Welcome to the RWE conference call. Markus Krebber, CEO of RWE AG, and Michael Müller, CFO of RWE AG, will inform you about the developments in fiscal year 2022. I will now hand over to Thomas Denny.
Thank you, Laura. Good afternoon, ladies and gentlemen. Thank you for joining us for RWE's conference call on fiscal year 2022 and, of course, the outlook for 2023. Our CEO, Markus Krebber, and our CFO, Michael Müller, will guide you through our presentations before we start the Q&A sessions later. With this, I'll hand over to Markus.
Yeah. Thank you, Thomas, a warm welcome to everyone. 2022 was a dramatic year. A horrible Russian war in Europe with far-reaching consequences for the global energy markets. It has been a very demanding year for a European energy company. We are very proud that team RWE weathered the energy crisis that well. While being busy with crisis management, we delivered on our Growing Green strategy, we delivered an exceptional operating performance, and we accelerated the transformation of the company by agreeing to coal exit 2030, and by building a leading position in the U.S. renewable markets through M&A. Let's now move on to the presentation and page 4 of the slide deck. In all these respects, 2022 was a very successful year for RWE. We have substantially exceeded our financial targets.
We commissioned 2.4 GW of green capacity. We currently have another 6 GW under construction. With our success in the offshore auctions in the US and the Netherlands, we managed to further extend our substantial offshore pipeline. On top of that, we have broadened our strategic footprint and balanced our portfolio through attractive acquisitions, which add another 4.5 GW of operating assets and more than 16 GW of green generation pipeline. At the same time, we have accelerated the coal phase out by eight years and, hence, taken an important step towards compliance with the 1.5 degree CO2 reduction pathway. Our strong strategic and operational performance drives our share price. We have continuously outperformed the European Utilities Benchmark in the last years. Our ambition is clear. We will continue to deliver on our promises and create further shareholder value.
Last year, we delivered strong earnings across our entire core business. Earnings in renewables were driven by capacity additions, better wind conditions, as well as favorable market prices. Our flexible generation portfolio delivered an exceptional result, with higher earnings from the short-term power plant deployment and higher generation margins. Q4, in particular, showed how well our flexible generation assets complement the wind and solar portfolio. Our trading business has recorded an outstanding result on the back of dynamic market conditions. Attractive investment opportunities are key for our growth program. We have delivered EUR 4.4 billion net investment in 2022, and we are keeping up the pace to ensure profitable future growth as well. In 2022 alone, we successfully completed more than 30 projects in 11 countries and commissioned 2.4 GW of operating capacity. A further 6 GW of capacity is currently under construction.
Our own development activities have been complemented with strategic acquisitions. Certainly, the acquisition of Con Edison Clean Energy Businesses is a significant boost for our U.S. renewables business. We have added more than 3 GW of operating solar capacity and have almost doubled our portfolio in the U.S. to more than 8 GW of assets in operations. With CEB, some 500 experts with an impressive track record in development and operations have joined the RWE team and will contribute to future growth and investments. We expect the business to increase our EBITDA by around $600 million on a full year basis. Required pipeline of more than 7 GW will deliver 500 MW growth per annum on top of our existing build-out plans.
Through this unique combination of complementary portfolios in onshore wind, solar, and batteries, RWE has achieved a leading position in the U.S. renewables market. We have also strengthened our future growth pipeline in other regions. In 22, we were successful in offshore auctions in the U.S. and in the Netherlands. By winning the New York Bight auction, RWE made a significant move in entering the U.S. offshore market and took an important step in our offshore growth ambitions. The California lease auction is our first commercial scale floating offshore wind project. The successful auctions in 2022, RWE's offshore development portfolio now totals 3.9 GW. In Europe, the acquisition of the East Celtic Offshore Project in Ireland will enhance our development portfolio. We also focus on our solar and battery platform in Europe.
We have always said that the acquisition of solar development pipelines in attractive markets where we are not adequately represented is our M&A priority. We have delivered on this and acquired two attractive project pipelines in Poland and the U.K., totaling around 9 GW. RWE is delivering on its green growth strategy and complements a successful development. Following the CEB acquisition, we cover leading positions in all of our core regions, the European Union, the U.K., and the U.S. In 2022, our flexible generation portfolio delivered an exceptional result. With an EBITDA of around EUR 2.4 billion and a strong outlook for year 2023, our dispatchable hydro, biomass, and gas assets are perfectly complementing our wind and solar business.
Our flexible low CO₂ generation fleet can balance out the intermittency of power generated from renewables, both from a volume perspective as well as from an earnings perspective, as shown with the strong Q4 results. We are also growing our flexible generation business. With the successful acquisition of the Magnum Gas Power Station in the Netherlands, one of the most modern power plants of its kind, we are adding 1.4 GW of installed capacity. Through the commissioning of the Biblis Gas Power Plant and Grid Stabilization Unit, RWE is adding another 300 MW capacity to its portfolio. Today, we are not only growing low carbon generation capacity, we are also decarbonizing our existing portfolio. One example is the Amer Power Plant in the Netherlands, which we are converting to 100% biomass. We are expected to complete this by the end of next year.
In Germany, we plan to build H2-ready gas-fired power station with a capacity of up to 3 GW to replace coal units. We expect that the German government will create an attractive and reliable incentive scheme to make these investments happen. In our hydrogen business, we recently ordered two 100 MW electrolyzers for the GET H2 Initiative, which is one of the most advanced hydrogen projects in Germany. We plan to commission the first of the two plants in 2024 on the site of the gas-fired power station in Lingen. The second plant is scheduled to start operating one year later. All our renewables and our system integration capabilities came together when we were awarded the Hollandse Kust West project in the Netherlands. With this, we will enter the Dutch offshore market and plan to unlock full system integration.
We will combine offshore wind with electrolyzer capacity for green hydrogen production and other flexible demand solutions like e-boilers and battery storage. Our goal is to perfectly match the demand for energy to the production profile of offshore wind farms and to contribute to the grid stability. We are not only massively investing in the energy transition, we are also accelerating our decarbonization path at the same time. Through reaching an agreement with the German government, the state of North Rhine-Westphalia, we have brought forward our coal exit by eight years and underpin our strong ambitions to transform as quickly as possible. Our responsibility to the people in the Rhine coal region does not end at the factory gates.
