Ladies and gentlemen, thank you for standing by and welcome to EDP's 9M results presentation. At this time, all participants are in a listen-only mode. Later, we will conduct a question and answer session. If you would like to ask a question, please press star followed by one on your telephone keypads. Should you require any assistance during this call, please press star zero. As a reminder, today's conference call is being recorded. I would like to now turn the call over to Mr. Miguel Viana, Head of Investor Relations. Please go ahead, sir.
Good morning, ladies and gentlemen. Thanks for attending EDP's first nine months of 2021 results conference call. We have with us today our CEO, Miguel Stilwell d'Andrade, and our CFO, Rui Teixeira, who will present the main highlights of the nine months of 2021 financial performance and an update on strategy execution. We'll then move to the Q&A session, in which we'll be taking your questions both by phone or written questions that you can enter from now onward on our webpage. This call should last close to 60 minutes. I'll now give the floor to our CEO, Miguel Stilwell d'Andrade.
Thank you, Miguel. Good morning, everyone, and thank you for participating. I'm sure it's been a long week for all of you with a lot of results calls this week. We'll try and do just a brief presentation and then turn it over for Q&A. If we go to slide three, what we can see is that in the first nine months of the year, we continued to accelerate growth. We had growth investment increasing by 15% to EUR 2.7 billion. We remain the third greenest utility in Europe, with over 75% of our total production from renewable energy.
You have seen, for those of you who attended the call on Wednesday, that 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 renewable deployment. We have 3.9 GW of capacity installed or under construction. We've also accelerated our growth in electricity networks. In Spain, the integration of Viesgo continues to move forward at a good pace and ahead of the initial plan. In Brazil, EBITDA growth was supported by the execution of our investments in transmission projects, in 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 revisions.
Overall, recurring EBIT was around EUR 2.5 billion in the period, a 1% decline year-on-year, but that includes the negative ForEx impact of -4%. If we strip that out, the recurring EBITDA ex ForEx increased by around 8%. Obviously, the high energy prices in Europe are something that, you know, 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 results of our energy management division, mostly due to an increase in energy sourcing costs, and also upfront negative mark-to-market of hedging positions. Note that this should be compensated by higher unhedged operating margins in the near future. It's a shorter-term impact, which will then unwind.
Also worthy of note is that from an integrated risk management perspective, part of the negative energy management performance is offset by the positive results in hydro generation in Iberia, as well as in the supply division. It's good to look at this from an integrated perspective. In this period, we continued 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 amounts recorded last year, although we expect more gains in the fourth quarter from transactions that have already been agreed upon and announced. We are pending the final approvals for the financial closing, so we can actually register them in the accounts.
Overall, net profit reached EUR 510 million without any material net impact from non-recurring items, and we continue to be on track to deliver the 2021 guidance of around EUR 800 million net income. If we move to slide four, I think it's worth taking a step back and saying we continue to see a policy environment that is highly supportive of the energy transition. For EDP, we remain completely committed to this ambition. This is particularly relevant given that COP26 is taking place now in Glasgow. 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.
No one said this was going to be easy, so this is going to be something that requires a lot of steps every year: people coming together, reiterating their targets, and continuing to increase the level of ambition. I think that's also something relevant to note. Also, note that the Association of Southeast Asian Nations, or ASEAN, restated its target of 23% of primary energy coming from renewable sources by 2025, versus 14% in 2018. This global fight against climate change, I mean, it calls for strong fundamentals; it calls for huge growth in renewables.
That was highlighted by the International Energy Agency, which came out with a report saying that we should be looking at annual global clean energy investments of around $4 trillion per year by 2030, four times as much as the $1 trillion invested in 2020, to limit global warming to 1.5 degrees by 2050. I mean, these are obviously staggering numbers. In Europe, the European Commission's toolbox to tackle the increase in energy costs has reinforced the need to deploy renewables, to develop energy efficiency solutions, and also to continue to build out grids across the continent. This will also depend on the deployment of EUR 750 billion from NextGenerationEU.
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 talk about that during 2022. In the U.S., two 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 clean energy investments, namely the 10-year ITC and PTC extensions and tax credits, a total amount of $320 billion. 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.
We announced the acquisition of Sunseap on Wednesday, and we explained that in depth on the EDPR conference call. We truly believe that this solidifies EDP's status as a global clean energy player. It allows us to expand our presence into the Asia Pacific region, making it EDP's fourth regional hub after Europe, North America, and South America. Just a note about Sunseap: it's a solar-focused player, present in nine Asian markets. It's worth highlighting Singapore and Vietnam. It has a strong asset base and capabilities in solar DG, but it's also expanding operations in centralized solar. This is a strategic acquisition.
It has an implied EV of EUR 870 million, and it gives us around 700 MW of secured capacity: 540 MW of operational or under-construction capacity, and an additional 130 MW already contracted. These are very young assets, under 2 years old, with 20-year contracted revenues, so 76% with PPAs and 24% regulated, with an average price of EUR 75 per MWh. This represents low risk, stable long-term cash flows, fully aligned with our EDPR strategy, and a pipeline of around 5 GW, which will support strong growth over the next few years. Clearly, the price here includes not only the operational under-construction assets and the already contracted assets, but also the pipeline that we expect to develop over the next couple of years. Moving on to slide six.
