RWE Aktiengesellschaft (RWE) Earnings Call Transcript & Summary

Welcome to the RWE conference call. Rolf Martin Schmitz, CEO of RWE AG; and Markus Krebber, CFO of RWE AG, will inform you about the developments in fiscal year 2020. I will now hand over to Thomas Denny.

Good afternoon, everyone, and thank you for joining us today to discuss RWE's results for fiscal 2020 and to 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 Muller, who will be happy to answer your questions, too. And 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 the full year call with you before I step down from the Board. So 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. With that, let's 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 operation with strategic and strategical steps, and exceeded the earnings expectation 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 of -- for additional growth in our renewables business. As such, we completed the acquisition of the 2.7-gigawatt 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 we'll propose this to the AGM in April. Net debt declined significantly to EUR 4.4 billion. And with the leverage factor was -- and that the leverage factor was 1.7x net debt to core adjusted EBITDA, well below our target of 3x. As evidenced by these numbers, we experienced only relatively minor issues related to the pandemic last year, such as negative one-off in the financial results stemming from Q1 and delays in the commissioning of new onshore and solar assets, primarily in the U.S. There's a farm-down announcement 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 4 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. And 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 core plants, Ibbenbüren and Westfalen. Both plants have been taken off the grid and are subject to confirmation whether it's Bundesnetzagentur, which is expected by end of June this year. With that, RWE will no longer operate hard coal power stations in Germany. Furthermore, we have 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 phaseout. 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 gigawatts 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 month. And to round this 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. And thirdly, we will also propose renewal of the authorized capital as existing authorization was partly utilized with the capital increase last year. Now on Page 5, 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 & Trading business, even if the business closed below the exceptional 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 Amprion, 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 Amprion. And now dear investors, dear analysts, I will hand over to Markus.

