Good afternoon, everyone, and thank you for joining us today to discuss RWE's results for fiscal 2020 and what lies ahead of us for the current year. We hope you all had a good start to 2021, and let's keep our fingers crossed that this year is, from a pandemic point of view, much better than 2020. I'm joined by our CEO, Rolf Martin Schmitz, our current CFO, Markus Krebber, and also our future CFO, Michael Müller, who will be happy to answer your questions too. With this, I hand over to Rolf. Yes, thank you, Thomas, and a warm welcome to everyone. It's a little bit of a special day for me. It's the last time I'm doing this full year call with you before I step down from the board. You can imagine it's a real pleasure to speak to you today, and I'm really pleased that I can hand over a great company and all we have achieved into the safe hands of Markus and the new entire board. Let us have a look to 2020, and 2020 was another very good year for RWE. We continued our transformation into a leading renewable player, took important operational and strategic steps, and exceeded the earnings expectations for the year. After completion of the transaction with E.ON, the business is now fully integrated and operating in the target structure since summer last year. We have set the course for additional growth in our renewables business. As such, we completed the acquisition of the 2.7 GW Nordex development pipeline, and we successfully raised EUR 2 billion in new equity back in August last year. For 2020, we have exceeded the group's guided KPIs. Adjusted EBITDA of the core business amounted to EUR 2.7 billion. Adjusted EBITDA for RWE Group amounted to EUR 3.2 billion, and adjusted net income went beyond EUR 1.2 billion. With this, we confirm our dividend target of EUR 0.85 per share for fiscal year 2020 and will propose this to the AGM in April. Net debt declined significantly to EUR 4.4 billion, and the leverage factor was 1.7x net debt to co-adjusted EBITDA, well below our target of 3 x. As evidenced by these numbers, we experienced only relatively minor issues related to the pandemic last year, such as a negative run-off in the financial results stemming from Q1 and delays in the commissioning of new onshore and solar assets, primarily in the U.S. With the farm- down announcements in December, we also demonstrated very good results from our asset rotation program. The farm- down of the Humber U.K. offshore wind farm, as well as the farm downs of the four onshore wind farms in our Texas portfolio, created value from the development and construction of assets. When it comes to total investments, we can now report that 84% of our CapEx is eligible as green investments under the proposed EU taxonomy. With this, let's shift the focus to ESG. With regards to coal operations, we have been successful in Germany's first hard coal closure auction with both of our remaining coal plants, Ibbenbüren and Westfalen. Both plants have been taken off the grid and are subject to confirmation by the Bundesnetzagentur, which is expected by the end of June this year. With that, RWE will no longer operate hard coal power stations in Germany. Furthermore, we not only closed the first lignite plant at the end of 2020 under the German coal exit law, we also signed a public law contract with the German government on the lignite phase-out. Above all, our clear target is to become carbon neutral by 2040. Our climate targets are in line with the Paris Agreement. This has been officially acknowledged by the Science Based Targets Initiative. We will have closed almost 3 GW of lignite capacity by the end of 2022, resulting in a reduction of over 3,000 jobs, which we will, of course, manage in a socially responsible way. This will be done in agreement with the unions based on the collective agreement which has been negotiated over the last months. To round that off, when mining activities come to an end, our high-quality renaturation program gives local communities valuable areas for recreation. Our efforts in renaturation are therefore an important contribution to the environment and biodiversity. On diversity, we scored above average among our peers for our inclusive culture at RWE as part of the Bloomberg Gender Equality Index. Good governance is a backbone for future performance. At the next AGM, we will bring in various topics for renewable and will ask for our shareholders' approval. Firstly, we will introduce shorter election cycles and a staggered board system for shareholder-appointed Supervisory Board members. Secondly, the proposed revised management remuneration system includes ESG targets, share ownership guidelines, and a clawback clause. Thirdly, we also propose renewal of the authorized capital as existing authorization was partly utilized with the capital increase last year. Now, on page five, you can see our full year performance on EBITDA levels. As I mentioned at the beginning, adjusted EBITDA of the core business and the RWE Group exceeded the guided outlook for the year. The core business was driven by the very strong results from the Supply and Trading business, even if the business closed below the exceptionally high level of the previous year. The Wind and Solar business has increased earnings by roughly 10%. Offshore took advantage of excellent wind conditions in the first quarter, and earnings at the Onshore Solar division increased on the back of capacity additions. In total, the Wind Solar business made up more than 50% of the core adjusted EBITDA. The result from other consolidation was better than expected, thanks to a very good contribution from Rampion, the German TSO, where we have a stake of 25.1%. Speaking of which, let me stress that we have no intention of selling our stake in Rampion. Now, dear investors, dear analysts, I will hand over to Markus. Yeah, thank you, Rolf, and hello to everyone also from my side. I hope you are all well. Let's continue with an update on our development activities. You can see on page six, the development pipeline has increased significantly since our last update back in March 2020. Our development pipeline has grown to around 34 GW, but 34 GW excludes all central tenders and lease auctions. With regard to Offshore, we have a reasonable amount of development projects coming online by the end of this decade. Of course, we are pleased that with the latest addition of 3 GW as a result of the U.K. round four seabed lease auction. In Onshore Wind Solar, our origination efforts and the acquisition of the Nordics pipeline paid off. Given the continued attractiveness of the ITC regime, we have significantly extended our solar pipeline in the U.S., but we also continue to see the U.S. as an attractive market for onshore wind. Now, moving on to the progress of our construction program. Ladies and gentlemen, total capacity stood at 9.4 GW year-end. Another 3 GW are currently under construction, and we are well on track to reach our target of at least 13 GW by the end of 2022. In Q4, we have taken final investment decisions for some 100 MW of onshore projects, mainly in France and Poland, stemming from the Nordex pipeline. From our transaction with E.ON, we will integrate the acquired 20% stake in the U.K. Rampion offshore wind farm. This will add another 80 MW to our capacity. The transaction is expected to close in the next couple of months. If you also take into consideration the farm-downs at the four onshore wind farms in Texas, which we have already announced, capacity will be reduced by 0.6 GW on a net basis from asset rotation during the course of this year. Let's now take a closer look at the offshore business on page eight. 