Here, just taking a step back and looking more globally at EDPR, we continue to accelerate growth with 2.5 GW of gross capacity added in the last 12 months. 8 GW so far secured, so 75% of our target capacity additions until 2023. As I've mentioned before, 4.1 GW of PPAs are at advanced stages of negotiation. We've been able to secure this capacity with attractive returns and in line with our investment criteria, around 1.4 times WACC or above a 2% spread. All in all, the spread over WACC for the 8 GW secured is roughly 300 basis points. From a risk perspective, we continue to focus investments on long-term contracted assets and contracted cash flows, which typically represent 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 these long-term predictable cash flows. If we move forward to slide 7, we continue to be well protected from 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 this; it's a sector-wide increase in CapEx. From that perspective, it's not impacting our competitiveness when bidding for new projects. The return thresholds are being preserved because everyone is obviously feeling the same impact.
In relation to the 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. 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 eight, on the asset rotation. Nine months into the business plan, we have EUR 2.3 billion of proceeds, transactions already agreed. This represents 30% of the target from the 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. It links back to that discipline in terms of investment returns and also in terms of the profile of these assets. Clearly, there is strong appetite from the private markets for these types of renewable assets. Overall, we are on track to deliver 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 transactions. If we move on to slide 9, we'll talk a little bit about Portuguese electricity distribution. On October 15th, as is usual, we had the release of the proposal by ERSE for the 2022 to 2025 regulatory framework for electricity distribution remuneration, so a four-year period. In the past, it used to be three years.
It's moved to four years. The proposal establishes a slight decline of regulated revenues in 2022, around EUR 10 million year-on-year, which results from the decrease of around 45 basis points in the rate of return on the regulated asset base, so it's now at around 4.3%. This is lower than in other neighboring 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. There is a natural hedge on the trend of the long-term interest rate. If they go up, there is an adjustment for this rate of return to increase. Limited downsides, and depending on how bond yields go in Portugal, it will follow that bond yield 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. Overall, despite the low rate of return, we believe that the limited change in the regulated revenues, the medium-term indexation to long-term yields, and the update to inflation all reinforce the medium-term visibility of the remuneration of this activity. Okay. Talking about Portugal still, but talking about the regulatory framework, also for the consumers, let's say. The Portuguese regulator presented a proposal with a 0.2% increase for the 2022 end-user tariff for the residential and SME segment.
This is a remarkable achievement if we consider the strong increase in 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, is that in Portugal there's been a significant volume of generation contracted at stable feed-in tariffs, with an average price of around EUR 90 per MWh. What was previously an overcost 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 residential consumers are the off-takers of these feed-in tariffs. So, they have a slight long position in the wholesale electricity market, which is benefiting, let's say, and allowing the tariffs not to increase.
The spread inversion between feed-in tariffs and wholesale prices enabled a 52% reduction in grid access tariffs and an overall 50% system debt decline 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, talking about electricity spot prices. I mean, these are obviously extremely high, and, you know, we're all aware of that.
There is a strong backwardation of forward prices, so we see an increasing demand from corporate clients for longer-term contracts to basically smooth out this short-term spike and lock in these longer terms of lower prices. The recent spike in energy prices means that most consumers, especially industrial ones, are looking for ways to reduce exposure to volatile energy prices. We've experienced a significant increase in multi-annual contracts, which give long-term stability to selling prices. Currently, we have hedged around 50% of the expected base load generation for 2022-2025 at an average of EUR 60 per MWh. This is an upside to the average selling price of EUR 47 per MWh, which we had assumed in the business plan. I think this is something worth highlighting.
Moving on to slide 12, a little bit about Brazil. There have been significant developments in Brazil's portfolio. We talked about the reshuffling, and 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 our operations in Brazil. Concretely, regarding the transmission asset rotation strategy, in this quarter, we bought a controlling stake in Celg Transmissão with almost 760 km of lines in the region of Goiás. We expect strong electricity demand growth in the coming years here, and we sold roughly 440 km at a very attractive multiple. It's a higher multiple than what we were buying. We've also added two greenfield transmission projects, one in the secondary market and another in the latest regulatory auction.
I think it also shows 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 GW of hydro assets. We've talked about that. It's aligned with the commitment to reduce hydro exposure in Brazil. Finally, Brazil also announced an additional amount for 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. First, we are absolutely committed to ESG action. We've been top performers 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 toward the energy transition, 76% of EDP's total generation now comes from renewables within the first nine months of 2021. Revenues aligned with the EU taxonomy rose 66%, which gives visibility on achieving the 2025 target of 70%. Not only have we committed to ESG excellence, but we've also been focused on providing transparency regarding EDP's ESG profile. An example of that was our ESG day. 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 at all levels.
With that being said, I'll pass the word to Rui Teixeira for a more detailed breakdown of the nine-month results, and then I'll come back for some closing remarks. Rui.