Yes. Thank you, Rolf, and hello to everyone also from my side. I hope you are all well. So let's continue with an update on our development activities. You can see on Page 6, the development pipeline has increased significantly since our last update back in March 2020. Our development pipeline has grown to around 34 gigawatts. The 34 gigawatt 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. And of course, we are pleased that with the latest addition of 3 gigawatts as a result of the U.K. Round 4 auction. In Onshore Wind/Solar, our origination efforts and the acquisition of the Nordex 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 continued 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, installed capacity stood at 9.4 gigawatts at year-end, another 3 gigawatts are currently under construction and we are well on track to reach our target of at least 13 gigawatt by the end of 2022. In Q4, we have taken final investment decisions for some 100 megawatts 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 18 megawatts to our capacity. The transaction is expected to close in the next couple of [indiscernible]. If we also take into consideration the farm-outs at the 4 onshore wind farms in Texas, which we have already announced, capacity will be reduced by 0.6 gigawatts 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 8. '21 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, driving nonstop generating power. The wind farm is expected to be fully commissioned at the beginning of next year. Our German Kaskasi project in preconstruction is well on track. Offshore construction work will start later this year. For our 1.4-gigawatt Sofia project located from Dogger Bank, we will take FID during the course of H1. As already mentioned, we have been successful in the U.K. round for these auctions, where we were awarded with a maximum of 3 gigawatt, 2 adjacent sites of 1.5 gigawatts each located on Dogger Bank close to our Sofia project. Development activities 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 when CfD allocations will be granted by direct notification. The Grid Connection Agreement is already secured. We have handed in our CfD application, and we are -- 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 '22. The CfD regime is still being developed in Ireland. The project size is now up to 900 megawatts from 600 megawatts, of which we hold 50%. In Taiwan, we are preparing the Chu Feng project for its participation in the grid allocation 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 '22. Furthermore, there are various variety of central tenders and lease auctions taking place globally in '21. Among them is the central tender in Denmark for the [ TOR ] project. We are delighted to be 1 of 6 shortlist bidders who may bid for the license of electricity production at a CfD scheme. Let's continue with the onshore solar division. More than 20 projects with a commissioning date in '21 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 '21. The diversity of the project is obvious, a few large project in the U.S. in contrast to multiple smaller projects across Europe. And now moving on with an update on our hydrogen activities. Our engagement in hydrogen continues to take shape. We have a dedicated Board member in resources and RWE generation for H2, who are defining and implementing the hydrogen strategy for the RWE. It is clear. Carbon-free hydrogen is currently the only truly sustainable option to decarbonize energy-intensive industries, aviation and heavy-duty transportation. And it is also a potential climate-neutral fuel for gas plants. However, carbon-free hydrogen needs a government support framework to compete with plain hydrogen. Today, our focus is on 2 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 plant's 100-megawatt electrolyzer, which will be the biggest in Europe. The AquaVentus initiative in Heligoland will produce H2 directly at seas, 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 a large H2 consortium and are driving forward our Eemshydrogen project for a 50-megawatt electrolyzer to supply local industry with clean 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. So that's 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 '21. Our Offshore Wind division realized an adjusted EBITDA of almost EUR 1.1 billion, up 11% versus 2019. We closed 2020 clearly 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, of course, cash divestments primarily reflect the 49% Humber farm-down. For '21, we increased the outlook to EUR 1.05 billion to EUR 1.25 billion. We expect earnings from the commissioning phase will drive a lot of positive contributions from the full consolidation of Rampion, and we will have increased our stake to 50.1%; at the same time, return to normalized wind conditions and increased development expenses for the mid- to long-term growth to 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 megawatts year-on-year drove earnings up by 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. Beside 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 active temperatures in combination with up to 10 centimeters 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. So our hedge volumes for February were already lower than for other winter months. And for the same period of the year, we do not hedge at all -- for some periods of the year, we do not hedge at all if we see the risk of having to pay higher market prices during periods of low production. We then adjust our hedging volumes the closer we get to actual production. It became apparent that the icing of the Texas freeze will significantly lower our expected output, it was not possible to reduce our exposure due to the already high power prices and low market debt. But 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 USD 9,000 per megawatt hour and for such a long period of time. On average, we were short some 400 megawatts 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 '21. 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 of various legal proceedings. And therefore, the final result might change. Besides our regulatory and legal proceedings, our focus is now on the 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 in covering all aspects: hedging policies, asset management and investment decisions. Earnings guidance for '21 also reflects capacity additions, which will have a positive effect and the book gain for the farm-down of our 4 onshore wind farms in Texas, which will also be accounted for in '21. However, slightly increased development expenses for the further mid- to long-term growth in line with the progress of our development pipeline will impact '21 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 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 '20 figures accordingly. And from Q1 onwards, we'll report the restated figures. You will find a table with the 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 to EUR 250 million. Earnings at the Hydro/Biomass/Gas division amounted to EUR 621 million, with this division closed in the upper half of the guidance range. Very strong fourth quarter benefited from the earnings contribution of the day-to-day optimization of the power plant dispatch. Year-on-year, earnings are lower, mainly due to one-off payments in Q4 2019 from the resumption of the British capacity market. For '21, the outlook for the division is EUR 500 million to EUR 600 million. We expect a normalized level from the short-term optimization. Also, the half year earnings contribution from Georgia Biomass in '20 is missing as we have sold it. However, operations at the entire power plant are now back to normal. This is partly compensating for the shortfall. Moving on to Supply & Trading. The division contributed EUR 539 million in EBITDA, on the back of a very strong performance throughout the year. But in particular, the performance at the end of the year was significantly stronger than anticipated, which led to the division outperforming the outlook. For '21, we expect to return to a normalized earnings level, so the outlook is EUR 150 million to 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 hedged generation margin. Division has closed the year as expected. For full year '21, the division can once more increase earnings from 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 to 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 a stranded investment. After ruling from the Federal Constitutional Court in Germany in favor of, [ Westfalen ] 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 nonoperating result. The agreement between the German government and the operators need to pass the German Parliament and is subject to new disposals. 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. Adjusted financial result of minus EUR 315 million includes a negative one-off of approximately EUR 150 million from Q1 and the E.ON dividend received in Q2. 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 minus EUR 114 million. Originally, we had expected a positive contribution for the full year, especially due to the payment for the British capacity market from '18 and '19, which we received in Q1 '20. However, this was negatively overcompensated, mainly by higher year-end accruals in the Supply & Trading and the wind and solar business, which will revert for the most part in '21. For '21, 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 '20 compared to '19. Finally, moving to the outlook for '21. 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 in Supply & 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 minus EUR 150 million. Adjusted minorities will also increase and amount to approximately minus EUR 100 million, which goes hand in hand with the consolidation effect of Rampion as well as income from the commissioning phase. Adjusted net income is therefore expected to range between EUR 750 million and EUR 1.1 billion. For fiscal '21, the dividend target is EUR 0.90 per share. For the leverage factor, we expect it to be below 3x net debt to core adjusted EBITDA. A year ago, we gave an outlook for 2022 as well and some guidance on significant drivers beyond '22. Let me briefly revisit that. Today, we can fully confirm the outlook for '22. I can also confirm the outlook on a 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 U.S. dollar and additional development efforts for our long-term growth plans. We adjusted for the Rampion consolidation effects in the line item-adjusted minorities. The expected range for adjusted net income for '22 is confirmed, with a midpoint of EUR 1.1 billion. Furthermore, I want to remind you about a few relevant aspects for the period beyond '22. In Offshore Wind, the dropout from the high level of the EEG compression model will start at the offshore wind farm, Nordsee Ost, in '22 and Amrumbank in '23. In the year '23 to '25, this will result in a negative EBITDA impact of minus EUR 320 million in total. For Coal/Nuclear, I can confirm the guidance from the CMV. After '22, the division will have an EBITDA contribution in the range of EUR 0 to EUR 200 million per year. Including efficiency improvement, the lignite operations will, on average, be cash flow positive. Finally, as well on tax. Due to the announcement in the U.K., while increasing the corporate tax rate from 19% to 25% in '23, we will most likely need to adjust our general tax rate, which we apply to calculate adjusted net income. Ladies and gentlemen, before we move on to the Q&A session, allow me some personal remarks as this my last investor presentation as RWE's CFO and the last one with Rolf together. It has been quite a journey since 2016 when we both took office in our current roles. I mean just to name most relevant events from a capital market perspective of the last almost 5 years. We closed the nuclear chapter for RWE with the fund where we contributed EUR 7 billion, winning the core case on nuclear fuel tax, and the recent compensation agreement, which will finally close the file. And you will, as we do, all remember the day of the unexpected negative court ruling at Humber. We made a virtue of necessity, so sorting out our coal business with a clear path ahead and a very limited economic exposure going forward based on 2 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. And then, 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 transaction in our industry. And now we are setting our renewable growth plans, already including the Nordex acquisition and a 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 months are sometimes not easy to digest, but highly valuable. Please continue your good work. I'm looking forward to also interact 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. But now we need to go back to work and the Q&A session. Tommy?

