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

Hello, everybody, and welcome to the EDP 2021 Full Year Results Presentation. My name is Bethany, and I will be your operator today. [Operator Instructions] I will now hand the call over to your host, Miguel Viana, Head of Investor Relations at EDP, Miguel, over to you.

Good morning, ladies and gentlemen. Thanks for attending EDP's 2021 Results Conference Call. We have today with us our CEO, Miguel Stilwell de Andrade; and our CFO, Rui Teixeira, which will present you the main highlights of 2021 financial performance and also some updates on the 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 insert from now onwards at our web page. This call should last around 60 minutes. I'll give now the floor to our CEO, Miguel Stilwell de Andrade.

Thank you, Miguel. And good morning, everyone. Nice to have you back, and thank you for coming to this call. If we move into the presentation and to talk about the '21 results, I think we can say that in difficult and quite volatile market conditions, we've been able to deliver on the '21 targets. And I think this shows that really we have a good business model. We have a good execution ability and we achieved the results, although with a different composition. Overall, in 2021, our recurring EBITDA rose 7% year-on-year to EUR 3.7 billion, so plus 9% if you exclude the FX. And so we achieved our guidance. In renewables, we added a record 2.6 gigawatts of wind and solar capacity during the year. And regarding asset rotation, we managed to book greater returns than predicted in our business plan and budget. In Networks, we optimized our cost structure in Iberia. We've been driving digitalization and the integration of Viesgo. And also we ramped up EDP's investment activity in Brazil, both in transmission, and we did the acquisition of CELG-T towards the end of last year and distribution as well on the back of good CapEx increase. This strong performance in Renewables and Networks was partially mitigated by substantial increase in European power prices that had a negative impact on the results of our hydro and energy management divisions, mostly due to an increase of energy sourcing costs and also very importantly, upfront negative mark-to-market of gas hedging positions of around EUR 200 million. So just to put this in perspective, in terms of the hydro, at the end of the first 9 months, we were up 13% versus an average year. But in the fourth quarter, we had less than half of the normal volume for an average year. So we ended up the year down 7% versus an average year. Recurring net profit increased 6% to EUR 826 million, in line with the guidance and mainly supported by the EBITDA performance. I'd also would like to highlight on the balance sheet that the net debt figure is the lowest reported by EDP in 14 years, so declining 6% to slightly above EUR 11.5 billion, even after considering the sector-wide working capital negative impact. So we'd included, for example, the most recent asset rotation deal, the net debt fall well below our guidance interval, and also tariff deficit that we sold at the beginning of the year, either of these transactions would reduce the net debt level even further. Regarding dividends, we will be proposing to the Annual Shareholders Meeting in April, the distribution of the dividend of EUR 0.19 per share, aligned with our dividend policy. So all in all, we managed to deliver the growth, but also to improve our overall portfolio and set the stage, I think, for good opportunities ahead of us. If we move to the next slide, Slide 4. So during 2021, we took some important steps towards delivering our 25 business plan targets. In particular, I think, it's worth talking about our growth plan. So total secured capacity of 8.4 gigawatts of renewable projects. As you know, typically long-term contracts, good returns. This represents 40% or more than 40% of our 20-gigawatt target capacity for 2025, and all of this with a low-risk profile. On electricity networks, we ramped up our operations ahead of schedule. So we had CapEx reaching EUR 750 million, covers more than 20% of our 2025 objective, mainly including investments in Brazilian networks. In the meantime, we also provided greater solidity to our balance sheet. So with EDPR is EUR 1.5 billion capital increase, which not only funded our green growth, but also enabled the refinancing of our debt structure with green hybrids at a cheaper rate. So all in all, around EUR 2 billion of hybrids issued -- green hybrids issued with yields below 1.9%. So with all of this, we met our target of maintaining an FFO to net debt of around 20%, which drove the credit rating upgrade from S&P, Moody's and Fitch. So clearly, we've come a long way in terms of getting a much more solid balance sheet. In terms of the funding, we've also increased our share of green funding to 39% and overall brought down the average cost of debt also over the year. Finally, in terms of our contribution to decarbonization, clearly, we have the biggest share of renewable energy production so far, around 75%. This meant that we were included -- EDP was included in the S&P Global Clean Energy Index, and it also contributed to us having a leadership position in the Dow Jones Sustainability Index. So really, I think, a great time to be in the sector and clearly moving in the right direction. If we move on to Slide 5, so throughout the year, we've been reinforcing EDP's green footprint. We reached 21 gigawatts of renewable capacity around the globe. With the acquisition of Sunseap, which we expect to close probably next week, we've expanded into 12 new markets, all of which with good, strong growth prospect, and we've added an overall record of 2.6 gigawatts of gross capacity. So in particular, in Europe, we installed around 700 megawatts of wind onshore, and we entered the Hungarian and U.K. markets. In North America, we strengthened our position in the U.S. and Canada, with around 900 megawatts of wind onshore and around 300 megawatts of solar capacity. In Latin America, we added around 200 megawatts of both solar and wind onshore capacity in Brazil. So all in all, 2021 expansion for renewables, very much aligned with our business plan, and with good expectations around 80% of CapEx investments in Europe and North America. So keeping also this focus on the 2 core geographies. I think it's also worth mentioning the substantial development in the wind offshore gross capacity. So we increased to around 1.5 gigawatts, and that was mostly because of a word of projects in the U.S., U.K., Poland and Korea. Moving on to Slide 6. So here, talking about accelerating growth across all the platforms. Significant amount of PPAs with execution taking a little bit longer, as I talked about previously, but given adjustments driven by the increase in CapEx. So many of these will be announced over the next couple of months. Overall, 8.4 gigawatts of secured capacity, 75% of our 2021 to '23 target additions, so well on way to achieving our target additions. And we do this, as you know, always with a very disciplined approach to investments with returns above 1.4x WACC and around 300 basis points of spread. In terms of profitability, I think it's also worth mentioning, first, that 90% of our secured capacity is protected against CapEx inflation. The second is that we have a significant amount of PPAs in execution, which are taking longer in order to incorporate the higher CapEx costs. So given the recent inflationary pressures on raw materials. So this should translate into increases between EUR 2 to EUR 5 or dollars, depending on the geography in the overall PPA pricing. And many of these PPAs, as I mentioned, will be announced over the next couple of months. For reference, we had literally over 1 gigawatt ready to sign, but we prefer to go back and adjust for changes in the cost and just make sure we have the required profitability for this project. So we are privileging, making sure we get the economics we like and not just the megawatts. Finally, in relation to timing for capacity additions in '22 on track for wind with most of the equipment already on-site or nearby. On the solar project, we have about 1 gigawatt concentrated at the end of the year, could have a delay of 1 to 3 months. So that's something that we are monitoring very, very closely. In a nutshell, we see the supply chain having a short-term impact potentially moving some capacity from '22 to '23, but overall, we don't see it impacting the overall growth plan of 20 gigawatts until 2025. If we move to Slide 7, talking about asset rotation. So here, we had the really strong execution in '21, with gains almost twice as the business plan yearly target. Achieved