Thank you, Miguel, and good morning to you all. Now let's look at EDP's performance for the nine months of 2021. Let's move to slide 15. 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 the renewables platform was down 4%. This has been affected by weaker wind resources and lower asset rotation gains when, of course, we compare to last year. There was an adverse ForEx impact of EUR 95 million, mainly due to the 11% depreciation of the Brazilian real versus the euro. On the positive side, this performance in wind and solar was partially offset by the good performance in 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. In Brazil, the inflation update of regulated revenues and the execution of the transmission growth. On the Client Solutions & Energy Management platform, this was penalized by the sharp increase in 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 exceptionally positive performance last year. Moving on to slide 16, EBITDA from EDPR declined 15% year-on-year, down to EUR 917 million. Despite this, the 13% increase of installed capacity, EBITDA was penalized by overall weak wind resources, which is 5% below average.
Lower asset rotation gains compared to last year, representing around a EUR 49 million decline year-on-year. Lower average selling price reflects the more competitive projects added to our portfolio in the last 12 months, but also the negative impact in the US, namely in the first quarter from the polar vortex tax that we have discussed extensively. In Spain, this is due to weak resources 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. Of course, this is on the back of very strong hydro resources.
The realized price increased 13% to EUR 61.4 per MWh, following an increase in the premium of realized prices over the base load, higher revenues from ancillary services, and, of course, generally 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 positively impacted them by EUR 47 million. In Brazil, the hydro EBITDA increased 30%. Despite the current hydro crisis in Brazil, performance was well supported by the hedging strategy in place, with more energy allocated toward the second half of the year.
Hydro Brazil's EBITDA was also positively impacted in the third quarter by a EUR 26 million positive impact from the extension of the hydro concessions that we also discussed last year. If you move now to slide 18, these first nine months of 2021 were marked by a strong performance of the networks platform, with recurring EBITDA increasing 43% year-on-year. In Iberia, EBITDA amounted to EUR 682 million. That's a 41% improvement compared to the nine months of 2020. This is happening on the back of Viesgo's integration, of course, and a positive impact from the reversal of a provision on regulated revenues in Spain as well.
A 21 million increase in Portugal was 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 in local currency as well. This is mainly due to the increase in volumes of distributed electricity. They are up by 9% year-on-year, and there's a positive impact from inflation indexation on distribution and tariff updates. Lower losses resulted from the sale in the wholesale market of electricity volume surplus, the so-called over-contracting. All in all, EBITDA was positively impacted, very positively impacted, in distribution. 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. Here is where we have another performance. As you know, EBITDA declined 66% year-on-year, also compared to exceptional growth or strong performance in the nine months of 2020, which still included a positive EBITDA contribution of around EUR 37 million from the Sines coal plant, which, as you know, was shut down at the end of 2020. In Iberia, the last two quarters were particularly challenging. The energy management activity was penalized by the sharp increase in energy prices to record-high levels, which increased our energy sourcing costs and also implied a negative mark-to-market impact from hedging contracts for future periods. The MTM losses are mostly non-cash and are expected to be offset by higher operating margins in the near term.
In this quarter, these negative impacts were partly offset by the increase in client service penetration, which we expect to keep increasing since 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 the same plant, our coal plant in Brazil, and a positive mark-to-market on new client contracts. If we move now to slide 20, in this context of very high energy prices in 2021, I think it's important not only to show the detail, to share the detail, but also to highlight the value of our integrated portfolio. 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.
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. Basically, you see that the sum of these brings us to a very neutral position in terms of integrated portfolio. Also, we have in this period close to EUR 110 million of non-cash mark-to-market in financial hedging positions, mostly gas hedges, that with this will imply higher operational margins going forward. 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.
If we adjust for one-off costs, these 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. This is driven by the decline in average net debt, which is around EUR 500 million, and a 10 basis point increase in the average cost of debt. This is mostly driven by the increase in the average cost of Brazilian real-denominated debt, which represents around 12% of our total debt. 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 continually issuing green hybrids.
The one 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 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 of EUR 0.3 billion, strongly penalized by a EUR 0.5 billion increase in working capital.
This is related to the proactive anticipated payment to suppliers that we discussed at 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 was fully paid in April. EUR 1.7 billion of net expansion investments followed the acceleration in the build-out of our activity, with EUR 2.3 billion expansion investment and the anticipation of some bill payments to fixed asset suppliers of EUR 0.4 billion. This was also partly offset by EUR 0.6 billion proceeds from the asset rotation deal that we concluded in the U.S. already this year.
We also had 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. Finally, the effects of exchange fluctuations had a negative impact of EUR 0.2 billion on net debt. Just to finalize on my side, on page 23, overall reported net profit reached EUR 510 million. This represented a 21% increase year-on-year.
Adjusted for one-off impacts and the operations disposed of in Iberia in 2020, the recurring net profit decreased 2% year-on-year, benefiting from improved financial results and lower minority interests, reaching EUR 510 million as net non-recurring items had a zero contribution to net profit in these nine months of 2021. With this being said, we continue to be very committed to what's ahead. I also take this opportunity to thank you all for your time today. You know, as Miguel said, it has been a very intense week. Miguel, I'll now pass the word to you for closing remarks. Thank you.