Thank you, Markus, for all the kind words to all of us here in the room. Operator, please start the Q&A session. [Operator Instructions] Thank you. Molly, over to you.

[Operator Instructions] The first question today comes from the line of Alberto Gandolfi calling from Goldman Sachs.

And Rolf, thank you so much. I wish you all the best on your future endeavors. And thanks a lot for making this, yes, hard work, but very exciting in the past few years. And the best wishes to Markus and Michael. So okay, now to the questions, two. The first one is actually quite rare, but about power prices. We haven't talked about power prices in RWE for a while. And I guess my question is, can you maybe remind us what power prices have you been using in your 2022 guidance? I know you're hedging on the legacy. I wonder on some of the renewable assets as well that may no longer be on subsidies. And am I right in thinking that when you were guiding to the EUR 350 million, EUR 400 million negative impact beyond 2022 to 2024, '25, 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. So was 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 auction, seabed auction. Now 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 per kilowatt? What makes you comfortable that this is going to be a pass-through costs? What do you think is going to be the first capacity CfD auction you can be participating into? Is it 2025, later? And how are you thinking about the gain theory because now there's a negative incentive, right? So you keep paying that until FID. So 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 2 more years of a negative liability to pay for. So what do you think this is going to do to the returns? I know there's like 8 questions in 1. But perhaps if you can tell us how you're thinking about the seabeds, how you think about returns, why did you pay what you paid? Anything you can -- any color you can give us would be fantastic.

