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Intrinsic Value is all-important and is the only logical way to evaluate the relative attractiveness of investments and businesses.
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 Mr. Thomas Denny. Thank you.
Thank you, Laura, and 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 presentation before we start the Q&A session later.
And with this, I'll hand over to Markus.
Yes. Thank you, Thomas, and 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. In everything, a very demanding year for a European energy company but we are very proud the team RWE weathers the energy crisis well. And while being busy with crisis management, we delivered an all 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 market through M&A.
Let's now move onto the presentation on Page 4 of this slide deck. In this respect, 2022 was a very successful year for RWE. We have substantially exceeded our financial target. We commissioned 2.4 gigawatts of green capacity and we currently have another 6 gigawatts under construction. With our success in the offshore auctions in the U.S. and the Netherlands, we managed to further extend our substantial offshore pipeline. And on top of that, we have broadened our strategic footprint and balanced our portfolios with attractive acquisition, which add another 4.5 gigawatts of operating assets and more than 16 gigawatts of green generation pipeline.
At the same time, we have accelerated the coal phase-out by eight years and have taken an important step towards compliance with 1.5 degree CO2 reduction pathway. Our strong strategic and operational performance drives our share price. It continuously outperformed the European utilities benchmark in the last year. And 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. And Q4 in particular showed how well our flexible generation assets complement the wind and solar portfolio. And our trading business has recorded outstanding results on the back of dynamic market conditions.
Attractive investment opportunities are key for all growth programs. We have delivered 4.4 billion net investments in '22 and we are keeping up the pace to ensure profitable future growth as well. In '22 alone, we successfully completed more than 30 projects in 11 countries and commissioned 2.4 gigawatts of operating capacity. Further 6 gigawatts 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 gigawatts of operating solar capacity and have almost doubled our portfolio in the U.S. to more than 8 gigawatts of assets in operations. The 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 US$600 million on a full year basis.
The acquired pipeline of more than 7 gigawatts will deliver 500 megawatt 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 achieved a leading position in the U.S. renewables market. We have also strengthened our future growth pipeline to 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. With the successful auctions in 2022, RWE's offshore development portfolio now totals 3.9 gigawatts. In Europe, the acquisition of the East Celtic offshore project in Ireland will enhance our development portfolio. But 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. And we have delivered on this and acquired two attractive project pipelines in Poland and the UK totaling around 9 gigawatts.
RWE is delivering on its green growth strategy and complements its successful development of projects with strategic acquisitions. Following the CEB acquisition, we cover leading positions in all of our core regions; the European Union, the UK and the U.S. In '22, our flexible generation portfolio delivered an exceptional result with an EBITDA of around €2.4 billion and strong outlook for year '23, 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 renewable, both from a volume perspective as well as from an earnings perspective, as shown with the strong Q4 results. And we are also growing our flexible generation business. 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 gigawatts of installed capacity. And to the commissioning of the Biblis gas power plant and grid stabilization unit, RWE is adding another 300 megawatt 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 stations with a capacity of up to 3 gigawatts to replace coal units. We expect that the German government will create an attractive and reliable incentive scheme to make these investments.
And in our hydrogen business, we recently ordered two 100 megawatt 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 '24 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 decarbonisation 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. However, our responsibility to the people in the cold 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 to 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. Whereas RWE’s 2016 earnings were still strong and dominated by the coal and nuclear business, we have taken massive steps on our path to grow green. And 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 degree CO2 reduction pathway.
Coming to Page 10 and our outlook for '23. We expect the capacity of our core business to reach 35 gigawatts by the end of this year. In terms of EBITDA, we expect to continue our strong performance this year with a range of €5.8 billion to €6.4 billion. Based on the strong earnings and our positive outlook, we propose to increase the dividend for fiscal year '23 to €1.00. We plan to provide a full strategic and financial update and long-term outlook in the Capital Market Day in Q4 this year.
And with this, let me hand over to Mike who will now walk you through the financials in detail.