We want to play our part in ensuring that the region remains structurally resilient and integrated with the energy sector by building new gas plants on the sides of existing coal plants, or through the expansion of renewable energy in that area. RWE's significant speed in the transformation to a full green energy producer is also strongly reflected in the relative share of coal in our EBITDA. RWE's 2016 earnings were still strongly dominated by the coal and nuclear business, we have taken massive steps on our path to Growing Green. In 2030, our EBITDA will be 100% from our green core business. With the accelerated coal exit, we have taken an important step to achieving compliance with the 1.5 degrees CO₂ reduction pathway. Coming to page 10 and our outlook for 2023.
We expect the capacity of our core business to reach 35 GW by the end of this year. In terms of EBITDA, we expect to continue our strong performance this year with a range of EUR 5.8 billion-EUR 6.4 billion. Based on the strong earnings and our positive outlook, we propose to increase the dividend for fiscal year 2023 to EUR 1. We plan to provide a full strategic and financial update and long-term outlook in a capital market day in Q4 this year. With this, let me hand over to Mikey, who will now walk you through the financials in detail.
Yes. Thanks, Markus, good afternoon also from my side. 2022 has been a challenging year for the European energy companies, RWE has managed the energy crisis very successfully. The business has performed extremely well. Since the capital market day in 2021, we have upgraded our guidance for 2022 twice and even exceeded our outlook on the back of a very strong Q4. Adjusted EBITDA of the group reached EUR 6.3 billion and adjusted net income, EUR 3.2 billion. In 2022, we invested EUR 4.4 billion net in our green growth, 50% more than in previous year.
This includes investments in our German offshore wind farm Kaskasi, our UK offshore wind farm, Sofia, that is due to be commissioned in 2026, and in the 3 GW seabed lease we have been awarded in the New York Bight. In addition, RWE invested in more than 30 new onshore solar and storage projects, and more than 80% of our CapEx has been taxonomy-aligned. In 2023, we will continue our green growth program and will invest even more. When investing, we apply strict investment discipline and continue to achieve 100-300 basis points returns above WACC. Given the high inflation environment and raising interest rates, it is important to lock in project spreads. In our offshore wind project, Sofia, we have been awarded an inflation-linked CFD, and we have secured all supply contracts.
In the current favorable price environment, we are signing long-term PPAs to lock in attractive margins for our projects. A good example are the long-term PPAs we announced for our German offshore fleet at the beginning of the year. We are also actively managing the supply chain. We are entering into long-term framework agreement with suppliers where we see scarcity in the future, such as operations and maintenance, as well as installation vessels. We sign supply contracts for upcoming projects. Examples are turbine contracts for our offshore wind farm Thor in Denmark and the German offshore cluster. We have secured long-term financing to hedge our interest rate exposure. In 2022, we issued EUR 2 billion long-term green bonds to finance our green growth, and a EUR 2.4 billion mandatory convertible to finance our acquisition of CEB.
The mandatory convertible bond was converted into new ordinary shares this month. RWE has managed the energy crisis very well. As I've reported in earlier calls, we took immediate actions to mitigate all risks from exposures to Russian counterparties. To cope with the high short-term liquidity requirements, we issued a EUR 1.25 billion short-term bond, extended existing credit lines, agreed on new ones. We have continued to focus on strict risk management and have adapted our hedging accordingly. Overall, RWE has a solid financing and a strong balance sheet. We are well-positioned to fund our future green growth. Let's now move on to the details of our strong financial performance. In 2022, adjusted EBITDA for our core business reached EUR 5.6 billion and EUR 6.3 billion for the group.
In offshore wind, adjusted EBITDA increased to EUR 1.4 billion on the back of new capacity additions, namely our wind farms, Triton Knoll in UK and Kaskasi in Germany, and the full consolidation of Rampion for the full period. Wind conditions were better than last year, even though they were below the normal average. For the onshore wind and solar division, adjusted EBITDA was EUR 827 million. This is significantly higher than last year, mainly due to the absence of the negative one-off effect from the Texas cold snap. Higher power prices and new capacity additions and better wind conditions compared to previous year also increased earnings. Adjusted EBITDA of the Hydro Biomass Gas division reached EUR 2.4 billion for the full year. The flexible generation business was significantly up year-over-year due to higher margins and exceptional short-term asset optimization.
Performance was particularly strong into Q4. An outage at the Dutch gas plant Claus at the beginning of the year partially offset the increase. Adjusted EBITDA of the supply and trading segment increased to EUR 1.2 billion on the back of an outstanding performance across all commodities and regions in volatile markets. The strong performance was partially offset by the write-off of Russian coal delivery contracts. This charge of EUR 750 million was previously booked in non-operating result. We have now reclassified the charge so that all charges related to Russian counterparties are booked in adjusted EBITDA. The German coal nuclear operation showed lower earnings year-on-year as a result of capacity closures, partially compensated by relative related cost savings, high utilization of plants, and higher earnings from short-term asset optimization.
Adjusted EBITDA from coal nuclear was EUR 751 million. On the back of the strong operational performance, adjusted net income amounted to EUR 3.2 billion. Depreciation increased in line with our Growing Green investment and write-backs for our conventional assets on the back of improved market conditions. The year-on-year adjusted financial result is lower due to higher interest environment and liquidity requirements in volatile commodity markets. For adjusted tax, we applied a general tax rate of 15% for the RWE Group. Adjusted minority interest increased in line with higher earnings in the wind business and new capacity additions with minority partners. The adjusted operating cash flow was EUR 2.4 billion at the end of the year and reflects the impact from operating activities on net debt. The adjusted operating cash flow echoes the higher level of earnings.
It was marked by a higher operating working capital, driven by higher volumes and prices for gas and storage at the year-end. Net debt was negative at EUR 1.6 billion at the end of the year. In 2022, we invested EUR 4.4 billion net in our Growing Green program. Other charges and net financial debt reduced by EUR 2.7 billion. This includes the inflow from the mandatory convertible bond that was booked in equity to the largest extent. It also includes timing effects such as variation margins from hedging and trading activities. Our net position for variation margins for power generation hedging stood at EUR 3.4 billion. This includes net variation margins from the sale of electricity, as well as the purchase of the respective fuels and CO2.
In the context of higher discount rates, pension provisions have decreased, partially offset by a negative performance of plan assets. Coming to page 17 and our outlook for 2023. In 2022, RWE delivered a strong financial performance. In 2023, we will deliver a strong performance too. Let's start with the divisional outlook for 2023. In offshore wind, we will benefit from the full-year contribution of Kaskasi and Triton Knoll. We expect normalized conditions. Higher hedge prices will partially be offset by European and UK price caps and higher development expenses for mid and long-term growth. Onshore solar business will increase substantially year on year, driven by the earnings contribution for our enlarged US portfolio after the closing of the CEB acquisition on March 1st.