2021 is an important year for Offshore Wind, and we have started well by already reaching a couple of important milestones. On construction, slightly ahead of schedule, Triton Knoll started generating power. The wind farm is expected to be fully commissioned at the beginning of next year. Our German Kaskasi project in pre-construction is well on track. Offshore construction work will start later this year. For our 1.4 GW Sofia project located on Dogger Bank, we will take FID during the course of H1. As already mentioned, we have been successful in the U.K. Round 4 lease auctions, where we were awarded with a maximum of 3 GW, two adjacent sites of 1.5 GW each, located on Dogger Bank close to our Sofia project. The development activity started immediately. In Poland, the Offshore Wind Act has been published and paves the way for our Baltic II project. It qualifies for the first phase, and CfD allocations will be granted by direct notification. The grid connection agreement is already secured. We have handed in our CfD application, and we hope to receive positive feedback from the Polish government this summer. Moreover, we are preparing our Dublin Array project for this first CfD auction, which might take place in early 2022. The CfD regime is still being developed in Ireland. The project size is now up to 900 MW from 600 MW, of which we hold 50%. In Taiwan, we are preparing the Chu Feng project for its participation in the grid location round, which also includes a 20-year feed-in tariff for the auction winner. The auction is expected to take place at the beginning of 2022. Furthermore, there are a variety of central tenders and lease auctions taking place globally in 2021. Among them is the central tender in Denmark for the Thor project. We are delighted to be one of six shortlisted bidders who may bid for the license of electricity production as a CfD scheme. Let's continue with the onshore solar division. More than 20 projects with a commissioning date in 2021 are currently under construction. As you can see, we are not only driving growth in onshore solar and batteries in the U.S., where some of our projects experienced COVID-related delays, but also in our core European markets, where we expect the commissioning of the first project for the Nordex pipeline by the end of 2021. The diversity of the project is obvious. A few large projects in the U.S. in contrast to multiple smaller projects across Europe. Now, moving on with an update on our hydrogen activities. Our engagement in hydrogen continues to take shape. We have a dedicated board member and resources in RWE Generation for H2, who are defining and implementing the hydrogen strategy for the RWE Group. It is clear: carbon-free hydrogen is currently the only truly sustainable option to decarbonize energy-intensive industries, aviation, and heavy-duty transportation. It is also a potential climate-neutral fuel for gas plants. However, carbon-free hydrogen needs a government support framework to compete with gray hydrogen. Today, our focus is on two aspects of the evolving hydrogen economy. On the one hand, we are actively participating in the debate on how to regulate the H2 business and how to incentivize the use of carbon-free hydrogen and stimulate the necessary investments. On the other hand, we engage in many projects and with numerous partners to actively shape future H2 business models and its value chain. Today, we are active in more than 30 hydrogen projects together with many different partners. To name a few, our GET H2 project in Lingen plants a 100 MW electrolyzer, which will be the biggest in Europe. The Aqua Ventus initiative in Heligoland will produce H2 directly at sea, so with electrolyzers at the offshore site. In the U.K., our Pembroke site belongs to the South Wales Industrial Cluster, which aims to centrally produce and distribute hydrogen. In the Netherlands, we are part of the Nort H2 Consortium and are driving forward our Eemshydrogen project for a 50 MW electrolyzer to supply local industry with green hydrogen. Today, we are one of the very few players who cover the entire value chain. We can produce green electricity, we can run electrolyzers, we know how to transport and store, and we can structure offtake solutions for industrial customers. That is it for the brief strategic update. We will now continue with a detailed discussion of our financials for 2020, as well as the outlook for 2021. Our Offshore Wind division realized an adjusted EBITDA of almost EUR 1.1 billion, up 11% versus 2019. We closed 2020 cleanly in the upper end of the guidance thanks to very good wind conditions in the first quarter of the year. Whilst cash investments are mainly driven by Triton Knoll construction work, gross cash divestments primarily reflect the 49% Humber farm-down. For 2021, we increased the outlook to EUR 1.05 billion-EUR 1.25 billion. We expect earnings from the commissioning phase at Triton Knoll and positive contributions from the full consolidation of Rampion, and we will have increased our stake to 51%. At the same time, we return to normalized wind conditions and increased development expenses for the mid to long-term growth through partly offset this. The Onshore Wind Solar division increased adjusted EBITDA by 7% year-on-year to EUR 472 million. The increase in capacity of approximately 800 MW year-on-year drove earnings up, while an unfavorable development of power prices in the U.S. and also in various European markets had a negative impact. However, performance fell short of expectations as we experienced poor wind conditions in the fourth quarter. Besides that, the COVID-19-related delays in our construction program have eased earnings. COVID-19 might further impact the construction progress depending on how the situation further develops in 2021. The outlook for fiscal 2021 is significantly impacted by the extreme weather conditions in Texas in February this year. Once-in-a-century weather event led to extreme levels of demand, combined with an unprecedented amount of infrastructure failures due to freezing weather conditions, including outages on natural gas pipelines, conventional plants, nuclear, coal, gas, and solar and wind generation assets. Record-low Arctic temperatures in combination with up to 10 cm of ice also significantly affected our operations, in particular in the north and west of Texas, where many of our assets are based. To reduce earnings volatility, we hedged a certain share of our expected production upfront. In evaluating our expected production, we, of course, take weather into account. Our hedge volumes for February were already lower than for other winter months. For some periods of the year, we do not hedge at all if we see the risk of having to pay high market prices during periods of low production. We then adjust our hedging volumes the closer we get to actual production. When it became apparent that the icing of the Texas freeze would significantly lower our expected output, it was not possible to reduce our exposure due to the already high power prices and low market depth. To be fair, at that time, we also did not expect regulatory intervention in the form of the order of the PUC to drive prices even further up and fix them at $9,000/ MWh and for such a long period of time. On average, we were short some 400 MW during the critical week in February. So far, this has caused a financial loss of slightly more than EUR 400 million, which is reflected in the fiscal year guidance for 2021. However, it is also clear that the event and actions taken remain under review by many of the regulatory authorities in the U.S. and are also subject to various legal proceedings, and therefore the final result might change. Besides our regulatory and legal proceedings, our focus is now on a full review of the incident. We need to see what learnings we can identify not only for our U.S. business, but the wider group, and covering all aspects: hedging policies, asset management, and investment decisions. Earnings guidance for 2021 also reflects capacity additions, which will have a positive effect on the book gain for the farm-down of our four onshore wind farms in Texas, which will also be accounted for in 2021. However, slightly increased development expenses for the further mid to long-term growth in line with the progress of our development pipeline will impact 2021 earnings. Finally, as of the 1st of January this year, we will account for tax benefits as part of the U.S. tax equity incentive scheme in adjusted EBITDA. So far, this has been part of the tax income below the EBITDA line. We think the new methodology better reflects the economic nature of the income, and it is then in line with how our peers present tax incentives in their earnings. Year-on-year, this has a positive impact of about EUR 40 million. For this reason, we have restated 2020 figures. Accordingly, and from Q1 onwards, we'll report the restated figures. You will find a table with restatement in the appendix of the presentation. The outlook for Onshore Wind Solar will be significantly below last year's level, ranging between EUR 50 million-EUR 250 million. Earnings at the Hydro Biomass Gas division amounted to EUR 621 million. With this, the division closed in the upper half of the guided range. Very strong fourth quarter benefited from the earnings contribution from the day-to-day optimization of the power plant dispatch. Year-on-year, earnings are lower mainly due to one-off payment in Q4 2019 from the resumption of the British capacity market. For 2021, the outlook for the division is EUR 500 million-EUR 600 million. We expect a normalized level from the short-term optimization. Also, the half-year earnings contribution from Georgia Biomass in 2020 is missing as we have sold it. However, as operations at the Eemshaven power plant are now back to normal, this is partly compensating for the shortfall. Moving on to Supply and Trading, the division contributed EUR 539 million in EBITDA on the back of a very strong performance throughout the year. In particular, the