Yes. Thanks, Marcus and good afternoon also from my side. 2022 has been a challenging year for the European energy companies, but 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 €6.3 billion and adjusted net income €3.2 billion. In 2022, we invested €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 gigawatts seabed lease we have been awarded in the New York Bight. In addition, we invested in more than 30 new onshore solar and storage projects and more than 80% of all CapEx has been taxonomy aligned.
In 2023, we will continue our green growth program and we'll invest even more. When investing, we apply strict investment discipline and continue to achieve 100 to 300 basis points returns [indiscernible]. Given the high inflation environment and rising 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 margin for all projects. A good example of 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're 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. And we signed supply contracts for upcoming projects. Examples are turbine contract for our offshore wind farm Thor in Denmark and the German offshore cluster. And we have secured long-term financing to hedge our interest rate exposure.
In 2022, we issued €2 billion long-term green bonds to fund our green growth and the €2.4 billion mandatory convertible to finance our acquisition of CEB. The mandatory convertible bonds were converted into new ordinary shares this month. We have 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 €1.25 billion short-term bond, extended existing credit lines and agreed on new ones. And we have continued to focus on strict risk management and have adopted our hedging accordingly. Overall, RWE has a solid financing and a strong balance sheet. We're well positioned to fund our future of green growth.
Let's now move on to the details of our strong financial performance. In 2022, adjusted EBITDA for our core business reached €5.6 billion and €6.3 billion for the group. In offshore wind, adjusted EBITDA increased to €1.4 billion on the back of new capacity additions, namely our wind farms Triton Knoll in the UK and Kaskasi in Germany, and the full consolidation of Rampion for the full period. Furthermore, 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 €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 €2.4 billion for the full year. The flexible generation business was significantly up year-on-year due to higher margins and exceptional short-term asset optimization. Performance was particularly strong in Q4. An outage at the Dutch gas plant Claus C at the beginning of the year partially offset the increase.
Adjusted EBITDA of the supply and trading segment increased to €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 €750 million was previously booked in non-operating results. 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 related cost savings, high utilization of plants and higher earnings from short-term asset optimization. Adjusted EBITDA from coal/nuclear was €751 million. On the back of the strong operational performance, adjusted net income amounted to €3.2 billion.
Depreciation increased in line with our green growth investments 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 a high interest environment and liquidity requirements in volatile commodity markets. For adjusted tax, we applied the 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 €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. However, it was marked by a higher operating working capital driven by higher volumes and prices for gas and storage at year end. Net debt was negative at €1.6 billion at the end of the year. In 2022, we invested €4.4 billion net in our green growth program.
Other charges in net financial debt reduced by €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 €3.4 billion. This includes net variation margin from the sale of electricity as well as the purchase of the respective fuels and CO2. In the context of high discount rates, pension provisions have decreased partially offset by a negative performance of plan assets.
Now 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 wind conditions. Higher hedge prices will partially be offset by European and UK price cuts and high development expenses for mid and long-term growth.
On solar/wind business, we have increased substantially -- our onshore solar business will increase substantially year-on-year driven by the earnings contribution from our enlarged U.S. portfolio after the closing of the CEB acquisition on March 1. We also assume normalized wind condition and higher hedge prices partially offset by revenue cap and additional development expenses for mid and long-term growth.
Hydro, biomass, gas is expected to continue with a strong performance in 2023. However, 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 '23 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 €5.8 billion and €6.4 billion. Depreciation and amortization will increase year-on-year. This is driven by investment 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 €3.6 billion and €4.2 billion in 2023.
Adjusted net income is forecasted to range between €2.2 billion and €2.7 billion. As Marcus has pointed out, we propose to increase the dividend based on the strong earnings and our positive outlook. We are targeting to pay €1.00 per share for fiscal year 2023. And we deem this as the new floor for the coming years.
And with that, let me hand back to Tom.
Thank you, Michael. Thank you, Marcus. We'll now start the Q&A session. Operator, please kick it off.
Thank you. [Operator Instructions]. 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. And obviously, stick to the rule of two. The first one please is on renewables permitting. Your execution has been great in '22 despite all the supply chain issues. You have 6 gigawatts 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 gigawatt? And 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. So 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 there is one aspect I think of your investment case where you might be a little bit victim of your own success. You've been delivering outstanding earnings compared to the original guidance, and you have been beating and beating and beating. The problem is that some of these profits are a function of volatility in trading or function of maybe high power prices that sooner or later normalize. So 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 to RWE, 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'll 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 completed a large acquisition, but any observation would be very helpful? Thank you so much.
