments increasing by 15% to EUR 2.7 billion. We remain the third greenest utility in Europe, over 75% of our total production from renewable energy. And you'll have seen, for those of you that attended the call on Wednesday, we are planning to expand with a new Asia Pacific platform for the group out of Singapore. And I'll talk about that. We've ramped up the renewable deployments. We have 3.9 gigawatts of capacity installed or under construction. We've also accelerated our growth in electricity networks. So in Spain, the integration of Viesgo continues to move forward at a good pace and ahead of the initial plan. And in Brazil, the EBITDA growth was supported by the execution of our investments in transmission projects, greenfield transmission projects. We've also reinforced the CapEx on the distribution networks. And we've had a positive impact from the inflation updates of the regulated revenues in the recent tariff provisions. Overall, recurring EBITDA at around EUR 2.5 billion in the period, a 1% decline year-on-year, but that includes a negative ForEx impact of minus 4%. So we strip that up at a recurring EBITDA ex ForEx increase of around 3%. Obviously, the high energy prices in Europe is something that we've been talking about a lot. There's been a lot of press about this. A lot of you have written about this. It had a negative impact on the result of our Energy Management division, mostly due to an increase of energy sourcing costs, also upfront negative mark-to-market of hedging positions. Note that this should be compensated by higher unhedged operating margins in the near future. So it's a shorter-term impact, which will then unwind. Also worthy of note that from an integrated risk management perspective, part of the negative energy management performance is offset by the positive results in the hydro generation in Iberia as well as in the Supply division. So it's good to look at this on an integrated perspective. In this period, we continue to be affected by the wind resources, which are below average, as we discussed in the EDPR call. The asset rotation gains are below the amount recorded last year, although we expect more gains in the fourth quarter from transactions that we were already -- that have already been agreed and announced. We are pending the final approvals for the financial closing, so when we can actually register them on the account. Overall, net profit reaching EUR 510 million without any material net impact from nonrecurring items, and we continue on track to deliver the 2021 guidance of around EUR 800 million net income. If we move to Slide 4. I think it's worth taking a step back and saying we continue to see a policy environment which is highly supportive of the energy transition. And so for EDP, we remain completely committed to this ambition. And this is particularly relevant given the COP26, which is taking place now in Glasgow. And just looking at some of the news flow coming out of that, clearly, it is solidifying the need to elevate global commitments. Measures to fight climate change are being put forward. This is -- no one said this is going to be easy. So this is going to be something which requires a lot of steps every year, people coming together, reiterating their targets and continue to increase, let's say, the level of ambition. So I think that's also something that's relevant to note. Also, note that the Association of the Southeast Asian Nations, so ASEAN, restated their target of 23% of primary energy coming from renewable sources by 2025 versus the 14% in 2018. So this global fight against climate change, I mean, it calls for strong fundamentals. It calls for a huge growth in renewables. That was highlighted by the International Energy Agency, which came out with a report saying that you should be looking at annual global clean energy investments around $4 trillion by 2030 per year, 4x as much as the $1 trillion invested in 2020, so as to limit the global warming to 1.5 degrees by 2050. So I mean these are obviously staggering numbers. In Europe, European Commission's toolbox to tackle the increase in energy costs. It has reinforced the need to deploy renewables, to develop energy efficiency solutions and also to continue to build up grids across the continent. So this will depend also on the deployment of the EUR 750 billion from the European Next Generation funds. And that process is now moving to the stage of application of projects at the national level. And I'm sure we'll have more visibility on that, and we'll talk about that during 2022. In the U.S., 2 legislative packages: the first, the $1.2 trillion infrastructure bill and also the more recent $1.75 trillion Build Back Better framework. This includes good visibility, which is now pretty consolidated, of fiscal incentives for the clean energy investments, namely the 10-year ITC and PTC extensions and tax credits, total amount of $320 billion. So we truly believe that, that will support the renewables medium-term growth targets in the U.S. Okay. Moving on to Slide 5 and just talking a little bit about Sunseap. So we announced Sunseap -- the acquisition of Sunseap on Wednesday, and we explained that in depth on the EDPR conference call. We really believe that this solidifies the status of EDP as a truly global clean energy player. It allows us to expand our presence into the Asia Pacific region. So it becomes the EDP's fourth regional hub after Europe, North America, South America and now Asia Pacific. And just a note about Sunseap, it's a solar-focused player. So it's present in 9 Asian markets. It's worth highlighting Singapore and Vietnam. It's got strong asset base. It's got capabilities in solar DG, but it's also expanding operations in centralized solar. As a strategic acquisition, it's got an implied EV of EUR 870 million. And it gives us around 700 megawatts of secured capacity. So 540 megawatts of operational or under construction capacity and an additional 130 megawatts already contracted. Very young assets, under 2 years old, 20-year contracted revenues, 76% with PPAs and 24% regulated with an average price of EUR 75 per megawatt hour. So low risk, stable, long-term cash flows, fully aligned with our EDPR strategy. And a pipeline of around 5 gigawatts, which will support the strong growth over the next years. So clearly, here, price includes not only the operational and under construction assets, the already contracted assets and also the pipeline that we expect to develop over the next couple of years. Moving on to Slide 6. So here, just taking a step back and looking more globally to EDPR. We continue to accelerate growth with 2.5 gigawatts of gross capacity added in the last 12 months. 8 gigawatts so far secured, so 75% of our target capacity additions until 2023. And as I've mentioned, 4.1 gigawatts of PPAs, in which we are in advanced stages of negotiation. So we've been able to secure this capacity with attractive returns and in line with our investment criteria of around 1.4x WACC or above 2% spread. So all in all, spread over WACC for the 8 gigawatts secured is roughly 300 basis points. And from a risk perspective, we continue to focus investments on long-term contracted assets and contracted cash flows, which represent typically around 60% of the NPV of the project. This is absolutely key for the asset rotation strategy. And that's, I believe, why investors come to us and like the portfolio that we put together. It's just long-term predictable cash flows. If we move forward to Slide 7. So we continue to be well protected from a CapEx cost inflation. We've discussed that in previous quarters. In terms of material exposure, it's limited to around 10% of our secured capacity. For new projects, we are seeing the PPA market and the auctions price adjust to a sector-wide increase in CapEx. So from that perspective, it's not impacting our competitiveness when bidding for new projects. And so the return thresholds are being preserved because everyone is obviously feeling the same impact. In relation to supply chain, our scale, both in the short- and medium-term procurement of equipment, allows us to continue to have strong long-term relationships with our key suppliers. And so we continue to actively monitor and manage any supply chain disruptions, and that's something certainly on the wind side that we have a very good feeling for. And on the solar side, a little bit more uncertainty, but also something that we are managing. On Slide 8, the asset rotation. So 9 months into the business plan, we have EUR 2.3 billion of proceeds, transactions already agreed. This represents 30% of the target from 2021 to 2025 plan. So good solid execution by our teams in such a short period. Importantly, it is a great performance in terms of the multiples achieved. So it links back to that discipline in terms of investment returns and also in terms of the profile of these assets. So clearly, strong appetite from the private markets for these type of renewable assets. Overall, we are on track to deliver the capital gains north of EUR 300 million this year. The final amount, as I said, will depend on the exact timing of the regulatory approvals and the closing of the transaction. If we move on to Slide 9. So talking a little bit about the Portuguese electricity distribution. On October 15, as usual, we had the release of the proposal by ERSE for the 2022 to 2025 regulatory framework for electricity distribution remuneration. So a 4-year period. In the past, it used to be 3 years. It's moved to 4 years. The proposal establishes a slight decline of regulated revenues in '22, around EUR 10 million year-on-year, which results from the decrease in around 45 basis points of the rate of return on the regulated asset base. So it's now at around 4.3%, which is lower than in other neighborhood countries. However, this is on a sliding scale with a floor of around 4%. And this rate of return can change based on the evolution of the Portuguese 10-year bond yield. So there is a natural hedge on the trend of the long-term interest rates. So if they go up, there is the adjustment to this rate of return to increase. So limited downside, and depending on how bond yields go in Portugal, it will follow that bond yields up. The regulatory framework proposed also provides an annual update to inflation, namely to the GDP deflator. This is corrected by an efficiency factor of 0.75%, which is applied to the regulated asset base of around EUR 2.8 billion and also the accepted OpEx and CapEx base. So overall, despite the low rate of return, we believe that the limited change on the regulated revenues, the medium-term indexation to long-term yields, the update to inflation of this reinforces the medium-term visibility of the remuneration of this activity. Okay. Talking about still Portugal but talking about the regulatory framework also on the -- let's say, for the consumers. So the Portuguese regulator presented a proposal with a 0.2% increase for 2022 end-user tariffs for residentials and SME segment. This is a remarkable achievement if we consider the strong increase of the wholesale electricity prices, both in the spot and forward markets. The main explanation for this -- and this is certainly a contrast to some other markets. But the main explanation for this here in Portugal is that there's been a significant volume of generation contracted at stable feed-in tariffs with an average price of around EUR 90 per megawatt hour. So what was previously in over cost ends up being a surplus. These generation volumes, mostly from renewables, more than cover the consumption in the residential and SME segments in Portugal, which means that the residential consumers are the off-takers of the feed-in tariff. So we have a slightly long position in the wholesale electricity market, which is benefiting, let's say, and allowing the tariffs not to increase. So the spread inversion between feed-in tariffs and wholesale prices enable a 52% reduction of grid access tariffs and an overall 50% system debt declined between 2020 and 2022. I think this is really worth highlighting because certainly, I know one of the things that sometimes we get asked is the sustainability of the overall electricity system debt. And you can see a very significant decrease in the debt this year to around EUR 1.7 billion. Moving on to Slide 11 and talking about electricity spot prices. I mean these are obviously extremely high, and you're all aware of that. There is a strong backwardation of the forward prices. So we see an increasing demand from corporate clients for longer-term contracts to smooth out basically this short-term spike and lock in these longer-term sort of lower prices. The recent spike in energy prices means that most consumers, especially the industrials are looking for ways to reduce exposure to volatile energy prices. And so we've experienced an increase, a significant increase of multi-annual contracts, which gives long-term stability to selling prices. So currently, we have hedged around 50% of the expected base load generation for 2022 to '25 at an average of EUR 60 per megawatt hour. So this is an upside to the average selling price of EUR 47 per megawatt hour, which we had assumed in the business plan. So I think this is something which is worth highlighting. Moving on to Slide 12, a little bit about Brazil. So significant developments in Brazil's portfolio. We talked about the reshuffling. We've given visibility on that. I think it's good. It shows value crystallization of some of the assets there and also improves the growth prospects for operations in Brazil. So concrete on -- concretely on the transmission asset rotation strategy. In this quarter, we bought a controlling stake in CELG transmission with almost 760 kilometers of lines in the region of Goias. We expect strong electricity demand growth in the coming years here. And we sold roughly 440 kilometers at a very attractive multiple, at a higher multiple than what we're buying. So we've also added 2 greenfield transmission projects, one in the secondary market and another in the latest regulatory auction. So I think it shows also the value of doing some asset rotations in the Brazilian portfolio. In the meantime, we've also engaged in advanced negotiations for the disposal of roughly 0.5 gigawatts of hydro assets, and we've talked about that. So it's aligned with the commitment to reduce hydro exposure in Brazil. Finally, Brazil also announced an additional amount of its share buyback program, up to around 4% of its share capital, with the objective to optimize capital structure and maximize shareholder value. Moving on to ESG and just before I turn it over to Rui. So first, absolutely committed to ESC excellence. We've been a top performer across the different metrics, internationally recognized in the ESG rankings, and some of you will have seen the recent event we did on this theme. Both EDP and EDPR maintained top 10 positions in the recent rebalancing of the S&P Global Clean Energy Index. In terms of our developments towards the energy transition, 76% of EDP's total generation now comes from renewables within the first 9 months of 2021. Revenues aligned with the EU taxonomy rose 66%. So it gives visibility on achieving the 2025 target of 70%. So not only have we committed to ESG excellence, but we've also been focused on providing transparency regarding EDP's ESG profile. So an example of that was our ESG Day that we did. Hopefully, that enabled us to show what our strategy for ESG is for the coming years and also the top management's engagement with all of these matters, so at all levels. With that being said, I'll pass over to Rui Teixeira for a more detailed breakdown of the 9 months results. And then I'll come back to have some closing remarks. So Rui?