We also assume normalized wind condition and higher hedge prices, partially offset by revenue caps and additional development expenses for mid and long-term growth. hydro, biomass, gas is expected to continue with a strong performance in 2023. Earnings will be lower than 2022 due to lower realized power prices and normalized contributions from short-term asset optimization. The segment will benefit from our investments in green growth as our acquired Magnum plant in the Netherlands and the new build grid stabilization plant in Biblis will contribute to 2023 earnings. For supply and trading, we assume normalized earnings. On the back of the continued high volatility in commodity markets, we have increased our normalized earnings expectations for this year.
The earnings of the coal and nuclear segment will increase year-on-year on the back of higher hedged margins, despite the closure of our last nuclear plant in April 2023. Adjusted EBITDA for the RWE Group is expected to be between EUR 5.8 billion and EUR 6.4 billion. Depreciation and amortization will increase year-on-year. This is driven by investments into our green growth, including the acquisition of CEB. We also plan higher D&A in our conventional generation business due to the write back in 2022. Adjusted EBIT is assumed to be between EUR 3.6 billion and EUR 4.2 billion in 2023. Adjusted net income is forecasted to range between EUR 2.2 billion and EUR 2.7 billion.
As Markus has pointed out, we propose to increase the dividend based on the strong earnings and our positive outlook. We are targeting to pay EUR 1 per share for fiscal year 2023. We deem this as the new floor for the coming years. With that, let me hand back to Tom.
Thank you, Michael. Thank you, Markus. We now start the Q&A session. Operator, please kick it off.
Thank you. As a reminder, if you would like to ask a question, please press star one on your telephone keypad. Thank you. We'll now take our first question from Alberto Gandolfi at Goldman Sachs. Your line is open. Please go ahead.
Thank you, operator. Afternoon. Thanks for taking my questions. Obviously stick to the rule of 2. The first one, please, is on renewables permitting. I mean, your execution has been great in 22 despite of the supply chain issues. You have 6 GW under construction. I wanted to ask you a bit of a broad question. When do you believe we might start to see some benefits from the U.S. IRA? Do you think we are going to see just better visibility or potentially an acceleration in GW? Are we going to expect some tailwind from Germany as well? We had an Easter Package last week. Could we see another package that apparently the government is working on? There's quite a lot of ferment on faster permitting in Germany at the European Commission level. We saw legislation.
Can you tell us what should we think in terms of speed and rapidity of renewable development in your geographies in the next 12, 24, 36 months, please? The second question is a little bit more left field, but, you know, there is one aspect, I think, of your investment case where you might be a little bit victim of your own success. You know, you've been delivering outstanding earnings compared to, you know, the original guidance, and you have been beating and beating and beating. The problem is that some of these profits, you know, are function of volatility in trading, are function of maybe high power prices that sooner or later normalize.
I was wondering, to provide better visibility to the high multiple portion of your business, renewables, is there a case down the line for running two RWEs? Essentially renewables on one side and everything else on the other. Could be interesting source of funding, could be potentially interesting because the renewable business are actually growing, so there will be no doubt about the true value of these assets. Any thoughts you may have on that? I know it's early days, and I know you just completed a large acquisition, but any observation would be very helpful. Thank you so much.
Yeah, thank you, Alberto. It's Markus. Let me start with your first question on permitting, and tailwinds from the IRA, and when we might see a pickup in COD, so in delivered capacity.
First of all, let's start with the European Union and specifically Germany, but actually more or less every country from Poland, UK, France is accelerating permitting and planning. It's too early to tell whether these measures are sufficient to bring us on the target build-out pathway. I think they are all hinting in the right direction. The politicians are implementing the right measures. I think it will take 12 months, maybe 18, to see how much acceleration we're gonna see. When we see the first cause ruling in favor of wind farms, when you have appealed, so that the likelihood goes up, when you see that environmental studies pass the bureaucracy faster.
I think it's too early to tell, but I have no doubt that if the feedback of the industry to the politicians will be, "We are not yet there," that they will implement more measures because I wouldn't call it panic, but it's urgently needed. Everybody knows we need to invest significantly, otherwise, we have a sheer volume problem in terms of energy supply and also a decarbonization problem. In terms of build-out, of course, you need to add another 2 years. For us, I would say, if everything goes very well, you're gonna see the pickup for our core European markets where we do origination activity ourselves, especially Germany from, let's say, 25 onwards.
Of course, we have now bought some pipelines with also very mature projects, so there you can expect some additions already next year on top of the old plans. The IRA, of course, with the 24 gigawatt combined pipeline, we have a lot now which we can do. I would currently say under the IRA, the bottleneck is currently not the profitability of the project. They are excellent. The problem is more on the supply chain, especially on solar, how many solar panels do you actually get? We are now working with our relevant suppliers also, to build local manufacturing capacity and get our hands around or hold of supply. So here also maybe 2 years.
That is exactly why we said it's definitely time at the end of the year to give you a full update, and we have a bit more visibility, what the build-out plan, the new one, which will definitely be above the old one, how that will look like. The other question is one on the company structure, where I think we currently don't see that that would make sense. I give you the reasons. First of all, strategy of RWE, and we see the benefits of that, especially in the last year, is not that we're gonna be in, let's say, IPP wind and solar producer, where you actually are an asset owner and not running a business model.
We want to be a fully integrated energy supplier, which can also supply industries and consumers of load profiles which differ from the production from wind and sun. We see huge value. If you ask me, an outlook for the next, let's say, 10, 15 years, I think wind and solar will become pure commodities. Probably the value, the real value is in decarbonized flexible generation capacity. I think we should make the case that we even accelerate the decarbonization of our flexible assets that you also call them green. I mean, that's our core of our business.
When you see, especially in Europe, with higher penetration rates of renewables, the relevance of these flexible assets, storage capabilities, system knowledge, and so on, which all came together with the system integration offshore auction in the Netherlands, will be where the fun is and not running individual projects. I would turn the question around. If we see the significant growth, it's probably more the case to take on board partners for this huge EUR billions of wind and solar commodity investments. The system integration part you wanna keep under control. I don't see the case of splitting the company along the lines you outlined.
Fascinating. Thank you.
Thank you, Alberto. Next question, please.
Thank you. We'll now take our next question from Peter Bisztyga at Bank of America. Your line is open. Please go ahead.