Okay. Thank you, Rui. 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 solidifies, I think, our status as a global clean energy player. I think it has a fantastic strategic fit. The pipeline—it's got a fantastic pipeline. It's got a great track record. It's got fantastic management. It's got a good footprint in fast-growing markets, and so it'll allow us to tap the massive Asia-Pacific growth opportunities. I think definitely a good fit. It contributes to the execution of our growth plan. It's got a focus on renewables, you know, over 8 GW already secured with long-term contracts with attractive returns.
Just to reiterate, 75% of our target for 2021 to 2023. Okay. We've also seen Portugal's new regulatory framework this quarter, which keeps residential tariffs flat, a very strong decline in the system debt, and provides medium-term visibility on the regulated returns and distribution. You know, 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. It certainly eliminated a lot of uncertainty that might have existed. The recent surge in wholesale prices has created the conditions to extend the maturity of our contracts with clients.
The base load production between 2022 and 2025 is now approximately 50% hedged at an average of EUR 60 per MWh, which is above the 47% and EUR 47 per MWh 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 with Brazil's portfolio. As we talked about in the past, we said we were going to do it. We're concretely showing now the transactions coming through in terms of the portfolio reshuffling, decreasing the exposure to hydro generation, and growing the electricity networks asset base. I think that's coming through, certainly in terms of the value of Brazil, highlighting that this has been a commitment that we've made and something we're following through on.
As a result of that, we showed the asset rotation in Brazil, the acquisition of Celg-T and disposal of three transmission lines to Actis, buying and selling at attractive multiples, and at the same time advancing negotiations to dispose of around 500 MW of hydro assets in Brazil. We expect to probably have signing before the end of the year. We're certainly working towards that. All in all, nine 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, good risk management because we're probably living through some of the most chaotic and uncertain times in terms of volatility in the market.
I think the fact that we are continuing to move forward through all of this really shows the risk management that we've been doing. Having said all this, we reiterate our confidence in terms of delivering the 2021 financial guidance. I'd just like to leave it there on that note. Thank you for the results, and we can now move to Q&A.
Thank you, ladies and gentlemen. If you would like to ask a question at this time, please press star one on your telephone keypad. To cancel your question, please press star two.
Okay, I think we have the first question from Harry Wyburd from Bank of America. Harry, please go ahead.
Hi. Thanks. Hi, everyone. Three questions from me, please. The first one's on working capital. Actually, it's 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. I noted that your working capital didn't increase by that much. I think that you put about a EUR 0.5 billion increase in the presentation today, and that was already EUR 0.4 at first half. It doesn't look like you've seen a big increase in working capital in the third quarter.
I wondered if you could just elaborate a little on what you're seeing in working capital at an industry level, because I'm just trying to understand whether increases in working capital are something that we should be braced for more widely across the sector after some of your peers reported increases. That's the first one. The second one is specifically on energy management and hydro in Iberia. You mentioned on slide 20 that the overall net impact of, I guess we could call it the gas crisis impact, and all the hedges and so on, high spot prices is about EUR 110 million for nine months.
Then you mentioned you're hedging your power at about EUR 13/MWh higher in 2022-2025, so on sort of just below 10 TWh of hydro output. That's another kind of EUR 100 million or 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 from those businesses? The final one, 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. The, I guess the Iberian assets' implied valuation is still very low relative to, I guess, the intrinsic value reflected in peers. I wondered if there'd been any update in your thinking there?
Maybe just ask specifically. I wondered about 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 situated more closely with the wind and solar assets? I guess, valuation-wise obviously, but also industrially, pumped storage hydro is obviously a natural fit for intermittent renewables. I just wondered if there's any update on your thinking on that, and sorry for the long questions. Thank you.
Okay. Hi, Harry. It's Rui here, so I'll address the first two, and then I'll hand over to Miguel for the third one. In terms of working capital, basically, what we have in our books right now within these nine months is, first of all, the advanced payments we made to suppliers at the beginning of the year, given the liquidity that we had, the excess liquidity. And then more recently,
Given the high prices in power markets, I mean, everything related to the payment conditions, they basically increase the working capital just given that the unitary price is higher. But also, we have an impact from cash collaterals that we are called upon or, you know, margin calls, given the hedges that we have in place, particularly the ones in the market, that, of course, they, you know, they require us to post this additional collateral. I would expect, everything else being equal, that by Q4, we actually should be reducing. That has to do with the fact that the higher power prices are creating a surplus in terms of, as you know, through the regulated retail business.
They are buying from renewables in Portugal at the tariff, which is below current market prices. There is a surplus being generated there, and I would expect that to have a positive impact in Q4. Actually, I would expect that we would improve the working capital until the end of the year. With regard to the second question, I would expect that, yes, there will be some positive impact in 2022. I would prefer not to comment on the number right now. Yes, I would expect some improvement coming from the hedges in Hydro. Over to you, Miguel.