Thank you, Miguel, and good morning to you all. So now let's come to EDP's performance for the 9 months 2021. And let's move to Slide 15. So recurring EBITDA decreased 1% to EUR 2.5 billion. If we were to exclude the ForEx impact, the performance would be a 3% increase year-on-year. The recurring EBITDA from Renewables platform was down 4%. This is penalized by weaker wind resources for asset rotation gains when we -- of course, we compare it to last year. Adverse ForEx impact of EUR 95 million, mainly due to the 11% depreciation of the Brazilian real versus euro. On the positive side, this performance in wind and solar was partially offset by the good performance in the hydro. Also on the positive side, electricity networks recurring EBITDA increased by 43%, benefiting from the integration of Viesgo, which had a EUR 148 million EBITDA contribution. And in Brazil, the inflation update of regulated revenues and the execution of the transmission growth. On the client solutions and energy management platform, this one was penalized by the sharp increase in the energy prices in the wholesale markets, which implied higher energy sourcing costs as well as negative gas mark-to-market impact on hedging contracts. This also compares to an exceptional positive performance last year. So moving on to Slide 16. EBITDA from EDPR declined 15% year-on-year, so down to EUR 917 million. Despite this 13% increase of installed capacity, EBITDA was penalized by overall weak wind resources, so that's 5% below average; lower asset rotation gains when compared to last year, representing around EUR 49 million decline year-on-year; lower average selling price, this reflects the more competitive projects added to our portfolio in the last 12 months; but also the negative impact in the U.S., namely in the first quarter from the polar vortex that we've discussed extensively, and in Spain due to weak resource and regulatory and some financial hedges that we have detailed in the EDPR conference call. If we move now to Slide 17. Adjusted by the change in consolidation perimeter, the hydro recurring EBITDA increased 25% year-on-year to EUR 515 million. In Iberia, EBITDA increased EUR 73 million year-on-year, impacted by a 12% increase in higher production. And of course, this is on the back of very strong hydro resources. The realized price increased 13% to EUR 61.40 per megawatt hour following an increase on the premium of realized prices over the base load and higher revenues from ancillary services and, of course, in general, higher pool prices. The results were also positively impacted by the reversion of some hydro levies in Spain in the second quarter following a court decision, which impacted us positively by EUR 47 million. In Brazil, the hydro EBITDA increased 30%. So despite the current hydro crisis in Brazil, performance was well supported by the hedging strategy in place. We have more energy allocated towards the second half of the year. And the hydro Brazil's EBITDA was also positively impacted by the third quarter -- in the third quarter, sorry, by EUR 26 million positive impact from the extension of hydro concessions that we also discussed last year. If we move now on to Slide 18. These first 9 months of '21 were marked by a strong performance of the Networks platform with a recurring EBITDA increasing 43% year-on-year. In Iberia, EBITDA amounted to EUR 682 million. That's a 41% improvement comparing to 9 months 2020. And this is happening on the back of the Viesgo integration, of course, positive impact from the reversion of a provision on regulated revenues in Spain as well; and EUR 21 million increase in Portugal due to OpEx savings as a result of the gradual increase in digitalization, specifically the rollout of smart meters. In Brazil, EBITDA went up by 48% to EUR 266 million. That's a 66% increase also in local currency. And this is mainly due to the increase in volumes of distributed electricity, they are up by 9% year-on-year; the positive impact from inflation indexation on distribution annual tariff updates; lower losses from the sale of the wholesale -- wholesale market of electricity volume surplus, the so-called overcontracting. So all in all, EBITDA was positively impacted, very positive impact on distribution. And in transmission, there is a positive impact from the full commissioning of the transmission lines. Let's move to the last platform, client solutions and energy management. So here is where we have an underperformance. As you know, EBITDA declined 66% year-on-year also compared to an exceptional growth or strong performance in the 9 months 2020, which still included a positive EBITDA contribution of around EUR 37 million from Sines coal plant, which, as you know, was shut down at the end of 2020. In Iberia, the last 2 quarters were particularly challenging. The energy management activity was penalized by the sharp increase in energy prices to record high levels, which increased energy -- our energy sourcing costs and also imply the negative mark-to-market impact from hedging contracts for future periods. The MTM losses are mostly noncash and are expected to be offset by higher operating margins in the near term. On this quarter, these negative impacts were partly offset by the increase in client service penetration, which we expect to keep increasing since the energy efficiency is becoming more and more relevant in an environment of surging energy prices. In Brazil, I think it's also worth mentioning the positive impacts regarding the high availability of Pecem plant, our coal plant in Brazil, and a positive mark-to-market on new client contracts. So if we move now to Slide 20. In this context of very high energy prices in 2021, I think it's important also to not only show the detail -- share the detail but highlight the value of our integrated portfolio. So during this third quarter, the energy sourcing costs were higher, mainly on the back of a slight short position to satisfy the needs of our energy supply activities. But this was more than compensated through our higher hydro production and higher realized price. Additionally, we have optimized our thermal generation assets as a physical hedge. So basically, you see that some of these brings to a very neutral position in terms of the integrated portfolio. But also we have in this period close to EUR 110 million of noncash mark-to-market in financial hedging position, mostly gas hedges, that this will imply higher operational margins going forward. But that's the sum of how it is impacting our third quarter results, but again, highlighting the value of having this integrated portfolio. Now let's move to Slide 21 on financing costs. So if we adjust by one-off costs, and those are related to the repurchase of outstanding bonds, the acquisition of a minority stake in Soto 4 CCGT in Spain and ForEx differences, adjusted net financial interest fell by 6% year-on-year. These are driven by the decline in average net debt that's around EUR 500 million and 10 basis point increase in average cost of debt. This is mostly driven by the increase in the average cost of Brazilian real-denominated debt. That represents around 12% of our total debt. And so this saw a 170 basis point increase in average cost to 8.6%. I think it's important to highlight as well that we have been issuing green hybrids. The one that was issued this quarter really solidifies our share of green financing with green bonds now representing 39% of EDP's total financial debt. I believe that really going to this -- resorting to this cost competitive funding will contribute to lower recurring net financial costs over the next quarters. On net debt on Page 22, it remained fairly flat, decreasing around EUR 0.1 billion to EUR 12.1 billion. This is impacted by recurring organic cash flow, EUR 0.3 billion, strong penalized by EUR 0.5 billion increase in working capital. This is related to the proactive anticipation payment to suppliers that we discussed in the beginning of the year in order to optimize treasury management given the context of the financial liquidity but also related to the recent increase in energy prices in terms of collaterals and margin calls. Also EUR 0.75 billion relative to our annual dividend that was fully paid in April, EUR 1.7 billion of net expansion investments following the acceleration in the build-out of our activity with EUR 2.3 billion expansion investment and the anticipation of some deal payments to fixed asset suppliers of EUR 0.4 billion. This was also partly offset by 0.6 billion proceeds from the asset rotation deal that we concluded in U.S. already this year. We had also a positive impact from the EUR 1.5 billion proceeds from EDPR capital increase in April and around EUR 1 billion relative to 50% of the EUR 2 billion hybrid bonds that we issued over 2021. And finally, the effects of exchange fluctuations have a negative impact of EUR 0.2 billion on a net debt. And just to finalize on my side on Page 23. Overall, reported net profit reached EUR 510 million. This represents a 21% increase year-on-year. Adjusted by one-off impacts in the operations disposed in Iberia in 2020, the recurring net profit decreased 2% year-on-year, benefiting from improved financial results and lower minority interest, reaching the same EUR 510 million as net nonrecurring items have a 0 contribution to net profit in these 9 months 2021. With this being said, we continue to be very committed with what's ahead. And I take, again, also the opportunity to thank you all for your time today. As Miguel said, it definitely has been a very intense week. So Miguel, I'll pass now the word to you for closing remarks. Thank you.