EUR 1.5 billion of proceeds rotating less megawatts than expected. And so by definition, with mathematically higher gains of EUR 530 million versus the EUR 300 million that we gave as business plan guidance. And also on the transmission side, we closed our first network asset rotation transaction, disposing of 3 transmission lines in Brazil at an attractive multiple and added EUR 46 million of gains to 2021 results. Looking forward, we're starting '22 already with almost EUR 900 million of asset rotation proceeds, so signed in Poland, Spain and the U.S. We communicated this last year. And we're also kicking off the additional transactions to make sure that we complete the asset rotation program for 2022. So all in all, clearly, we continue to see a strong appetite from investors, a lot of demand and the overall execution has been going very well. On Slide 8. Slide 8, we can see in relation to networks. So here in Portugal as the end of December established a new regulatory framework for 2022 to '25. So this provides good visibility on the regulated returns. For '22, we already have now stability in terms of return on RAB at around 4.7%. I think it's important to highlight that over this period, we're keeping an important indexation of our returns and regulated revenues to the evolution of the Portuguese government 10-year bond yield and inflation. In Iberia, our networks platform has also been a focal point of the group's efficiency initiatives, and we had overall controllable cost per customer decreasing by 12% on a pro forma like-for-like basis, mostly driven by digitalization of our networks. We already have almost 70% of smart meter penetration and also the efficiency gains coming from really moving forward with Viesgo's integration. So all in all, medium term, we expect to really drive efficiency based on the efforts on these 2 fronts, targeting 100% of smart meter penetration in the Iberian networks and also the full integration of Viesgo. On Brazilian networks, so last week, we closed the acquisition of CELG-T, which has been rebranded to EDP Goiás at an attractive multiple. And this allowed us to really tap into a region that has good high electricity demand growth and also a big need of infrastructure investment to meet this trend. So we'll be investing EUR 165 million in 2021 as we -- we also invested for the construction of 4 different lines. And on top of this, we've also added 2 new greenfield transmission projects, which represents a total investment of around EUR 80 million. In distribution, here, we've ramped up our investments during '21. We had CapEx increasing by 35% year-on-year to a level 2.7x the regulatory depreciation, so supporting a good growth of our asset base. Again, highlighting the focus in expanding our footprint and also working on improving our portfolio. Finally, last, but not the least, we had the annual tariff updates, which were indexed to inflation. So we had an increase of 12% and 10% increase for EDP Sao Paulo and EDP Espírito Santo tariffs, respectively. So that was also a good update last year. If we move to Slide 10, and this is an extremely important slide. So over the last quarter, energy prices went up, not just in the short term, but also over the next couple of years. And you can see that here on the left-hand side of the chart. For 2022, EDP has a full hedge of its baseload production at roughly EUR 60 per megawatt hour. Given the drought in Iberia in January and February, we're seeing hydro volumes significantly lower than expected. Mentioned around 2 terawatt hours down for our portfolio for this period. On the other hand, and this is extremely important, we've seen very strong increase of thermal demand in the Iberia electricity market due to the low hydro generation and also the net exports to France. So this means that we're, at the same time, increasing substantially our volumes of thermal generation, both gas and coal, which, for EDP, should be more than twice the negative deviation in hydro volumes. Note that these volumes are being sold in the short-term market conditions. And so this means mostly what we're doing is unhedged, unexpected generation that we are producing. I think it's important also just to highlight to manage expectations that the hit on the hydro will be mostly in the first quarter of '22. That's where most of our hydro takes place over the year. And so only partly mitigated by the thermal in the first quarter. Over the rest of the year, we expect that the continued thermal production will compensate for this lower hydro that we had in the -- we're having in the first quarter. For 2023 and '25, we hedged close to 40% of the expected base load generation at an average of EUR 60 per megawatt hour. This hedging is around for 50% for 2023 instead lower than that for '24 and '25 to get the overall 40% average for that period. I think it's important to emphasize, and this is a structural change that given the recent changes in the market context, we will be increasing the weight of merchant volumes in our generation portfolio going forward and making sure that we optimize the hedging strategy. On Slide 11 and moving on to people and really the talent that we are attracting. I think, as you know, we are growing very strongly in renewables, very strongly on the retail side and on distributed generation. So we really think that organization is also a key steppingstone to make sure we have a future proof organization. In 2021, the renewables platform grew around 21% in terms of overall headcount, mainly on the back of the strong expansion activity carried out through '21. Obviously, by definition, if we have more projects and more megawatts, we need to have a work force to go along with that and deliver on that. However, at the same time, we managed to keep the overall headcount stable at the group level because given just the digitalization of many of the processes and the efficiency overall that we're getting across some of the more conventional generation and distribution and things like the Viesgo integration, we had a net -- well, a slight net increase, but with the reduction in the more conventional legacy areas and an increase in the newer growth areas. So I think it's really great to be able to be recruiting overall across the board, which is really important also for having a strong succession plan for the top management positions. I think I'd also like to highlight that, in 2021, 81% of the open management positions were filled by EDP professionals, so internal hires, so moving people within the organization. And I think that shows we have a really strong bench of talent internally. In terms of making sure we also have a good alignment, the weight of the variable remuneration is being reinforced and aligning it with the 3 pillars of the business plan. So the growth objectives, the future-proof organization objectives in terms of digital and innovation and also the ESG excellence, making sure that we have that alignment across the organization. Overall, we've been an industry leader in terms of employee engagement ladders, comparing very well and above the general market and the sector's benchmark and high-performance companies. And so we've been recognized as a top employer in multiple regions. And I think that's one of the things that really has distinguished us and enabled us to continue to grow successfully. Just before I hand over to Rui, just to talk about our ESG targets and what we've been doing here across the board in terms of metrics. First, in terms of our generation -- renewable generation, we achieved 75% of the total production coming from these technologies. The revenues aligned with the EU taxonomy also rose to 63% and have given us good visibility on achieving the overall target of 70% by 2025. Then we continue to work on reducing the specific emissions throughout the year. 2021 was penalized by the hydro crisis in Brazil that prompted the higher utilization rate of [ Pecém ] thermal plant, which has now been reduced. We will have some increase in Iberia because of what I mentioned earlier. Overall, and I think this is important, these achievements were highlighted by top-tier institutions. So we had the Dow Jones Sustainability Index naming EDP as the most sustainable electric utility in the world, the best results so far in terms of overall performance. The S&P Global Index also attributed EDP and EDPR's top 10 position in the clean energy index. And Bloomberg also included EDP and EDPR and its Gender Equality Index. And so I think also good achievements for the year more on the ESG front. With that being said, I'll now pass the word to Rui Teixeira for a more detailed analysis of the '21 results. I'll come back for closing remarks.