Yeah. Thanks, Rui. Hi, Harry. Listen, you're right to ask the question. We ask it ourselves, so you know, 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, in the sale of the CCGTs and the customers, clearly, you know, we think that those are good references. I mean, by definition, they are good references for the intrinsic value of some of those assets. 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. It is something we are monitoring, and we continue to think about whether there's any additional move we should or could make. Obviously, we do continue to provide as much information. I 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 the implicit values of some of these assets are.
I just had 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 assets, 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, you know, the measures which were outlined by the Portuguese government, the fact that the tariffs in 2022 aren't expected to increase. Now we have good visibility on the distribution remuneration. We have good visibility on the reduction in the system debt. You know, I think if there was uncertainty there, that should certainly allow it to sort of be mitigated.
In relation to Spain as well, I mean, you know, I can appreciate there was some uncertainty in Spain. That also seems to have reduced. You know that as well as I do, the sort of, you know, the points that have or the evolution that's been done in terms of the negotiation and the proposals by the Spanish government. Clearly, I think these are all or it's been relatively positive news flow, and that should reduce the uncertainty around those assets. Listen, I think that's the best answer I can give. You know, 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 now have a question from Stefano Bezzato from Credit Suisse.
Yes. Hi, good morning. It's Stefano Bezzato from Credit Suisse. Three questions, if I may. The first one for the CEO, I guess. Your expectations for European energy policy in 2022: what steps do you expect Europe to take following the EU toolbox next year? In particular, any chance of seeing a reform of the power price mechanism or the power market? The second question is on your hedging strategy. You gave us 50% over 2022-2025. Can you elaborate a bit more on how the percentage is moving across the years from the beginning of 2022 towards the end of this timeframe? And finally, the last question is on asset rotation.
Can you elaborate a bit on how what you are achieving compares to your expectations at the beginning of the year, and how is the pipeline for asset rotation shaping up for 2022?
Okay. Thanks, Stefano. In relation to the first one, EU policy, I think, first, a couple of key pieces of legislation have been coming out, or at least now 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. I think that's important. The toolbox is a short-term guideline, really, as to how governments should try and mitigate the impact of the wholesale prices in the short term. You know, again, the Spanish government came out with some measures that were 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 prices then start coming down, I think that will disappear or be mitigated. 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 reforms when everyone is under high stress, because normally that means you have a more reactive approach to how people deal with it. 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, or 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, to have capacity payments for availability. I think those are some of the refinements that can be made. I would be hesitant to talk about a full reform of 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.
I think there are definitely areas we can work on to improve it and to adapt it to a world that will have more renewables, more intermittency, and how to deal with that. In relation to the second point, the hedging strategy, I don't want to comment too much on a quantitative basis. I'd say obviously in the shorter term, 2022, we will 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 60 EUR per MWh. 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. It is above our expectations, only for now. You know, we had multiples implicit in the business plan of around EUR 200,000 per MW. 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, and we might even be announcing one or two in the short term. You know, because this is a continuous process, we keep working on this. Hopefully, that answers your question.
Thank you very much. Okay, we can now go to the question from Manuel Palomo from BNP Paribas. Please, Manuel, go ahead.
Hello. Good morning, everyone. I also have three questions. The first question is about yesterday's announcement and the snap election in Portugal, and the potential impacts you foresee on the company's CapEx plan. Could the election lead to any CapEx delays, at least in Portugal? That would be my first question. The second one is about M&A in renewables, where the company has been very active: Viesgo in 2020, and now Sunseap in 2021. My understanding is that those acquisitions are considered 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? Lastly, a confirmation.
You mentioned that you reaffirmed your guidance for the year. My question is whether you confirm the full guidance—I mean, the net profit being above EUR 800 million, EBITDA being around EUR 3.7 billion, and net debt between EUR 11 billion and EUR 11.5 billion. Thank you very much.
Okay, Manuel. Hi. In relation to the snap election, I don't believe it'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 made well in advance. Most of the CapEx in Portugal relates to the distribution networks. I mean, we have some on the generation side, but mostly it relates to the upkeep of the existing power plants. We also have around 140 MW of solar. I wouldn't expect any delays or changes to the CapEx plan in Portugal as a result of this.
In fact, I wouldn't expect any real impact on any other issue as a result of this, in relation to Portugal. On the second point, I mean, M&A is part of growth. We may do it, particularly if it brings portfolios, which is certainly the case with Sunseap. In the case of Viesgo, I think it's just because there's a great fit with our existing networks in Spain, so we saw a good value creation perspective there. 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. We'll. Okay. It's part of the way of doing business.
In terms of the actual targets, I think you were pointing or alluding to that as well. For example, in the case of Sunseap, yes, that CapEx associated with the acquisition of Sunseap is included in the overall CapEx that we have. It's not on top of; it's within the around EUR 19 billion of CapEx that we had for the 2021 to 2025 period. In relation to the guidance, yes, it's on both. I wasn't trying to avoid any particular point. 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're seeing good progress, so that's certainly the base case, and I'd say we feel comfortable with that guidance at this point.
Thank you.
Okay. We now have a question from Alberto Gandolfi from Goldman Sachs. Alberto, please go ahead.