Okay. Thank you, Rui. So just to summarize perhaps some of the key points on the call. First, we announced the acquisition of Sunseap. I think it provides us with a fantastic growth platform in a rapidly growing region. It really solidified, I think, our status as a global clean energy player. And I think it has a fantastic strategic fit. The pipeline. So it's got a fantastic pipeline. It's got a great track record. We've got fantastic management. It's got a good footprint in fast-growing markets. And so it will allow us to tap the massive Asia Pacific growth opportunity. So I think definitely a good fit. It contributes to the execution of our growth plan. It's got a focus on renewables, over 8 gigawatts already secured with long-term contracts with attractive returns. So just to reiterate, 75% of our target for '21 to '23. Okay. We've also seen Portugal's new regulatory framework this quarter, which keeps flat residential tariffs, keeps a very strong decline in the system debt, gives medium-term visibility on the regulated returns and distribution. And so given all the circumstances, given all the stress going on in the market and the high volatility of the wholesale electricity prices, I think this is extremely positive news coming out of Portugal and sort of certainly eliminated a lot of uncertainty that might exist. Recent surge in wholesale prices. They have created the conditions to extend the maturity of our contracts with clients. So the baseload production between 2022 and '25 is now approximately 50% hedged at an average of EUR 60 per megawatt hour. So above the 47% -- EUR 47 per megawatt hour, which was assumed in the business plan. I've said it before in this presentation. I just wanted to reiterate this number because I think it is important. We've also engaged on Brazil's portfolio. As we've talked about in the past, we said we're going to do it. We're showing concretely now the transactions coming through in terms of the portfolio reshuffling, decreasing the exposure to hydro generation, growing the electricity networks asset base. And I think that's coming through, certainly in terms of the value of Brazil. So highlighting that has been a commitment that we've done and something that we're following through. And as a result of that, so we showed the asset rotation in Brazil, the acquisition of CELG-T and disposal of 3 transmission lines to Actis, buying and selling at attractive multiples and at the same time, advancing negotiations to dispose of around 500 megawatts of hydro assets in Brazil. So expect to probably have signing before end of the year. We're certainly working towards that. So all in all, 9 months driven by the growth we saw in the networks, good performance in hydro, offset by a weak quarter in wind and energy management. It does show though the value of the diversification of our asset base and also, I think, a good risk management because we're probably living through some of the most chaotic and uncertain times in terms of volatility in the market. And I think the fact that we are continuing to move forward through all of this shows really the risk management that we've been doing. Having said all of this, we reiterate the confidence in terms of delivering the '21 financial guidance. So just like to leave it there on that note. Thank you for the results, and we can now move to Q&A.