Thank you, Miguel, and good morning to you all. So now let's deep dive into the EDP's performance for 2021. So moving to Slide 14. Recurring EBITDA increased 7% to EUR 3.74 billion. That's a 9% increase if we are to exclude the ForEx impact. The recurring EBITDA for renewables platform was up by 4%, with positive results supported by the strong performance of the asset rotation strategy, definitely overcompensating the weak effect that we have, or the year that we have in the hydro, namely in Iberia. In electricity networks, the recurring EBITDA increased by 51%, driven by the expansion in Iberia due to the acquisition of Viesgo, and then Brazil, due to the commissioning of new transmission lines. Finally, a note on the client solutions and energy management platform, that, as you know, was penalized by the sharp increase in the energy prices. And of course, this also compares to an exceptional positive performance in 2020, but we'll deep dive a little bit into that in a few slides. So if we move now to Slide 15. The EBITDA from EDPR increased 6%, year-on-year. There was a positive impact driven by the asset rotation gains of what we were initially foreseeing that reached EUR 530 million in 2021, and 1% increase in the average selling price that reflects a significant recovery, particularly in Europe versus the 9-month 2021. And these effects were somewhat mitigated by weak wind resources that's 4% below average and some adverse ForEx impact driven by the depreciation, about 4% of U.S. dollar against euro. On Slide 16 and looking now to the hydro. So adjusted by the change in the consolidation perimeter, hydro recurring EBITDA decreased 3%. In Iberia, EBITDA decreased 16% year-on-year. This is negatively impacted by the low hydro resources that despite being 13% above the average level in Portugal in the first 9 months of the year, they were 57% below average in the fourth quarter of '21. This was coupled with pre-hedged volumes and a strong increase in electricity prices in the end of the year. In the Brazilian market, hydro EBITDA increased 38%. Despite the hydro crisis in Brazil, performance was well supported by the hedging strategy, with more energy allocated towards the second half of the year, combined with the recovery of resources in the same period, which naturally led to an increase in terms of the hydro production in this region. Now in networks, if you move to Slide 17, it was marked definitely by a strong performance on this platform, with the recurring EBITDA increasing 51% on the year. In Iberia, EBITDA increased 48%. This is on the back of the Viesgo's integration, which more than doubled the operations in the region, a positive impact from the reversion of provision on regulated revenues in Spain and a positive impact of around EUR 54 million in Portugal due to OpEx savings as a result of the gradual increase in digitalization, namely the rollout of the smart meters. In Brazil, EBITDA rose 57% to EUR 427 million, that's a 73% increase in local currency. And this includes the increase of -- in volumes of distributed electricity that were up 7% year-on-year, the positive impact from inflation indexation on distribution and rural tariff updates, and the asset rotation gain of around EUR 46 million that is a result of the sell-down of the 3 transmission lots to Actis. So definitely good performance on the Networks business. On client solutions and energy management, on Slide 18. Recurring EBITDA declined 73% year-on-year versus an exceptionally strong performance in 2020, which still included a positive contribution to EBITDA of around EUR 22 million from the Sines thermal plant that, as you know, was shut down at the end of that year. 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, particularly in the end of the year. This, of course, increased the energy sourcing costs and also imply the negative mark-to-market impact from hedging contracts for future periods, so beyond 2022. These mark-to-market losses are mostly noncash. They are expected to be offset by higher operating margins in the following years. On this quarter, these negative impacts were partially compensated by increase in client service penetration, which we expect to keep increasing since the energy efficiencies become more and more relevant in this environment of surging energy prices. In Brazil, also worth mentioning that the positive impact regarding the higher availability of the Pecém plants was partly offset by rising fuel procurement costs that impacted the coal stocks. So now moving to Slide 19, because I think it's important also to provide some, again, additional information about the performance on an integrated basis -- an integrated portfolio basis. So the fact that we hold this diversified generation portfolio in Iberia, I think it was critical to mitigate these negative impacts. So in 2021, the energy sourcing costs were about EUR 0.2 billion higher than we would have assumed in our perspective for the year, and mainly on the back of the slight short position in terms of volumes satisfied the needs of the -- in terms of energy supply activities, which were amplified by the sharp increase in terms of the energy prices. This increase of energy sourcing costs was essentially offset by higher end contracted volumes and margins in thermal generation, and then an increase in terms of realized price on the -- or the realized price premiums in the hydro generation versus what we were expecting throughout the year. So overall, these 2 factors, the higher cost in terms of sourcing, but also the higher margins in terms of thermal and the higher realized price on the hydro compensated each other. Then we have a negative EUR 0.2 billion deviation of our integrated margin in 2021 versus our estimates that was mostly justified by the negative mark-to-market of gas financial hedging that is partly to be reverted through operational margins, mostly through 2022 and '23. So these are, again, noncash mark-to-market that we are having as an impact in our P&L. So now moving to the financial costs, on Slide 20. So adjusting by nonrecurring items and their financing costs, noninterest related, those are the cost of repurchase of outstanding bonds, so liability management that we did throughout the year. the acquisition of the minority stake in Soto 4, combined cycle in Spain and the ForEx differences. Adjusted net financial interest remained flat year-on-year, driven by the decline in the average net debt, that's around EUR 700 million, and 20-basis-point increase in average cost of debt, mostly driven by the rising cost of the Brazilian real denominated debt, which is indexed to inflation and represents about 12% of our total debt. Note that the average cost of debt in Brazilian reals increased 320 basis points to 9.3%. I think it's also worthwhile highlighting that the EUR 2 billion of green hybrid bonds that were issued throughout the year, they solidify the share of green financing, with green bonds now representing 39% of EDP's total financial debts. So now on Slide 21, just some comments on how we are protected against inflationary and interest rate pressures. I'd like to highlight that the portfolio -- of what is the portfolio sensitivity to these elements. So regarding inflation, we can break down the gross profits in about 35% of merchant hedged, which are mostly contracted in the Iberian electricity market, which carries potential upside in a rising price context, particularly as the hedges roll over. So as mentioned, we have a very high level of hedging for 2022, but then 40% hedged for '23 to '25, of which 50% in '23 going down to around 30%, 35% in 2025. So the second point is that about 40% of our gross profit is linked to inflation, which act as a natural hedge. This refers almost 100% of the operations in Brazil, networks in Portugal and around 30% of EDPR's revenues. And finally, flat revenues that represent 25% of the whole portfolio and are mostly related to electricity networks in Spain, another 30% of EDPR's revenue mix. So regarding the debt structure, close to 70% of the debt is contracted at fixed rates and more than 50% of maturities are scheduled post 2025. So all in all, we remain well protected against inflation and rising yields, with a significant share of revenues linked to inflation and the debt structure mainly contracted at fixed rates. So now if you look to net debt in Slide 22. So as mentioned by Miguel in the beginning of the presentation, we delivered on our deleverage commitment, increasing our FFO to net debt to 21%. With this being said, net debt decreased EUR 0.7 billion to EUR 11.6 billion, and this is the result of recurring organic cash flow of around EUR 0.6 billion. And here, just to highlight that we were penalized by a total negative impact of around EUR 1.2 billion associated with the increase of energy prices. So that's around EUR 0.8 billion increase from working capital and negative noncash impacts from the mark-to-market of derivatives. Also noting that just by these factors, the organic cash flow would be EUR 1.8 billion in 2021. Additionally, net expansion investments amounted EUR 2 billion, following, of course, the acceleration of the build-out activity, with EUR 3.3 billion of gross expansion investment. And this was partly offset by the EUR 1.4 billion proceeds from the asset rotation deals that we concluded throughout the year. We also have a positive impact from the EUR 1.1 billion proceeds from the EDPR capital increase in April, and about EUR 1 billion relative to the 50% equity content associated with the 2 billion hybrid bond that issued in 2021. And finally, effect of exchange rate fluctuations had a negative impact of around EUR 0.3 billion on net debt due to a USD 8% appreciation against euro has a positive impact of EUR 0.7 billion reduction of regulatory receivables, mostly in Portugal. So finally, assuming that the asset rotation transaction is -- in Portugal was closed within 2021 financial year, net debt declined to EUR 11.2. Just a final note. Recurring net profit increased 6% to EUR 826 million in 2021. That's the growth in EBIT and improvement of financial costs over power, the increase in noncontrolling interest. So additionally, the net nonrecurring items at net profit level increased from EUR 26 million in 2020 to EUR 169 million in 2021, leading to a reported net profit of EUR 657 million. As we described before, these nonrecurring items in 2021 are mainly related to impairments in our thermal power plants in Iberia. And with this being said, I want to share that we are very committed with what is ahead and the challenges ahead. Thank you all for the opportunity today. And, Miguel, I'll pass over to you for the final remarks.