So Alberto, thank you very much. It was a very creative way to package. I don't know how many questions into 2. You have 2 themes in those 2 questions. The first one, on power prices. I mean it's not that we have set power prices at a certain level. So we continuously update the forecast of '22 and also beyond based on the open position and the current forward curves. So we can fully confirm '22 guidance. There are lots of moving effect. I mean the minor one, to be honest, is power prices. Actually, FX is for us, when you look at our U.S. dollar and British pound exposure, maybe even more relevant. And especially on the U.S. dollar part, we have seen a negative development by around 10% from when we have given guidance originally for '22 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 100 to 40 or 45, that doesn't actually make a huge difference. So 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's a very interesting topic overall. So we look at it from 2 angles. One is, of course, and that's 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 20s? And 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. So the question is, what is our -- well, it's a scenario analysis because you're absolutely right. When you take a linear view and say, develop as fast as possible, bid into the next CfD auction, that, of course, means that what you have paid until then is some costs. It's irrelevant for decision-making. But when you take a decision, how much you are willing to pay as a lease auction today, you need to factor it in. So the question is, how competitive are the markets? I think 2 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 5 years. So you are actually securing something which is very scarce. And the other thing is, how do you actually act relatively to your peers? And there, when you look at our auction results, I mean, first of all, the sites, the adjacent sites, feeling 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 -- and the expectation that you can earn excess returns significantly above your cost of capital 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.

The next question comes from the line of Lueder Schumacher calling from Societe Generale.

All the best for the future, Rolf. It certainly is an interesting time. First question is -- 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? And 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% also in Q4? And how much is due to operational improvements? And the second question is on your renewable growth capacity. You say on Slide 9 that just in onshore wind NPV, you expect growth of 2 gigawatts 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 have the capital increase. You had the Nordex pipeline. How much renewable capacity can you now put in the ground per annum on average?

Yes, 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 1 and 2 years, where we see then the lignite business profitability. I mean the significant part was, of course, the nuclear part is a big open position. Lignite was already given that we have to the CO2 hedges in place, a much smaller position. But in future, you have 2 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. So by just looking at the margin, you need a lot of information on the cost side as well to guide. And we will make it easy for you, so we will guide straight the net amount. And we said, we are comfortable with the guidance of EUR 0 to EUR 200 million EBITDA for the years to come from '23. So we definitely talk about more than 3 years into the future of the EUR 0 to EUR 200 million. And there is more information than you would actually get in guidance performance for that segment with more disclosure on the hedge prices for the next 2 to 3 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 them up with my successor. And because he needs to deliver on that for the years to come and not myself, so I shouldn't make any promises at this point in time. On the renewable growth, I'm 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 2020, a year ago, when we presented the first plan. But 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 delivering 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. But 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 competition is, of course, increasing. I think by steering gross additions, maybe that looks sexy on the surface. But I mean I don't want to put the teams under too much pressure to deliver every individual project from the pipeline. So 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. And 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. And 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. And I think that's the wrong steering. So 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 the icing of the cake. But I mean throwing out the gross figures is not the right thing to do in this environment.

Your next question comes from the line of Sam Arie calling from UBS.

And yes, let me add my congratulations, Mr. Schmitz. It's been a pleasure being part of the coverage during your tenure, and you've done a massive amount. And I think we've all enjoyed that -- 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 the total 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. And then also, 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. So it would be helpful if you could talk us through that in a bit more detail. And then, 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 has got their 3 big things they want to do and there are 3 big problems that they worry about. And I just would love to hear what's on your -- what are on your list of 3 right now.

So Sam, thanks for the question. I mean in the beginning, I have thought one question is for Rolf, one is for me. Since the accounting one is not for Rolf, I have to answer that one. So I have to delay the answer to the second question maybe to the Capital Markets Day. And 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. And what we realize is our tax income was slightly better than expected. And 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, a part of the tax advantage was in the tax line item. And then we looked into it, and we also looked into how our peers presented in their adjusted figures. And we found that it's 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 doesn't make a difference to adjusted net income, because you either take these advantages, directly strengthen the EBITDA line as we do it in the future, or you need to put them -- you need to reflect them in the calculated average tax rate. So 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 didn't know about the effect, but I think the right -- the guidance range is still EUR 200 million. So don't name me now whether we are more optimistic to be at the mid -- above the midpoint in '22. Now or not, as I said, FX is actually potentially the major driver for where we come out if everything operational runs as expected. And the other question, I'm happy to answer when I have the full reflection of the -- with my Board and the operating management teams at the CMD later this year.