Thank you, Alberto. This is Markus. So let me start from your first question on permitting and tailwinds from the IRA and when we might see pickup in COD [ph], so in delivered capacity. First of all, it targets the European Union, 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 or pathway. So 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 going to see. So when we see the first cause ruling in favor of wind farms, when you see -- when you have -- so that the likelihood goes up, when you see that environmental studies pass the bureaucracy faster. So 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 sheer volume problem in terms of energy supply and also a decarbonisation problem.
In terms of build out, of course, you need to add another two years. So for us, I would say, if everything goes very well, you're going to see the pickup for our core European markets where we do origination activity ourselves, especially in Germany from, let's say, '25 onwards. Of course, we have now bought some pipelines with also very mature projects so that you can expect some additions already next year on top of the old plans. And 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? And we are now working with our relevant suppliers also to build local manufacturing capacity and get our hands around or hold off of supply. So a year or two, maybe two years. And that is exactly why we said it's definitely time at the end of the year to give you a full update. We have a bit more visibility [indiscernible] plan the new one, which would 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'll give you the reasons. First of all, strategy of RWE as we see the benefits of that, especially in the last year, is not that we're going to be in, let's say, IPP wind and solar producer, where you’re actually 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 low profiles, which differ from the production from wind and sun and 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. And probably the value, the real value is in decarbonized flexible generation capacity. So I think we should make the case that we even accelerate the decarbonisation of our flexible tests that you also call them green. It's kind of a core of our business.
And when you see, especially in Europe, with higher penetration rate of renewables, the relevance of these flexible assets, storage capabilities, system knowledge, and so on, which all came together with system integration, offshore auction in the Netherlands, will be where the fun is, and not running individual projects. So 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 billions of wind and solar commodity investments, but the system integration part you want to keep under control. So 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. So one question first for Markus, which is I was wondering if you can maybe use -- for example, you'll 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 X, whether it's on German policy, or whether it's any other EU policies that are actually practically helping that project to move forward more rapidly. Today, or if there's a different example, then that would be interesting as well. So really what practical changes are we seeing today that from a policy perspective?
And then the second question for Michael, can you provide us an update with what your current hedging levels actually are across your generation activities? And also what sort of assumptions about the commodity price environment underpin your guidance range for 2023? Maybe ultimately what I'm getting at is how much risk is there to your guidance range if gas and power prices continue to fall? Thank you.
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 sight. We not only run our last nuclear unit, which will be decommissioned or shutdown in four weeks, we ran 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 connected project of storage and testing existing pipelines for conversions. And we have now said, let's move forward. We are still waiting for the [indiscernible] approval in Brussels to get the funds.
But we said we're not going to 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. But that is of course helpful because in the end, what is driving it is other national governments. The European frame is nice, but I will more turn around. We need to get the federal governments in the different countries to implement the right measures. And then we hope that European policies, regulation state and approvals do not prevent them to introduce it. So I would not overestimate the impact from European policies national level is still in European energy policies, the most relevant part.
Peter, coming into your question on, I guess it's more around the confidence of the guidance we have now put forward. 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 forward markets, for example, in the Netherlands or in the UK. So hedging is more difficult. Yes, we already have incorporated the recent developments of commodity prices in our forecast that, as you know, have come significantly down since December. So that's incorporated that overall we are very confident with the numbers we presented. And 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 assets optimization and the capacity markets, and especially the ancillary service and the short-term optimization benefit from the current environment of scarcity was 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 and good afternoon, everyone. I’m 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 price movement versus the current quarter, a minus 20, 30, 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? So 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 inframarginal caps? Basically how long do you assume them to last? Do you have like until mid year, are you going further out? And that would be very interesting for us. And the last question is going back to a comment you said, you said that the profitability excellent in the state, yes, 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 a bit of 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 would be very helpful.