Okay. Thank you, Rui. So just to wrap up the presentation and just highlighting here some of the key points. First of all, we delivered on the '21 guidance. So we had a strong growth in the networks. We had good returns on the asset rotations. And that ended up offsetting the weaker energy management results, which were very much penalized by the adverse mark-to-market impacts. And so important to note that these will be reverted over the following years. So this shows I think that there is value and the diversification of our asset base and having a good risk management and portfolio quality. The overall volatility in the wholesale price and also the average hedge of the baseload from '23 to '25, so it's now 40% hedge at an average of EUR 60 per megawatt hour, it creates the conditions so that we can increase the structural weight of merchant volumes in our generation portfolio to really optimize our hedging strategy. If we look forward and talking about renewals, the 8.4 gigawatts secured represents 75% of our target for '23, and, as I mentioned earlier, booked with long-term contracts at attractive returns. And that gives us good visibility on the delivery of our target 20 gigawatts by 2025. So we've done well on the asset rotation strategy. We booked gains twice as large as the business plans yearly target for the same scope of assets. I think this is really important. So doubled the gains per megawatt that we are expecting in the absolute terms as well. Entering '22, we are committed to maintaining this level of performance. So we already have EUR 800 million in asset rotation proceeds, so on track for delivering the '25 objectives. In parallel with the growth, we are protected against inflationary interest rate pressures. Rui talked already about that. More than 70% of our gross profits are not fixed, and 70% of our debt portfolio contracted at fixed rate. Finally, we continue to accelerate the contribution to decarbonization, the largest weight yet of renewables in our energy mix and improved and aligned with the EU taxonomy. And then also EDP's recognition of the world's most sustainable electric utility by the Dow Jones Sustainability Index and the top 10 weight in the S&P Global Clean Energy index. So I'll stop there. So thank you once again for the results call, and we can now move to Q&A. Thank you.

[Operator Instructions] The first question comes from Stefano Bezzato at Credit Suisse.

I have 3 questions, if I may. The first one is if you can clarify what the impact on fuel costs and energy management EBITDA you expect from the current hydro situation in Iberia? In other words, if you had to roll forward Page 19 of the presentation to 2022, how would that chart look? The second question is on asset rotation. What is your expectation for 2022 in terms of asset rotation gains? And how does this split between unitary gain and amount of capacity that you are planning to sell down? And the third question is pretty much consequence of the first 2 questions, which is, can you comment on the current level of consensus for 2022? I think in the file that you sent around a couple of days ago, you had highlighted EUR 4 billion EBITDA and EUR 940 million net income. Are you comfortable with these levels?

Thank you, Stefano. So in relation to the first one, I can probably pass it to Rui. I'll just answer the second and the third one. So in relation to the asset rotation gains for 2022, we expect it to be comfortably above the EUR 300 million that was in our business plan. And so just based on what we've already signed last year, and what we are kicking off now, we would expect not only to continue to deliver on the proceeds, but also in terms of overall absolute gains being above what we had in the business plan. So that's what would be my expectation. I'm not giving you a specific number, but clearly above the EUR 300 million. On the current level of consensus, as you know, we don't typically provide guidance at this stage, precisely, because this first quarter of the year is extremely volatile depending on the hydro and all of that. But overall, I would say, and we still have to evaluate them the first -- the results of the first quarter. But typically, we would be looking for some growth versus the previous year, both in EBITDA and in net income. We will obviously talk more about this in the first quarter results. I'll pass it over to Rui for the first one.

Thank you, Miguel. Thank you, Stefano, for the question. So as you know, I mean, throughout the year, what we are currently seeing is that we will have, at least for the time being, 2 terawatt hours of less hydro generation. We might have around 4 terawatt hours in terms of thermal. So we are seeing the spreads expanding. I would say that, at this point, we would still see some compensation throughout the year. Having said that, I mean, first quarter, of course, we don't have that thermal margins compensate -- or the spreads compensating for the loss of the hydro. But throughout the year, at this point, I would expect the thermal spreads to mitigate the reduction in terms of hydro volumes.