performance at the end of the year was significantly stronger than anticipated, which led to the division outperforming the outlook. For 2021, we expect to return to a normalized earnings level, so the outlook is EUR 150 million-EUR 350 million. Having now reported on the core business, let's move on to the Coal and Nuclear division. Adjusted EBITDA increased to EUR 559 million mainly due to a higher realized hedge generation margin. The division has closed the year as expected. For full year 2021, the division can once more increase earnings on strengths of higher realized hedged margins. However, we also expect additional implementation costs stemming from the accelerated coal exit plan. To sum this up, the outlook for the Coal Nuclear division is EUR 800 million-EUR 900 million in 2021. We are pleased that a compensation agreement regarding the economic consequences from the nuclear exit has been reached with the German government. The compensation payment of EUR 880 million will cover the remaining unusable nuclear generation rights, as well as the stranded investments. After a ruling from the Federal Constitutional Court in Germany in favor of Vattenfall in September last year, the German government had to rework its compensation proposal. We will report the payment of EUR 880 million as part of the non-operating result. The agreement between the German government and the operators needs to pass the German Parliament and is subject to EU approval. Moving on to the earnings drivers down to adjusted net income. Thanks to the very good operational performance, our adjusted net income amounted to EUR 1.2 billion at the end of the year, clearly beating expectations. The adjusted financial result of EUR -350 million includes a negative one-off of approximately EUR 150 million from Q1 and the E.ON dividend received in Q2. The adjustments in the tax are applied with our general tax rate of 15%. With that, on to the adjusted operating cash flow on page 18. For 2020, adjusted operating cash flow went up to EUR 2.7 billion in view of the high adjusted EBITDA. Changes in operating working capital turned negative at year-end to EUR -140 million. Originally, we had expected a positive contribution for the full year, especially due to the payment from the British capacity market from 2018 and 2019, which we received in Q1 2020. However, this was negatively overcompensated mainly by higher year-end accruals in the Supply and Trading and the Wind and Solar business, which will revert for the most part in 2021. For 2021, we expect the cash effect from changes in operating working capital to turn positive. Turning to the details on the net debt development, net debt decreased to EUR 4.4 billion. This is mainly due to the high adjusted operating cash flow and the capital increase. Other changes in net financial debt include the redemption of the hybrid bond and timing effects from hedging and trading activities. Another driver is the change in pension provisions by roughly EUR 400 million compared to year-end, resulting from lower discount rates at year-end 2020 compared to 2019. Finally, moving to the outlook for 2021, we expect earnings to be lower year-on-year. This is because of the negative effect in the onshore solar division from the extreme cold snap in Texas and fully reflected in the earnings guidance. Furthermore, we expect normalized earnings at supply and trading and a higher contribution from offshore. Adjusted EBITDA of the core business is expected to be between EUR 1.8 billion and EUR 2.2 billion. Adjusted EBITDA for RWE Group will range between EUR 2.65 billion and EUR 3.05 billion. The forecast for adjusted EBIT is EUR 1.15 billion to EUR 1.55 billion. The adjusted financial result is expected to be roughly EUR -150 million. Adjusted minorities will also increase in the amount to approximately EUR -100 million, which goes hand in hand with the consolidation effect of Rampion, as well as income from the commissioning phase of Triton Knoll. Adjusted net income is therefore expected to range between EUR 750 million and EUR 1.1 billion. For fiscal 2021, the dividend target is EUR 0.90 per share. For the leverage factor, we expect it to be below three times net debt to core adjusted EBITDA. A year ago, we gave an outlook for 2022 as well and some guidance on significant drivers beyond 2022. Let me briefly revisit that. Today, we can fully confirm the outlook for 2022. I can also confirm the outlook on the divisional level. We now see the offshore division in the upper half of the guided range, whereas onshore solar might be in the lower half of the range. The latter is driven by a weaker US dollar and additional development efforts for our long-term growth plans. We adjusted for the Rampion consolidation effect in the line item adjusted minorities. The expected range for adjusted net income for 2022 is confirmed with a midpoint of EUR 1.2 billion. Furthermore, I want to remind you about a few relevant aspects for the period beyond 2022. At Offshore Wind, the dropout from the high level of the EEG compression model will start at the offshore wind farm Nordsee Ost in 2022 and at Amrumbank in 2023. In the years 2023 to 2025, this will result in a negative EBITDA impact of EUR -320 million in total. For Coal Nuclear, I can confirm the guidance from the CMD. After 2022, the division will have an EBITDA contribution in the range of EUR 0-EUR 200 million per year. Including efficiency improvements, the liquid operations will on average be cash flow positive. Finally, a word on tax. Due to the announcement in the U.K. about increasing the corporate tax rate from 19% to 25% in 2023, we will most likely need to adjust our general tax rate, which we applied to calculate adjusted net income. Ladies and gentlemen, before we move on to the Q&A session, allow me some personal remarks, and this is my last investor presentation as RWE CFO and the last one with Rolf together. It has been quite a journey since 2016 when we both took office in our current role. I mean, just to name most relevant events from a capital market perspective of the last almost five years. We closed the nuclear chapter for RWE with the fund where we contributed EUR 7 billion, winning the court case on nuclear fuel tax and the recent compensation agreement, which will finally close the file. You will, as we do, all remember the day of the unexpected negative court ruling at Humber. We at RWE made a virtue of necessity, sorting out our coal business with a clear path ahead and very limited economic exposure going forward based on two things. One, the agreement on the coal exit with the German government, and two, turning our large CO2 short into a neutral to long position with a creative hedging approach. Of course, we have the ongoing revolutionary transformation of RWE based on the transaction with E.ON, one of the largest and most probably complex transactions in our industry. Now we are setting our renewable growth plans, already including the Nordex acquisition and the successful EUR 2 billion capital raise overnight in August last year. We know that we have kept you all very busy, and we would like to thank you for your excellent coverage of RWE. It was not always easy for you to look through a lot of legacy to see the new RWE evolving. We personally enjoyed the interactions with you all very much, and we appreciate the open feedback and food for thought we got from the market. The controversial ones are sometimes not easy to digest but highly valuable. Please continue your good work. I'm looking forward to also interacting with you in my future role, but probably not as regular as in the past. As CFO, I leave you now in the trusted hands of Michael supported by the best IR team I can think of. Now we need to get back to work and the Q&A session, Tom. Thank you, Markus, for the kind words to all of us here in the room. Operator, please start the Q&A session, and if you have the time, please stick to two questions each. Thank you. Molly, over to you. Thank you. If you would like to ask a question, please press star one on your telephone keypad. Please ensure your line is unmuted locally. You will then be advised when to go ahead with your question. The first question today comes from the line of Alberto Gandolfi, calling from Goldman Sachs. Please go ahead. Your line is unmuted. Thank you, Operator, and thanks, management, for taking my questions. Rolf, thank you so much. I wish you all the best on your future endeavors. Thanks a lot for making this, yes, hard work, but very exciting in the past few years. The best wishes to Markus and Michael. Okay, now to the questions. Two, the first one is actually quite rare, but about power prices. We have not talked about power prices in RWE for a while. I guess my question is, can you maybe remind us what power prices have you been using in your 