[Operator Instructions]

I think we have the first question from the line of Harry Wyburd from Bank of America.

Three questions from me, please. So first one is on working capital. Actually -- it's actually less of a question directed at EDP specifically, but I just wanted to understand what you're seeing because a lot of your peers have reported some pretty amazing increases in working capital, specifically in the last quarter. So I noted that actually, your working capital didn't increase by that much. I think that you put about 0.5 billion increase in the presentation today, and that was already 0.4 billion at first half. So it doesn't look like you've seen a big increase in working capital in the third quarter. But I wondered if you could just elaborate a little on what you're seeing in working capital just at an industry level because I'm just trying to understand whether increases in working capital are something that we should be sort of braced for more widely across the sector after some of your peers reported increases. That's the first one. And the second one is specifically on energy management and hydro in Iberia. So you mentioned on Slide 20 that the overall net impact of -- I guess we could call it the gas crisis impacts and all the hedges and so on, high spot prices, is about EUR 110 million for the 9 months. And then you mentioned you're hedging your power at about EUR 13 a megawatt hour higher in 2022 to '25. So on sort of just below 10 teras of hydro output, that's another kind of EUR 100 million or so. So would I be right to be thinking of about a EUR 200 million kind of EBITDA year-on-year improvement next year on the current outlook for those businesses? And then the final one, and I apologize for asking this because you must be fed up with this question coming up every single time, but I think it's still very important for investors. So the -- I guess the Iberian assets implied valuation still is very low relative to, I guess, the intrinsic value reflected in peers. So I wondered if there had been any update in your thinking there. And maybe just asked specifically, I wondered on the hydro assets that sit within the holdco, is there a more natural fit both from a valuation and an industrial standpoint for those assets to be perhaps that more closely with the wind and solar assets, I guess, valuation-wise, obviously? But also industrially, pump storage hydro is obviously a natural fit for intermittent renewables. So I just wondered if there's any update on your thinking on that. And sorry for the long questions.

Okay. Harry, it's Rui here. So I'll address the first 2, and then I'll hand over to Miguel for the third one. So in terms of working capital, so basically, what we have in our books right now until this -- within this 9 months is, well, first of all, this -- the advanced payments we did to suppliers in the beginning of the year given the liquidity that we have, the excess liquidity. And then more recently, given the high prices in power markets, I mean, everything which is related just to the payment conditions, they basically increased working capital just given the unitary price is higher. But also, we have an impact from cash collaterals that we are called upon or margin calls. Given the hedges that we have in place, particularly the ones in the market, that -- of course, they require us to post this additional collateral. I would expect, everything else being equal, that by Q4, we actually should be reducing. And that has to do with the fact that the higher power prices are creating a surplus in terms of the -- as you know, the regulated -- through the regulated retail business, we are -- they are buying from the renewables in Portugal at the tariff which is below the current market prices. So there is a surplus being generated there. And I would expect that to have a positive impact in Q4. So actually, I would expect that we would improve the working capital until the end of the year. And with regard to second question, I mean I would expect that yes, there will be some positive impact in 2022. I would prefer not to not to comment upon the number right now. But yes, I would expect some improvement coming from the hedges in hydro. Miguel?