The next question comes from Manuel Palomo at BNP Paribas.

I've got a few questions. I will stick to 2 or 3. First question is on -- again, on one of your slides, which you say that your baseload production is hedged at EUR 60 per megawatt hour. My question is, for the year 2022, what is your assumption on hydro because you said that now you plan to have 2-terawatt hour less, but we do not know what was the starting point? And also whether you could please comment on the impact on your expected EBITDA from replacing 1 terawatt hour of hydro with 1/3 hour of thermals? Then second question is on the impairment in Iberia, I think that they amounted to EUR 232 million. I was wondering whether you could tell us what assets have been impacted, maybe Sines maybe some of the Spanish plants? And what has changed? Because if I'm not wrong, you were not expecting these provisions. And I think that I will leave it here. I'm sure that there's plenty of questions from other people.

Okay, Manuel, thank you. So I'll do the one on the impairments, and we can talk about the first question on the baseload assumptions. In terms of the impairment, as you know, we do the -- I mean, on an annual basis, we look at what is, let's say, the fair value versus what is on the registered books. And I think what we've seen and that was, let's say, the results of the impairment test this year is that if you look at the overall value of the combined cycles, we're talking combined cycles, we're not talking about Sines or any of the coal plants because those have been pretty much all amortized small exception of Abono, but everything else has been totally amortized. So that's been -- that's at 0. But in relation to the combined cycles, we did an impairment given, let's say, the fair value that we expect over the long run. So that's the test we do every year. Last year, we've also done some impairments on the combined cycles. As you know, we have an objective of, let's say, being coal-free by 2025 and being all green by 2030, and that's -- it's consistent also with the way we're looking at that. In relation to the first point, Rui?

Thank you, Miguel. So Manuel, just to give you a sort of a perspective here. So we expect -- our average hydro here should be around 8 terawatt hours. So that's sort of the reference. I mean, the 2022 production is hedged, I would say, slightly above EUR 60 per megawatt hour. So basically, if we have a gap of those 2-terawatt hours, so if you ask me what is 1 terawatt hour hydro versus the terawatt hour thermal, of course, then we will be losing those EUR 60 . but on the thermal side, in terms of the spreads, what we were seeing is around spreads above EUR 60 -- actually around EUR 80 per megawatt hour in the first quarter and then reducing over time over the year. So I would say that's why I would expect some mitigation impact from the thermal throughout the year. But of course, in the first quarter, I mean, we cannot have the thermal compensating for the loss of the hydro in its full extent.

The next question comes from Alberto Gandolfi at Goldman Sachs.

I'll skip over returns and CapEx because I think it was very clearly yesterday, but maybe 3 on my end as well. The first one is just to understand 100% sure the definition of recurring net income, the EUR 826 million. I went through it last year just to be sure I'm not making any mistake. So the EUR 826 million, for instance, does not include liability management, does not include the impairment, but includes asset rotation gains, of course. So if that is the case, what would be the impact of -- within the EUR 826 million from the asset rotation gains? I think you have like EUR 1200-something million gross in EDPR and another EUR 46 million in Brazil. I don't know if I missed anything. So what I'm trying to say is that are we talking about a EUR 450 million net income, excluding capital gains, and I know you had losses in the U.S., the hydro was not great. So maybe you were talking more about [ 5600 ] but I'm trying to gauge what is the underlying net income starting point in '21 we should use for the 2022 forecast. The second question is on energy bills affordability. I don't know if we haven't seen it or if just Portugal has been really a positive, very good exception here because the debates on affordability is huge in Italy and Spain and electricity bills and gas bills are up, basically, they have doubled, right, for consumers. So they also have doubled, I expect, for Portuguese consumers. And I was wondering if you hear any measures that the government is working on? And what could this be? Is it a fiscal measure? May you be required to contribute a bit to that? Or, on the other side, perhaps, given elections and a bit less extreme left part is perhaps now actually the debate is even more relaxed than it used to be. So it will be very helpful to have your thoughts on how you're thinking about this tail risk. Last not least, I wanted to ask you, yesterday, you made clear that you seem to be basically a little bit ahead of your own plan in terms of renewable additions. And it's very good that you have secured all of those projects. And I guess, versus your original plan, now you're also expanding into Asia Pacific. So my question is, your organization, how quickly could you upgrade further your annual growth rate? And how would you be able to fund it? Would you be -- would it be open in a couple of years, a year time to use more equity at the EDPR level? Do you have room for hybrids? Do you think you can take on more leverage now that your net debt has been coming down? So just trying to think capital structure in the context of expanding project opportunities.

Thank you, Alberto. So I'll go through the 3 questions and then maybe if Rui wants to complement some of them. But I'd say that in relation to the definition of net income, so it's our standard definition. It doesn't include nonrecurring or things that are exceptional, so things like liability management, as you mentioned, or the impairments, which are done one-off test. And if they are registered as an impairment, then you have to write it off, and I think that's a common practice across the industry. In terms of the asset rotation gain, I mean, that's part of our business model. And as you know, we've been doing that for a number of years, and it's what we include in the recurring net income definition. So both the 2 numbers that you mentioned, the around the EUR 500 million and the EUR 46 million, obviously, you need to take into account also minorities. So that has to be adjusted when you're looking at the EUR 826 million number because obviously, those values are for the -- let's say, for the EDPR and EDP Brazil, respectively, numbers. So that's just what you need to bear in mind also when working out what is the, let's say, net income, excluding asset rotation gain. On the second question, which is -- I mean it's a great question. So energy bill affordability, we do see that across Europe in many of the markets where we are. In Portugal, as you know, we have a slightly different situation. First, we had some costs, which came off last year in the system as a whole. So things like the Pegos coal plant, which had a very generous PPA. That rolled off. That was like EUR 100 million. The government also decided to inject things like the CO2 revenues auctions that they're getting. And we also have a very high level of renewables. And so what used to be a tariff deficit is actually currently a super surplus. And so when all those things were put together, it was possible to reduce the excess tariffs to let's say the tariff was shared between all the different consumers. And that compensated for the increase in the wholesale price. And I'm talking of mostly domestic consumers, so B2C. So the sum -- the net of these 2, so you're increasing the wholesale price, but a decrease in the, let's say, the access tariff from the over cost of renewables and the other things I mentioned, ended up meaning that the increase '22 versus '21 in the regulated tariff was actually minimal. And so that really means that the whole discussion around energy bill affordability in Portugal at the moment is not an issue. For the customers -- the B2B customers, slightly different. There, the excess tariff doesn't have as much weight. So even when you reduce it, it doesn't compensate fully for the wholesale price. There, what we see is the customers, the B2B customers doing longer-term contracts. So we've seen a significant increase in the number of customers contracting 5-plus years versus in the past, I'd say the vast majority would contract 12, 18 months and then just go on renewing -- just go on and do new contracts. Now a lot of them are coming to us and asking for this 5- to 10-year contract, and there, we're pricing in the 5- to 10-year expected market price. In terms of the third question, so in relation to upgrading growth in Asia Pacific, I'll actually be in Asia next week and get a better feeling for it. But clearly, we do see a lot of growth potential there. What we set out in our business plan was already pretty ambitious so the 20 gigawatts. And we did a capital increase last year precisely so that we would feel comfortable in funding that business plan to the fullest. Now at the renewable levels, we are getting good asset rotation gains and proceeds from even less megawatts. So that's, I think, also a good source of financing. So I definitely -- sort of where I'm sitting today, I don't see the need for additional leverage or capital increases or I think we can fund it through the ordinary course of business. I mean, certainly, the current business plan. And if we were to do a change to the current business plan, we would have to obviously sit down and think about how we finance it. But I think that's not something which is on the table at the moment. Okay, I don't know Rui, if you want to comment on the first one?

