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

Good afternoon, everyone. Thank you for attending EDPR 9 Months 2023 Results Conference Call. We have here with us our CEO, Miguel Stilwell de Andrade; and our CFO, Rui Teixeira, will run you through the key highlights on the update of the execution of our strategic plan and on the financial performance over the first 9 months of the year. We'll then move to Q&A in which we'll be taking your questions, both by phone and the written questions that you can insert from now on in our conference web page. This call is expected to last close to 60 minutes. I'll give now the floor to our CEO, Miguel Stilwell de Andrade.

Thank you, Miguel. Good afternoon, everyone. So it's been a very eventful few months since we last spoke in July. And I think it's clear to everyone that the renewable sector has been impacted by some negative news flow, which has also ended up impacting EDP Renewables share performance. So I really hope that this presentation today will provide some useful and important data points and information, both in terms of the sector, how we're seeing it and also in terms of EDPR, both operationally and financially. I think just to start off by the bottom line, literally, I mean, we believe that the 12% increase on recurring net profit of EDPR in the first 9 months of the year is an important data point. There are things that are going quite well, very well. I mean if you look at the successful execution of 2 important asset rotation transactions, both the Polish one and the Spanish one, that was obviously a very strong contribution to that result for the 9 months. But we've had other positive developments in the period, and I think that's important to consider when we talk about the execution of our strategic plan until 2026. The first one is perhaps just to mention that there have been important developments regarding government support to our sector, both in Europe and in the U.S. And I'll comment on that in the next couple of slides. But the second point is that we've reached now around 9.3 gigawatts of renewable capacity secured for the business plan period. That represents more than 55% of our target capacity for the period. Has an improved average IRR minus WACC spread of more than 200 basis points. And for the projects approved in 2023, the average approved IRR minus WACC spread was around 120 basis points. Now this is risk-adjusted WACC incorporating the increases in the cost of capital over the last few months. Another important point, and we've talked about this in previous calls, but is that both the PPAs and the centralized auctions as it continue to show higher energy prices, and I'll show that also later on in the slides. So this continues to be strongly supportive on target returns in the context of these higher interest rates. CapEx has also evolved positively, with significant reductions, particularly in solar and BOS. Regarding our asset rotation strategy, we've shown great execution with the asset rotation gains above expectations, and we have around EUR 0.4 billion of sales on a -- around 400 megawatts. Regarding headwinds. So -- well, those were the positives I just spoke about regarding the headwinds that we faced this year and that we discussed also in previous calls. We had essentially 2 issues, very specific issues that we've talked about. One was the supply of LONGi solar panels in the U.S.A. That's now operationally solved. The construction rate is ramping up in the U.S. now with the supply chain cleared with the Uyghur Forced Labor Protection Act compliant modules going through customs. So it has impacted 2023. However, we have now clear line of sight to the projects being built in 2024. And we have the teams ramping that up to get that done. The other issue we had this year is Colombia, I mean, the situation remains challenging. We have still ongoing repermitting efforts for the transmission line, the interconnection line, which is a key bottleneck for the project. Unfortunately, there also continues to be a negative impact of significantly below average wind resources, particularly in the U.S., as we indicated in previous calls. And this is very much correlated with the El Nino effect. We've already given visibility to that over the last couple of months and quarters. I mean this has implied only a 3% increase in renewable generation versus an 8% increase in the average installed capacity. The decline of the electricity market prices in Europe has also had a 7% decline on the average selling price in line with what we previously highlighted in the first half results conference call in July. Overall, bottom line, as I mentioned, the close to EUR 400 million asset rotation gains achieved on the 2 transactions in Poland and Spain have more than compensated the challenging operational context in the period. And so the net income is up 12% year-on-year. Now let's move forward to Slide 5 and talk about the government support. And taking a step back and looking at the big picture. First, government throughout the world, they continue implementing new initiatives that strengthen the structural push for the renewables build out and for accelerating this build-out. The most recent update just as of last week as you'll have seen, was the European Wind Power Action Plan or the Wind Package, had 15 concrete actions to be implemented immediately to support the industry. And I'll just mention a couple of them, which I think are more relevant. Their measures to improve and to simplify the design of the auctions, including indexation to inflation, which is extremely important, prequalification criteria and no negative bidding. So this is critical. We also had issues like the increase of the cap levels of prices in places like France and Germany. I'll show that later on. We had just a widespread introduction of inflation updated prices and generally promoting the right incentives to long-term players in the sector. So I think this is definitely a positive. In terms of permitting, again, something that the sector talks about a lot. There's been a reinforcement of the digitalization at the national law. We have the European guidelines, really sort of reinforcing that for the different member states. And we have seen work being done by the different member states to accelerate this. There's also going to be a publication now in November for an action plan on grids addressing some of the bottlenecks, particularly around great reinforcement and expansion. Again, a critical aspect for the scale up of renewables. And finally, just regarding the wind manufacturers. There's an increase in the efforts to establish fair market standards and to generally promote competitiveness in compliance. So again, obviously, very important to ensure a strong wind manufacturing sector supporting the industry growth. So the whole value change needs to be sustainable going forward. On the right-hand side, we have a couple of comments on the U.S. So as you know, when the IRA was published, the Inflation Reduction Act, there was some uncertainty on how some of the measures were going to be implemented. The ITC's bonus guidance has now been published, and that clarifies the key issues outstanding. It gives a sector clear rules of the game in terms of what our bonuses for areas with -- or projects built in energy communities and low-income communities. Now the clarification came on the anti-circumvention tariffs, again, providing solar panel suppliers to the U.S. with clear visibility of tax requirements. On the tax equity funding, we've seen the market adapting to this as well. The -- now you can also -- you don't just need to have tax equity partners. You can also have tax credit transferability between companies. So that's something we're also looking at for some of our projects. It's slightly different from the more traditional tax equity, but it could certainly be an interesting instrument as well for financing the project. And finally, maybe just regarding wind offshore, just highlighting the importance of the recent pledges and the statements also of the state governors from the 6 North -- east states and also from California, where we have one of our offshore projects. So clear support for the wind offshore industry growth. One good interesting data point. The recent auction results in New York are very encouraging, incorporating much higher prices around $150 per megawatt hour based on updated market conditions. And so as you know, we walked away from the PPA, we had there sort of in the mid-70s. So clearly, the possibility