Yes. Thanks, Rui. Harry, listen, you're right to ask the question. We ask it ourselves. So definitely no problem in asking it. The answer though is probably the same that you've heard in the past. I mean clearly, when we look at what transactions we've done over the last 12, 18 months in the hydro, in the distribution with Viesgo and the sale of the CCGTs and the customers, clearly, we think that those are good references. I mean by definition, they are good references for the intrinsic value of some of those assets. So that is something we would certainly point to in terms of what you can use in terms of the read across. I mean in terms of hydro and EDPR, listen, it's one scenario definitely. We can continue to explore other additional scenarios. So it is something we are monitoring, and we continue to think about whether there's any additional move we should do or could do. Obviously, we do continue to provide as much information. And so thank you for the question because it does allow me to reiterate the answer, which I think is obviously quite straightforward. I mean sometimes you don't need to do transactions. You just need to point to evidence that we have, which is very clear as to what is the implicit values of some of these assets. I'll just add one additional point, which I think has come out over the last couple of weeks. And I think it's very relevant also in relation to the intrinsic value of the Iberian asset. And that's that we have a lot more visibility now on the regulation in Portugal and Spain. I mean now with the proposal by ERSE in Portugal with the measures which were outlined by the Portuguese government, the fact that the tariffs in 2022 aren't expected to increase, so now we have good visibility on the distribution remuneration. We have good visibility on the reduction in the system debt. So I think if there was uncertainty there, that should certainly allow it to sort of be mitigated. And in relation to Spain as well, I mean, I can appreciate there is some uncertainty in Spain. That also seems to have reduced. You'll know that as well as I do that -- sort of the points that have -- or the evolution that's been done in terms of negotiation and the proposals by the Spanish government. So clearly, I think these are all -- or it's been relatively positive news flow that should reduce the uncertainty around those assets. So listen, I think that's the best answer I can give. You can keep asking the question, and I'll keep giving you the answer. But I think it is worth giving it because -- well, just to try and contribute to more information on the issue.

We have now a question from Stefan Bezzato from Credit Suisse.

Stefano Bezzato from Credit Suisse. Three questions if I may. The first one for this year, I guess, your expectations for European energy policy in 2022, what steps do you expect Europe to take following the EU toolbox next year? And in particular, any chance of seeing a reform of the power price mechanism of the power market? The second question on your hedging strategy. You gave us 50% over 2022, 2025. Can you elaborate a bit more on how this percentage -- how the percentage is moving across the years from the early '20 -- from the beginning of 2022 towards the end of this time frame? And finally, the last question on asset rotation. Can you elaborate a bit on how -- what you are achieving, comparing to your expectations at the beginning of the year? And how is the pipeline for asset rotation shaping up for 2022?

Thanks, Stefan. So in relation to the first one, the EU policy. So I think first, a couple of key legislation that's been coming out or at least not with -- in the case of the Fit for 55 and also in terms of guidelines around the toolbox. The Fit for 55, I think, is good because it does provide additional visibility and ambition in relation to the rollout of renewables, energy efficiency, I mean, a bunch of different things which are important for the medium- to long-term growth expectations in Europe. So I think that's important. The toolbox is a short-term guideline really as to how government should try and mitigate the impact of the wholesale prices in the short term. And again, the Spanish government came out with some measures that was highly contested. Europe also came out with this toolbox. Spain seems to be evolving in the right direction. I expect there will continue to be discussion around this issue. Obviously, if the prices start coming down, I think that will disappear or be mitigated. And so that leads on to the other part of your question, which is reforming the power price market. First, I don't think it's a good idea to try and talk about the reforms when everyone is in high stress because normally, that means you have a more reactive approach to how people deal with it. And policy should be set out and thought through carefully, particularly when you're talking about something like the energy sector. I'd say that the current model works. The marginal pricing system is good for short-term dispatching. I think what we need to do, and that's something we've talked about also in the past and with various policymakers in Europe, is make sure that we are incorporating long-term price signals so that you can continue to build out renewables, whether that's through PPAs, CFDs, feed-in tariffs. I mean there can be a lot of options, but you need to provide those long-term price signals. It's important also capacity payments for availability. So I think those are some of the refinements which can be done. I would be hesitant to talk about a full reform of the power pricing. In fact, I think some of the countries in Europe have come out and said that they certainly don't want to go down that path. So I think there are definitely areas we can work on to improve it and to adapt it to a world which will have more renewables, more intermittency and how to deal with that. In relation to the second point, the hedging strategy. So I don't want to comment too much on a quantitative basis. I'd say obviously in the shorter term, 2022, we'll have -- we have a higher percentage hedged and at a higher price. And towards the back end, we'll have less hedged and at a lower price. Overall, as I say, 50% over this period at around the EUR 60 per megawatt hour. In relation to the third point, asset rotations, it is coming in above expectations. I think interest rates have also stayed low, and we continue to see a lot of good demand from investors. So it is above our expectations, certainly, for now. We had multiples implicit in the business plan of around EUR 200 -- EUR 200,000 per megawatt. And so we're comfortable with that, and we actually see multiples above that for the transactions that we've done on average. We are now already preparing asset rotation deals for 2022. We might even be announcing 1 or 2 in the short term. But because this is a continuous process, so we keep working on this. So hopefully, that answers your question.

Okay. We can go now to the question from Manuel Palomo from BNP Paribas.

I've got also 3 questions. First question is about yesterday's announcement and the snap election in Portugal and potential impacts that you could see on the company CapEx plan. Could the election lead to any CapEx delays, at least in Portugal? That would be my first one. Second one is about M&A and renewables, where the company has very -- has been very active in 2020, Viesgo, in 2021, now Sunseap. My understanding is that those acquisitions are considered as part of the existing installation targets. My question is whether future installation targets include any additional M&A. Or should potential additional M&A be considered on top of the current targets? And lastly, confirmation. You mentioned that you reaffirmed your guidance for the year. But my question is whether you confirm the full guidance, I mean, net profit being above EUR 800 million, EBITDA being at around EUR 3.7 billion and net debt between EUR 11 million and EUR 11.5 billion.

Thank you very much. So in relation to the snap election, I don't believe we'll have any impact on the company's CapEx plan. I mean obviously, these CapEx plans are long-term plans in the sense that they are taken with a lot in advance. Most of the CapEx in Portugal is relating to the distribution networks. I mean we have some in the generation side but mostly sort of relating to upkeep of the existing power plants. And then we also have around 140 megawatts of solar. So I wouldn't expect any delays or any changes to the CapEx plan in Portugal as a result of this. In fact, I wouldn't expect really any impact also on any other issue as a result of this in relation to Portugal. On the second point, so M&A, I mean, M&A is part of growth. I mean we may do it, particularly if it brings portfolios, which is certainly the case of Sunseap. In the case of Viesgo, I think it's just because it's a great fit with our existing networks in Spain. So we saw a good value creation perspective there. So I think it's an instrument in the toolbox. Obviously, it's something that we look at. I mean that's also part of our fiduciary duty. But I mean I'd say it's part of the way of doing business. In terms of the actual target, I think you were pointing or alluding to that as well. So for example, in the case of Sunseap, yes, that CapEx associated with the acquisition of Sunseap is included in the overall CapEx of the -- that we have. So it's not on top of. It's within around EUR 19 billion of CapEx that we had for the 2021 to 2025 period. In relation to the guidance, yes, so it's on both. I wasn't trying to avoid any particular point. So guidance on EBITDA and guidance on net income, comfortable with that. Obviously, it does depend on the closing of the different asset rotation transactions we have in place. We see good progress. So certainly, that's the base case. And I'd say we feel comfortable with that guidance at this point.