No. Maybe just additional comment, just related to Spain on the -- related to the second question. because we know that this is -- the market is aware that there is an ongoing discussion between the Spanish government and the sector. I think that just recently, at least my view is that there is some openness to discuss some potential short-term tariff deficit, which is, from a financial perspective, something very valuable. But also the positioning from the Spanish government that they want, whatever is done is -- has to be done in agreement with the sector. So I think my -- there's a positive view there that these ongoing discussions that will -- hopefully will result in some sort of changes if agreed upon.

The next question comes from Arthur Sitbon at Morgan Stanley.

So my first question is on the working capital deterioration that you highlighted. I think it was EUR 1.2 billion. I was wondering if you could help us understand a bit the timing -- the potential timing for normalization there? My second question is a follow-up on hydro. It seems that you're confident that throughout the year in 2022, thermal will offset the weakness in hydro. But I was wondering if this is at the given hydro production now. Or -- and is it assuming a normalization of hydro in Q2, Q3, Q4? Or did assume a weak hydro production for the whole year?

So regarding the working capital, again, I mean, this is basically though -- so when we are buying electricity from the market, and this goes to December, we are, of course, buying -- pretty much paying it at that moment. But then customers receivables, we have about sort of 30 days. So we'll get -- we have that cash received then in sort of a month from that point. So I would say that throughout 2022, I mean these amounts are effectively going to be settled. So this is much more of an impact from these very high power prices that we felt, particularly in December, and then this gets reversed throughout the beginning of 2022. And then, of course, we'll see on -- how it evolves over the power prices, how they evolve throughout the year. But unless we have that sort of a peak that we saw in December, I mean, this should be normalizing. Also an additional impact in terms of working capital was that because of those high power prices, all the hedges that we have, in some cases, we have to post some cash collaterals. I mean something very reasonable within, of course, there are no stresses in terms of liquidity for EDP, but that also restricted some cash movement. So that's why you see this -- those 2 impacts are primarily what is causing this higher working capital by the end of 2021. In terms of the hydro, when we -- I mean it's considering that there will be a normalization throughout the year. So what we would expect is that from -- let's hope this from March onwards, we get normalized, so not necessarily recovering the gap in January and February, but normalizing throughout the year.

The next question comes from Sara Piccinini from Mediabanca.

I have 3, hopefully, very quick. So the first one is on the guidance for 2022. I understand that you cannot provide a number, but maybe, as you said, you expect some growth. So can you please indicate what are the drivers that should compensate the weak hydro and the weak energy management and that justify this growth for 2022? The second question is on Viesgo. So you say that you are ahead of schedule. If you maybe can quantify the synergies that you have achieved and that you expect -- if you expect to increase this level of synergies also in 2022? The third was on the working capital that was addressed, but maybe, if, in this case, you can give an indication of the net debt so that you expect for 2022 also considering the CapEx and the price for Sunseap? And finally, the last question is on the capacity addition. So maybe I'm doing something wrong, but as you said in the presentation last day, you are expecting more than 3.5 gigawatt increase on average for 2022, '23. And as of today, you have secured 5.3 gigawatts for these 2 years, so for 2022, '23. So we are missing still 1.5 gigawatt. Does it means that -- how do you intend to accelerate on these capacity additions? And in this case, it can include also some M&A?

Okay. Thank you, Sara. So I'd say, in relation to the first question, I mean, in terms of guidance, as I say, we're not -- we don't give numbers for the -- at this point in time just given the uncertainty still in terms of the hydro conditions overall. But what I'd say is that, in the normal conditions, we'd see an increase in -- just in the renewables overall, typically networks, I mean it had a very good year last year, but we continue to expect it to perform well. I mean under normal conditions, we see the supply business also doing very well. And then obviously, we have all of the, let's say, the conventional generation, which, as I mentioned, depending on -- or assuming that we have a normalization of hydro conditions after the first quarter, we would have that very much compensated by the thermal. And so you'd end up more in line in terms of what would be our expected numbers for energy management throughout the year. And so sort of when you sum all these different parts, and we can get into that more in the first quarter results, we would have some growth. But anyway, let's talk about that in the first quarter numbers because there will have a full picture of what's actually happened during the first 3 months. In terms of the Viesgo's synergies. So we don't quantify them explicitly, but overall, they're in line with what we -- what the market has been estimating, which is around EUR 20 million of operational synergies. Then there are also some tax synergies, which we talked about at the time of the acquisition, and that is also coming through. So I'd say that we are very much in line in terms of the synergies, obviously trying to frontload them as much as possible. And so I'd say it's on track or even better than what we had. Working capital, net debt, ' 22, Rui, you want to take that one?

Yes, sure, Miguel. So I mean, for 2022, again, without providing specific guidance, I mean, yes, we'll be paying Sunseap acquisition, hopefully closing next week or so. Of course, we'll have the execution of the growth and the CapEx plan for 2022. The asset rotation proceeds. So as you know, the cash in from the sell-down of the Portuguese transaction was already booked and received in January. We have already 3 transactions signed that will be closed in 2022. And of course, we are setting up the -- and actually kicking up the transactions, remaining transactions for 2022. So those asset rotations at EDPR, would also have a positive impact in terms of cash. And then in terms of the organic cash flow, we do expect a significant improvement versus the end of 2021 because of what I said. I mean, we have abnormally high power prices. that had that impact in terms of receivables and some cash collaterals. So all in all, I would expect that net debt to increase, mostly driven, of course, by the expansion plan and the acquisition of Sunseap, but in terms of ratios, of course, meeting the target towards the BBB rating that we currently have.