to recontract at much higher prices. going forward. So I think the wind offshore development in the U.S. can still be an effective technology to efficiently decarbonize the U.S. power sector. I mean the ecosystem still needs to be further developed. It's not as mature as the European offshore industry, but I think with these levels of prices, more projects will start getting built and so that ecosystem will develop naturally. If we move forward to Slide 6, changing topic, but one which I know is top of mind for many investors and obviously, top of mind for ourselves. So here, we wanted to highlight that we are keeping our clear investment framework. It's a selective and disciplined approach. As I said at the beginning, we have 9.3 gigawatts secured, representing around 55% of the total '26 target, which 3 gigawatts secured corresponds to the 2023 year-to-date. In 2023, we've already approved around EUR 3 billion of capital, quite well diversified over our main geographies and technologies with wind and Lat Am having the highest project IRRs and Europe and wind representing the highest share. And you can see that clearly on the graph on both the left and the right-hand side of the slide. Apart from the cost of capital -- so I think this is an important point. Apart from the cost of capital, which obviously depends on interest rates to a certain extent. Key variables for the profitability are the PPA price and so the cash yields for the first years of the project and also the energy prices post PPA. Now this is a question we get asked a lot, so I'll be very clear. We model conservative assumptions, in some cases, with discount rates or discount factors, higher than 50% in the solar prices versus the base load prices particularly in markets with high solar PV penetration. So this is something we've talked about. This is the solar adjustment factor that should be incorporated in when we're doing the analysis of projects, and we've been doing that for a while. We were very early on beginning to talk about this effect, and that's what we consider in our models. When we look at the 2023 projects, they've shown an increase in absolute returns while preserving the risk levels and here a couple of data points. So around 16 years of average contracted period, it contracted NPV of more than 60% on average. And that's important because it means that a significant part of the NPV is locked in, both on the revenue side and on the cost side. On average, the nominal equity payback period was 11 years and the spread of IRR of WACC was around 220 basis points, as I mentioned. So I wanted to highlight also that all these returns exclude additional upsides from asset rotation transaction. So most of the transactions we do -- or the asset rotations we do, we actually end up rotating the assets more quickly and the IRRs are substantially higher, and I'll talk about that later on. But -- so value creation is supported by the higher contracted energy prices more than offsetting the higher interest rate environment and higher inflation. And if we move to Slide 7, I'll just insist a little bit more on energy prices. As I said, we continue seeing strong energy prices. They're supporting long-term revenues resulting from government organized auctions, increasingly inflation updated and through corporate PPAs where demand, supply and balance and higher inflation are supporting the increase of PPA prices. We've talked about that. So $60, $70 per megawatt hour, EUR 40 to EUR 60 per megawatt hour, that type of range is much more common now, whereas 2 years ago, we were sort of in the -- in some cases, EUR 20 to EUR 30 per megawatt hour. So a very significant increase in PPA prices between 2020 and 2023. And in our portfolio, 70% increase on average in Europe and around a 50% increase in the U.S. In terms of auctions, a couple of -- additional couple of data points, but in current prices, we are awarded in France, a 20-year CFD at EUR 85 per megawatt hour. We were awarded 43% of the total Italian auction with a 20-year CFD at EUR 65 per megawatt hour. And we were awarded a 15-year CFD in the U.K. at GBP 71 per megawatt hour. So I just wanted to highlight these are public numbers, and so we can point to them quite easily. But that gives you a sense for different European markets, some of the prices that we are seeing for these projects. On the merchant side, over the last 3 months, forward electricity prices for '24 to '26 deliveries have also rebounded significantly. It's a positive impact. So we have around 14% merchant exposure in 2024 and close to 20% for 2025 and 2026. And so you can see there the prices are pretty much aligned with what we had in our business plan throughout the next couple of years. If we move forward to Slide 8, and let's talk about CapEx. We have equipment prices going down. This trend is more striking in solar than in wind. Turbine prices are relatively stable. But in solar, we clearly see the polysilicon prices coming back down to pre-pandemic levels. They had a very strong rise back to a normalized level. And we've seen module prices, which have been in the region of $0.15 per watt. So that's already material in our recent contracts and will flow through primarily in 2025 and beyond. In the U.S., solar module prices are still higher than the rest of the world due to the difficulty in the imports, the tariffs and just generally moving the manufacturing base back to the U.S.A. As you'll recall, we contracted around 1.8 gigawatt peak with First Solar for 2025 onwards. And so that will support us in our, let's say, our solar panel supply in the U.S. going forward. In terms of construction, also a downward trend in European costs, both for wind and solar after a pickup, basically the balance of plant in early 2023. All in all, we're taking advantage of this market momentum, and we're managing to have competitive procurement for projects to be delivered in 2025, already more than 1 gigawatt and continuing to prioritize the highest ESG standards in our contract. I think this is extremely important. Traceability is a key word, not just in the U.S., but for all of our procurement. So for 2024, we already have a diversified supply chain with a high focus on this traceability to reduce delivery delay risks. Move to Slide 9 and talk about the asset rotation transactions in more detail. So we spoke briefly about the 2 transactions in Spain and Poland, very attractive multiples. Positively impacted by buyers incorporating both higher electricity prices and the value from additional hybridization and possible repowering despite the higher cost of capital. Now I wanted to point out something which is important. These assets are quite recent in our portfolio. They had CODs in 2023 for Brazil, fourth quarter '21 for Poland and offshore U.K. And we actually bought the assets in Spain in the fourth quarter of 2020, so relatively recent CODs. But the FIDs were mostly in 2019 when the cost of capital was very low. So when we get these multiples, this is not a cost of capital arbitrage from investing at a time when there's a higher cost of capital and then selling when the cost of capital is lower, it's exactly the reverse. These were investment decisions that were taken when the cost of capital was lower. We're selling them when the cost of capital is much higher, and we're getting these multiples, okay? So just to clarify that and sometimes get the comment if there's a spread arbitrage that's happening here. As we see in the graph, the asset rotation gains over invested capital achieved. It's a good proxy, reference for cash-on-cash value creation, is much higher for the 2023 deals and for the '21 and '22 deals. As a matter of fact, after the asset rotation transactions, the chief project IRR is actually higher than 30%. Because you're basically concentrating all of the cash flows or all of the NPV in a much shorter time frame until you get a much higher IRR from that asset rotation transaction. And then you can redeploy that capital back into the business into new projects with higher returns. Now as we stated in previous calls, what we see is an increasing interest from strategic investors with a focus on renewable assets linked to ESG targets versus the usual financial institutions, we expect to end the year with more than EUR 400 million of capital gains and proceeds of more than $1.5 billion to achieve the 25% of the target proceeds for the full business plan period. So again, year after year, transaction after transaction we show that we can deliver the proceeds and the value creation.