Let me start with your question on the commodity prices and inframarginal cap, and Markus can pick up on the offshore business. I wouldn't come up with a number on commodity prices that would put our guidance at risk. But looking at commodity markets, what we have seen is that gas prices have come down, but they are now on the level of energy prices. And that's what we always said. So in the current environment, Europe is relying on LNG. So therefore LNG is somehow providing -- LNG prices are providing a floor to gas prices. And 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. So therefore, there is something like a protection against power prices falling further.
And the same is actually true with the inframarginal cap, because what you currently see is that power prices have come down so that the inframarginal cap, at least for some technologies, doesn't have a big impact anymore. So therefore also irrespectively of what assumption we have included, that doesn't have a big impact. So what I'm saying is this kind of -- we feel comfortable with the numbers we are seeing. And as I said, especially in the gas business -- the hydro, biomass, gas business where there are potentially some more positions 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.
Let me continue on the offshore question. It’s not only relevant for the U.S. market. I think you have also now the first project 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. So it's your economics if you have not procured your turbines, cables, substations and so on, because CapEx inflation is much higher than the CPI. Fortunately, we have none of these projects. Michael has outlined in his speech very clearly, that was 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 of the Danish project procured.
And we have now that 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. So for us, they become also risk free the moment we sign the contract. And coming to the U.S., we have the New York Bight project. We have made that public that we participated in the off-take auction in New York. Results to be expected in the coming weeks and months. But of course, it was already known under the new supply constraints. So we have factored that into our [indiscernible] if we build, we can build successfully. So I can also put it differently. When we put together the companies now going back a couple of years, you will have been disappointed that we did not have a huge pipeline especially in the years to come.
And now you can say, okay, it was a -- sometimes you have to be lucky. And now we have the learnings and we don't suffer. So whenever we place a bid or we take an investment decision, the most relevant discussion we're going to have around economics is what kind of open positions do we have? Because what we now experienced in the offshore industry is actually the developers who are committed to uptake for fixed price CFDs, but did not procure, structurally the same problem then with the OEMs selling us turbines at fixed prices, but not buying the stuff they need to produce it. And 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 to the wrong party, you end up with even higher costs and prices for the consumers.
Thank you, Markus.
Thank you, Vincent. 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 U.S. East Coast. So, Markus, taking your point about sort of the challenges and the CapEx inflation, the economics of some of the projects require that we see meaningfully higher tariffs in the new 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 coal lignite foundation in Germany? Thank you.
Yes, Ahmed, thanks for the question. Please understand that I cannot -- I'm not willing to reveal internal calculation. But what I can tell you is, and we see that across more or less almost all regions and technology, that for the first time in the renewables industry as UAE saw cost base -- the cost of electricity may go up, and I'm not talking in nominal terms, even without correcting for inflation, we see that SUE [ph] go up in real terms. And 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. And that is why some of the projects are now also in very difficult territory.
State aid, that of course means to make these projects profitable, we need to see higher tariffs. That is clear in real terms. State aid, it's a very painful long process, but the sentiment 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 a 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 2.6 billion in summer this year. Whether we get it before the summer break or later, that doesn't matter. So I think if we meet for Q3 results, it should be. And then on the foundation, I mean, you know what is in the contract and the law and the agreement with the German government that we committed to look -- as they committed with us together to look into it the moment we have capacity. But please understand that I'm not willing to give you an update there every here and there. So if there is news, we're going to 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 a 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 kind of returns profitability in the renewable industry, and particularly in offshore. And I suppose what we're wrestling with a bit on our side is, on the one hand, hearing many projects in the industry are delayed and over budget, that supply chain bottlenecks and so on is 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. But then 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.
So it feels like nobody is going to start building a new offshore project for a lower return on equity than you get these days on regulated onshore projects. So I suppose that seems to say people are probably going to 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. So I'm just trying to weigh up these kind of two arguments, the problems in the industry versus the sort of higher outlook on returns. And just as always, we'd really appreciate any commentary from you. How you think we should think about this? And should we be worried or should we be optimistic looking forward?