And Sara, in relation to the last point, the capacity additions. So what I'd say is that we had several PPAs more than 1 gigawatt that was ready to sign by the end of last year, which aren't included in those numbers that you talked about. We delayed that because we went back and we renegotiated the price to include the increases in CapEx that we were seeing happen at the time. So that resulted in, let's say, a readjustment of $2 to $5 or euro depending on the geography. And so those are expected to be signed over the next couple of weeks, months. But that but a gigawatt, which was -- which we clearly have already identified from an organic perspective. I'd say that we continue to work very much on the organic side or semi-organic, some that are ready to build. But above all, I think what we've always stressed is that the investments should comply with our overall return investment criteria, so the 1.4x WACC or the minimum 2% spread over WACC. So as well as some of the other metrics in terms of payback periods and sort of ability to resist stress test. But so that's what obviously underlies our investment criteria. But as I say, we have I think, a good pipeline still over the next couple of weeks and months.

The next question comes from Javier Garrido at JPMorgan.

Apologies for coming back to the same topic, but I was wondering if you could be a bit more specific about the dynamics of the thermal offset in 2022? because I think there is some confusion given that you're talking of 2 terawatts hour lower hydro production, you still put -- or hedge at EUR 60 per megawatt hour. So could you just put a bit more light on how the thermal offset would work in terms of numbers in order to fully offset losing those 2 terawatt hours of hydro production? And then the second question is on the marking to market -- the negative impact of the mark-to-market in 2021. If you could be a bit more specific about when do you think this net in mark-to-market will revert? And actually what would be your expectations with the current gas prices? I understand that this mark-to-market is obviously very volatile depending on the gas price. But given where gas prices are now, what would be your expectation for the year?

Okay. Javier, so let me start by the second one. So for the contract -- the gas contracts that we have, I mean, our hedging policy is that we are locking in the spread. So basically, we buy those -- that gas at Henry Hub. And we will then use that gas as a reference to the TTF in Iberia. So basically, we lock in that spread for the next years, for '22, '23 onwards. So those volumes that are related to those future deliveries, what's happened is that because we -- we then -- we lock in that TTF at the price which is lower than currently is in the market. And of course, we may have to book a negative mark-to-market today because those are future volumes, we cannot treat it as a hedge instrument, and therefore, we need to treat it as a speculative instrument. And that's what is causing the mark-to-market impact, that negative mark-to-market impact, which is affecting this -- the delta between the TTF prices that we saw in particularly late 2021 and then -- and versus the hedging prices. These volumes -- I mean, we will be consuming these volumes in 2022, in 2023, then there's a small portion goes into 2024. But I would say the bulk, the majority will be in 2022. So basically, what you will see is that when we have the physical use of the gas, basically, we will be unwinding this position. So we will not have an impact then in terms of the margins. I mean the margins will be selling the output or selling to customers. And the sourcing cost will be the hedge that we have when we close it. So that's why we say that this is, again, a noncash item, and it is unwinding have this impact in Bristol going forward. Unless, of course, I mean, gas prices go again through the roof. If you ask me what is -- what do we forecast? I think it's hard to say that. I mean what we see is extreme volatility. Nowadays, it's much more related to geopolitical tensions between Russia and Ukraine and of course, Europe, more than the fundamentals of the gas. And we saw last few days that there was some positive news flow around the geopolitical case and gas prices corrected going down. Recently, they have been going up again. So again, I think there is volatility in there. It's hard to predict where the gas prices will go in the nearby future. But other than the geopolitical case, we would see the gas prices progressively going down throughout the year. Also winter has not been very cold. We're getting through the winter as well. So from a fundamental perspective, we would expect gas prices going down, but again, high volatility coming from a geopolitical case. Towards the first question, so just to be clear, I mean, yes, we have -- we would have a gap on those 2 terawatt hours in terms of the hydro, but also there is a mitigation impact, which comes from the clean dark spreads. So the thermal spreads that we have in the coal plants that are operating in Spain, they have widened substantially, particularly in the first quarter, then they are reducing over the quarters towards the year-end. So that's how we can mitigate that impact coming from the lack of hydro through the thermal spreads. Now having said that, again, I mean, it's -- we will see that happening throughout the year, but not necessarily in the first quarter.

May I have a follow-up on your gas -- on your gas contracts, because can you let us know whether you are fully hedged into 2023? Because as the spreads have widened, would you have some exposures and open position to that widening of the spread?

I mean we don't have it fully closed for 2023. I mean the way also we are hedging those gas positions is making sure that we are meeting also with the commitments that we have either from selling to customers or then using that gas at the CCGT. So basically, we try to hedge this having an integrated view between what is the sourcing of the gas and the use of the gas in the power side. So it's not fully hedged for 2023.

The next question comes from Jorge Guimarães at JB Capital.

I have 2 questions, 2 of them are follow-ups. So the first one would be a follow-up on the hydro versus coal switch that you are saying. When you say that you are 2 terawatt short of hydro, I assume you mentioned just Q1, if I'm not mistaken, and please correct me if I'm wrong. If that is the case, and you were saying that the spread -- the dark spreads will go down throughout the year, then you'll need to produce much more coal to compensate the loss -- the loss or the less lower gain that sustained in Q1. So if you could -- sorry to come back to this question, but if you can help us navigating through this, it would be helpful. The second one, it's also related to water. I believe I understood some -- during the call that you said that your average production of water in Iberia is 8 terawatt hour. Is this the average hydro year? Or is this the 80% of volume hedged that you mentioned in the past? I mean, so this is the P50, right? Or is 80% of the P50? So sorry, if I'm not totally clear, but the question at the end of the day is your average hydro production is 8 terawatt hours or 10 terawatt hours for an average hydro year? And the final one is very specific on Portugal. Can you -- given the new regulation of Portuguese distribution, is it still possible to recover significant amount of OpEx guidance? Or will those be translated into lower OpEx later in the next regulatory period?

Okay. So on the hydro versus coal, and if you want -- no, of course, we can take this offline, so that we can get through more in detail. But again, the overall concept is, yes, we will be in principle short of these 2 terawatt hours. I mean it's just -- it doesn't rain. So it's a fact. But that thermal capacity that we have, in this case, the coal capacity that we have in Spain, I mean as we were securing those thermal spreads over the last month or the last months, we are able to compensate part of that lack of hydro with that higher spreads on thermal. But we can follow up a bit more in detail, and we can take it off-line. The hydro just be clear, the 8 terawatt hours is our average expected production in Iberia Peninsula, right? So that's what -- it's not what we hedge, it's what we produce.