If we move on to Slide 10, talking about capacity additions. So capacity execution is on track. We've got an expected addition of around 6.5 gigawatts between '23 and '24, evolving, as I mentioned, was the profitability spread of around 230 basis points. We expect to install the bulk of this year's new capacity around 1.7 gigawatts by the end of the year. That's typically what happens backloaded. It's a big effort when compared to previous years in terms of organic growth. We're talking about more than 50 projects being built globally in various different markets.

As I mentioned, one of the issues we had this year was importing of LONGi solar panels into the U.S. This is solved, as I mentioned, this is going to be installed in 2024, and it doesn't affect our long-term relationship with one of the biggest solar manufacturers worldwide. So we already anticipated that 2023 would be impacted with the cost of these delays in the U.S., but we also wanted to share some of the positives that the team has done in terms of renegotiating the PPAs as a result of these delays. So we've renegotiated 1.1 gigawatt of PPAs in the U.S., an average increase in price of 12%, so around $5 per megawatt hour and also pushed back on an average about 7 months of postponement for the first energy delivery date to minimize penalties. So we will have panels '23 but substantially less than we would otherwise have had as a result of these delays. For 2024, we expect installations to be around 4 gigawatts, it could be more, but the Colombia project is proving challenging with the repermitting process and the transmission line. It's been enlarged now the repermitting process to involve 130 communities in the consultation process. So we're assuming these 500 megawatts will be delayed to post 2024. So that's already excluded from these 2024 numbers. All in all, doing a really strong effort in terms of organic growth, the whole company totally dedicated to really do all the engineering and construction of more than 5 gigawatts of assets, more than 50 projects to be installed this year and more than 70 next year. So I think the whole team is fully engaged on making sure that this happens. We move on to Slide 11 and just talking briefly about offshore. So the investments from '23 to '26 are mostly projects under construction in Europe with strong economics for all of them. They have inflation-linked revenues. They have fixed CapEx already locked in. They have CODs for '25 and '26. It's important to mention that EDPR owns minority stakes, and so it's well diversified, and we have a strong risk management associated with this. As a general comment for all of our offshore projects, portfolio. Project Finance covers 70% of this investment, of which 70% is at fixed rates on average lower than 4% and with an average of 18 years debt maturity. So we've locked in the top line inflation linked and we've locked in the costs, both CapEx and financing at very attractive terms. In terms of projects under development, we have 9 projects totaling more than 10 gigawatts with rights secured and a total of 7.6 gigawatts with a low current devex or development expenditure of around EUR 200,000 per megawatt. So as an example, when we look at OW's most advanced projects under development, we have B&C wind in Poland has inflation-linked tariff, CapEx not yet contracted. But SouthCoast in the U.S., for example, it's a project, it's got advanced permitting interconnection. Revenue is not secured. As you know, we've stepped out of the PPA and we don't have the CapEx contracted. So that means we have no top line, no bottom line, no costs to have locked in, and we have that optionality to bid into projects that may occur now in 2024. All in all, I think what's really important is that our investment decisions are based on this strict investment criteria with very short periods between fixing contracted revenues, CapEx and project financing terms. As I mentioned, the European projects are good examples of that. Just finally talking about something which is really top of mind for us, for myself or for the whole team. Cash is king. Preservation of value is critical to increase the profitability and keep solid ratios. And we just -- we're very conscious that this inflationary environment is driving growth in terms of costs, but we are very focused on initiatives for driving efficiencies. So various different initiatives that we've been promoting over the last couple of months, both on the CapEx and O&M excellence programs. We're adapting the cost structure to the company's growth pace. One note here is in terms of our O&M structure, we have a very strong structure. The 50% of our fleet is internal, which means we have a strong negotiating power between outsourcing and in-sourcing O&M services, and we can make sure we are arbitrating that to get maximum value. We have ongoing efficiency measures, which are expected to have a positive impact in 2024 accounts of more than EUR 30 million of savings, and we continue to work on additional initiatives. So being a leaner organization is absolutely a critical issue for us to become a more efficient company and to continue to promote synergies, taking advantage also of EDP Renewals being part of the global EDP group. So we're extending also the global business services model, which currently services the EDP Group in both Europe and South America, and we're expanding that services also to include or to serve EDPR in both North America and APAC. So we believe this will bring additional synergies and cost efficiency. In terms of digital, just to say that we continue to implement really our digital road map, and we're expecting that to also bring substantial efficiency both in terms of process optimization and automation. So finally, just before I turn it over to Rui. Just talking more globally about the market environment for renewals. Capacity growth bottlenecks, so there's a really strong public-private support for the energy transition execution in the next decade. I mean, of course, there are short-term challenges but the underlying trend continues to be there. We continue to see that strengthen. Just looking at the recent International Energy Agency messages around big fossil fuels this decade, looking at the growth in solar that all the different countries are predicting all the growth in onshore wind and offshore wind. So really, it's a question of being selective in growth and focusing on value creation and taking advantage of this really secular macro trend. In terms of interest rates, they're expected to be higher for longer, we have fully incorporated that. But on the other hand, we also think that we're close to a peak judging from the recent European Central Bank and Fed comments. In terms of returns, absolute returns for new projects are close to historical peaks that we've seen over the last decades. And as you know, we've been investing now for over 15 years in renewables. I mean these absolute IRRs are obviously driven by the cost of capital, higher demand for renewable energy and the scarcity of it's ready-to-build projects. Energy prices, as I mentioned throughout the -- earlier in the presentation, we see this upward trend in PPA and auction prices as well as merchant prices, both in Europe and in the U.S. And as I mentioned, post-PPA prices in our models include conservative assumptions with discount factors, higher than 50% in solar prices versus baseload prices, particularly in markets with higher solar PV penetration. I know that's a concern. I just want to be very, very clear. We've been modeling that since the very beginning. And supply chain CapEx, the visibility on supply increases, expected to have a positive impact on the renewables CapEx prices. And so on one hand, we have this indexation of project revenues to inflation and increased auction caps, we have decreasing prices, for example, for solar and relatively stable turbine prices. So I think that eliminates plenty of risks that we've seen over the last 12, 18 months. And I'll just pause there, and I'll turn it over to Rui to walk you through in the first half results, and then we'll come back for closing remarks and then Q&A. Thank you.