Miguel, thank you for taking my questions, and good afternoon. Congratulations on the hedges. It sounds very intelligent and promising. I have three questions. We debated this yesterday, but considering there's quite a lot of skepticism out there, could I ask you to reiterate your procurement policy and any concerns you may have about 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. I know you discussed this briefly yesterday, but it would be great to kind of kill the debate once and for all.
The second question is if you can help me with a couple of adjustments to net income. Considering you had positive hydro in Portugal and kind of negative across the portfolio, the generation, would you be able to give us a EUR 1 million impact in nine months 2021 from volumes, i.e., if we were to normalize hydro and wind? I know I can do my calculation as well, but I was wondering if you can give us what you think it is for 2021, nine months, what would be the impact on your accounts on normalized load factors and normalized energy management and the supply trend? I'm trying to understand what should be more through the cycle on those two. Last question, I couldn't help but notice that you had great cost control and reduction in networks.
I know you talk about Portugal, but I was wondering, a few quarters into it, maybe could you tell us how many cost reductions/synergies we may see from here, thanks to the integration of Viesgo into your wider portfolio? Thank you.
Hi, Alberto. In relation to your first question, the procurement, just to try and close this again. We have around 90% of our procurement closed and protected. What we don't have is obviously limited by definition or limited in terms of the impact it can have both on returns and in terms of, let's say, the implementation of the project. That's for the existing under-construction projects. 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. I've given this example before.
You can see, for example, in Spain, the increase in the average price of the recent auction versus the auction earlier this year. There's an increase there, both in solar and wind. That is a result, I believe, of that cost inflation, but it translates into higher PPA prices or higher auction prices. We see that even in bilateral PPAs that we have. You know, 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. You know, for us to keep our returns, the PPA price has to be X." By the way, this is happening across the sector. The competitive advantage we have is maintained because people see that.
That is translating into, you know, $2-$4 or EUR 2-4 per megawatt, you know, per megawatt-hour, a potentially increase. It's something which is manageable and which we've felt that from customers, they are able to absorb that. That is something that we've seen, obviously for new projects, and it's something that we're passing through. Just in terms of delays, I would definitely differentiate between turbines and panels. The reason I do that is because turbines, there's a lot more production capacity, certainly in the West, in 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's more uncertainty.
It doesn't mean there will be delays, but I think the suppliers themselves are a little bit more cautious about giving out or committing to it right at the moment. You know, we don't see any material delays there. That's just on the solar side. It's not so much a question of the price because I said that's something that you can pass through. In terms of delays, again, I 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 reductions.
Thank you, Miguel. Alberto, if you want, we can also follow up with you with some more precise numbers, but just to give you some reference points. The hydro total outperformance: 70% of that is coming from price, around 30% is coming from volume. Let's say from the EUR 110 million outperformance, around 30% should be volume. From wind, there's a negative impact, which volume-wise is around 5% below average. Again, bear in mind that we have these specific situations from ERCOT and the Spanish hedges. We can definitely follow up more precisely on this aggregation.
In terms of energy management, what we would expect is that, on a run rate, it should be delivering an EBITDA of around EUR 300-400 million, specifically around EUR 400 million by the end of the year's business plan. However, let me follow up with you so that we can provide more precise data points. Regarding cost control, we've stated that there was some consensus, coming from the market and yourselves, about the operational synergies we would capture from the Viesgo integration. We feel that's pretty much in line with our expectations, and things are going according to plan.
2021 is the ramp-up year, so typically it is where we bear some of the costs in terms of the restructuring. That, of course, will be, you know, we'll see the positive side in 2022 going forward. I would expect that 2022 would have sort of almost full speed, with these synergies being captured. The progress, I mean, the plan is going according to plan. Actually, it's slightly better than we were anticipating in terms of timing.
Great answers. Thank you.
Okay, we now have a question from Fernando Garcia from RBC. Fernando, please go ahead.
Hi, good morning. I have a couple of questions on your gas situation. Can you remind us of your expected gas IVPEE, for example, let's say 2022 and 2023, versus gas contracts going forward, and 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, but I wanted to ask you for how many years this TTF reference is for. That is the first question. The second question is about the potential reversal of these EUR 130 million of gas derivatives.
Is this because you expect to use all this gas in 2022, or is it also because of your expectations of TTF pricing? Thank you.
Okay. Let me maybe start with the last one. The mark to market, again, just to recap what this is, just to remind you all what this is. Basically, we have a large contract indexed to Henry Hub. You know, our hedging policy, through that, what we do is that knowing that we will be selling this gas or consuming this gas in Iberia, basically we want to close the TTF indexation, and therefore we close the, you know, we hedge these 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.
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 hedging a JKM, that would imply that there would be a physical sale of this gas to Japan or, I mean, to 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 were speculative and, therefore, a mark-to-market. It's not. I mean, we are not speculating. It's just, you know, how we are optimizing this relationship in terms of spreads between Henry Hub, TTF, which is a primary goal, but also including the JKM.
You know, the view that we have is with the current forward curves that we have for the fourth quarter and the following quarters this year and throughout 2022, and considering the physical consumption that we will effectively have for this gas throughout this period. You know, 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 a mark-to-market, we will be unwinding those, and therefore this will pretty much disappear over the course of the next quarters.