So the 8 is the average?

Correct.

It is the average to which -- so the 2 is 25% of the overall average.

Okay.

In relation to the distribution in Portugal, I mean, we continue to optimize it. And so I think you'll have seen in one of the slides we had sort of some of the reduction in headcount that we continue to see as we continue to bring smart meters on board as we continue to automate and digitalize the company, there are still OpEx gains to be had and there's a mechanism mode of how we share those gains then with the system. But it's clearly still work in progress. I mean, obviously, the -- let's say, it's not a huge amount given a lot of that work has been done over the many years, but it continues to be possible to optimize, particularly on the headcount and given sort of the ability to digitalize the processes.

The next question is from Gonzalo Sanchez-Bordona at UBS.

I have 2 questions and one clarification with, if I may. I think you said that the thermal spreads are now sound at the beginning of the year was something like or 80 or 18. Could you clarify what number was at because I didn't quite get it. And then on the question side. So one is a bit more strategic. Is this much reduced hydro production that you're seeing in Iberia at the moment in the fourth quarter of last year, at the beginning of this one, still, we think kind of the normal parameters that you expect based on your long-term studies? Or you think there is some kind of structural change ongoing? And if that's the case, would that change your kind of long-term view, particularly for the 2025 plan or even up to 2030? Like would you do something different if that was the case? And then the second question is you've been on previous calls, commenting that you were looking at potential options to optimize the portfolio. And I think you mentioned at some point, things happening in Brazil. What is the status of that? There's been any developments or potential sale of hydro assets or other assets or redeployment of CapEx there between the current portfolio and other new assets. So any light on that, that will be appreciated.

So, Rui, do you want to take the thermal spread to clarify.

Sure, absolutely, Miguel. So Gonzalo, I mean, just to be clear, if you go back to December and you look to the thermal spread, the clean dark spread at the time, you can easily find moments in time where spreads were around the 80. I mean nowadays, if you move to the -- at least for the first quarter. If you now look to the spreads throughout the year, throughout the quarters, you will see that there is -- I mean, they are declining. They are compressing. So I would say they are more now towards the 20, 30. So I would say overall, on average throughout 2022, we should be above the 30s. But the first quarter, particularly if you -- looking back to December, they were quite high.

Okay. And on the second and third questions. On the second question, I mean, obviously, we had -- we are having very dry months. Is this a structural change? I mean no, we've seen -- 2012 was extremely dry. 2005 was extremely dry. I mean this is becoming a very dry year, but we've had other very dry years in the past. And so just the general volatility in hydro is obviously much higher than, for example, wind and certainly then solar. So hydro, you can have plus or minus 50% in a particular year, if it's a particularly bad year or a particularly good year. So I don't think -- I certainly wouldn't read any structural change to it, and I certainly wouldn't assume any changes to the '25 plan based on this year's hydro conditions. In terms of other options to optimize the portfolio in Brazil, I mean, we continue to work on that. And we would like to provide news as soon as possible. These are complex processes, but we continue to work on just optimizing the Brazilian portfolio in general, moving it much more towards networks, also on the renewable side, both utility scale and also distributed generation in Brazil, for example, to B2B customers. And so that's part of the ongoing program together with just making sure that we have a good capital structure in place so in terms of dividend payout in terms of the share buyback. So we will continue to optimize the Brazilian portfolio going forward. And the team is very focused on that at the moment I can tell you.

I think we have no more questions. So, Miguel, if you can give for final remarks, please.

So listen, thanks for being on the call. I think as you can see, the fourth quarter of last year was a tough quarter. I think there's no denying it. It's not -- no sugar coating it. I think overall, though, we were able to meet the targets, with a different composition in terms of the earnings and the EBITDA. But I think you can definitely see sort of the very strong performance in the network, the strong performance in the renewables and then that ended up mitigating sort of the weaker performance in the energy management. I mean it's exceptionally dry this year. I had the opportunity to mention, I think, in January, 1/3 of the normal rain and 1/5 of the normal rain in February. So it really is an exceptional part dry year. We will be compensating for it as much as possible with the thermal producing, obviously, much more additional volumes. So the unitary margin on the hydro is higher, but then you'll have more volumes on the thermal side, so more terawatt hours on the thermal with slightly lower unitary margin, but which will mitigate part of it. So anyway, let's see how the rest of the months go we'll update you, obviously, at the first quarter results and provide more visibility on that in this particular area. Taking a step back, I think the good point is that we continue to be growing very strongly on the renewable side. We continue to see a lot of demand. We continue to think that sort of the underlying trend, if anything, it's just that we should be accelerating, not us, but just generally, the sector should be accelerating renewables much more for 2 reasons because renewables continues to be, by far, the most competitive technology out there. And we've just been talking about the extremely high energy prices. I mean renewables is even more competitive now. And I think, secondly, it has an extraordinary important characteristic at the moment, which is it provides more energy independence in Europe. And so I know that this is something that a lot of the different countries in Europe in general and also other regions of the world are looking at, and wanting to sort of really accelerate that, work on the permitting, work on the licensing, work on the investment on the infrastructure to make sure that, that can be accelerated. So I'm clearly very bullish still on the long-term trend for that. In terms of the 2025 plan, we continue to work hard on it. Obviously, it's not great that it's not raining this year. But I think more importantly is to look forward, look at the 2030 and onwards in terms of what we have in open positions. So if the energy prices stay like this, we are mostly a CO2-free company. As I mentioned, 75% of our generation is renewables or CO2 free. So that means that we will be able to benefit on the upside from the higher energy prices going forward. And I think that is something that we need to obviously work through the next couple of months as we did through the second half of last year and get to the other side of this. But I think, clearly, we are seeing much higher potential given our existing portfolio and given the way we're positioning ourselves now for high energy prices going forward. In terms of capacity, also continue to work on it. Obviously, the supply chain disruption has delayed some of the solar projects, but they continue to be -- to progress. And in terms of signing PPAs, again, as I say, we've gone back in many cases because of the CapEx increases we've gone back and renegotiated that. And I think that's a good sign that we've been able to, let's say, get the original profitability that we're looking for and keeping with the [ 1.4 ] returns. So overall, we continue to be very optimistic about the medium and long term. We have had some difficult months. We will have some difficult months -- or we are living through some difficult months in terms of the hydro, but I have no doubt that we'll get through it. So thanks very much, and talk to you soon.

This concludes today's conference call. Thank you for joining. You may now disconnect your lines.