Thank you, Miguel. Good afternoon to you all. So now let's go through the first half -- sorry, the 9 months result very quickly. So as we already anticipated in Slide 15, the -- we anticipated in the last call, 2023 performance is impacted by some short-term headwinds. I would say that the most significant ones are those related with the low wind generation, reflecting an expected impact of around EUR 0.2 billion in 2023 versus what we were estimating a few months before of around EUR 0.1 billion. I mean we already explained these weather cycles affect quarterly results, but we include this into our long-term projections. So we don't expect any impact on the asset valuation coming from these new cycles. Also, as we announced at the beginning of the year, Romania and Poland CapEx, these are still having an impact in our accounts. For the 9 months this year, it represents about EUR 71 million at the EBITDA level. Still much lower than what was expected on the back of the lower power prices in these 2 markets. The impact is related mostly to the tax in Poland, which is due to end in December this year. And we have ongoing litigation against this poor implementation of the clawback mechanism. We have also incurred in costs with delays in U.S. and Colombia, totaling around EUR 55 million in the 9 months of the year. And we have been working to limit the short-term impact mainly through successful PPA term renegotiation. So U.S. is mostly secured. Harbor challenges still continue in Colombia, as Miguel just explained. Also, as many of you that you already know, the Spanish government updated the reference price for the [indiscernible] assets with the band being adjusted accordingly. This is leading to an accounting impact of around EUR 67 million in the 9 months. Again, this is a noncash impact and also no impact on the valuation nor the project returns. So we do expect these items to be fundamentally 2023 impact, although some could be here still in the beginning of 2024. I mean, for example, El Nino doesn't care really about cutoff dates on the 31st of December but we fundamentally believe that these are 2023 impacts. If we move now to Slide 16. We increased our generation by 3% year-on-year. This is driven by higher capacity in operation that to some extent, mitigated the low-wind volumes. Regarding the wind volumes, Q3 reflecting below-average wind resources, mainly driven by the U.S., where gross capacity factors stood at 91% versus the P50 on the back of the El Nino, pushing down the whole metrics for EDPR during the quarter. As you can see on the bottom hand right of the slide, a substantial blue area in U.S.A. with below average wind resource. Now on EBITDA on Slide 17. Recurring EBITDA was EUR 1.4 billion. That's minus 3% year-on-year, mainly driven by an increase of 6% year-on-year of installed capacity that was naturally penalized by the lower renewable resource. The lower averaging selling price, minus 7% year-on-year, with you coming down from the abnormal peak prices that we saw in 2022. But on the other hand, a sustained increase of 8% in U.S. And of course, the temporary headwinds in Europe and the Americas that I just explained. Brazil, new capacity in operation contributing positively with a 30% year-on-year performance. APAC EBITDA was driven by new capacity in operation, along with the full contribution from Sunseap during the last 12 months versus the 9 months 2022, sole contribution since February. The reduction of share of profits from associates was driven by the reduction of wholesale electricity prices in U.K. and the PPA cancellation penalty booked in Q2 that impacts Ocean Winds books. And the asset relation gains, as explained by Miguel, were higher than expected at around EUR 0.4 billion. So if you move now to Slide 18. As of September 2023, net debt was at EUR 6.1 billion, that's EUR 1.1 billion above December 2022. And this is driven by EDPR's organic cash flow, the asset rotation proceeds. These are not including the proceeds from the transaction in Poland that in the meantime, they were received in October. And the EUR 1 billion capital increase, which funded the EUR 2.7 billion of net expansion investment, including CapEx and financial investments. So all in all, net debt over EBITDA ratio stood at 2.9x. But just looking a bit more into the debt structure on Slide 19. We are rebalancing our debt structure, reducing exposure to U.S. dollar from the current 65% and broadly aligning it with our asset mix by market, thus growing our U.S. dollar-denominated equity exposure. This has been ongoing since June this year, and we expect to conclude it in December '24. This is important, as following the strategy, we expected to have interest rates or interest savings from lower U.S. dollar refinancing needs in the period of 2024, '26 and with a positive impact of around EUR 100 million, and these were not included into our business plan financials. So if we look to the financial results on Slide 20, those amounted to EUR 257 million in the 9 months. excluding ForEx and derivatives, financial costs increased by 30%, 31%, a bit more than half coming from higher average gross debt and the rest from higher average cost of debt to 4.9% and this is mainly from the combination of, one, the high relative weight of U.S. dollar-denominated debt. As I said, it will go down over time. Two, the new long-term shareholder loans with EDP as the current ones mature. And three, the short-term cost of funding in euros. So this is coming from the current accounts that we have with EDP and the short-term lines for cash management. EDPR debt has 82% at fixed rates and again, it's very important to mention in terms of financial liquidity. This is cash and committed credit lines. It does cover refinancing needs beyond 2026. And that more than 70% of our debt actually is maturing post 2026. Now on Slide 21, on the net profit. Recurring net profit totaled EUR 467 million. That's a 12% increase year-on-year, and this is explained by better financials, lower taxes due to asset rotation gains fiscal treatment and lower minorities. And this offsets the EBIT reduction. Nonrecurring net profit accounts for events, including the PPA cancellation in Massachusetts that Miguel just mentioned, on U.S. offshore project [indiscernible] and Romania provision and depreciation and amortization related to the tax clawback and this is amounting -- this is a total of EUR 12 million. So I will hand over back to Miguel for closing remarks. Thank you.