2022 guidance? I know you are hedging on the legacy. I wonder on some of the renewable assets as well that may no longer be on subsidies. Am I right in thinking that when you were guiding to the EUR 350 million-EUR 400 million negative impact beyond 2022 to 2024, 2025, maybe can you give us an update of that roll-off of subsidies? I suppose that with power prices going higher, that impact is getting smaller. We are just trying to reconcile a little bit if that earnings cliff post-2022 is getting smaller. The second question is on the U.K. leasing option, seabed option. I mean, I wanted to ask you if you can give us maybe your mindset. Why did you bid this, I think it was GBP 82/ kW? What makes you comfortable that this is going to be a pass-through cost? When do you think is going to be the first capacity CfD auction you can be participating into? Is it 2025, later? How are you thinking about the game theory? Because now there is a negative incentive, right? You keep paying that until FID. If you, Total BP, or whoever else is going to win the Scottish seabed, if you miss out on a capacity auction, you automatically have two more years of negative liability to pay for. What do you think this is going to do to the returns? I know there are like eight questions in one, but perhaps if you can tell us how you are thinking about the seabed, how you think about returns, why did you pay what you paid, anything you can, any color you can give us would be fantastic. Thank you. Alberto, thank you very much. That was a very creative way to package, I do not know, how many questions into two. You had two themes, maybe not two questions. The first one on power prices. I mean, it is not that we have set power prices at a certain level, so we continuously update the forecast of 2022 and also beyond based on the open position and the current forward curves. We can fully confirm 2022 guidance. There are lots of moving effects. I mean, the minor one, to be honest, is power prices. Actually, FX is for us, when you look at our US dollar and British pound exposure, maybe even more relevant, and especially on the US dollar part, we have seen a negative development by around 10% from when we had given guidance originally for 2022 and today. I mean, the earnings cliff is a bit smaller for the compression model, but I mean, look where power prices are coming from in the hundreds. Whether you move from in the hundreds to 40 or 45, that does not actually make a huge difference. The number is still around the same which we have communicated 2020, so a year ago. Now, on the U.K. lease auction, I think that is a very interesting topic overall. We look at it from two angles. One is, of course, and that is the most relevant one, is an absolute level. Do we see that with this lease payment, we have a very high confidence that we can deliver valuable projects in the second half of the 2020s? Here the clear answer is yes. How are we exactly going to do that? I mean, which year and so on, that is also part of the assessment and, of course, sensitive information because there are potentially also different routes to market, and it depends on when we bid our extension projects, when others might bid, and so on. The question is, what is our, it's a scenario analysis because you are absolutely right when you take a linear view and say, "I develop as fast as possible, bid into the next CfD option." That, of course, means that what you have paid until then is some cost. It's irrelevant for decision-making. When you take a decision, how much you are willing to pay as a lease auction today, you need to factor it in. The question is, how competitive are the markets? I think two things are important, and here it comes to the relative part of the answer. One is, do you have high conviction that the renewable build-out targets are valid for the U.K. because the next lease auction is due only in five years? You are actually securing something which is very scarce. The other thing is, how do you actually act relatively to your peers? When you look at our auction results, I mean, first of all, the size, the adjacent size fitting good in our portfolio, and we are paying the lowest average lease auction, we also feel very comfortable. Is it significantly more competitive than previously? Yes, but I think we also need to make the point that an expectation that you can earn excess returns significantly above your cost of capitals for decades to come is totally unreasonable. I mean, competition is the basis of a market-based economy, so we need to get used to competition also in our business here. Thank you, Markus. Thank you. Next question, please. Thank you. The next question comes from the line of Lueder Schumacher, calling from Société Générale. Please go ahead. Your line is unmuted. Good afternoon, everybody, and also from my side, all the best for the future, Rolf. It certainly has been an interesting time. First question, this is really a question and a request, and it's on things that aren't in your presentation anymore. You no longer show the outright hedges or the implicit fuel hedge or the variation margin. Is there any chance you could restore the old level of disclosure? Adding to this, bearing in mind your net debt improved significantly in Q4. How much of this is due to the variation margin given that carbon prices rose 22% or so in Q4, and how much is due to operational improvements? The second question is on your renewable growth capacity. You say on slide nine that just in Onshore Wind N PV, you expect growth of 2 GW in 2021. Where do you now see your annual execution capacity? In March last year, if memory serves right, it was 1.5. Of course, we had the capital increase. You had the Nordex pipeline. How much renewable capacity can you now put in the ground per annum on average? Yeah, Lueder, thanks for the questions. I mean, on outright power prices and the implicit fuel action, we have decided to not disclose that information in the future because we think it is not relevant to assess the profitability of the business. We will guide you also, I mean, with an outlook not only of one and two years where we see then the lignite business profitability. I mean, the significant part was, of course, the nuclear part with the big open position. Lignite was already given that we have the CO2 hedges in place, a much smaller position. In future, you have two elements. You have the hedged margin, and the margin is already hedged for years to come, and the efficiency program because we need to reduce costs significantly. By just looking at the margin, you need a lot of information on the cost side as well to guide it. We will make it easy for you, so we will guide straight the net amount. We said we are comfortable with the guidance of EUR 0-EUR 200 million EBITDA for the years to come from 2023. We definitely talk about more than three years into the future of the EUR 0-EUR 200 million. That is more information than you would actually get in guidance performance for that segment with more disclosure on the hedge prices for the next two to three years. On variation margin, yes, there was a significant effect in Q4. I mean, you know that a significant part of our position is gas and CO2-driven, and especially CO2, but also to a minor extent, the gas position gained significantly in value. Your request to disclose more, I propose that you pick that up with my successor because he needs to deliver on that for the years to come and not myself, so I should not make any promises at this point in time. On the renewable growth, I am a bit reluctant to give you the answer now, but of course, you are addressing a very significant topic. What is possible in terms of absolute growth? We are definitely more bullish than we have been in 2020, a year ago when we presented the first plan. Let me also tell you what has recently changed in the mindset of management. When we first said maybe financing is not the limiting factor, but it is delivery capability, and we are a bit cautious when we first guided because we still have the integration of the renewables team and the full review of the pipeline and so on in front of us. I think financing also after the capital raise is definitely not the problem. Also, our pipeline looks very rich. Steering today, we would probably focus more on what is our net invested capital and what is the return of that capital because I think also now, and we all realize that that competition is, of course, increasing. I think by steering gross additions, maybe that looks sexy on the surface, but I mean, I do not want to put the teams under too much pressure to deliver every individual project from the pipeline. The ratio between gross pipeline and what you commit to deliver is important. If that is an overstretch, you risk that you need to do every project which is possible. On