Hi. Good afternoon, and thanks for the presentation today. One question first for Markus, which is, I was wondering if you could maybe use, for example, your GET H2 project as a bit of a case study to show us whether there is anything that's happened on the policy front, whether it's the Net-Zero Industry Act, whether it's on German policy, whether it's any other EU policies that are actually practically helping that project to move forward more rapidly today. If there's a different example, then that would be interesting as well. Really, you know, what practical changes are we seeing today that from a policy perspective?
The second question, for Michael, can you provide us an update with your current hedging levels actually are across your generation activities? What sort of assumptions about, you know, the commodity price environment or underpin your guidance range for 2023? Maybe ultimately what I'm getting at is, you know, how much risk is there to your guidance range if gas and power prices continue to fall? Thank you.
Yeah. Thank you, Peter. Maybe the disappointing answer to your question is that actually what we have seen on European level as recent legislation does not have anything on GET H2. We are now moving forward. It's a fascinating site. We not only run our last nuclear unit, which will be decommissioned or shut down in 4 weeks. We run one of the most modern gas plants in Lingen. We have already one of the largest batteries, and then we are now entering hydrogen with not only electrolyzers but also the connected project of storage and testing existing pipelines for conversions. We have now said, I mean, let's move forward. We are still waiting for the IPCEI approval in Brussels to get the funds.
We said we're not gonna wait any longer. We move forward. What that has caused is frustration also with our federal government here. They don't understand why it all takes so long in Brussels. That is, of course, helpful because in the end, what is driving it is are the national governments. I mean, the European frame is nice, I would more turn it around. We need to get the federal government in the different countries to implement the right measures, and then we hope that European policies, regulations, state aid approvals do not prevent them to introduce it. I would not overestimate the impact from European policies. National level is still in European energy policies, the most relevant part.
Yeah. Peter, coming to your question on, I guess, it's more around the confidence of our of the guidance we have now put forward. I mean, talking about hedge levels, clearly, we have stated that the hedge levels are somehow lower than we had them in previous years. First of all, from a risk management perspective, we deliberately have reduced them, and we also see less liquidity in some of the markets, the forward markets, for example, in the Netherlands or in the UK, so the hedging is more difficult. Yes, I mean, we already have incorporated the recent development of commodity prices in our forecast that, as you know, have come significantly down since December. That's incorporated. Overall, we are very confident with the numbers we presented.
I mean, finally, also please bear in mind, especially if you talk about the flexible generation fleet, this fleet not only benefits from spreads, but there are also additional incomes from ancillary services, from short-term asset optimization, and the capacity market, and especially the ancillary service and the short-term optimization benefit from the current environment of scarcity, where our flexible generation can jump in.
Great. Thanks very much.
Thank you, Peter. Next question, please.
Thank you. We'll take our next question from Vincent Ayral at JPMorgan. Your line is open. Please go ahead.
Yes, thank you for taking my question. Good afternoon, everyone. Doing a bit of a follow-up on the question regarding commodities, drilling down a bit on that. Basically, before your guidance would become at risk, what would you need to see on the power price movement? There's the team worker, a minus 20, 30, a minus 10. Something like that would be of interest, I'm sure for all of us. Knowing that, you have stopped reporting and you're hedging, now a few years ago. It's lower, yes, but we have to do a lot of guesswork here on our side in order to forecast your profitability. Still, sticking to the assumptions behind the guidance, what is the assumption on the infra-marginal caps?
Basically, how long do you assume them to last? Do you have like an assumption until mid-year? Are you going further out? That would be very interesting for us. The last question is going back to a comment you said. You said that the profitability excellent in the U.S., yeah, maybe on solar. We've seen a number of examples where there are big questions being asked on the U.S. offshore. Could you give us enough color on what you see? What is the state of your project there, and basically the key challenges and the type of return you get there? That would be very interesting.
Okay. Thank you. Let me start with your question on the commodity prices and the infra-marginal cap, and then Markus can pick up on the offshore business. I mean, I wouldn't now come up with a number on commodity prices that would put our guidance at risk. I mean, looking at commodity markets, what we have seen is that gas prices have come down, but they are now on the level of LNG prices, and that's what we always said. In the current environment, Europe is relying on LNG. Therefore, LNG prices are providing a floor to gas prices.
I think in the global markets, LNG prices are rather now at the lower end, given that the Asian demand is substantially less than it was previously. Therefore, there is something like a protection against power prices falling further. The same is actually true with the infra-marginal cap, because what you currently see is that power prices have come down so that the infra-marginal cost cap, at least for some technologies, doesn't have a big impact anymore. Therefore, also irrespective of what assumption we have included, that doesn't have a big impact. Yeah. What I'm saying is kind of, We feel comfortable with the numbers we are seeing.
As I said, especially in the gas business, the Hydro/Biomass/Gas business , where there are potentially some more position not yet hedged. It's not a pure spread play. It also includes other income streams that are actually potentially strong in the years to come, given the scarcity we see in the market.
Yeah. Let me continue on the offshore question. It's not only relevant for the US market. I think you have also now the first projects in the UK where there is a discussion in the market that when you have locked in CFDs, even when they are CPI inflated, you run into problems with your economics if you have not procured your turbines, cables, substations, and so on, because CapEx inflation is much higher than CPI. Fortunately, we have none of these projects. I mean, Michael has outlined in his speech very clearly that with all projects we have under construction and in the pipeline, we have for Sofia, everything, more or less everything has been procured some time ago, fixed prices.
Also with Thor, we have now more or less everything, the Danish project procured. Where we have now that's maybe the new normal, where you have commodity price indices in your big-ticket items like steel and others, we have the capabilities through our trading division to hedge these. For us, they become also risk-free the moment we sign the contract. Coming to the U.S., we have the New York Bight project. It's now, we have made that public that we participated in the offtake auction in New York. Results to be expected in the coming weeks and months. Of course, that was already known under the new supply constraints. We have factored that into our bid that we ensure if we build, we can build successfully.
I can also put it differently. I mean, when we put together the companies now going back a couple of years, we were a bit disappointed that we did not have a huge pipeline, especially in the years to come. Now you can say, okay, it was a sometimes you have to be lucky. Now we have the learnings and we don't suffer. Whenever we place a bid or we take an investment decision, the most relevant discussion we're gonna have around the economics is what kind of open positions do we have? Because what we now experience in the offshore industry is actually the developers who committed to offtake for fixed price CFDs but did not procure.
It's structurally the same problem than with the OEMs, selling us turbines at fixed prices, but not buying the stuff they need to produce it. I mean, that is probably the topic also for future auctions designs, because we need to decide together with our suppliers and regulators who is placed best to take which risks, because otherwise, if you allocate the risk at the wrong party, you end up with even higher costs and prices for the consumers.