The next question comes from the line of Peter Bisztyga calling from Bank of America.

Yes. It's Peter Bisztyga here. And I'd also like to wish Rolf for 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. So I was wondering if you could comment on that. And also, do you face any potential future claims or liabilities that could actually increase the EUR 400 million figure? So that's my first question. Then the second one is regarding your coal exit contracts with the government, which actually have clauses that stipulate that you could spin-off or transfer your coal business with the permission from either federal or regional government. So I was just wondering whether you've had any further thoughts about the prospects of an earlier exit from your lignite activities.

Yes, Peter, on Texas. There are a couple of things ongoing. I mean you already mentioned the political discussions to partly roll back the USD 9,000 per megawatt hour. And 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. But we think that effect on us will be very, very minor given the overall size of our business compared to the conventional colleagues and, of course, claims going in both direction. 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 proceeding but also mutualization, what I expect there is definitely smaller and maybe not relevant for our guided earnings here. But the potential rollback would be positive for us. But it's too -- I mean it's unprecedented. So we don't know how the proceedings will go on, who will take the decision now. And of course, if something will be changed, that's not to the benefit of everybody, they will claim again. So I think it's too early to tell, and I expect actually maybe a year-long proceeding on these issues. So 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 noncore business. There is nothing new to report. I mean our focus is now on the efficiency program on the -- to support the state aid approval, where the German government is in and also to implement the closures and the efficiency program.

The next question comes from the line of Ahmed Farman calling from Jefferies.

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. And I obviously see your sort of the leverage target, but there is quite a big gap between where FY '20 net debt was and what sort of probably the upper end of your sort of leverage target implies. So 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 be worse or there might be some further inflow. So that would be helpful. And my second question is actually on Slide 6 where you show a significant pipeline. And I appreciate sort of your point earlier that you may not want to sort of talk too much about at this stage about the specific growth targets. But maybe I mean I'm just trying to better understand what does that sort of gigawatt of pipeline tells us about the potential ability to sort of per annum -- drive per annum additions in gigawatt terms? And what are the parameters around that? So how has your thinking changed around probability of success on the pipeline and CapEx inflation since your Capital Market Day?

Yes, Ahmed. Thanks for the question. Let me start with the latter. So 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, but we can either build and sell, build and farm now, but we can also, of course, sell developed 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 gigawatt 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 gained significant depth. So we are actually very happy with the development here and success profitability has not changed, so the gross potential to deliver gross has significantly increased. But we are reluctant to give you gross build-out targets because we think it's not the right steering metrics. But let us give -- we need to take some more time to tell you how we think we're going to present the future long-term strategy of the business for the years to come, and we do that then later this year. But I mean, for me, it's clearly a very, very positive development. Of course, it comes at a bit more development expenditures. But of course, this pipeline is highly valued. And as I have said before, the higher competition has 2 effects. One is, at your existing business and your development pipeline gains in value. And that pipeline is now significantly broader and deeper. And the second one is, of course, in some central tenders and auctions, you see more competition than before. On the debt side, yes, I think net debt clearly developed positive. But given power price and CO2 price development also this year, we currently do not expect that it significantly reverse in the year '21. I mean you know our group EBITDA target. Operating cash flow will be around the same because we expect a negative -- a positive working capital effect, which will offset the utilization of provisions. But what we have is a significant investment program also on the gross side. I mean currently, we have the 2 big offshore wind farms under construction and we will start also significantly spending on Sofia, which we still have not farmed out. We keep 100%. So we expect a significant ramp-up in gross investments this year, significant more than in '20. And then we have, of course, still a positive effect, which is the compensation from the government on the nuclear exit. So even with the lower EBIT -- significant lower EBITDA from the taxes given we are very optimistic to stay below -- maybe significantly below the 3x net debt to EBITDA.

Does that answer your question, Ahmed?

Yes.

The next question comes from the line of Vincent Ayral calling from JPMorgan.