the other hand, if you have big gross targets, everybody, and especially you, will ask us immediately, "What is the disposal and what is the asset rotation?" If you throw out big promises on disposal gains, you are also under pressure to sell and probably the best projects first when there is more competition. I think that is the wrong steering. We will clearly focus on what capital do we net employ if we do gross a bit more and do a bit asset rotation, that is the icing of the cake. I mean, throwing out big gross figures is not the right thing to do in this environment. Very clear. Thank you. Thank you, Lueder. Next question, please. The next question comes from the line of Sam Arie, calling from UBS. Please go ahead. Thank you very much. Good afternoon, everybody. Yeah, let me add to my congratulations, Mr. Schmitz. It has been a pleasure being part of the coverage during your tenure, and you have done a massive amount. I think we have all enjoyed watching that. I wanted to just use my questions to ask one kind of detailed point and then one kind of handover-related question for Markus. The detailed one is on this little accounting change that you mentioned very briefly in the presentation, which is at the back of the appendix today. Could you spend a minute just to explain how that works because it does look like it gives you a bit of a benefit on the bottom line? I suppose whether that rolls forward in future years and I suppose how it relates to guidance because I guess the guidance stays the same, but now the accounting benefit gives you a little bit of a boost towards that. It would be helpful if you could talk us through that in a bit more detail. Markus, my kind of bigger picture question for you as you take over. You made some comments about how you see things now in the sort of CEO view, but my experience is every CEO's got their three big things they want to do and their three big problems that they worry about. I just would love to hear what are on your list of three right now. Thank you. Sam, thanks for the question. I mean, in the beginning, I thought one question is for Rolf, one is for me. Since the accounting one is not for Rolf, I have to answer that one. I have to delay the answer to the second question, maybe to the Capital Markets Day. I think it's not the right point to discuss it here now. On the accounting side, yes, I mean, you always learn, so we also learned, to be quite frank. What we realized is our tax income was slightly better than expected. That was because part of the tax incentives, not all, but I mean, according to the old tax treatment we inherited from the businesses we took over, part of the tax advantage was in the tax line item. We looked into it, and we also looked into how our peers presented in their adjusted figures, and we found that it is better to reflect it fully in the EBITDA because it will also be used to pay down tax equity debt. When you look at it in the long run, it does not make a difference to adjusted net income because you either take these advantages directly straight in the EBITDA line as we do it in future, or you need to reflect them in the calculated average tax rate. I mean, you can now discuss whether it gives us an upside of a couple of EUR 10 million for our original guidance in 2022 because we did not know about the effect, but I think the guided range is still EUR 200 million. Do not nail me now on whether we are more optimistic to be above the midpoint in 2022 now or not. As I said, FX is actually potentially the major driver for where we come out if everything operationally runs as expected. The other question I am happy to answer when I have the full reflection with my board and the operating management teams at the CMD later this year. Okay. Thank you. We'll look forward to that. Thank you, Sam. Next question. The next question comes from the line of Peter Bisztyga, calling from Bank of America. Please go ahead. Yes. Good afternoon. It's Peter Bisztyga here, and I'd also like to wish Rolf all the very best for the future. Two questions from me, please. Firstly, on Texas, you sort of mentioned the EUR 400 million exposure could change. I was wondering if you could elaborate a little bit on that. I think the Senate this week approved a bill to correct 32 hours of emergency prices. That seems to me like that should benefit you potentially. I was wondering if you could comment on that. Also, do you face any potential future claims of liabilities that could actually increase the EUR 400 million figure? That's my first question. The second one is regarding your coal exit contracts with the government, which actually has clauses that stipulate that you could spin off or transfer your coal business with permission from either federal or regional governments. Just wondering whether you've had any further thoughts about the prospects of an earlier exit from your lignite activities. Peter, on Texas, there are a couple of things ongoing. I mean, you already mentioned the political discussions to partly roll back the $9,000/ MWh. Clearly, if that happens, that would benefit us. That is now a minor detail, but there are also discussions to roll back partly the price for ancillary services, which were set at $25,000. If that would be rolled back, that would partly harm us, but to a lesser extent than the first benefit. The second big topic is mutualization because we can expect a lot of, if nothing changes, if nothing is rolled back, further bankruptcies. We think that effect on us will be very, very minor given the overall size of our business compared to the conventional colleagues. Of course, claims going in both directions. We also have legal proceedings ongoing. If I look at everything, I would say the definitely biggest effect will come from rolling back the $9,000. All others on legal proceedings, but also mutualization, what I expect there is definitely smaller and maybe not relevant for our guided earnings here. A potential rollback would be positive for us. It's too, I mean, it's unprecedented. We don't know how the proceedings will go on. Who will take the decision? Of course, if something will be changed that's not to the benefit of everybody, they will claim again. I think it's too early to tell. I expect actually maybe a year-long proceeding on these issues, nothing which will be resolved over the next couple of weeks. That's why we have also decided to put in it already into our guidance. On the other topic, the potential spin-off or divestiture of our non-core business, there is nothing new to report. I mean, our focus is now on the efficiency program to support the state aid approval where the German government is in and also to implement the closures and the efficiency program. Okay. Thanks very much. Thank you. Next question, please. The next question comes from the line of Ahmed Fahrman, calling from Jefferies. Please go ahead. Yes. Good afternoon, everyone, and best wishes from my side to Rolf as well. Two questions from my side. Firstly, just on net debt, where you had a sort of a big beat versus consensus. I mean, I obviously see your sort of the leverage target, but there is quite a big gap between where full year 2020 net debt was and what sort of probably the upper end of your sort of leverage target implies. I was hoping if you could give us a bit more granularity there around the sort of the big moving parts and given current commodity prices, what part of the variation margins might reverse or there might be some further inflow there. That would be helpful. My second question is actually on slide six, where you show a significant pipeline. I appreciate sort of your point earlier that you may not want to sort of talk too much at this stage about sort of specific growth targets. I mean, I'm just trying to better understand what does that sort of gigawatt of pipeline tell us about the potential ability to sort of drive per annum additions in gigawatt terms and what are the parameters around that? How has your thinking changed around probability of success on the pipeline and DevEx inflation since your Capital Market Day? Thank you. Yeah. Ahmed, thanks for the question. Let me start with the latter. Our probability of project success has not changed on the pipeline, to be very clear on that. More the steering that we will focus more on where do we want to spend our own money and keep the project. If we can do things on top, we can either build and sell, build and farm down, but we can also, of course, develop projects. I think the clear positive is that the pipeline has developed quite substantially into the right direction, not only by Nordex and the 3 GW of the U.K. Round 4, but especially, and I think I have been explicit about that, that I would like to see more solar, especially the solar pipeline has significant depth. We are actually very happy with the