Thank you, Michael. Thank you, Vincent Ayral.
Thank you.
Next question, please.
Thank you. We'll take our next question from Ahmed Farman at Jefferies. Your line is open. Please go ahead.
Yes, thank you for taking my question. I actually just have a follow-up again on the offshore wind market, particularly in the US East Coast. Markus, taking your points about sort of the challenges and the CapEx inflation, does the economics of sort of the projects require that we see meaningfully higher tariffs in the New York round three versus previous rounds? That's my first question. My second question is, can we quickly have an update from you on the state aid process around the German coal phase out and anything you can share on the current state of debate around the coal lignite foundation in Germany? Thank you.
Yeah, Ahmed, thanks for the question. I mean, please understand that I cannot, or I'm not willing to reveal internal calculation. What I can tell you is, and we see that across more or less almost all regions and technologies, that for the first time in the renewables industry, LCOE, so cost-based, the cost of electricity, they go up. I'm not talking nominal terms. Even without correcting for inflation, we see that LCOE go up in real terms. The reason is very simple, because the supply chain has to pick up. We have simply scarcity in the market, and build-out needs to increase significantly and supply chain build-up is a bit delayed. That is why some of the projects are now also in very difficult territory.
State aid. And that of course means to make these projects profitable, we need to see higher tariffs. That is clear, yes. Even in real terms. State aid, yeah, it's a very painful long process, but the assessment has not changed. I think the recent announcement from the European Commission reopening it or readjusting it after the new agreement with the government were very constructive and positive, where they clearly said that the calculation put forward by the German government to justify the payment to RWE looks now much more conservative. We take it as a very positive signal, so we expect the clearance at the full amount of EUR 2.6 billion in summer this year. Whether we get it before the summer break or later, that doesn't matter.
I think if we need for Q3 results, It should be banged in. On the, on the foundation, you know, what is in the contract and the law and the agreement with the German government that we committed to look Or they committed with us together to look into it, the moment we have capacity. Please understand that I'm not willing to give you an update there every here and there. If there is news, we're gonna update you, but all other discussions are confidential.
Thank you, Markus. Next question, please.
Thank you. We'll take our next question from Sam Arie at UBS. Please go ahead.
Thank you very much. Hi, everybody. Thanks for, you know, great presentation and great set of results. Forgive me, I want to ask another question on this topic that we've already touched on a little bit about kinda returns profitability in the renewable industry and in particular in offshore. I suppose what we're wrestling with a bit on our side is, you know, on the one hand, hearing many projects in the industry are delayed and over budget, that supply chain bottlenecks and so on are still not fixed. You hinted at this a bit when you spoke about the long-term supply chain partnerships that you were looking at in areas of scarcity and so on.
On the other hand, PPAs are going up, government support is going up, oil majors may be backing off a bit if we listen to what they say. It feels like nobody is gonna start building a new offshore project for a lower return on equity than you get these days on, you know, regulated onshore projects. I suppose that seems to say people probably gonna end up looking for 15%, 20% equity returns rather than whatever 8%, 10%, 12% that we were hearing from different industry players a few years ago. I'm just trying to weigh up these kind of two arguments, the problems in the industry versus the sorta higher outlook on returns.
Just as always, would really appreciate any commentary from you, how you think we should think about this and, you know, should we be worried or should we be optimistic looking forward?
Good, Sam. Thank you for the question. I hope all is going well with the Swiss banks. Yeah, interesting developments also in your industry. Now coming to your question. I would like to differentiate it. I think we have to differentiate projects where you have, now, let's say, challenges with your risk management or your open positions where you have committed to the revenues or the supply, but not procured everything. Of course, that is not a nice situation you are in. Looking forward, I think nobody will develop and build an offshore project without decent returns.
Our current expectation, we also see that with our latest projects commissioned, but also under construction, that the margin you expect to earn on offshore, I mean, we always said renewables needs around 100 to 300 basis points on top of WACC, is more or less stable. Of course, in this environment, when you do your calculations, you probably have higher contingencies for CapEx overruns and so on. Then, of course, if everything goes well, means that margins are higher. On the other hand, the risk that something goes wrong is also higher. That's why it's probably needed.
I think we also discussed in one of the other calls. I said, on average, it should be the same or fine, but it's much more challenging to get the project de-risked. The moment you have de-risked them, the returns should be fine. I mean, the numbers you have put out with 15%, that seems, I think, very optimistic. Of course, this is an absolute number. What we are looking at is what is the margin, because the moment we take an FID, we not only want to have procured the CapEx, we also lock in our financing costs, in absolute returns and know what the value contribution of the project will be. Overall, maybe allow me that final comment.
The relative attractiveness of offshore wind, with its very stable production profile to other renewables, like onshore wind and solar in the core markets we are in, has not changed. In the end, the entire game is the demand supply, and then on the supply side, relative attractiveness of the different technologies that in our view has not changed. Thank you.
Okay. Thank you.
Thank you. If you find that your question has been answered, you may remove yourself from the queue by pressing star two. We'll now take our next question from Wanda at Credit Suisse. Your line is open. Please go ahead.
Hi, Wanda Serwinowska, Credit Suisse. Just one question from my side. Markus, I would appreciate any comment from you on the new power market design that was basically proposed by the EC and the Europe's response to IRA. What do you think about it? Is there anything that is missing in both proposals? Thank you.
Yeah. Thank you, Wanda. What a nice sequence, the two Swiss banks, in a row. Also all the best for you.
Thanks.
On the European market design question. I mean, first of all, we at RWE, we appreciate that the European Union took a very, let's say, evolutionary approach and not a revolution and drawing the wrong consequences or conclusions from the crisis we have been in last year. Overall the market is still functioning very well and has actually also delivered via very good price signals. I think, the overall theme when it comes to the generation part, I now leave out, the retail regulation they want to impose on the suppliers.
On the generation side, the overall theme seems to be, let's incentivize more longer-term offtake agreements, be it state organized like CFDs or be it PPAs in the private market is exactly right, because that would, of course, immunize off-takers against short-term price spikes, but also it will help developers to get bankable projects by long-term visibility of returns or of offtake. Of course, the devil is in the detail.
We are strongly advocating, especially on the CFD side, which is important for offshore wind, that you need proper inflation adjustment and you better go for two different kinds of inflation adjustment, more CapEx based, until FID, so auction till FID and a more CPI, so operating cost related one when it comes to the operating phase of projects. Let's see how the trial now goes. We know that some Southern European countries are advocating more severe interactions or interference in the market, but it seems to be that the European Commission itself has a very clear view, after their assessment, after consulting with the industry, with the entire industry, including Southern Europe, and that the current proposal put forward has strong support in our home country, but also Scandinavia, Netherlands, and some others.