In terms of gas, you know, I mean, right now it's mostly long-term gas, mostly the 1 BCM that we have from our Cheniere contract in the U.S., which is, as I said, the one priced at Henry Hub, and then of course, we index it back to TTF.
Okay. I think we can go to the next question, which is from Sara Piccinini, from Mediobanca. Sara, please go ahead.
Thank you, Miguel, and thank you for taking my questions. The first question is about the regulatory impact. Starting with Spain, what do you think would be the impact for EDPR regarding the government's proposal 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? The second question is, is there any update about the possibility of paying a stamp duty for the sale of hydro assets in Portugal? Regarding the measures that you welcomed 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 have no impact on EDP? On the networks in Portugal, regarding ERSE's proposal, how do you see the introduction of the TOTEX system? Finally, just a clarification on the guidance, I'm sorry for that.
Regarding net debt, do you expect the net debt for 2021 to be at the upper end of the guidance range of EUR 11-EUR 11.5? Shall we include the impact from the Sunseap acquisition on debt from 2022, so after the closing? Many thanks.
Thanks, Sara, for quite a few questions. I'll take some of them, and then I'll pass to Rui. 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, and accounting advisors who are working with us, so it's a very plain vanilla transaction. In relation to the government's measures, just to clarify, these measures don't have an impact on the company. We are essentially talking about measures. Well, in some cases, it's things like lower costs, because, for example, the Pego power plant, which had a PPA, which had an overcost for the system, rolled off, so that's less.
You have higher CO2 revenues coming in. You have the fact that renewables are there and are putting a dampening effect on the increase of the wholesale price. There are also some funds coming from the environmental funds which are being channeled into the tariffs. In general, several different measures all add up to, let's say, an amount which allows the mitigation of any impact. I guess the key one, or certainly one of the key ones, is the fact that there are a lot of renewables in Portugal, in this case, serving as a dampener on the impact. Because as we mentioned earlier, let's say the...
There's so much renewable energy in Portugal already that producing at an average tariff of EUR 90, when you have higher prices than that, it actually works not as an overcost, but as a surplus. In terms of the ERSE TOTEX, yes, we think it makes sense. I mean, it has an inflation update, and also the efficiency factor has gone down to 2.75%. It was previously at 2%. There, you know, it's an evolution of the regulation, and quite frankly, we're okay with it. We don't see that as a problem. In fact, it's already something that had been discussed and implemented, at least for part of the asset base, previously.
In terms of the guidance, the Sunseap transaction is not expected to be included in the end-of-year net debt. When we provide guidance on net debt, we are expecting that Sunseap will close in 2022. I think that answers it. In relation to the regulatory impact in Spain, regarding the proposal for renewables, I don't think we're assuming any major impact there, but Rui?
Yeah. Yeah, Miguel, that's right. I mean, it's still quite premature in the sense that there has been this ongoing discussion between the government and the renewable 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 what exactly is, you know, if and what exactly is published.
Again, I think that one of the important features is that, in our view, this, you know, ideally should be voluntary, in the sense that if at the end of the day, the government asks for the renewables to sell at the regulatory cap, that, you know, the different players decide whether or not they want to adhere to that or just follow this on a voluntary basis. But I would say, I mean, let's wait for the final, you know, what the final, you know, draft is on that, but at this point, I would not expect any material impact.
Okay. We have now some
Thanks, Sara.
Thank you, Sara. We now have a question from Jorge Guimarães from JB Capital. Jorge, please go ahead.
Hi, good morning, everyone. I have two questions also on the regulatory front. 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. This is the case with you, I believe. Going forward, are you planning to continue to pay the hydro canon or just stop paying it? The final one is related to Portugal.
What do you believe is the impact of the elections, and more precisely, of not having a budget proposal, on the IVPEE or the special energy tax for 2022? Since it is enshrined in law, it should decrease, but there is no budget. What should we expect for IVPEE in 2022? Many thanks.
Okay, thanks. In relation to the IVPEE, and then I'll pass it over to Rui Teixeira. I mean, it's a good question. To be honest, I don't have the exact answer. I would say that probably the worst-case scenario is it stays, and I'm sure they will be counting on it. If it's not in place by the end of the year, they will probably find a way next year to ensure it is in place. I mean, I have no, let's say, information that leads me to believe that they would eliminate the IVPEE next year or not find a way of keeping it, perhaps just to manage expectations on that side. In relation to the first two questions, I don't know, Rui Teixeira, do you want to take them?
Sure. Well, thank you, Miguel. Related to the first question, I mean, if I understood properly, does it make sense to keep on, say, having some hedging strategies for the renewables in the context of this proposal? I mean, if the price is-
Correct.
Set at the cap. Yeah, I mean, if the price is set at the cap, then of course, it's not important to the hedging. The hedging is there, in our view, because, you know, we currently have a collar, and if we don't want to have the entire generation exposed to volatility within the collar, then we decide to hedge. I mean, if it is sold at the cap, then of course, you know, it's no longer relevant to keep the hedging. As for the second question on the hydro tax, to be clear, there are two different court decisions on hydro taxes in Spain.