We have now a question from Alberto Gandolfi from Goldman Sachs.

Congratulations on the hedges. It sounds very, very intelligent and promising. Maybe questions 3 on my side. We debated this yesterday, but considering there's quite a lot of skepticism out there, could I ask you maybe to reiterate once again your procurement policy and any concerns you may have on cost inflation across the supply chain and/or potential delays due to bottlenecks in the supply chain? I'm talking about CapEx procurement, freight, anything that could increase CapEx and potentially squeeze returns. Or if you can tell us for how long you have visibility on those. And I know you discussed this briefly yesterday, but it would be great to kind of kill the debate once for all. The second question is if you can help me with a couple of adjustments on net income. Considering you had positive hydro in Portugal and kind of negative across the portfolio generation, would you be able to give us EUR 1 million impact in 9 months 2021 from volumes, i.e., if we were to normalize hydro and wind, and I know I can do my calculation as well, but I was wondering if you can give us what you think it is for '21 9 months. What will be the impact on your accounts on normalized load factors and normalized energy management and supply trend? So I'm trying to understand what should be more through the cycle on those 2. And last question. I couldn't help but notice that you had great cost control and reduction in networks. And I know you talked about Portugal, but I was wondering. A few quarters into it, maybe could you tell us how many cost reduction synergies we may see from here, thanks to the integration of Viesgo into your wider portfolio?

Yes. Alberto, so in relation to your first question, the procurement, so just to try and close this again. We have around 90% of our procurement closed and protected. So what we don't have is obviously limited by definition -- or limited in terms of the impact they can have both on returns and in terms of, let's say, the implementation of the project. So that's for the existing under construction projects. Obviously, the operational is, by definition, not an issue. For future projects that we are looking at locking in or that we are discussing sort of RFPs or PPAs, we are passing through any cost inflation into those prices. And so I've given this example before. You can see, for example, in Spain, the increase of the average price of the recent auction versus the auction earlier this year. And so there's an increase there both on the solar and the wind. So that is a result, I believe, of that cost inflation. But it translates into higher PPA prices or higher auction prices. And we see that even in bilateral PPAs that we have. And I can give you a couple of examples where we have gone back to the clients and we have said, listen, we are seeing higher CapEx for the future, and for us to keep our returns, the PPA price has to be X. And by the way, this is happening across the sector. So the competitive advantage we have is maintained because people will see that. So that is translating into $2 to $4 or EUR 2 to EUR 4 per megawatt hour and potentially increase. So it's something which is manageable and which we've felt that from customers, they are able to absorb that. So that is something that we've seen, obviously, for new projects. And it's something that we are passing through. Just in terms of delays, I would definitely differentiate between turbine and panels. So the reason I do that is because turbines, there's a lot more production capacity in -- certainly in the U.S. and Europe, et cetera. It's more distributed. Even Brazil, it's more distributed. And so there, we have no indication of delays there. In terms of solar panels, there is more uncertainty. It doesn't mean there will be delays, but I think that the suppliers themselves are a little bit more cautious about giving out sort of -- or committing right at the moment. So we don't see any material delays there. That's just on the solar side. So it's not so much a question of the price because, as I said, that's something that you can pass through. In terms of delays, again, don't have any material feedback on that. In terms of the second point, I'll probably pass it to Rui, if you want to just comment here on the adjustments, and then you can comment also on the cost reduction.

Thank you, Miguel. So Alberto, if you want, we can then also follow up with you with some more precise numbers, but just to give you some reference points. So the hydro total outperformance, 70% of that is coming from price. Around 30% is coming from volume. So that's -- so let's say from the EUR 110 million outperformance, around 30% should be volume. I mean from wind, I mean, there's sort of a negative impact, which is volume-wise, is around 5% below average. Again, bear in mind that we have the specific situations from the ERCOT and the Spanish hedges. So definitely, we can follow up more precisely on disaggregation. In terms of the energy management, what we would expect is that on a run rate, it should be delivering an EBITDA around EUR 300 million, EUR 400 million, I mean, towards the end of the year. The business plan, around the EUR 400 million. Let me follow up with you so that we can give you some more precise data points. And on the cost control, I mean, what we've said is that there was some consensus around what sort of operational synergies we would capture from the Viesgo integration, that consensus coming from the market, from yourselves. We feel that's pretty much in line with what we would expect. Things are going according to plan. 2021 is the ramp-up year. So typically, it's where we bear some of the costs in terms of the restructuring. And of course, will be -- we'll see the positive side in 2022 going forward. So I would expect that 2022 would have sort of almost full speed, the synergies being captured. And the progress -- I mean the plan is going according to plan -- actually, slightly better than we were anticipating in terms of timing.

Okay. We have now a question from Fernando Garcia from RBC.

I have a couple of questions on the -- on your gas situation. There, can you remind us your expected gas sales, for example, let's say, 2022 and 2023 versus gas contracts going forward? And there, what is your reference in pricing in your gas contracts and for how long? I think that you mentioned in the past that you have the Henry Hub reference now to the TTF. I wanted to ask you, for how many years is this TTF reference? And then -- that is the first question. And the second question is about the potential reversal of this EUR 130 million of gas, the realities. This is because you expect to use all this gas in 2022? Or is as well because your expectations of TTF pricing?

Okay. So let me maybe start by the last one. So the mark-to-market -- again, just to recall what it is, so I'll just remind you what this is. So basically, we have a large contract indexed to Henry Hub. Our hedging policy through that, what we do is that knowing that we will be selling this gas or consuming these gas in Iberia, basically, we want to close the TTF indexation. And therefore, we closed the -- we hedged this Henry Hub to TTF. I mean throughout this process, of course, we also look to optimizing the positions, and we also do some JKM indexation. And basically, the mark-to-market that we currently have is given that some of these contracts would imply that there would be some gas being shipped, for example, to -- so if I'm closing -- if I'm hedging a JKM, that would imply that there would be a physical sale of this gas to Japan or into Asia. If that doesn't happen because what we are doing is just an optimization, from an accounting perspective, we have to book this as if it was a speculative and therefore mark-to-market. But it's not. I mean we are not speculating. It's just how we are optimizing this relationship in terms of spreads between Henry Hub, TTF, which is a primary goal, but also including the JKM. So the view that we have is with the current forward curves that we have for the fourth quarter and the following -- this year and the fourth quarters -- in the following quarters throughout 2022 and considering the physical consumption that we will effectively have for this gas throughout this period, what we are expecting is that this mark-to-market -- or the gas that is now -- or these hedges that are now being booked in mark-to-market, there will be -- we will be unwinding those. And therefore, this will pretty much disappear over the course of the next quarters. In terms of the gas, I mean, right now, it's mostly -- long-term gas is mostly the 1 bcm that we have from our Cheniere contract in the U.S., which is, as I said, I mean, the one which is priced at Henry Hub. And then of course, we index it back to TTF.