Anything on the Green Deal? I mean, the Europe's response to IRA? Because there are, I mean, markets and thoughts on that, including the share of the green technology being produced in Europe by 2030. Do you see it as doable?
I read the European proposals here more like objectives. I think in the end, it's missing the relevant measures. I mean, what is the point of throwing out a target of X% solar panels produced in Europe? It's a target. It's a target like we have seen CO2 reduction targets in the last decades. I think the question is what is the implementation measure? But as I have said, to another question, I think it's not so much about the European level. I think in the end, a lot will be driven by the national levels, or the governments, the federal governments in the countries.
I currently don't see that on European level, we get to a point where you have a kind of support scheme which incentivizes to build the European supply chain. That is not a surprise because there is nothing they can tap. I mean, taxes are on national levels. What the, what the US do with IRA, incentivizing, giving additional incentives when you procure locally, is simply not possible on European level. That can be done on national level, and then you have to relax state aid approval. I think we need to wait whether we see a coordinated approach, how to implement these targets or implement measures that the target can be achieved by the national governments.
I doubt whether the Green Deal is really the answer which is matching the IRA, which has very specific measures and is very pragmatic because we know exactly what the support for green power or green kilogram of hydrogen, blue or green is, and that is missing in the European Union. Yeah.
Thank you.
Thank you, Wanda. Next question, please.
We'll now take our next question from Harry Wyburd at Exane. Your line is open. Please go ahead.
Hi, everyone. Thanks for taking my questions. Two quick ones. First, just to follow up on the European IRA response, sort of a very specific focus on state aid. I think that there's sort of two avenues that the commission's proposed for state aid. Firstly, under the power market reform, there's a mention of state support for CFDs, and then there's also the wider loosening of the state aid rules, which I guess could open up the door to tax breaks and so on, but at a national level. I was wondering, what do you think the member states, if this stuff is passed by the council, what do you think individual member states will actually do with these powers? Do you think we're gonna get state-subsidized generous CFDs for renewables projects?
Do you think we're gonna get accelerated tax depreciation? I'm interested if you've got any thoughts on whether you think Germany or Northern European member states might be more aggressive with those. Second one, very quickly, you mentioned development expenditure when you're talking about onshore and offshore wind guidance. Just interested, is there anything specific there that's driving that higher development expenditure? I wondered if you could quantify or whether there's anything structural there that's driving that change. Thank you.
Thanks for the question. I mean, CFDs, I would distinguish two levels of that. If you run a CFD auction like we know the Polish one or, the UK one, probably you'll also see a similar one in one of the next German auctions, not this year, but that is for me, not state aid because it's a competitive project. Who is able to build the project at the lowest cost? I think there is no state aid element to that. If, and I think that's what you are referring to, if government wants to then have a second leg of CFD, so to deliver this kind of power at lower cost than production cost to energy-intensive industries, like an industry power price, that of course, is an indirect subsidy and needs state aid approval.
I have no visibility how the discussions on European level are, how far they gonna go. Of course, I know from several countries they are interested to attract manufacturing jobs by giving tax breaks if you build up a manufacturing capacity, create certain number of jobs in some countries. Here's a problem on European Union is, of course, you have the disalignment among the different member states because some of the member states with lower debt to GDP ratios can of course afford more tax incentives to attract industries. What the European Union wants to prevent is a competition among the member states who gets what kind of jobs. That is currently where the discussion stands. Let's see how that goes.
I really hope that they can find agreement and that we get some kind of support to build a European supply chain. On the CapEx side, I mean, the higher CapEx Michael mentioned in his speech for the different renewable segments is driven, of course, one by inflation. We have some higher prices, but that's not the most relevant one. I mean, we simply have been more successful with our development activities. We are far beyond our build-out targets and development pipeline we have put forward with the Growing Green CMD. Of course, if we now want to de-deliver higher MWs, at least gross, let's see how much we can find. We put the figures together for year end. If we wanna develop it, I think development is always a value. It comes at higher cost in the beginning. This is actually additional investment in additional growth.
That's very clear. Thank you.
Thank you, Harry. Next question, please.
We'll take our next question from Robert Pulleyn at Morgan Stanley. Your line is open. Please go ahead.
Hey, good afternoon, gentlemen. One new question and a quick follow-up. The first one is on non-organic growth, following the recent deals, I'd love to hear your perspective on what you think is still missing from the portfolio and would augment the equity story, if anything, of course. Secondly, if we could just clarify an answer earlier from Michael about hedging. Specifically, may I ask, is there any hedging on the gas fleet, or is that something you've left open, which I think was the case for the second half last year? Thank you very much.
Rob, thanks for the question. I mean, we always said, leading position in all markets, we have achieved that. If we would go for solar because we are not well-positioned in solar. I leave it to you to figure out in which market we are not that big in solar yet, but I don't expect anything big. If we come along an attractive development pipeline, but probably not even the size we have acquired here in the U.K., then we would go for it. We are constantly screening the market, currently I don't see anything which might happen in the next month, maybe not even this year. The markets where we are still.
If we cannot get hold of a development pipeline, we're gonna build it organically, to be very clear. If we only go for M&A, if we see that the M&A path accelerate it so much that it's worth the acquisition amount, otherwise it takes a bit longer and we're gonna build solar besides wind organically. Maybe we have one or two countries on the European map where we would, if we can, accelerate a solar development, but not more.
Yeah. Rob, on your question on hedging, you correctly recall that we have had stopped hedging of gas assets. I mean, we talk about U.K., Netherlands and Germany. You may have heard that in U.K. there's now a new regulation in place that protects us more in case we don't get gas, but have already sold the power. Therefore, the risk is now gone that we had previously seen there. Therefore, to some degree, we have restarted hedging also of gas assets in U.K. You're also aware that the liquidity of the forward markets in U.K. markets is not so high, especially if you go to outer years. We have resumed hedging there.
On Netherlands and UK, we also have restarted hedging to some degree because at least, for this year, we are much more confident that given all the gas balances, there won't be a physical scarcity. That is obviously something we are carefully investigating and then taking decision based on what is our risk appetite, but obviously also what is the current market level? Is it attractive to hedge?
Thank you both very much. I'll hand over.
Thank you, Rob. Next question, please.
We'll take our next question from Olly Jeffery at Deutsche Bank. Please go ahead.