There is one which is on the recovery of tax paid in 2013 and 2014, and I would say those are more relevant to main hydro players in Spain, but it's, you know, to our peers, but it's rather immaterial for EDP. 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. This was much more relevant to EDP because most of the hydro plants that we have are located in the Nalón River Basin, which is located only in Asturias.
Therefore, related to these hydro plants located in the Nalón River, we have paid hydro taxes of EUR 19 million between 2013 and 2017, and we provisioned EUR 28 million for potential hydro taxes between 2018 and the beginning of 2021. 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. You had a total cost of EUR 90 million until now, and you just reverted 47. Is that so?
No. We had between 2013 and 2017, EUR 19 million, and then we had provisioned EUR 28 million for the period between 2018 and 2021. Okay? We are now reverting both provisions. Okay? Those are past. Basically, these EUR 47 million were hitting our P&L until now.
Okay, thank you.
Okay, we have two more questions on the phone. Olly Jeffery from Deutsche Bank. Olly, please go ahead.
Hey, thanks very much. Good afternoon. A few questions, please. The first one is going back to the gas financial market hedging. The question is, if you didn't have to incur this non-cash item, would you be lifting guidance for CS&EM, 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? First question. The second one is going back to the procurement cost. 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 products under construction?
Is it so minimal that it, you know, it doesn't register? The last question is kind of looking forward a bit more. 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 GW. The proceeds that you guys are making from your asset rotation, you know, are ahead of plan, such that it looks like you won't need to sell nearly as much GW-wise as you'd expected to hit the EUR 8 billion number.
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, you know, the opportunities are really there and you have the finances to do that? Those are the three questions. Thank you.
Okay. 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. The answer is yes. In terms of the second, the 10% procurement costs or the 10% open for, that's all open to be adjusted for procurement, I mean, it is relatively limited, to be honest. You know, we talk about the 300 basis points of spread. You know, I think it would be relatively residual on that amount, and still well above the 200 basis point spread. You know, 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 five years in renewables. You know, 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. Proceeds are ahead of plan. We do feel we are delivering well. You know, we talked about the 75% already closed for the 2021-2023 period. You know, if we don't need to sell as many gigawatts, and I've mentioned that I think in the past, if we get to the EUR 8 billion, then with fewer gigawatts, that's great. And that's really what we're solving for.
We're solving a balance sheet issue, making sure that we keep the BBB, you know, and are able to execute the investment plan. I don't want to get ahead of myself or ahead of, you know, the company in terms of pointing out whether we're going to revise targets or do anything like that. Certainly, you know, things are going well and on track. The fact that we, you know, built 2.5 GW year on year. That's a huge ramp-up versus what we were building in the past. As I say, we've got a huge amount still of megawatts already under construction over the next couple of months. You know, we are really seeing this big ramp-up.
We are seeing good multiples on the asset rotation. 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 a last question from
Thank you.
Thank you, Olly. We have a last question from the phone, from Arthur. We have some other questions on the web, but given that we are already quite long, I think we will answer the few questions that we have on the web offline. This last question is from Arthur Sitbon from Morgan Stanley. Please, Arthur, go ahead.
Thank you for taking my question. First, just a quick clarification on the provision reversal of the hydro cannon. 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 on the EUR 800 million recurring net income guidance for this year. I just wanted to confirm 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. My third question is just on the EU taxonomy exposure that you're talking about, the 66%.
I was a bit surprised by the 34% that are not included and not compatible with the taxonomy, and I was wondering what those assets are. Is it just the gas and coal plants, or are there other assets that are not included? Thank you.
Great. Arthur, it's Rui here. Just to be clear, this provision reversal was done and booked in the first half. What you're seeing now is, you know, already coming from the first half's results. Then, I mean, in 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, you know, again, comfortable with this EUR 0.8 billion in terms of net profit guidance. You know, we're eager for that. Miguel, do you want to take the… Actually, I would ask Rui for a clarification on the third question. I'm not sure we exactly…
I think you mentioned in the presentation that 66% of your revenues are compatible with the EU taxonomy. I was wondering what assets are not compatible? Essentially, what revenue streams are not compatible?
Hi, Arthur. Just to clarify. I think on the EU taxonomy revenue, we are taking the more restrictive criteria right now. As you know, there are discussions going on in Europe, but we exclude everything that is gas or nuclear, and obviously, even on the energy supply business, 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. 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 to the change in terms of the mix.
We have significantly reduced our supply with the sale of the supply business in Spain to TotalEnergies. We have also reduced our reliance on coal with the shutdown of operations and on gas with the sale of Castejón. We have been expanding our renewable energy portfolio, which is the main change in our year-on-year evolution.
Thank you very much.
I think I'll pass now to Miguel just for some final remarks.
Overall, I think we are doing well, and things are definitely moving forward. Issues with procurement also kept coming up or keep coming up. We will continue to keep you updated on anything there. As I said, we have full visibility. We have pointed to very limited impact, if any, on profitability and completely diluted in the overall CapEx of the company. 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.