Okay. So I think we can go to the next question that is from Sara Piccinini from Mediobanca.

The first question is about the regulatory impact. So starting from Spain, what do you think would be the impact for EDPR regarding the proposal of the government to set a price uncorrelated to the wholesale price? I know that this is still under discussion, but would you expect a negative impact given your hedging position in Spain for renewables? And the second question. Is there any update about the possibility to pay a stamp duty for the sale of hydro assets in Portugal? And also regarding the measures that you were -- from the government to set up a 0.2% increase and also the reduction in the tariff deficit, can you clarify that these measures would be entirely financed through the state budget, and therefore, there is no impact for EDP? And then on the networks in Portugal regarding the proposal of ERSE, how do you see the introduction of the TOTEX system? And finally, just a clarification on the guidance. I'm sorry for that. About the net debt, do you expect the net debt for 2021 to be at the upper end of the guidance range of EUR 11 million, EUR 11.5 million? And shall we include the impact from the Sunseap acquisition on debt from 2022, so after the closing?

Thanks, Sara, for your questions. I'll take some of them and then also pass to Rui. So stamp duty, no additional information on that. I think this will probably be a relatively long process. As you know, we continue to maintain that it was done absolutely by the book. We have all the usual financial, legal, accounting advisers working with us. And so a very plain vanilla transaction. In relation to the measures of the government, just to clarify, these measures don't have an impact on the company. So we are essentially talking about measures -- well, so in some cases, it's things like lower cost because, for example, the Pego power plant, which had a PPA, which has over cost for the system, rolled off. So that's less. You have higher CO2 revenues coming in. You have the fact that the renewables are there and so are putting a dampening effect on the increase of the wholesale price. There are a bunch of different -- there's also some funds coming from the environmental fund, which are being channeled into the tariffs. So in general, several different measures, which all add up to an amount which allows the mitigation of any impact. But I guess the key one or certainly one of the key ones is that the fact that there is a lot of renewables in Portugal in this case is serving as a dampener on the impact because as we mentioned earlier, let's say, the -- there's so much renewables in Portugal already, but producing at an average tariff of EUR 90 that when you have higher prices than that, it actually works sort of not as an over cost but as a surplus. In terms of the ERSE TOTEX, yes, we think it makes sense. I mean it has an inflation update where the -- and also the efficiency factor has gone down to 2.75%. It was previously at 2%. So there, it's -- I think it's an evolution of the regulation. And quite frankly, we're okay with it. Not -- we don't see that's a problem. In fact, it's already something which has been discussed and implemented at least for a part of the asset base previously. In terms of the guidance, so we expect to be closed in -- so the Sunseap transaction is not expected to be in the end of the year net debt. So when we give the guidance on the net debt, we are expecting that Sunseap will be closed in 2022. And so I think that -- in relation to the regulatory impact in Spain, the proposal of the renewables, I don't think we're assuming any major impact there. But Rui?

Yes, Miguel, that's right. So I mean it's still quite premature in the sense that there has been this ongoing discussion between the government and the renewables sector. I mean for us, it would be fairly neutral. So I would not expect any material change within this. But we'll have to see, I mean, what exactly is the -- if and what exactly is published. Again, I think that one of the important features is that in our view, this ideally should be voluntary in the sense that at the end of the day, the government asks for the renewables to sell at the regulatory cap that the different players decide whether or not they want to adhere to that or -- and just follow basically this on a voluntary basis. But I would say, I mean, let's wait for the final -- what is the final draft on that. But at this point, I would not expect any material impacts.

We have now -- thank you, Sara. We have now a question from Jorge Guimaraes from JB Capital.

I have some -- I have 2 questions also on the regulatory front. So the first one would be -- and this is a follow-up to Sara's question. If it still makes sense to hedge the production of regulated renewables in Spain, if this mechanism for selling at the cap or at the floor is in place. The second one is related to the hydro canon. All the companies in Spain are talking about a full recovery of past hydro canons, and this is the case with you, I believe. So going forward, are you planning to continue to pay the hydro canon or just stop paying it? And the final one is related to Portugal. What do you believe is the impact of the election and more precisely of not having a budget proposal on the sales -- or the special energy tax for 2022? Since it is [ described in light ] should go down, but there is no budget. So what should we expect for sales in 2022?

Okay. Thanks. So in relation to the sales, and then I'll pass it over to Rui. I mean it's a good question. To be honest, I don't have the exact answer. I would say that probably worst-case scenario is that stays, and I'm sure they will be counting on it. So if it's not in place by the end of the year, they will find a way probably next year to ensure it is in place. So I mean I have no, let's say, information that leads me to believe that they would eliminate the sales next year or not find a way of keeping it. So perhaps just to manage expectations on that side. In relation to the first 2 questions, I don't know, Rui, do you want to take them?

Sure. Well, thank you, Miguel. So related to the first question, I mean, if I understood properly, so does it make sense to keep on having some hedging strategies for the renewables in the context of this proposal? I mean if the prices are at the cap -- yes, I mean, if the price is set at the cap, then of course, I mean it's not important to the hedging. The hedging is there in our view because we currently have a collar. And if you don't want to have the entire generation exposed to volatility within the collar, then we decide to hedge. But I mean if it is sell -- if it is sold at the cap, then of course, it's no longer relevant to keep the hedging. What concerns the second question on the hydro tax. I mean just to be clear, there are 2 different court decisions on hydro taxes in Spain. There is one which is on the recovery of tax paid in 2013 and '14. And I would say those are more relevant to main hydro players in Spain, but it's to our peers that it's rather immaterial for EDP. And then there is another court decision that clarifies that the hydro plants in river basins that are located in a single community should not pay the hydro tax. And this was much more relevant to EDP because most of the hydro plants that we have are located in the Nalon River Basin, which is located only in Asturias. So therefore, related to these hydro plants located in the river, in this Nalon River, EDP paid -- we have paid hydro taxes of EUR 19 million between 2013 and '17. And we provisioned EUR 28 million on the potential hydro taxes between 2018 and beginning of '21. So basically, given this positive court outcome, we are reverting EUR 47 million of the costs incurred in our P&L between 2012 and 2021.