Thanks, good afternoon. Two questions for you, please. The first is just on looking at the relationship between supply and trading and hydro, biomass, gas. Historically, both of these divisions have tended to do well in volatile markets. Looking back at your previous results, from 2019 to 2021, you had similar results from both of these divisions. Also again last year, where after excluding the Russian hard coal contract, again, broadly similar levels of profitability.
Looking to your guys for 2023, you know, Hydro, Biomass, Gas at EUR 2 billion, Supply and Trading at EUR 450 million. I mean, really should the read be here that historic relationship of, you know, expecting good profitability in Hydro, Biomass, Gas because of volatility, that in Supply and Trading, you also could have a very good result here by just being conservative? Is there anything in that historic relationship? On that, I don't know if you could say anything qualitatively on trading year-to-date, how things have gone there?
My last question is just when I look at the guys for 2023, you know, the midpoint for Hydro, Biomass, Gas, that is probably where the biggest delta was against consensus, guys, around EUR 2 billion, company call consensus at EUR 1.7 billion. Now looking ahead in 2024, company call consensus is at EUR 1.3 billion. So it makes me wonder, given the visibility you have on the market, on the volatility, and potentially having locked in some profit for 2024 or locked in enough to have visibility, do you see the 2024 consensus at EUR 1.3 billion for Hydro, Biomass, Gas as being conservative given how you're seeing that division evolve? Thank you.
Oli, good question. I mean, first of all, you are right that both businesses, Supply and Trading and hydro, biomass, gas, because of the flexibility of the assets, are benefiting from a volatile power environment. That's a fair assessment. I think on the hydro, biomass, gas business, what you see is, as I mentioned, that we are now seeing a structurally higher tightness in the market, and that is obviously a situation where also structurally this segment is benefiting from. On the Supply and Trading piece, I mean, we said that it's a normalized value going forward, yet increased because of the higher level of volatility we see. That is clearly something where we need to see how the year progresses.
Obviously, if there is more volatility there could potentially also be more upside, but needs to be seen where it's getting. On hydro, biomass, gas, I mean, as I said, that is a fair assessment going forward. Scarcity will probably stay. Again, here, if it turns out that markets get volatile, again, there might also be some more upside, but that needs to be seen. I mean, quality of Q1, you know, that's something although we are already close to quarter end, we don't communicate before quarter end, so please keep that question until we have the Q1 results in May.
The last question on 2024, obviously, I won't communicate now 2024 guidance on hydro, biomass, gas, but as I said, structurally, obviously, markets are tighter, and that obviously provides also more earnings potential for flexible generation.
Thanks very much.
Thank you, Olly. Next question, please.
Next question comes from Deepa at Bernstein. Your line is open. Please go ahead.
Thank you so much. I have two questions. I think the first one is on offshore wind. Obviously we're seeing higher inflation, higher LCOEs, yet it seems like governments haven't necessarily woken up. We saw in the U.K., the latest CFD parameters are quite disappointing. In Germany, the capital offshore wind is EUR 10 below onshore, and it seems like there is a tendency to go down negative bidding. This is moving obviously industry to seek PPAs. My question is, do you see the PPA market developing so deeply? Because even if I add up all the gigawatt just being auctioned this year by Denmark, Germany, the Netherlands, not even including France, easily talking about 30 GW.
I'm just wondering whether do you see that the governments will recalibrate auctions or does the PPA market deepen, or do all projects get delayed on offshore side? My second question is on US solar panel sourcing. I think you've seen delays. Your peers have seen delays. Given this is gonna be more relevant with the Con Edison CEB , what is your solution for this bottleneck? Do you think that the domestic supply chain will be up and running? What's the timing, and is your solution, essentially the domestic supply chain, or have you identified, you know, maybe another supplier that comes from Asia but can guarantee that there's no polysilicon from Xinjiang? Thank you.
Yeah. Thank you, Deepa. We see that the PPA market is much broader and deeper than years before. There is much more activity now. Especially now is a bit more normalized prices. Is it sufficient to back all the offshore build-out? Probably not. That is why European regulation or European proposals are now hinting especially to government-backed CFD auctions. This is a double-sided CFD. They specifically talk about double-sided CFD, not the single sided, which will in the end provide a floor where you can go for zero price bidding. Double-sided CFD, because that is probably needed to ensure the build-out of this huge offshore capacity wave, which is in front of us. PPA markets are much more active and, in terms of, volume and tenor. U.S. solar, what we are doing is, we are now.
Entering also, or have entered discussions with local suppliers who build a local supply chain to back capacity build out, but also secure deliveries there. We have also identified non-US suppliers, which are currently have no restrictions of importing. As we have pointed out earlier, we see some delays here and there, but not really material for the segmental result. We gotta sort it out over the next month, and then hopefully if we discuss it again in 2 quarters, it is solved, and we have a constant supply of solar panels without any restrictions.
Markus, any comments on the government auction pricing, like the U.K., for example? I mean, it would be impossible to build offshore wind at these sort of strike prices. It's double-sided, but that doesn't solve the problem, right?
Yeah, I mean, I'm not We are not in the, in the auction yet. It's 2012 prices. I mean, I haven't seen the numbers fully escalated to the build out year.
58, 59, something like that.
EUR 58, EUR 59 in today's prices?
In 2028 price.
In?
88.
Okay. Yeah, that looks very challenging. Deepa, I mean, I wouldn't rule out that it needs one wake-up call, that maybe we get in a, in an, in a totally undersubscribed or no offer at all auction. Maybe one of the big offshore projects, we are so withdrawing. In the end, for the offer industry, the relevant question is there a structural disadvantage? Are the LCOE of offshore going up more than the ones for onshore and solar? There I already commented we don't see that. We more or less see LCOE going up, more or less across the technologies. That doesn't mean that if you have a bad project and bad timing and have not procured correctly, that it's bad for an individual project, but I don't see it for the overall industry.
Great. Thank you so much.
Thank you, Deepa. Next question, please.
Next question comes from Peter at Citi. Your line is open. Please go ahead.
Hi. Good afternoon, everybody. Two questions from me, please. Firstly, I wanted to ask you about auctions for CCGT that are meant to be organized in Germany. There was headlines like this in press a couple of weeks ago. When shall we expect these auctions, and how would you see a competitive landscape in this type of bidding? Basically referring, do you think the returns on this CapEx, if it comes, could be better than in the plain renewable development? That would be the first question. Second, can you please provide a bit of a breakdown behind the hydro, biomass, gas division for 2023 guidance, whether you can make a geographical split of the guidance or technological split or, you know, we can have a bit of a better feeling where you make this EBITDA.