Okay. Thank you, Rui. So just to finalize the presentation, so we can then turn over to Q&A. I'll just start off by saying we're here to create value. And we invest throughout the economic cycle, we invest in renewable projects, and we're taking advantage of this macro trend. I mean, it sounds simple to say. But the really focus here is on creating value between the projects that we are investing in each particular moment in time where we are creating a spread of value versus our cost of capital. And then we also sell some of those projects to finance that growth and to capture that value creation. And I think that's been coming through very clearly over the last couple of years. Now it's important to also look at the context, increase of PPA and for electricity prices. That's a fact. Many, many data points we can point to, both in terms of merchant prices, PPA prices in the various different markets that support that. There's also a downward trend in the CapEx. So there was a high inflationary periods over the last 18 months, basically, but particularly in solar panels, but in general, it's a balance plant. We're seeing that really begin to come down, particularly for 2025 and beyond, which is when we're beginning to contract investments. So putting these 2 together, higher energy prices CapEx coming down, cost of capital is incorporated, obviously, in our valuations means that we're getting good returns on the investments that we are doing and with keeping risks under control. We're expecting to do around 2.5 gigawatts in 2023, as some gigawatts -- some megawatts have moved into 2024. For '24, we're expecting around 4 gigawatts as I said already excluding Colombia, which is about 500 megawatts, which has moved to beyond 2024. This is supported, as I say, by us having now a clear line of sight to the solar supply chain deliveries in the U.S. and also having just a diversified growth by market and technologies. I can then give you some more detail, if you want, or we can provide that off-line in terms of where we think those megawatts are coming from in which markets. The asset rotation execution in the third quarter, as I said, was done based on assets with a short time in our portfolio. So it's assets that we contracted over the last couple of years that we took an investment decision when cost of capital is at all-time lows. And yet, we're managing to rotate them with good valuation multiples. And obviously, that's because people look at not just the intrinsic value of what we're selling, but also all the hybrid potential, the merchant optionality, the repowering potential in some cases. So that more than compensates a higher interest rate environment. On the balance sheet, we've talked about that, where we've got a strong balance sheet, and that's obviously been reinforced by this asset rotation execution. We're declining the dollar debt weight to rebalance the debt mix. And generally, we have good visibility also on the tax equity financing in the U.S. So finally, market environment, strong demand for renewables, it continues to be there. I think that's undeniable. Independently of the headwinds or the short-term headwinds that the sector might face. There continues to be a scarcity of ready-to-build projects and we believe that this continues to create good conditions to invest with long-term attractive returns while controlling the risk. And I think that's really at the core of what we do. So we're not in this just to do volume for volume sake, we're in this to create value and make sure that we are being selective in the investment decisions that we take. We think it's possible to do volume because the market is growing a lot and get the returns that we are looking for. So I'll stop there and turn it over to you for Q&A. Thanks.

[Operator Instructions]

I think the first question that we have comes from [indiscernible].

The first one about this discussion about rising curtailments, not only in Spain but also in U.S., for instance, in Texas. The question here is, first, if you are being affected by this. on top of the El Nino effect in the latest quarter? And secondly, if you are seeing effective signs or willingness to make great reinforcement in these regions. And then if you can comment on the potential risks that this curtailment may have for demand from corporate PPAs.

Okay. So -- I mean curtailments are -- I mean, exist there typically relatively localized when we're talking about, let's say, network curtailment on this excess, let's say, excess supply of renewables or energy in a particular node. That's the case in some places in Texas. We have not been particularly affected. In fact, the curtailment this year has actually come down for us globally in the U.S. We were more affected by this in Spain. So historically, we never had any curtailments in Spain. We then had in the second quarter, higher levels of curtailment that's come down slightly in the third quarter. I think it's important to say that, first of all, not all curtailments are bad. I mean, you can be paid to curtail. In fact, I was just exchanging messages early on. You can get paid to reduce power. So there are only some types of curtailment, which are actually negative, let's say, because you're not getting remunerated for that loss of production. In terms of -- and as I say, so in Spain, we've taken several measures to reduce the level of curtailment that would not be remunerated in, let's say, in some of the specific nodes. It's also important to say that in those cases, it's normally because there's an excess of renewal. So it means the prices are low. And so let's say, the lost revenue is also low. So it's not a major impact that we had in -- it was slightly larger in the second quarter, it's lower in the third quarter. Grid reinforcement. So we haven't been asked well, we own networks, let's say on the EDP side, but certainly on the EDPR side, we've not been asked to do any grid reinforcement. I mean there's talk about just generally having more demand type flexibility. But so far, not doing investments to reinforce the network on the renewable side. I think what would probably be an interesting discussion here is if we see batteries begin to take off more in Europe. So far, as you know, they haven't really taken off. They've taken off in the U.K., they've taken off in the U.S., in many cases, both co-located and stand-alone. But in Europe for example, in places like Spain, et cetera, you still don't really see a lot of batteries. And that would help, for example, with issues like that. In terms of the -- of risk to corporate PPAs, we don't see that as being a factor at least if not something which has impacted us at all so far.

The next question comes from Alberto Gandolfi from Goldman Sachs.

Thank you, Miguel. I have 3 on my side. I really thank you for Slide 6. It's great to have visibility on IRRs. It looked like the average project is about 9%. But this seems what to be under development. So I was wondering if you can, first of all, talk about the IRR on your existing portfolio. So what is the IRR on the existing portfolio? And you seem to be hinting at 6.5%, 7% after-tax cost of capital. So just trying to see if your portfolio also has an IRR consistently above WACC. The second question is still on IRR, can you maybe give us a bit more details on what percentage of top line on your existing portfolio and under development is inflated? What percentage is merchant. So I'm trying to understand what is an offset to the cost inflation we have seen in the past 2.5 years? And maybe because IRRs are always a little bit difficult to visualize because it's an NPV of maybe 30 years. Can you maybe help us with some of the long-term assumptions, the power price that you are assuming, for instance, would be very helpful. And the last question is on the debt. The debt keeps creeping up your accelerated investments. I wanted to ask you, is there a chance that you might be open to a shift in capital allocation? Maybe less reliant on asset rotation, maybe go less, but why is 200 basis points the correct spread of WACC? Why can't you target more than that and maybe grow more the bottom line? Because I think that after all -- I know you had a lot of one-off negatives, which you highlighted in the slides. But right now, excluding capital gains, you're not even delivering EUR 100 million net income. So would you be open to perhaps focusing more on bottom line growth with higher returns and a bit less on top line growth.