Sorry, Rui, just let me ask you to clarify. So you had total cost of EUR 90 million until now and you just reverted EUR 47 million. Is that so?

So we have, between 2013 and '17, EUR 19 million. And then we had provisioned EUR 28 million for the period between 2018 and '21. So basically, we are now reverting both provisions. Okay. But those are past. So basically, this EUR 47 million hitting our P&L until now.

Okay. So we have more -- 2 questions on the phone. Olly Jeffery from Deutsche Bank.

So 3 questions, please. The first one is going back to the gas financial market hedging. The question is if you didn't have to incur that, this noncash item, would you be lifting guidance for CSEM, the EUR 200 million EBITDA that you spoke about last quarter? Would you potentially be lifting that if that hadn't happened and therefore be more confident about your full year guidance? That's the first question. The second one is going back to the procurement costs. You mentioned that 10% of the procurement costs are open or partially open. Can you give any indication if you expect that to have any impact on the spreads you're making from the projects under construction? Or is it so minimal that it doesn't register? And then the last question is kind of looking forward a bit more. So if you look at the pipeline that you guys have, that's increased a lot since the CMD, and it's now up 20% to 55 gigawatts. And the proceeds that you guys are making from your asset sales are ahead of plan, but it looks like you won't need to sell nearly as much gigawatts-wise that you expected to hit the EUR 8 billion number. So my question is, do you feel like you're ahead of plan in terms of the size of the pipeline and therefore potentially might be looking to, at some point, increase your targets in the outer years because the opportunities are really there and you have the finances to do that? Those are the 3 questions.

Okay. So thanks for the questions. I think -- I mean probably the answer to your first question is, yes in the sense that, obviously, if we didn't have that impact, we would be above the guidance, I think, by definition. So the answer is yes. In terms of the second -- the 10% procurement costs -- the 10% open for -- that's still open to be adjusted for procurement, I mean it is relatively limited, to be honest. So we talk about the 300 basis points of spread. I think it would be relatively residual on that amount and still well above the 200 basis point spread. So we'd still be very close to the 300. I mean bear in mind that we're talking about -- particularly placed in the context of a EUR 19 billion investment program over the 5 years in renewables, so we're talking about something which is going to be completely diluted in the overall context. In relation to the third point, I mean, yes, it's also a great question. So proceeds are ahead of plan. We do feel we are delivering well. We talked about the 75% already closed for the '21 to 2030 period. If we don't need to sell as many gigawatts, and I've mentioned that, I think, in the past, to get -- if we get to the EUR 8 billion, then -- with fewer megawatts, then that's great. And that's really what we're solving for. So we're solving for a balance sheet issue, making sure that we keep the BBB and are able to execute the investment plan. So I don't want to get ahead of myself or ahead of the company in terms of pointing out whether we're going to revise targets or do anything like that. But certainly, things are going well and on track. And the fact that -- we built 2.5 gigawatts year-on-year. So that's a huge ramp-up versus what we were building in the past. And as I say, we've got a huge amount still of megawatts already under construction over the next couple of months. So we are really seeing this big ramp-up. We are seeing good multiples on the asset rotation. So we'll take that all into consideration at some point and sit down and look at the plan and think about where we want to go from there.

Okay. We have the last question from the -- thank you, Olly. We have the last question from the phone from Arthur. We have some other questions on the way, but given that we have -- we are already quite long, I think then we'll answer a few questions that we have on the web offline. And so this last question is from Arthur Sitbon from Morgan Stanley.

First, just a quick clarification on the provision reversal of the hydro canon. You're talking about EUR 47 million. Is that already booked? Or will it be booked in Q4? Or will it be for next year? So that's the first question. The second one is just a follow-up one on the EUR 800 million recurring net income guidance for this year. I just wanted to have confirmation that this is based on -- assuming the EUR 300 million of asset rotation. So essentially, anything that comes on top of those around EUR 300 million would lead to going above the net income guidance? And my third question is just on the EU taxonomy exposure that you're talking about, the 66%. I was a bit surprised by the -- essentially the 34% that are not included that are not compatible with the taxonomy. And I was wondering, what are those assets? Is it the gas and coal plants? Or are there other assets that are not included?

Great. Arthur, it's Rui here. So just to be clear, this provision reversal was done and booked in the first half. So what you're seeing now is already coming from the first half results. Then, I mean, what concerns the guidance? I mean, yes, we are, at this point, targeting above EUR 300 million asset rotation capital gains. I mean -- but we are also, again, comfortable with this EUR 0.8 billion in terms of net profit guidance. So we [ adhere ] to that. Miguel, you want to take the -- actually, I would ask a clarification on the third question. I'm not sure we exactly...

I think you mentioned that you have 66% of your revenues compatible with the EU taxonomy in the presentation. And I was wondering, what are those assets that are not compatible? Essentially, what are the revenue streams that are not compatible?

Arthur, just to clarify, so I think on the taxonomy revenue, so we take the more restrictive criteria right now. As you know, there are discussions going on in Europe. So we exclude everything that is gas or nuclear and even obviously on the energy supply business. So we only take into consideration the energy efficiency services. As you know, this activity of supply has a big weight in terms of revenues, although much more limited in terms of EBITDA because the EBITDA margin is much smaller. So that's the main reason. I would say -- I would highlight the more restrictive criteria and the issue of supply and this increase in terms of change is also related with the change in terms of the mix. So we have reduced a lot of supply with the sale to Total of the supply business in Spain. We have reduced the weight of coal with the shutdown and gas also with the sale of Castejon. And so we have been growing in renewables. So that's the main change in terms of year-on-year evolution. So I think I'll pass now to Miguel just for some final remarks.

No. I think, again, it's been a long week. It's been a long call, so I'll just be very brief. I think I just wanted to reiterate some of the comments, going back to not only in terms of the growth in renewables, the Sunseap transaction, visibility on Iberia, both in Portugal and Spain. So I think these last couple of months have been -- have brought some good news flow, and strategically, I think definitely in the right place. Obviously, turbulent markets, so issues around the mark-to-market of the gas contracts, and I can see there are a lot of questions around that. We'll certainly continue to provide information and guidance on that so that you can go work through your analysis. But overall, I think we are doing well. And definitely, things are keeping -- are moving forward. Issues on procurement, also something that kept coming up -- or keeps coming up. I mean we will continue to keep you updated on anything there. But as I say, we have all the visibility we have, pointing to a very limited impact, if any, on profitability and completely diluted in the overall CapEx of the company. So again, we don't see that as an issue. Anyway, I'm sure we'll be talking soon, many of you. So I look forward to it. And take care. Have a good weekend. Thanks.

Thank you, ladies and gentlemen. This concludes today's call. Thank you all for joining. You may now disconnect your lines.