Peter, thanks for the question. I think the second one is for Michael. The answer is no, we don't provide a split there. Sorry for that. The first one, was it related to the offshore, the upcoming offshore auctions in Germany?
Yes. Yes.
Okay, good.
No, not offshore. The gas capacity.
The gas. Okay, good. Gas. Okay, good. The government is currently working on the framework. Of course, the framework needs to have certain elements. One is, what are the technological requirements? So the definition of H2 ready, how much volume versus a portion of hydrogen co-firing by, let's say, 2030 by 35? When do you achieve 100%? Then of course, what is the split or the mix of gas plants they want to see? How many CHPs? How many OCGTs? How many CCGTs? What are the location restriction? Because I mean the
Please pardon the interruption. One moment, please, while we get the speakers online. Thank you.
We can go back on live. Thank you.
Okay. Can you hear us?
Yes.
Okay, excellent. Sorry for the for the break. I mean, Thomas is very cost-conscious, so he had only booked it for 75 minutes because really, we are through after 75 minutes. We had to rebook a couple of more minutes. Coming back to your question. The government is working on the technical requirement, working on the right locations, because it needs to go hand-in-hand with grid. The third question is, of course, what kind of support do you get? Is it a capacity market, so an annual payment, or is it more an investment support, so upfront payment.
We expect the final, or not the final, but we expect a consultation of this in the first half of this year. We hopefully can then have an option early, latest early next year, first half of next year, and that would be sufficient to build the plant until the end of this decade.
Okay. Thank you very much.
Thanks, Michael. Next question, please.
Thank you. Next question will be from Martin Tessier at Stifel. Please go ahead.
Yes, sir. Good afternoon. Thank you for the presentation. Two questions from me. The first one on the hydro, biomass, gas segment. Could you please provide us with the isolated amount of earnings from the Magnum and the Diablo power plants? Second question on price caps and windfall taxes. Could you please just tell us what is the impact from windfall taxes included into your 2023 guidance. You said it was a rather small amount, but any insight would be much appreciated. Also, maybe could you communicate on how much volumes do you assume to fall under the price caps this year? Many thanks.
I mean, let's start with the price caps. The price caps obviously very much depend on power price levels you realize, and you know that hedges are included. What you can assume that especially, let's say in the lignite and also, yeah, in the lignite business, where we typically hedge out volumes longer term, we hedge them at lower levels, so you shouldn't expect an effect from price caps. Price caps are more relevant for those capacities that have come back into the market. For example, the security reserve or those assets that have now been prolonged and not been decommissioned, they fall under the price cap.
The same is true with renewables where they had a one-sided CFD, and now the power prices are all above the one-sided CFDs, and therefore you can capture higher returns, and they are now impacted by the price cap. That just gives you a broad sense in which area we're talking about. Again, as I said, those are typically unhedged volumes and it very much dependent on where the price in the end settles, and then also that leads then to how much is taken away. In a way, you can also say it's somehow a kind of hedge against falling prices because the moment prices fall, you also have less money taken away by the price cap.
Therefore, giving a guidance for 2023 is fairly difficult. On the hydro, biomass, gas division, I mean, we already had the try to get more details on countries. I also won't reveal, so apologize for that, return or income expectations from individual assets. Obviously, you can assume that the Diablo plant is assumed fully incorporated in the guidance and also the Magnum plant which we closed beginning of February. It's also fully included in the guidance.
Okay. Many thanks.
Thank you, Martin. Laura, I understand that was the last question. Is that correct?
Yes. We will take our last question from Louis at ODDO BHF. Please go ahead.
Yes. Hi. Thank you very much for taking my question. Indeed, maybe two question on my side. The first one with regards to the wind, a bit conjuncture here. I think that you mentioned that you were below long-term average last year for offshore and for onshore. You mentioned as well for your guidance that you expect a normal level of wind. Could you please tell us where you stand at the moment year to date on the wind level, maybe compared to last year or on absolute terms would be nice? My second question would be more structural with regards to the regulation, ongoing regulation, the flexible generation more particularly.
If you could tell us how do you feel comfortable with regards to the future investment in flexible generation in U.S., in U.K., and in Europe? In comparison to the regulated framework that you have, so on one side, the IRA, the other, the capacity remuneration in the U.K. and in Europe. If you think that all these regulation are good enough for the investment in flexible generation, or if you think that, in the opposite, there is some geography in which it will be better than in others? Thank you very much.
Yes. I pick up on the wind conditions here, right? We always assume normalized wind conditions for the full year guidance. I mean, January has been on average, so that's fine. February so far has been below average. I mean, you know that especially Q4 is very decisive for the wind conditions to come. It's too early to judge based on those two months where we'll end up. I mean, on returns on the flexible generation, as Markus Krebber pointed out, in principle, what you can say is that flexible generation as it only serves as a backup capacity, I mean, especially in Germany or in the European market, we see scarcity.
Those capacities will only run a few hours. That's why we need some additional incentivization to build that. That's why we lobby for a capacity market to make sure that those assets also earn the cost of capital and make a margin on this one and can be built. Yeah. If that's in place, we believe those investments should also be attractive because, I mean, otherwise we would allocate capital somewhere else.
Yeah. Then maybe in addition, you ask also about the regulatory environment. I mean, we run flexible generation in the U.K., in Germany, and in the Netherlands. The U.S. is not a single market. You have totally different market. I'm actually not in a position to judge that regulatory framework in the different markets. I exclude that part of my answer. If you look here in Europe, the U.K. has a full-fledged capacity market. You have also seen that the recent capacity market auction has actually attracted new build capacity which works. You get then a 15-year contract, not a 1-year contract. The biggest challenge will be Germany, because here is the biggest investment need.
The German government talks themselves about 20-30 GW of new build capacity until the early 2030s. I mean, no surprise, we replace coal and nuclear, and that was actually the firm capacity in Germany for the last decades. Here we probably will see a very targeted investment support scheme. I would be surprised if we see a full-fledged capacity market also favoring existing capacity, because that is not the problem. Our problem is not to keep existing capacity in the market like in the UK. Our problem here in Germany is to incentivize new build. You probably see a very targeted new approach to achieve that here.
Thanks very much.
Thank you, Louis. Thank you, Markus. Thank you, Michael. Thank you to the operator. This concludes our call for full year 2022. I'm sure we'll speak to many of you over the course of the next week, after doing our road shows across the world, and then we'll hear latest again through the Q1 call in mid-May. Have a great day. Thank you. Bye-bye.
Thank you. Bye. Bye-bye.