Okay. Thank you, Alberto. So I mean, the IRRs on existing portfolio. So it depends if you're talking about the overall asset like the full asset because we've been investing over the last 20 years, as you know. So our portfolio includes projects from -- with various different vintages. And typically, when we talk about the 200-plus basis points, it's on the investment decisions, which we are taking at any particular point in time. So just to take your numbers, the 6.5%, 7%, that would be, let's say, the IRRs for projects when we were investing at the low point of the interest rate cycle. And so the same way that now, we're investing closer to 9% because we're -- we'd be taking, let's say, more up-to-date cost of capital and applying the 200-plus basis points to that. So I don't have the specific numbers on the overall portfolio. We can maybe try to work it out. But what I'd say is that, that's basically the -- it works more sort of the vintages of investments that you go on doing over time. But it's also the reason why I pointed when we talked about the asset rotations that the investment decisions we took back in 2019 and in 2020, for example, in the case of the Macquarie assets, we were having that spread at the time of the cost of capital, and we're still able to generate value creation through that, even though the cost of capital has gone up. Also, I think one important thing to note when we're talking about the IRRs is we're also locking in cost of financing as we go on. So when you're talking about investing to 6.5%, 7% 2 years ago or thereabouts, we're also locking in very low cost of financing at the time. And so we're basically locking in the top line, but you're also locking in the costs. Yes, the CapEx locked in, the financing cost locked in. And obviously, the OpEx is a lower proportion of that O&M of the project. So hopefully, that is -- helps to answer your first question. Just maybe also to mention, I mean, even at the low point of cost of capital, we built in a buffer into the WACC. So we never did like a pure spot. I mean we never followed it all the way down. I mean we thought it went pretty far down. And so we basically had a buffer even at the low point of the, let's say, the interest rate cycles. In terms of IRRs, in terms of percentage top line inflated versus merchant, I'm just seeing here if we have that information. So okay. So inflation linked, this is around 30% of our total revenue. So I don't have it for -- I think you were asking just for the under construction. Was that it?

No, existing is probably more relevant, but whatever you have.

Okay. So for total revenues, we have 30% inflation linked, 15% escalator, typically 2%, 2.5% annual escalation around 20%, 25% between merchant and hedged and 30% flat revenue, okay? So hopefully, that gives you a breakdown of, let's say, flat revenue, which would be the case, which isn't -- well, which doesn't have any type of adjustment would be just 30% of our total revenues.

Miguel, forgive me to interject, but this -- what you just gave us, I think, is extremely important. So the 6.5%, 7% IRR, you thought you locked in at the trough in the cycle. Isn't it more like 8%, 8.5%, 9% today? Because 20%, 25% merchant prices have tripled inflation, which is 30% has been far higher than you were expecting. So is the 6.5%, 7% the right IRR to think of? Or is it more like 8%, 8.5% right now?

Just trying to work through. I mean, typically -- so I'm thinking about, let's say, what IRRs were when we take the investment decision, right? It's true that if it's inflation linked, I mean, that will be going up. You've got the CapEx locked in. So -- listen, I can get back to you and see if -- I don't want to misspeak, but I can certainly see there is upside if the revenues are inflation-linked. They'll be going up and if you've locked in a lot of the costs on that. But perhaps we can do some analysis and come back to you on that. On the -- but just still on this point, which I think you raised and which is important, and I just want to go back to something which I mentioned. You talked about the long-term power prices because really, when we're talking about these projects what are the key variables. One is cost of capital. We've discussed that. The other one is what is the PPA price, right? That's basically what are the cash yields you're going to have over the next 10, 15 years or so of the PPA price. And then the other question is, okay, what are you seeing post PPA price? If you have those 3 variables, you have a big part of the value of the project where you can work out some of the IRRs of the project, assuming you also have the investment. On the long-term power prices, we are bullish by nature on the penetration of renewables, which means we model already high penetration of renewables, which means we model already downward pressure on the power prices in the back end. And what we do on top of that is we factor in what we call that solar adjustment factor and the wind adjustment factors or the SAF and the WAF. So we don't just take baseload prices. This is something we've spoken about many, many times -- looking at baseload prices in 2030 or 2040 is not the relevant metric. You need to then apply what is the realized -- you need to find out what is the realized price that you expect for certain technology at that point. So in 2040, if there's a lot of solar, obviously, it's all going to be producing at the same time, and you're going to have a much lower realized price for solar than, for example, for a hydro, which will have, let's say, which can store and which can just produce at the peak hours. We know that. We incorporate that into our valuation models. That's done on a fundamental basis, bottom up for the different markets take into account the specific dynamics of what is the energy mix in each particular market. Obviously, Poland is different from Iberia, which is different from the U.S. So we have an energy planning team, which does that in a great amount of detail, and it's constantly cross checking with not only external sources, but also what are updated projections over the medium, long term from international -- things like international energy agency or whether it's the different government agencies that are responsible for energy planning. So that's a bottom-up analysis, which we are -- we do on a fundamental basis, we take it to the limit of almost looking at what are the hourly prices in many of these things. So there's a lot of stress test and a lot of analysis, which goes into trying to forecast that long-term power prices. And if anything, I'd say we are prudent on the way that we forecast that, okay? So I just want to -- I can't -- I'm not going to give you specific power price numbers for the back end. But what I can say is when we do asset rotation transactions and we get premiums and we get sort of large capital gains on that. It's because, obviously, the market is either believing they've got a lower cost of capital than we do or they're assuming higher energy prices in the future and value is being created by one of those 2 assumptions or a combination of both higher energy prices in the back end or lower cost of capital over the project life cycle. So again, don't just take my word for it. Look at all the various transactions, which have been done over time in multiple different markets to see that you have a lot of very sophisticated entities and companies actually going deep, doing their due diligence, really going to the numbers, hiring a lot of external consultants and then coming up with a number, and that's resulting in a capital gain in value creation. So as I say, don't just take my word for it. Look at what a lot of very sophisticated investors are doing and what they're paying for these assets. On the third point, on the debt increase and capital allocation shifting. Listen, I hear you because you have a higher IRR spread. It's a trade-off between -- in that case, if we go from -- we obviously look at what the market -- what is I say, market rates in terms of value creation spread, that's typically around the 200 basis points for the different markets. And on a portfolio basis, you could ask for a higher spread. You might be priced out of the market in certain. So you'd probably have to have the lower volume. So that's a trade-off that could potentially be done. It's not something that we are currently putting on the agenda at this point. Hopefully, that helped them, sorry if it's a long answer.

Our next question comes from Javier Garrido from JPMorgan.

Three questions from my side, too, if I may. The first one is on the '24 capacity addition target now that Colombia is out of the target where would you be -- where would you see your biggest execution risk? And is it fair to say that the risk profile in execution in '24 is now lower than in '23 given that a portion of the '24 capacity additions are the U.S. solar assets that have moved forward into '24? The second question is on the 2024 targets. I mean you have provided today a lot of information, a lot of detail. With those inputs, are you in a position to reiterate the target of EUR 2.5 billion EBITDA and EUR 0.7 billion net income for '24. And then third question is more strategic, as you are considering -- will you consider taking any action to support the share price, buyback looks difficult, given the leverage but would you consider any strategic realization of the group in the context of low share price?