development here, and success probability has not changed. The gross potential to deliver gross has significantly increased, but we are reluctant to give you gross build-out targets because we think it is not the right steering metrics. We need to take some more time to tell you how we think we are going to present the future long-term strategy of the business for the years to come, and we do that then later this year. I mean, for me, it is clearly a very, very positive development. Of course, it comes at a bit more development expenditures, but of course, this pipeline is highly valuable. As I have said before, this higher competition has two effects. One is that your existing business and your development pipeline gains in value, and that pipeline is now significantly broader and deeper. The second one is, of course, in some central tenders and auctions, you see more competition than before. On the debt side, yeah, I think net debt clearly developed positive, but given power price and CO2 price developments also this year, we currently do not expect that it significantly reverses in the year 2021. I mean, you know our EBITDA target, operating cash flow will be around the same because we expect a positive working capital effect, which will offset the utilization of provisions. What we have is a significant investment program also on the gross side. I mean, currently, we have the two big offshore wind farms under construction, and we will start also significantly spending on Sofia, which we still have not farmed down. We keep 100%. We expect a significant ramp-up in gross investment this year, significantly more than in 2020. We have, of course, still a positive effect, which is a compensation from the government on the nuclear exit. Even with a significantly lower EBITDA from the taxes, we are very optimistic to stay below, maybe significantly below, the 3 x net debt to EBITDA. Does that anwer your question, Ahmed? Yes. Thank you. Thank you. Next question, please. The next question comes from the line of Vincent Ayral, calling from JP Morgan. Please go ahead. Hi. Yes. Good afternoon, everyone. A number of questions have been asked here. I'll come back on a thematic within the since the beginning of the year, a number of clients asking questions regarding return on capital employed. I heard you talking about exactly it's problematic. We had a number of questions, for example, Ørsted not really understanding the U.K. Offshore Wind leasing. I would like to come back on this question and understanding exactly what was referred to by Alberto as a game theory. Yeah, I agree with it. You put the finger. How does that work? I'm not sure I really understood the answer on this specific point. As we have a CMD talking about return on capital employed, it will become a metric and something on which we'll have target and be able to monitor going forward. That's on, I would say, returns, the size of the returns. The second is on Texas. You've been talking about EUR 400 million. Yes, there is 400 MW, which was exposed. Still, this number seems, I would say, fairly conservative. Could you confirm or give us a bit of color on how this is calculated? Because when I do the numbers, it would mean you have been short 400 MW for quite a long time. The coal stuff did not last that long. That's where I'm not totally clear. Thank you very much. I'm not sure whether I got the first question. Can you maybe specify the question on U.K. Round 4? Yeah. U.K. Round 4, once you basically did and you got your leasing, I think it's Alberto. I I don't know if he will talk about it. He said the game theory had something similar. Once you spend this money, this can force you to be below acceptable returns. There is significant sunk cost, which are ticking by the year, basically. That is really an element which is not clear to us. How can you be sure you're going to be there on the first round and develop the project on time at acceptable returns? How can you be sure that the U.K. electricity payer will indeed end up on this extra cost and you'll be basically getting your proper return on this project? I'm not sure whether this is a question or, I mean, just what we discussed before. I'll give it a try. I mean, you need to have a scenario analysis of future outcomes of CfD auctions or general power prices. And of course, you know that a lot of projects will bid into CfD auctions, which are not as competitive as your new technology, I mean, extension projects and others. If the U.K. reduces the offshore build-out targets and do less CfD auctions, of course, you're going to see higher merchant power prices and can become a merchant case. Actually, what we are discussing here now, the concept of water under the bridge is to a smaller extent relevant. I mean, it's the same for every development spend you have for every individual project and also the lease payments you have to pay for the U.S. projects. If you do acquisitions and buy pipelines, it's actually the moment you go into a CfD auction or into a PPA, it's the same. I mean, conceptually, I don't see why U.K. Round 4 has changed anything. It's the same debate on any M&A. It's the same debate on any U.S. lease. It's the same debate on every development expenditure. When you look at it, at least for what we're going to pay compared to the investment amount, it is not, I mean, significantly more than you also pay for other projects. Maybe, as I said before, maybe there is now coming back more reasonable assumptions of what you can earn. We are very confident, and some of you have done the calculation, what are potentially expected returns, and they are fully in line with our own thinking and fully in line with our IRR expectations and hurdle rates. Of course, you can always come up with scenarios where the lease auction payment is not justifiable. I mean, new technology, lower power demand, I mean, lower offshore build-out targets and reverting the energy transition and going back to gas and cheaper gas prices. I mean, lots of scenarios. This is exactly the uncertainty which you have and where you need to build your potential future outcome. As I said, there are some very relevant and experienced market players around which are even significantly more aggressive than we have been. On Texas, it's a simple calculation. I mean, the shortfall was for around five days. If you calculate a gap of 400 MW for five days times $9,000, you are even above EUR 400 million. Does it answer your question, Vincent? Yeah. On the point number one, yes, some people paid more like BP, quite a high level. It is difficult for me, I would say, here, and for a number of people in the market to really get the scenario clear in our head in order to get the return on that. Ørsted, who is quite a leading name, cannot find a scenario. They told us they did not understand either. Here, I do not get an answer which helps me understand. I am sorry about that. For Texas, yes, I have done these numbers, but I thought we may not have a 400 MW short every day for the five days. That is fine. That is fine. Understood on the second one. Thank you. Thank you very much. Okay. Thank you. Thank you, Vincent. Next question, please. The next question comes from the line of Elchin Mammadov, calling from Bloomberg Intelligence. Please go ahead. Hi there. I have two questions, please. The first one is, again, a follow-up on Alberto's question. Is it possible for some reason, if you lose the next CfD auction for this sea bed that you just won, can you build it and have it running as a merchant until the next CfD auction where you can bid and secure the CfD payments? Or once the construction started building, you're not allowed to bid at the CfD auction? This is a bit of a more clarification question. The second one is on DevEx. I mean, your presentation mentions an increase in development expenses. Can you talk a bit more about it and increase compared to 2020, or is it more a long-term increase in DevEx? That'll be useful. Thank you. Yeah. Actually, thanks for the questions. I mean, on the second one, DevEx, that is higher compared to 2020, slightly higher than 2020. We are talking about a low double-digit million amount for offshore and for onshore PV, so for both. That is due to the, I mean, as we have said, with the capital raise, we're going to increase our CapEx targets with more financial headroom. Of course, you also need some more upfront development expenditures to go to a higher running level of renewable build-out. That was the second one. The first one on the CfD auctions, I mean, the easy answer is, I mean, it will depend on what is the CfD auction design in a couple of years. I mean, under the current CfD auction, if it stays unchanged, my understanding is you cannot start building the project and then bidding an existing or under-construction project into a CfD. You