Sam, thank you for the question. I hope all is going well with the Swiss banks, interesting developments also in your industry. But 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. But looking forward, I think nobody will develop and build offshore project without decent returns. So our current expectation, we also see that as our latest projects commissioned, but also under construction, that the margin you expect to earn on offshore, we always said renewables needs around 100 to 300 basis points on top of that 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. And then, of course, if everything goes well, means that margins are higher but on the other hand, the risk that something goes wrong is also higher. So that's why it's probably needed. I think we also discussed it in one of the other calls. So I said on average, it should be the same or fine, but it's much more challenging to get the project derisked. The moment you have derisked them, the return should be fine. The numbers you have put out was 15%. That seems I think very optimistic. And 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 -- but maybe allow me that final comment. Overall, 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, because 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.
Thank you. [Operator Instructions]. We will now take our next question from Wanda at Credit Suisse. Your line is open. Please go ahead.
Hi. Wanda Serwinowsk at Credit Suisse. Just one question from my side, Markus. I would appreciate any comments 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.
Thank you, Wanda. What a nice sequence. The two Swiss banks in a row, so all the best for you. On the European market design question, 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, because overall the market is still functioning very well and has actually also delivered very good price signals. So 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. But on the generation side, the overall team seems to be less incentivize, more longer term off-take agreements be it organized like CFDs or be it PPAs in the private markets is exactly right, because it will 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 off-take.
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 and more CapEx based until FID, so auction until FID and more CPI, so operating cost related one when it comes to the operating phase-out project. Let's see how the dialogue 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 the 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.
And anything on the green deal, the Europe's response to IRA, because America has fought on that, including the share of the green technology being produced in Europe by 2030. Do you see it? Is it doable?
I read the European proposals here more like objectives. I think in the end, it's missing the relevant measures. What is the point of throwing out [indiscernible] solar panels produced in Europe? It's the time. It's a target like we have seen CO2 reduction targets in the last decade. 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 level or the government, federal government in the countries. And I currently don't see that on European level, we get to a point where you have kind of support scheme which incentivizes to build the European supply chain. And that is not a surprise because there is nothing they can tap.
Texas is on a national level. So what the U.S. do with IRA, incentivizing, giving additional incentives when you procure locally is simply not possible on European level. Of course, that can be done on national level, and then you have relaxed [ph] state aid approval. So 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 government. So 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 kilowatt hour of power or green kilogram of hydrogen blue or green is. And that is missing in the European Union.
Thank you.
Thank you, Wanda. Next question, please.
We'll take our next question from Harry Wyburd at Exane. Your line is open. Please go ahead.
Hi, everyone. Thanks for taking my questions. I have two quick ones. So first is just a follow up on the European IRA response to the rate to focus on state aid. So I think that there's sort of two avenues that the commission has proposed for state aid. So firstly on the power market reform, there's a mention of state support 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. So 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?
So do you think we're going to get state subsidized generous CFDs for renewables projects? Do you think we're going to get accelerated tax depreciation? And interested if you've got any thoughts on whether you think Germany or more than European member states might be more aggressive with those? And then second one very quickly. You mentioned development expenditure when you're talking about onshore and offshore wind, guidance and just interested. Is there anything specific that's driving that higher development expenditure? I wondered if you could quantify whether there's anything structural that's driving that change. Thank you.
Thanks for the question. 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 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. And I think that's what you're referring to. If government wants to then have a second leg of CFD, so to deliver this kind of power at lower costs and production costs to energy intensive industries, like an industry power price, that of course is an indirect subsidy and need state aid approval. And I have no visibility how the discussions on European level are, how far they they're going to go?
Of course, I know from several countries, they are interested to attract manufacturing jobs by giving tax breaks if you build up manufacturing capacity, create certain number of jobs in some countries. But here's the problem on European Union is of course you have this alignment 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. And what the European Union wants to prevent is a competition among the member states, who gets what kind of jobs and is currently aware the discussion stance. 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 debit side, the higher debit Michael mentioned in his speech for the different renewable segments is driven, of course, one by inflation, so we have some higher price, but that's not the most relevant one. 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 and of course, if we now want to deliver higher megawatts, at least let's see how much we can find as put the figures together for year end. But if we want to develop that, development is always a value it comes at higher costs in the beginning. So this is actually additional investment in additional growth.