So a number of questions have been asked here. I will come back on the thematic looks in there since the beginning of the year. A number of client 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. So I would like to come back on this question and understanding exactly what was referred to by Alberto. As the game to a year ago, you put the finger. So how does that work? I'm not sure I really understood the answer on this specific point. And as we have a CMD talking about return on capital employed, it will become a metric and something on which we'll have a target and be able to monitor going forward. So that's on the, I would say, returns, the size of returns. And the second is on Texas. You've been talking about EUR 400 million. Yes, there is 400 megawatts which was exposed. Still this number since, I would say, fairly conservative. Could you confirm or give us a bit of color on how this is calculated? When I do the numbers, it would mean you have been short 400 megawatt hours -- per megawatt for quite a long time. The cold snap did not last that long. So that's where I'm not totally clear.

So I'm not sure whether I got the first question. Can you maybe specify the question on U.K. Round 4?

Yes, U.K. Round 4. Once you basically bid and you got your leasing. I think it's Alberto. We're not going talk about it. You said the games area had something similar. Once you spend this money, this can force you to be below acceptable returns. There is significant costs, which are taking by the year basically. So that's really an element which is not clear to us. So 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 area will indeed handle all these extra costs and you'll be basically getting your proper return on this reserve -- on this project?

I'm not sure whether this is question or just what we discussed before. I'll give it a try. I mean you need to have 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. But actually, what we are discussing here now, the concept of water under the bridge is, to a smaller extent, well, 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. Or if you do acquisitions and buy a pipeline, it's actually the moment you go into a CfD auction or into the 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. And 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. So maybe, as I said before, maybe there is now coming back more reasonable assumptions of what you can earn, but 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 target and reverting the energy transition and going back to gas and cheaper gas price. I mean lots of scenarios, and -- but this is exactly the uncertainty which you have and where you need to build your potential future outcome. And 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 5 days. And if you calculate a gap of 400-megawatt for 5 days, times $9,000, you were even above EUR 400 million.

Does it answer your question, Vincent?

Yes. On the point #1, yes, people -- some people paid more like BP, quite a high level. But it's difficult for me, I would say, here in front of a number of people in the market to really get the scenario clear in our head in order to get the return on that or share, there's always quite a leading name cannot find a scenario. And they told us they did not understand either. So here, I don't get it. And then so -- which helps me understand. I'm sorry about that. For the Texas, yes, I've done these numbers that our thought we may not have a 400 meg short every day for the 5 days. But that's fine. That's why I understood on the second one.

The next question comes from the line of Elchin Mammadov calling from Bloomberg Intelligence.

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 the seabed that you just won, can you build it and have it running as a merchant until the next day of the auction where you can bid them and secure the CfD payments? Or once the construction started building, you're not allowed to bid at the CfD auction? So this is a bit of a more clarification question. And the second one is on devex. I mean your presentation mentioned an increase in development expenses. Can you maybe talk a bit more about it, an increase compared to 2020? Or is it more a long-term increase in devex? So that will be useful.

Yes. Elchin, thanks for the question. I mean on the second one, devex, that is higher compared to '20, slightly higher than '20. We are talking about a low double-digit million amount for offshore and for onshore PV or both. And 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. And of course, we also need some more upfront development expenditures to go to a higher running level of renewal build-out. That was the second one. And the first one, on the CfD auction, I mean, the easy answer is, I mean it will depend on what is the CfD auction design in a couple of years' time when we bid. 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 projects into a CfD. You need -- can take -- of course, you can take a decision to go into a CfD auction. If you are not successful, you build merchant. But the moment you have building and are under construction, you cannot build it once more into the CfD. But it remains to be seen how things will change.

Your next question comes from the line of Rob Pulleyn calling from Morgan Stanley.

Let me join by saying thank you again to Rolf and congratulations. And of course, we wish you all the best for the future. And likewise, Markus, in his new role. And now to the questions. So firstly, just -- do you believe the shifting or potentially shifting political landscape in Germany could change the coal phaseout plan for the country? And what would this mean for RWE's position and the auction value you have around the coal exit law? And 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? And the second one, I hate to return to the U.K. seabed. There's many other things going on. But could I just ask specifically whether the IRR range you gave last year for mature offshore markets of 5.5% to 8.5% unlevered is still valid for the U.K. seabed project? And if I can stretch that to, you talked about the costs with Sofia. Would you be willing sort of directionally to give us an idea of how much cheaper this could come than Sofia?