Thank you, Javier. So on your first point, the 2024 capacity, yes, I think we see lower -- I think one important data point that we are -- that we've been now providing over the last quarterly calls, and we certainly gave it in this one is what we have under construction. And we currently have 5.2 gigawatts under construction. Let's say, we'll probably have about 1.7 gigawatts coming in still this year and the rest in 2024. And then obviously, we're still ramping up construction of some additional megawatts. So for this year, and then I'll go on to 2024. For this year, we're still expecting that we have about 900 megawatts coming in North America, about 500 megawatts of wind, 400 megawatts of solar. In terms of Europe, we'll have about 230 megawatts coming in, about -- again, half wind, half solar. We'll have about 400 megawatts coming in South America, about 180 megawatts wind and 212 solar and almost 100 megawatts in APAC. Then for 2024, that's where we'll have the bulk of North America projects coming in. So we'll have -- we expect to have more than 2 gigawatts coming in on North America. Most of that will be solar and about 1 -- more than 1.7 gigawatts, of which 900 megawatts is -- the famous 900 megawatts from 2023, which we are now building and will come in over 2024. So we're good line of sight to that. As I say, in Europe, we then have more than 1.1 gigawatts. Most of that wind or about 1 gigawatt solar, almost 200 megawatts of wind. South America, we also have about 400, 500 megawatts about split 50-50 wind and solar coming in. And then we have about 250 megawatts of solar DG coming in, in APAC. So we have pretty good line of sight to these projects. Again, we also put in that number of 17 projects coming in over the next year. We have names and surnames to these projects. We don't anticipate -- one of the -- sometimes, projects slip a bit or they can be anticipated. We're not seeing the type of supply chain disruptions that we had this year or that. And we've been contracting with longer and longer lead times to make sure that we get the slots and we get all of that done. So again, long answer, sorry, but just to say, yes, we are -- we do feel quite comfortable with the 4 gigawatts for 2024 and will be very focused on that. For the financial targets. So we'll be around the consensus numbers. I think there obviously a lot of moving pieces, prices seem to be doing pretty much okay. They've rebounded as I mentioned on the slides, they're sort of basically in line with our business plan numbers. A number of megawatts has obviously slipped and so that will be generating slightly less in 2024. Will depend a little bit on the volume, whether El Nino continues in '24 or not. But on the one hand, we're working hard on efficiency on the cost side and on the financial costs as well to sort of make up for that. And then we have the sort of asset rotation cap gains, which are also a little bit of -- I mean which can vary over time and so have a little bit more volatility there. But anywhere -- yes.

Sorry to interrupt that, you said you are comfortable with consensus. But if I look at Bloomberg, consensus for '24 is EUR 2.33 billion of EBITDA, which would be below your target of EUR 2.5 billion. So I just wanted to be sure you are thinking of net income -- in terms of net income, which is closer to your target or [indiscernible].

Yes. I'm clarifying that we should be around consensus because obviously, the megawatts that have moved into 2024. I mean we're trying to make up as much as we can for that, but I mean it is what it is. So we will certainly do our best to recover. But at the moment, what I'd say is that we are closer to consensus. On the -- so I don't know if I answered your second question. Did you ask us about net income? Net income, I think we give a lot of visibility on it because it just has a little bit more volatility on the back end. On the share price, obviously, we -- this is not a cliche answer, but just to say we do look at what we can do to make sure we are maximizing value. And so we would never rule out any reorganization if we were sure that, that created value for the shareholders.

The next question comes from Manuel Palomo from BNP.

I will try to be brief and stick to 2. First one is on asset rotations. I wonder whether you could please remind us on the already agreed and now asset rotations that you expect to book in 2023 on top of Poland and Spain that have been already booked in Q3? And if you could give us sort of a guidance on how the contribution from asset rotations will look like by the year-end? And the second question is about -- I think it's Slide #19. You talked about reducing U.S. debt. However, what I've seen this year is that most of the divestments are in Brazil and Spain, Poland, will you continue to add assets as you have just explained in the U.S. So I wonder how that process of reducing U.S. debt will take place. And lastly, you mentioned that so far, we've seen a decline in installation costs, mainly for PV also for wind onshore. So my understanding, looking at the PPA prices, they are still pretty high. Even now, I mean, the current assets that you're signing are in hotspots since the PPA prices are high, but maybe the installation costs will be lower. According to your experience, how long this should last until we start seeing maybe PPA prices softening a bit.

Thank you, Manuel. Rui, do you want to take that?

Yes, sure. Thank you, Miguel. So asset rotation, we have already signed the transaction in Brazil, so one of wind assets it's going through the, I would say, customary CPs. We expect it to be closed -- financial closing by year-end, so that we should come. So that basically means that we would be around EUR 450 million of contribution from capital gains pretax for 2023. But I mean, it's ongoing the CPs. So we should not -- I'm not expecting any surprises there. On the balance sheet, just to explain. So basically, what we -- if you look to the balance sheet, we have about 65% of our debt in U.S. dollar denominated. And you compare that, for example, with our asset base, it's about 55% U.S. dollar denominated. So what we are doing is really rebalancing and reducing the amount of U.S. dollar-denominated debt that we have in our books. We don't do this from one day to the other because it would imply just going back and buying back some of our outstanding debt and paying what sort of mark-to-market or penalties would incur. So -- but what we'll be doing is as we mature the U.S. dollar-denominated debt, we will be financing with euros or EUR 3 and making sure that we balance that between liabilities and assets going forward. We do this with the U.S. dollar because U.S. dollar is super liquid and the strongest liquidity -- currency in the world, and we feel comfortable with the -- also with how the equity, how the equity exposure in U.S. giving such an important and strategic market. For other currencies, for example, Polish Zloty there or even the Romanian Leu or some of the APAC currencies, they will be looking slightly different in making sure that we have from the onset, a match between the investment in local currency and the funding in local currency. So that's pretty much what we are doing, so reducing U.S. dollar-dominated debt that it will have a positive impact. In the cost and the financial costs, we are estimating right now around EUR 100 million of positive impact on financial costs between 2024 and 2026. And again, these were not considered into our business plan projections. And maybe just a comment on the installation cost. Yes, I mean we have seen, as Miguel said in the presentation, pretty much stable on the wind side and important reduction on the solar panels. I think there it's also important to highlight that we only use equipment with very strict traceability requirements. I'm sure that we will be able to find cheaper panels out there, it's debatable whether or not they are compliant with these ESG requirements and feasibility requirements. But I think that to your point, it doesn't -- it's not immediate. So I mean, it does depend also in the moment when some of the players are locking in their cost and discussing the PPA pricing. But obviously, at some point, you will see sort of a convergence on the PPA pricing towards what is the price that, together with the CapEx and the WACC, we've enabled the sector to meet the 200 basis points spread over cost of capital. And again, the dynamics, it's hard to say if it's going to be a month or 2 or 6, but they tend to converge. So there is so much you can capture from that upside throughout the period -- throughout the cycle.