That's very clear. Thank you.
Thanks, Harry. Next question, please.
We'll take our next question from Robert Pulleyn at Morgan Stanley. Your line is open. Please go ahead.
Hi. Good afternoon, gentlemen. One new question and a quick follow up. So the first one is on organic growth, following 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? And 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.
So Rob, thanks for the question. We always had the leading position in all markets, we have achieved that. And if we would go for solar, because we are not well positioned in solar, I leave it to you to figure out which market we are not that big in solar yet. But I don't expect anything big. So if we come along on an attractive development pipeline, but probably not even the size we have acquired here in the UK, then we would go for it. But we are constantly screening the market. And currently, I don't see anything which might happen in the next month, maybe not even this year. The markets where we are still -- and if you cannot get hold of development pipeline, we're going to build it organically to be very clear. So 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 going to build solar besides wind organically. But maybe we have one or two countries on the European map where we would if we can accelerate a solar development but not more.
And Rob, on your question on hedging, you correctly recall that we had stopped hedging off gas assets. We're talking about UK, Netherlands and Germany. You may have heard that in UK, there is now a new regulation in place that protects us more in case we don't get gas but have already sold the power. So therefore, the risk is now gone that we had previously seen there. And therefore, to some degree we have restarted hatching also gas assets in UK. But we also worry that the liquidity of the forward markets in UK markets is not so high, especially if you go to outer years, but 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. But 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 levels, is it attractive to hatch.
Thank you both very much.
Thank you, Rob. Next question, please.
We'll take our next question from Olly Jeffery at Deutsche Bank. Please go ahead.
Thanks and good afternoon. Two questions for you please. So the first is just on looking at the relationship between supply and trading and hydro, biomass, gas. Now historically, both of these divisions have tended to do well in volatile markets. And looking back at your previous results, from 2019 to 2021, you had similar results in both of these divisions. Also again last year after excluding the Russian hot coal contract, again broadly similar levels of profitability. Looking to your guide to '23, hydro, biomass, gas at 2 billion; supply and trading at 450 million. Really should the read be here that by historic relationship of expecting good profitability in hydro, biomass, gas because of volatility but in supply and trading you also could have a very good result here by just being conservative.
Is there anything in that historic relationship? And on that, I don't know if you can say anything qualitatively on trading year-to-date how things have gone there? And then my last question is just looking at the -- because the guide to 2023, the midpoint for hydro, biomass, gas that is probably where the biggest delta was against consensus of the guide around 2 billion company called consensus at 1.7. Looking ahead in 2024, company call consensus is at 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 '24 or locked in enough to have visibility, do you see the 2024 consensus at 1.3 billion for hydro, biomass, gas as been conservative given how you're seeing that division evolve? Thank you.
Olly, good question. First of all, you're right that both businesses supplying trading and hydro, biomass, gas, because of the flexibility of the assets, are benefiting from volatile power environments. 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, the segment is benefiting from. On the supply and trading piece, we said that it’s a normalized value going forward, yet increased because of the higher level of volatility we see. So that is clearly something where we need to see how the year progresses. Obviously, if there is more volatility that there could potentially also be more upside, but needs to be seen where it's getting.
And on hydro, biomass, gas, as I said, that is a fair assessment going forward. Scarcity will probably stay. And again here, if it turns out that markets get volatile again, there may also be some upside but that needs to be seen. Quality of Q1, 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. And the last question on '24, obviously, I won’t communicate now '24 guide 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. So I think the first one is on offshore wind. So obviously we're seeing higher inflation, higher and BOEs. Yet, it seems like governments haven't actually woken up. So we saw in the UK, the latest CFD parameters are quite disappointing. In Germany, the capital offshore wind is €10 below onshore. And it seems like there is a tendency to go down negative bidding. So this is moving obviously industry to seek PPAs. So my question is, do you see the PPA market developing so deeply, because even if I add up all the gigawatts just being auctioned this year by Denmark, Germany and Netherlands, not even including France, easily talking about 20 gigawatts.