Yes, Rob. I mean the easy one is yes, we can confirm the range of 5.5% to 8.5%. I mean to speculate now what our assumption is how cheap are we're going to build at the end of the '20 and first of year, 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 the bidding processes, of course, you have -- can have lots of assumptions. But the 3 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 costs, LCOE of the technology. So I mean I'm not willing to comment on all 3 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. And 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. And we all know that Germany struggles to build out renewables as planned. So 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 co closure dates. The relevant question is, how do we accelerate renewable build-out and then the coal phaseout, be it by market prices, by administration or by merit order, will be, I mean, a consequence of that. So it needs to be turned around. First, renewable build-out, then what happens on the coal side. And to be clear, I mean I'm not commenting on the individual business relationships. But what I don't accept is that some market participants just think 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 because that means you need to administer who is allowed to use how much power in Germany. And I mean that cannot be accepted, not by us as a company. But 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 for the Round 4 auction which we have that some of the Round 4 power bands, 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 and, therefore, there's not too much overcapacity in the market. And if you are not now coming into a capacity market with new government to build new capacity, gas-fired for example, into the market, that 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's coming up with the discussion. But what Markus said, I can only confirm the build-out of renewables. That's what is still the coal phaseout, nothing else.

The next question comes from the line of Deepa Venkateswaran calling from Bernstein.

So congratulation -- sorry, my best wishes to both of you for your new roles. So my two questions. So the first one is on the Onshore Wind outlook. I mean obviously, you've made this accounting change to realign with peers. But I suspect you have downgraded the '22 earnings to the lower end. So can you help us understand if there's anything else going on other than the U.S. dollar depreciation, which Markus, I think you highlighted have fallen 10%. I think that has around a EUR 50 million impact. So is it really just FX? Or is there anything else? I mean are you now targeting slightly lower additions or lower returns or anything? So that's my first question. And the second one, I apologize for this, sitting here in the U.K. and this being the #1 question from all clients, U.K. seabed. I suppose my hypothesis is that, obviously, these -- 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. So in the end, all of you are bound to include your seabed 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. So if there is a larger turbine, obviously, everyone will factor that in. So is that the kind of mean scenario that is embedding your auction building strategy?

Yes, Deepa, we still have years to go. So I mean, focus is currently on development, to speed up development and get the project ready. What is behind our different scenarios? And there, I can tell you, we have different scenarios for route to market time-wise, but also conceptually. But I mean I'm not going there because we still have years to go. And then, yes, let's see how it evolves. And I think we're going to see very interesting developments around U.K. offshore. And then I can also tell you that we are very confident that we have very little projects. But also, we never had expectations that we can sell projects with ongoing significant disposal gains for the years to come because that means, and I think the government has realized that they have given some very well project for very little money. 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 NPV, yes, you are right. It's FX. It's also slightly higher development expenditures. But please understand that, I mean when we gave the guidance for the 2 segments a year ago, I mean we had a rough understanding where we potentially farm-down and where we keep and -- 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 that we have anticipated years ago. But we also now have more offshore capacity with Rampion being available for us faster than expected. So I mean please read that. Also, that we fully confirm the renewables guidance. And the split in the business is now specification since we are now smarter since the year has passed, where we actually see the portfolio developing. And I would not read too much into that. So we are very happy with the development of both segments. And yes, we see an FX effect, but I'm 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, maybe and 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 might really be a clear opinion because they need more and more. And if you think about H2, then they need more and more and more green electricity. And therefore, in the moment to speak up to a 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 and targets which they have given themselves. It's more general. It's not so complete. It's not -- we cannot put in the numbers directly. But 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.

The next question comes from the line of Piotr Dzieciolowski calling from Citi.

Two questions from my side, please. So 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. And what's the process that is needed? And when do you expect to get the money on your account? And when the payment will come through? And second question, I'd like to ask on the renewable pipeline build-out. So you currently have a 34 gigawatt versus 22 last year. We can easily locate the Nordex pipeline plus the U.K. But what is the 6 gigawatt extra? Can you please tell us which assets you kind of added into the pipeline? And are they better or worse than the rest of the pipeline? Or you are the same positive about these prospects?