can take the, of course, you can take a decision to go into a CfD auction. If you're not successful, you build merchant. The moment you are building and under construction, you cannot bid it once more into the CfD. It remains to be seen how things will change. Thank you. Thank you, Elchin. Next question, please. The next question comes from the line of Rob Pulleyn, calling from Morgan Stanley. Please go ahead. Hi. Thank you. Good afternoon, everyone. Let me join by saying thank you again to Rolf and congratulations. Of course, we wish you all the best for the future. Likewise, Markus in his new role. Now to the questions. Firstly, just do you believe the shifting or potentially shifting political landscape in Germany could change the coal phase-out plan for the country? What would this mean for RWE's position and the option value you have around the coal exit law? I suppose a related question, if I may sneak a half question in, is to what extent does the anti-coal announcement by companies such as AXA feature in RWE's sort of discussion and perception around continued coal exposure? The second one, I hate to return to the U.K. sea bed. There are many other things going on. Could I just ask specifically whether the IRR range you gave last year for mature offshore markets of 5.5%-8.5% unlevered is still valid for the U.K. sea bed project? If I can stretch that to you talked about the cost with Sofia. Would you be willing sort of directionally to give us an idea of how much cheaper this could come than Sofia? Thank you very much, guys. Yeah, Rob. I mean, the easy one is yes, we can confirm the range of 5.5%- 8.5%. I mean, to speculate now, what our assumption is how cheaper we're going to build at the end of the 2020s than for Sofia, where we have already signed the turbine supply agreement, I think that's not good and also sensitive information what we think where prices will go. Because when you look at these bidding processes, of course, you can have lots of assumptions, but the three relevant ones are your own cost of capital and potential financing capacity in years to come because you take a decision for an FID in a couple of years' time. The other one is power price expectation. And the third one is, of course, LCOE of the technology. I mean, I'm not willing to comment on all three since we have more upcoming auctions. On the political side, I mean, it's quite easy. Politicians can wish whatever they want, but I mean, we need to physically balance the system every day. Given where we are, I think the agreement we have with the government on the coal exit is clearly one which goes hand in hand with the current renewable build-out plan. We all know that Germany struggles to build out renewables as planned. I think regardless who is in the next government, they will all know. It's not the question that you can easily decide on earlier coal closure dates. The relevant question is, how do we accelerate renewable build-out? Then the coal phase-out, be it by market prices, by administration, or by merit order, will be, I mean, a consequence of that. It needs to be turned around. First, renewable build-out, then what happens on the coal side. To be clear, I mean, I'm not commenting on individual business relationships, but what I don't accept is that some market participants just take one thing and say, "I mean, I don't want you to, I don't know, mine more than X million tons of coal," if that is totally inconsistent with everything else. That means you need to administer who is allowed to use how much power in Germany. I mean, that cannot be accepted, not by us as a company. I can tell you, if this is a trend, we're going to have not only a political debate but also a debate about who is a trusted partner, not only for us, but the entire business community. Maybe just to add, you have seen it now through the hard coal auction which we have, that some of the hard coal power plants which want to go out and have got their auction premium, they can't go out because they are needed for the stability of the system. Therefore, there's not too much overcapacity in the market. If you are not now coming into a capacity market with a new government to build new capacity or gas- fired, for example, into the market, then it will be much more difficult coming up for the coming years to take out coal-fired power plants because they are needed. They have not to produce a lot of kilowatt-hours, but they are needed in the market. Therefore, we will see what is coming up with the discussion. What Markus said, I can only confirm, the build-out of renewables. That is what is still in the coal phase-out, nothing else. That's super interesting. Thank you for the comments on offshore IRRs. I had to try, and I'll hand it over. Thank you. Thank you, Rolf. Next question, please. The next question comes from the line of Deepa Venkateswaran, calling from Bernstein. Please go ahead. Thank you. Congratulations. Sorry. My best wishes to both of you for your new roles. My two questions. The first one is on the Onshore Wind outlook. I mean, obviously, you made this accounting change to realign with peers, but I suspect you have downgraded the 2022 earnings to the lower end. Can you help us understand if there is anything else going on other than the US dollar depreciation, which Markus, I think you highlighted, has fallen 10%? I think that has around a EUR 50 million impact. Is it really just FX, or is there anything else? I mean, are you now targeting slightly lower additions or lower returns or anything? That is my first question. The second one, apologize for this. Sitting here in the U.K. and this being the number one question from all clients, U.K. sea bed. I suppose my hypothesis is that obviously your site will probably compete with the BP site and other newer sites because the existing sites will probably get over in the next few CfD auctions. In the end, all of you are bound to include your seed bed leases in the auction process. You would obviously have an advantage over a BP. Could you kind of confirm whether that is the line of thinking you have? I mean, obviously, technology costs and all of these things are going to be common for everyone. If there is a larger turbine, obviously, everyone will factor that in. Is that the kind of main scenario that is embedding your auction bidding strategy? Thank you. Yeah. Deepa, we still have years to go. I mean, focus is currently on development to speed up development and get the project ready. What is behind our different scenarios? I can tell you we have different scenarios for route to market time-wise, but also conceptually. I mean, I'm not going there because we still have years to go. Let's see how it evolves. I think we're going to see very interesting developments around U.K. offshore. I can also tell you that we are very confident that we have valuable projects. We never had expectations that we can sell projects with ongoing significant disposal gains for the years to come because that means, I think the government has realized that they have given some very valuable projects for very little money to. I mean, in the oil and gas business, it was common for years that you have to pay royalties. Maybe the seabed leases are something which are comparable to that one. In onshore N PV, yes, you are right, it's FX. It's also slightly higher development expenditures. Please understand that, I mean, when we gave the guidance for the two segments a year ago, I mean, we had a rough understanding where we potentially farm down and where we keep. The upper guidance for offshore and the lower guidance for onshore is maybe now a specification since we also know how our program looks like because we have actually sold down more on the U.S. project than we have anticipated years ago. We also now have more offshore capacity with Rampion being available for us faster than expected. I mean, please read that also that we fully confirm the renewable guidance. The split in the business is now a specification since we are now smarter since a year has passed where we actually see the portfolio developing. I would not read too much into that. We are very happy with the development of both segments. Yeah, we see an FX effect, but I am also, when I look at the screen, maybe see that going in the right direction for us on the pound and dollar side again, and it partly reversed. Deepa. Okay. Maybe more generally, if you look to all the targets which are given in Europe and in other countries to become climate neutral, every project which is developed will come into the business. That's my really very, very clear opinion because they need more and more. If you think about H2, then they need more and more and more green electricity. Therefore, in the moment to speed up your pipeline is the best thing you can do because I'm really confirmed that all