So I'm just wondering whether do you see that the government will recalibrate auctions or does the PPA market deepen, or do all projects get delayed on offshore site? And my second question is on U.S. solar panel sourcing. I think you've seen delays, your peers have seen delays. And given this is going to be more relevant with the [indiscernible], what is your solution for this bottleneck? And do you think that the domestic supply chain will be up and running? So what's the timing? And is your solution essentially the domestic supply chain or have you identified maybe another supplier that comes from Asia, but can guarantee that there's no [indiscernible]? Thank you.
Yes. Thank you, Deepa. We see that the PPA market is much broader and deeper than years before, so there's much more activity now and also especially now with a bit more normalized prices. Is it sufficient to back off the offshore build out? Probably not. And that is why European regulation or European proposals are now hinting especially to government-backed CFD auctions. And this is a double sided CFD. They specifically talk about double sided CFD, not the one -- the single sided which will in the end provide a floor where you can go for zero price bidding. So double sided CFD because that is probably needed to ensure the builder of this huge offshore capacity wave, which is in front of us. But PPA markets are much more active in terms of volume [indiscernible].
U.S. solar, what we are doing is we are now entering also -- I have entered discussions with local suppliers who build local supply chain to back capacity built out but also secure delivery. But we have also identified non-U.S. suppliers which have no restrictions of importing. So as we have pointed out earlier, we see some delays here and there, but not really material for the segmental result. And we got to sort it out over the next month. And then hopefully, if [indiscernible] again in two 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 UK, for example? It would be impossible to build offshore wind at these sort of prices. It’s double sided, but that doesn't solve the problem, right?
Yes, I'm not -- we are not in the auction yet. It’s 2012 prices. I haven't seen the numbers fully escalated to the build out here.
It’s 58, 59, something like that.
58, 59 is today’s prices.
And '28 price.
That looks very challenging. But Deepa, I wouldn't rule out that it needs one wakeup call that maybe we get in -- in totally undersubscribed or no offer at all auction, and maybe one of the big offshore projects withdrawing. But in the end for the offer industry, the relevant question is, is there a structural disadvantage? So are the SUEs of offshore going up more than the ones for onshore and solar? And I already comment that we don't see that. We more or less see SUEs going up on us across the technology. 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 Piotr at Citi. Your line is open. Please go ahead.
Hi. Good afternoon. I’ve got two questions from me please. So firstly, I wanted to ask you about auctions positivity that are meant to be organized in Germany. There was a headline saying this impressed couple of weeks ago. So when shall we expect these auctions? And how would you see a competitive landscape in this type of a bidding and basically reciting these things the returns on this cup as if it comes should be paradigm in the plain renewable development? So that will be the first question. And second, can you please provide a bit of a breakdown behind the hydro, biomass, gas decision for 2023 guidance, whether you can make graph charts later for the guidance or technological slate so we can have a bit of a better feeling where you make this EBITDA?
Piotr, thanks for the question. I think the second one is from Michael, but the answer is no. We don’t provide a split there. Sorry for that. And the first one was related to the upcoming offshore auctions in Germany.
Yes.
Okay, good.
Note also the gas capacity.
Okay, good. So the government is currently working on the framework. And 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, was this a portion of hydrogen coal-firing by let's say 2030 by '35 and do you achieve 100%? And 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 the --
[Technical Difficulty]
Please pardon the interruption while we get the speakers online. Thank you. And we can go back on live. Thank you.
Okay. Can you hear me?
Yes.
Okay, excellent. So sorry for the break. Thomas is very cost conscious, so he had only booked it for 75 minutes because usually we are through after 75 minutes. So we had to rebook a couple of moments. Coming back to your question, so the government is working on the technical requirements, working on the right locations, because it needs to go hand in hand with grid. And then the third question is, of course, what kind of support do you get? Is it a competitive market, so an annual payment or is it more an investment support or upfront payment? We expect one of the final, but we expect the consultation of this in the first half of this year. And we hopefully can then have an auction latest early next year, first half of next year, and that would be sufficient to build the plans until the end of this decade.
Okay. Thank you very much.
Thank you, Markus. Next question, please.