Yes. your first -- on the first question, the nuclear compensation. So it dates back years where when the government took the decision for the fast exit of nuclear and orders the operators to close or close some of the units immediately and also reduced the remaining production volumes. There was I mean legal proceeding is ongoing. And I think we finally, as an industry won the first court case, I think, in 2017. And based on that, the German government then came out with a compensation law, which then was disputed by Bundestag. And the constitutional court ruled that the compensation is not sufficient. So 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 Bundestag in Washington, because as a foreign investor, they could also claim under the foreign investment act. And this was simply then negotiation.

But the reason was, coming from 2001, there was consensus in nuclear, where you get the right to produce a special amount of electricity in your nuclear power plant. Then they gave more life to this in 2009 or '10, then they stopped it again in 2011 after Fukushima. And now it was not possible to produce all this electricity in the power plants which have the right to produce. And now they pay for these rights, which we have to produce electricity, and that's 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.

And the process is we are 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. And it needs EU approval, potentially not state approval, but generally EU approval, but it's 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, the pipeline is a living animal, so to say. I mean from the old pipeline of 22 gigawatts, we have taken 2 gigawatts of FID since then, so that brings it down to 20. And you have 3 gigawatt of the U.K. lease, around 4. You have the 3, 2.7 from Nordex. So there is a gap of 8, and that has been developed because, as you take FID, you constantly do development activity. And if you split that, that's around 2 in onshore, 3 in solar and 3 in storage.

Can you repeat the figures? 2 in onshore?

So it's 22. It's 2-gigawatt FID since early last year. Then we have the 3 gigawatt in U.K. Round 4. We have around 2.7 from Nordex from the pipeline. And then we have ongoing development activity, which added around 2 in onshore, 3 in solar and 3 in storage.

And you can -- 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, so they can also kind of do own calculations. But let us know if we can help you.

The next question comes from the line of Olly Jeffery calling from Deutsche .

Two questions from me, please. The first one is coming back to 2022 guidance. Can you confirm then if you are now above the midpoint of adjusted EBIT for 2022? Because if not, with the higher minority, that 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 wouldn't have been there when you came up with the guidance in CMD. That's the first question. And the second question is coming back to the U.K. seabed lease auctions. You mentioned the route to market. Could you please give a comment on the route to market in terms of where we have a preference between CfD, corporate PPA? And if on a worst-case scenario, would you be willing to run the product on a merchant basis?

Yes. Olly, I can confirm for '22, the midpoint of the adjusted net income, because that is, I mean, where everything is baked in: the consolidation effect of Rampion, the tax effects and also the minorities. So that is where we target on. And then plus/minus a bit. I mean it's not made it 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 earnings. So of course, either a government contract for the PPA. But not -- I mean the [indiscernible] project.

[Operator Instructions] The next question comes from the line of Tancrède Fulop calling from Morningstar.

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 IRR target to sort of watch plus spread return target. Will you maintain a firm IRR target for offshore? Or could you also shift to a watch spread-type of guidance? This is my first question. And my second question, coming to the end of the first quarter. Could you tell us about the Offshore Wind conditions year-to-date? So last year was very favorable for Offshore Wind in Q1. Year-to-date, is it below normalized conditions or normalized conditions?

Yes. So 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. But now speculating whether we can also consider changing it or not, I think that's leading nowhere. So if we decide to steer and guide it differently, we will let you know. And for the first quarter, wind conditions in January were slightly below average. January was on expectation and March so far also on expectation.

The final question comes from the line of Ahmed Farman calling from Jefferies.

Yes. Just on your solar and Onshore Wind business. When you, I guess, think about sort of, I guess, the sort of 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 a missing from the portfolio or where you can benefit from building some further scales? Just interested in some thoughts on that.

So 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 the team. So currently, I think in the core markets where we are active, we don't lack any relevant coverage. And the detailed tiering, which markets we see more promising than others can be done within the resources we currently have.

We have no further questions in the queue. So I'd like to hand the call back over to Thomas Denny.

Thank you, Molly. Thank you, Markus. Thank you, Rolf. Thank you, Michael. And thank you all for dialing in today. All stay safe and healthy. And talk to you again latest at Q1. Thank you. Bye-bye.

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