Okay. So we go to the last question from Jenny Ping from Citi.

A couple of questions from me, please. Just firstly, on Colombia. I understand 2023 has had around EUR 100 million of negative cost because you had to buy back the volume of power on the market to supply under your PPA contract. Given it's now deferred beyond 2024, can you quantify what you're expecting in terms of the cost associated with the delay of that contract? Secondly, can you talk a little bit about your expected '24 interest position. Obviously, you hinted at the EUR 100 million improvement in the interest line. Looking at consensus, we're probably about EUR 450 million implied interest cost. Is that something you're comfortable with? And then very lastly, just on the U.S. for SouthCoast wind. Is the accelerated New York auction something that you would be interested to bid that asset back into U.S. offshore wind? Thank you.

Okay. Jenny, it's Rui here. So just to be clear, the impact in Colombia is not EUR 100 million this year, it's way lower. I think it's around EUR 50 million and this is flowing through the P&L. So into 2024, it will also depend on whether there would be a PPA suspension. Again, when we -- this is something that we have been including into our numbers. So as Miguel said, that we are now comfortable around the consensus on EBITDA level. It's already incorporating that if we do not get that PPA suspension, I would say that we should have sort of a same ballpark figure into 2024. The main variable will be the power prices in 2024 and the impact that El Nino has. So in a nutshell, around the mid-50s this year so far and pretty much, I would say, the same levels into 2024, depending on how also power prices evolve in Colombia. On the interest rate, to be clear. So this EUR 100 million is spread through the period. So it's not a single year. It's not everything into 2024, unfortunately. So this is spread out through the period. So it would be a positive -- a small positive to the 2024 forecast. By the way, so I think it will be slightly below the EUR 450 million.

Yes. For the SouthCoast, the idea. Yes, I mean we have a great project. It has a low -- we paid what seems certainly now is by recent standards, low value for the seabed lease, the EUR 135 million at the time, of which we have 25% in direct stake. We have obviously developed the project substantially in terms of permitting and licensing and that. So it's a pretty mature project, probably one of the more mature projects in the U.S. And so we would be looking to bid into auctions now in 2024 to get that going forward. I think that's why we see it as a relatively good and interesting data point, the $150 per megawatt hour PPA, which was awarded recently in New York because I think that serves as an interesting benchmark for the sector. And obviously, the SouthCoast was contracted previously at around the high $70 per megawatt hour, PPA price. That obviously doesn't make sense anymore. So we were able to step out of that contract with a relatively small penalty. And so now we can rebid into the auction and hopefully get a higher PPA price and to be able to move forward with the project, and that's the intention. So I think these are good options, offshore options that we have in the U.S. Obviously, as you know we have relatively low capital employed or deployed there. And so there are good upside, let's say, if we can get a good PPA for these projects.

Okay. Brilliant. Sorry, just to check -- you did say less than EUR 450 million, right? That it dropped out in terms of implied interest?

Yes.

I was just commenting, we will address -- we have more a few questions, but we'll address the rest by phone on IR and we can now go to conclusions.

Thank you, Miguel. Probably that's my fault because I probably gave some longer answers until last time. But yes, we'll definitely get back to you on the IR with more detailed replies to any of the questions you might have. I mean feel free. And obviously, we'll be on the road as well in terms of investor meetings and meeting with you throughout the next couple of weeks. But perhaps just final remarks, I mean, we continue to see the structural tailwinds there for the sector. Obviously, we've seen what happened to the share prices generally of renewables in the last couple of months, 6 months, and there's obviously been pretty negative news flow in general in the sector. But I think if you look at -- if you take a step back, the sector as a whole continues to have good growth opportunities. So going back we do see good opportunities to deploy capital at attractive returns. I think that the history and the track record of the asset rotation is a good market test. It's not just -- let's say, don't just take our work for it, but we can create value. We are doing it sort of and showing us through some of these asset rotations. Obviously, we are being hit this year with some negative headwinds in terms of both, I mean, much less wind, El Nino. I mean we're talking about very, very low wind in the U.S., which is obviously flow straight through to the bottom line. So we're losing a lot of net income, but it's coming straight from the top line COD delays and less wind and that flows straight through to the bottom. So going back a little bit to Alberto's question about the EUR 100 million. I think if you strip out some of these on a more normalized basis, you would get certainly a healthier net income. And so I think we need to look through the quarters and look at more the sort of medium and long-term trends and you would expect to have in terms of net income. If you're looking from quarter-to-quarter and take tactical decisions on that basis then, I mean, it's not compatible with taking some of these investment decisions, which are long-term investment decisions. We are totally focused on value creation. We're totally focused on making sure we're deploying capital with good returns. We are very conscious of the higher cost of capital and that we need to have a spread to that. We're very conscious of the way that we model these products. And so we spent some time not just in the presentation but also in answering the questions. Talking about the long-term power prices and how we model that. We've been doing this for many, many years and I think we know this pretty well, I'd say, as well as anyone else in the sector better. And so we feel comfortable with the way that we project these, let's say, investment decisions that we're taking. In any case, we are going to be very focused on efficiency as well, increasing much more. It's not that it wasn't important before, but clearly an inflationary environment, efficiency is critical, looking at all potential avenues and initiatives to really drive down costs and get the economies of scale that are important for a business that's growing. And so I'd leave it on that note, just saying hope to talk to you soon. But as more information comes out -- and I'm sure we'll have additional information coming out over the next weeks and months in terms of when we close the asset rotations when we close PPAs, we'll provide additional information in the market and guidance. And yes, and so hopefully, with the data points we recognize, I mean this is one of the things I've been talking about, which is I think it's important to build back trust. And I think that's impacted the sector over the last couple of months. And I know we'll need to earn it back through providing data points, providing information, providing results over the next 3, 6, 12 months so that we can all feel comfortable with what's happening in the sector. So you can count on us to do that. Thank you very much.