Thank you. Next question will be from Martin Tessier at Stifel. Please go ahead.
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 Biblis problems? And second question on price caps and windfall taxes. Could you please just tell us what is the impact from windfall taxes included into your '23 guidance? You said it was a rather small amount, but any insight would be much appreciated. And then maybe could you communicate on how much volumes do you assume to fall under the price caps this year? Many thanks.
Let's start with the price caps. The price caps obviously very much depends on power price levels you realize and you know that hedges aren’t included. So what you can assume that especially staying in the lignite business where we typically hedge out volumes longer term, we have hedged 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 markets. So for example, the security reserve of those assets that have now been prolonged and not been decommissioned, they fall under the price cap. And the same is true with renewables where they had a one sided CFD and now the power prices are above the one sided CFDs. And therefore you can capture higher returns and they are now impacted by the price cap. So that just gives you a broad sense in which area we're talking about.
But again, as I said, those are typically unhedged volumes. So it's very much dependent on where the price in the end settles, and then also that leads then to how much is taken away. So in a way, you can also say it's somehow a kind of hedge against falling prices, because the moment the prices fall, you also have less money taken away by the price cap. So therefore getting a guidance for 2023 is fairly difficult. And on the hydro, biomass, gas division, we already had today [ph] tried to get more details on the countries. I also won’t reveal, so I apologize for that, return of income expectations from individual assets. But obviously, you can assume that the Biblis power plant is assumed fully incorporated in the guidance and also the Magnum plant which we closed beginning of February is also fully included in the guidance.
Okay, many thanks.
Thank you, Martin. [Indiscernible] enough questions, is that correct?
Yes. We'll take our last question from Louis at ODDO BHF. Please go ahead.
Thank you very much for taking my question. Maybe two questions on my side. The first one with regards to the wind, a bit conjectural [ph] here. I think that you mentioned that you were below long-term average last year for offshore and for onshore and you in turn 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 results maybe compared to last year on absolute [indiscernible]? And then my second question would be more structural with regards to the ongoing regulation, the flexible generation, particularly if you could tell us how do you feel comfortable with regards to the future investment in flexible generation in U.S., in UK and in Europe in comparison to the regulatory framework that you have [indiscernible] the IRR, there was also capacity remuneration in the UK. And in Europe, if you think that the consolidation are good enough for the investment in flexible generation, or if you think that the opposite there is some geography in which it will be better than in others? Thank you very much.
Yes, so I pick up on the wind conditions here, right. So we always assume normalized wind conditions for the full year guidance. January has been on average, so that's fine. February so far has been below average, but you know that especially Q4 is very decisive for the wind conditions to come. So it's too early to judge based on those two months where we'll end up. On returns on the flexible generation, as Markus 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 where you can see scarcity, those capacities will only run a few hours. And that's why we need some additional incentivization to build them. That's why we lobby for capacity markets to make sure that those assets also earn their cost of capital and make a margin on this one and can be built. If that's in place, we believe those investments should also be attractive, because otherwise we would allocate capital somewhere else.
And then maybe in addition, you asked also about the regulatory environment. We run flexible generation in the UK, in Germany and in the Netherlands, and the U.S. is not a single market, you have totally different markets. I'm actually not in the position to judge that regulatory framework in a different market. So I exclude that part of my answer. If you look in Europe, the UK has a full-fledged capacity market. You have also seen that the recent capacity market auction has actually attracted new build capacity, which works to get that 15-year contract or a one-year contract. But the biggest challenge will be Germany because here is the biggest investment need, the German government [indiscernible] themselves about 20 to 30 gigawatts of new build capacity until the early 2030s, because no surprise, we replace coal and nuclear and that was actually the full capacity in Germany for the last decade. And 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 builds. So you probably see a very targeted new approach to achieve that here.
Thank you very much.
Thank you, Louis. Thank you, Markus. Thank you, Michael. Thanks to the operator. This concludes our call for full year 2022. I hope to speak to many of you over the course of next week during our road show and then again with the Q1 call in mid May. Have a great day. Thank you. Bye-bye.
Thank you. Bye.
Bye-bye.