these projects will come into the business because otherwise they would have no chance to fulfill the expectations, their targets which they have given themselves. That's more general. It's not so concrete. It's not you can not put in the numbers directly. Looking to the market and which amount of green electricity is needed in the next 10 years, it's really so much everyone can invest. Makes sense. Thank you. Thank you, Deepa. Next question, please. The next question comes from the line of Piotr Dzieciolowski, calling from Citi. Please go ahead. Hi. Good afternoon, everybody. Two questions from my side, please. Firstly, I wanted to ask you about the EUR 800 million nuclear compensation. Can you please tell us what is the justification of it? Why did you agree on EUR 800 million? Because I understand that was a mutual agreement. What is the process that is needed and when you expect to get the money on your account and when the payment will come through? Second question, I'd like to ask on the renewable pipeline build-out. You currently have 34 GW versus 22 last year. We can easily locate the Nordex p ipeline plus the U.K. What is the 6 GW extra? Can you please tell us which assets you kind of added into the pipeline? Are they better or worse than the rest of the pipeline? We are the same positive about these prospects. Yeah. On the first question, the nuclear compensation, it dates back years when the government took the decision for the fast exit of nuclear and ordered the operators to close some of the units immediately and also reduced the remaining production volumes. There was, I mean, legal proceedings ongoing. I think we finally, as an industry, won the first court case, I think, in 2017. Based on that, the German government then came out with a compensation law, which then was disputed by Vattenfall. The constitutional court ruled that the compensation is not sufficient. They need to find a solution again. The German government then decided to close the file and also close the file on the arbitration proceeding of Vattenfall in Washington because as a foreign investor, they could also claim under the Foreign Investment Act. This was simply then a negotiation. The reason was coming from 2001, there was a consensus in nuclear where you get the right to produce a special amount of electricity in your nuclear power plant. They gave more license to this in 2009 or 2010. They stopped it again in 2011 after Fukushima. Now it was not possible to produce all this electricity in the power plants which you had the right to produce. Now they pay for these rights which we have to produce electricity. That is the reason why we get this money, EUR 880 million. There are only EUR 20 million of frustrated investments in this, EUR 860 million coming up from this amount of electricity which was given to us to produce, and we are not able to produce because of the lifetime shortages. The process is, yeah, currently as an industry in negotiations with the government about the detailed contract that will be signed within weeks, then it will be part of the parliamentary process. It needs EU approval, potentially not state approval, but generally EU approval. It is a compensation payment, so it should be easier. The expectation is that we get the money around end of this year latest, early next year. Your second question on the pipeline, I mean, look, a pipeline is a living animal, so to say. I mean, from the old pipeline of 22 GW, we have taken 2 GW of FID since then. That brings it down to 20. You have 3 GW of the U.K. lease R ound 4. You have the 2.7 from Nordex. There is a gap of 8. That has been developed because as you take FID, you constantly do development activity. If you split that, that's around 2 in onshore, 3 in solar, and 3 in storage. Can you repeat that? Because two in onshore. 22 is 2 GW FID since early last year. We have the 3 GW in the U.K. R ound 4. We have around 2.7 from Nordex from the pipeline. We have ongoing development activity which added around 2 in onshore, 3 in solar, and 3 in storage. Okay. Thank you very much. If you compare the chart, the pipeline chart that we gave in this year, and you compare the total per technology to what we gave last year, you can also kind of do your own calculations. Let us know if we can help you. Okay. Thank you very much. Thank you, Piotr. Next question, please. The next question comes from the line of Olly Jeffery calling from Deutsche Bank. Please go ahead. Thank you. Good morning, everybody. Two questions from me, please. The first one is coming back to the 2022 guidance. Can you confirm then if you are now above the midpoint of adjusted EBIT for 2022? Because if not, with the higher minorities, it implies you're closer to the EUR 1.1 billion adjusted net income, particularly if you factor in the tax equity benefit that you now include that would not have been there when you came up with the guidance and CMD. That is the first question. The second question is coming back to the U.K. seabed lease auctions. You mentioned the route to market. Could you please just give a comment on the route to market in terms of whether you have a preference between CfD, corporate PPA, and if on a worst-case scenario, would you be willing to run the project on a merchant basis? Thank you. Yeah. Olly, I can confirm for 2022 the midpoint of the adjusted net income because that is, I mean, where everything is baked in, the consolidation effect of Rampion, the tax effect, and also the minorities. That is where we target on. Plus minus a bit, I mean, it's not nailed down to EUR 25 million up and down. The other question is, I mean, we have a clear preference, especially for offshore, to ensure secured earning streams. Of course, either a government contract or a PPA, but not, I mean, the preference is really not to take the project merchant. Okay. Thank you. Thank you, Olly. Next question, please. Before we move to the next question, please be reminded if you would like to ask a question, please press star one on your telephone keypad. The next question comes from the line of Tancrede Fulop calling from Morningstar. Please go ahead. Hello. Good afternoon. Thank you for taking my question. I have two. The first one is a follow-up on the IIR question for Offshore Wind. Ørsted already announced that at their next Capital Market Day, they will shift from a firm IIR target to sort of watch plus spread return target. Will you maintain a firm IIR target for offshore, or could you also shift to a watch plus spread type of guidance? This is my first question. My second question, we're coming to the end of the first quarter. Could you tell us about the Offshore Wind conditions year-to-date? Last year was very favorable for Offshore Wind in Q1. Year-to-date, is it below normalized conditions or normalized conditions? Thank you. Yeah. I mean, the first one, I mean, the moment we decide to change our return expectations or the framework, how we guide our return expectations, we will let you know. Now speculating whether we can also consider changing it or not, I think that's leading nowhere. If we decide to steer and guide it differently, we will let you know. For the first quarter, wind conditions in January were slightly below average. January was on expectation, and March so far also on expectation. Is that okay Tancrede? Yes. Thank you. Next question, please. The final question comes from the line of Ahmed Farman calling from Jefferies. Please go ahead. Yes. Thank you. Thank you for taking another question from my side. Just on your Solar and Onshore Wind business, when you, I guess, think about sort of, I guess, the medium-term outlook, are there any sort of regional markets that fit your investment criteria in terms of growth rate and underlying project IRRs that you see as sort of missing from the portfolio or where you can benefit from building some further scale? Just interested in some thoughts on that. Thank you. Ahmed, definitely, when I look at the current market coverage which we have, there is no strategic gap. I mean, we had that gap in France, which we closed with the Nordex acquisition. And then when you have a team on the ground, you can, if you decide to ramp up development activities, as we have also shown from the development of our pipeline, you can do it with a team. Currently, I think in the core markets where we are active, we do not lack any relevant coverage. The detailed steering, which markets we see more promising than others, can be done within the resources we currently have. Okay. Thanks. Thank you, Ahmed. We have no further questions in the queue. So I'd like to hand the call back over to Thomas Denny. Thank you. Thank you, Molly. Thank you, Markus. Thank you, Rolf. Thank you, Michael. Thank you all for dialing in today. All stay safe and healthy and talk to you again latest at Q1. Thank you. Bye.