RWE Aktiengesellschaft (RWE) Earnings Call Transcript & Summary

Welcome to the RWE conference call. Markus Krebber, CEO of RWE AG; and Michael Muller, 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. And good afternoon, ladies and gentlemen. Thank you for joining us for RWE's Conference Call in Fiscal Year 2022 and, of course, the outlook for 2023. Our CEO, Markus Krebber, and our CFO, Michael Muller, will guide you through our presentations 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 is far-reaching consequences for the global energy markets. It has been a very demanding year for the European energy company, but we are very proud that team RWE weathered the energy crisis that well. And 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 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 portfolio through attractive acquisition, which add to another 4.5 gigawatts of operating assets and more than 16 gigawatts of green generation pipeline. And at the same time, we have accelerated the coal phaseout by 8 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. 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 an outstanding results 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 '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. A 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 Business 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. 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 USD 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 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. Through successful auctions in 2022, RWE's offshore development portfolio now totaled 3.9 gigawatts. In Europe, the acquisition of the East Celtic Offshore Project in Ireland will enhance our development portfolio. But we also focused 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 2 attractive project pipelines in Poland and the U.K. totaling around 9 gigawatts. RWE is delivering on its Green Growth Strategy and complements the 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 U.K. and the U.S. In '22, our flexible generation portfolio delivered an exceptional result with an EBITDA of around EUR 2.4 billion and a 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 renewables, both from the 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. 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 gigawatts of installed capacity. And through 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, but 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 gigawatts to replace coal units. We expect that the German government will create an attractive and reliable incentive scheme to make these investments happen. And in our hydrogen business, we recently ordered 2 100-megawatt electrolyzers for the green H2 initiative which is one of the most advanced hydrogen projects in Germany. We plan to commission the first of the 2 plants in '24 on the side 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 8 years and underpin our strong ambitions to transform as quickly as possible. However, our responsibility to the people in the range, 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 side 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. Whereas RWE's 2016 earnings were still strongly 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 are taking 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 EUR 5.8 billion to EUR 6.4 billion. Based on the strong earnings and our positive outlook, we propose to increase the dividend for fiscal year '23 to EUR 1. 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, Markus, 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 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 U.K. offshore wind farm, Sofia that is due to be commissioned in 2026; and in the 3 gigawatt 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 to 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. And we signed supply contracts for upcoming projects. Examples are turbine contracts 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 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 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 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 U.K. and Kaskasi in Germany, and the full consolidation of Brunsbüttel for the full period. Furthermore, wind conditions were better than last year, even though they were below the normal average. For the Onshore Wind/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-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 & 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 nonoperating results. We have now reclassified the charge so that all charges related to Russian counterparties are booked in adjusted EBITDA. The German coal nuclear operations 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 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 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 for -- 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. However, 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 green growth program. Other charges and net financial debt reduced by EUR 2.7 billion. This includes the inflow from the mandatory convertible bonds 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 increased -- have decreased, partially offset by a negative performance of planned 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 U.K. price caps and higher 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 for our enlarged U.S. portfolio after the closing of the CEB acquisition on March 1. We also assume normalized wind conditions 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. 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 newbuild grid stabilization plant in Biblis will contribute to '23 earnings. For Supply & 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 in our -- 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 proposed 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, 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, Markus. We'll now start the Q&A session. Operator, please kick it off.

[Operator Instructions] We'll now take our first question from Alberto Gandolfi at Goldman Sachs.

Obviously, stick to the road of two. The first one, please, is on the renewables permitting. I mean your execution has been great in '22 despite of 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 gigawatts? And are we going to expect some tailwinds 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 with the 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 2 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.

Yes. Thank you, Alberto, it's Markus. So let me start from -- 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, specifically Germany, but actually more or less every country, from Poland, U.K., 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. 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 appeal so that the likelihood it goes up, when you see that environmental studies pass the [ work to see ] faster, so I think it's too early to tell. And -- 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 decarbonization problem. In terms of build-out, of course, you need to add another 2 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, so 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 plants. And the IRA, so 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 all relevant suppliers also to build local manufacturing capacity and get our hands around or hold of supply. So here, also maybe 2 years. And that is exactly why we said it's definitely time at the end of the year to give you a full update where 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 going to be in, let's say, the 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. 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 decarbonization of our flexible assets that you also call them Green. I mean that's core of our business. And 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 fund 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 millions 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.

Thank you. We will now take our next question from Peter Bisztyga at Bank of America.

Thanks for the presentation today. So one question first for Markus, which is, I was wondering if you can maybe use, for example, you get H2 project. It was a bit of a case study to show us whether there is anything that's happened on the policy front, whether it's the [indiscernible] Industry Act, whether it's on the 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 from a policy perspective? And then the second question for Michael. Can you provide us an update with your current hedging levels actually are across your generation activities? And also, what sort of assumptions about the commodity price environment will 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?

Yes. 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 side. We not only run our large 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, which not only electrolysis, but also will connect project of storage and testing existing pipelines for convergence. And we have now said, I mean let's move forward. We are still waiting for, let's say 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 are the national governments. I mean the European frame is nice, but 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 regulation state 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.

Yes, Peter, coming into 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 done 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 -- forward markets, for example, in Netherlands and in the U.K. so the hedging is more difficult. Yes, I mean we already have incorporated the develop -- the recent development of commodity prices in our forecast that, as you know, have come significantly down since December. So that's incorporated. So overall, we are very confident with the numbers we presented. And I mean, finally, also, please bear in mind, especially if you talk about the flexible generation fleet, this fleet not only benefit from spreads, but there are also additional incomes from ancillary services from short-term asset optimization and the capacity markets and especially the ancillary services and the short-term optimization benefit from the current environment of scarcity, where our flexible generation can jump in.

We'll take our next question from Vincent Ayral at JPMorgan.

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 movements versus [ looking forward ] to 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 any 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 infra marginal caps? Basically, how long do you have -- do you assume them to last? Do you have like an assumption until midyear? Are you going further out? 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 states, yes, maybe on solar. We've seen a number of examples where there are big questions being asked on the U.S. offshore. Can you give us enough color on what you see? What is the state of your project there and basically the key challenges in the type of return you get there would be very...

Let me start with your question on the commodity prices and inframarginal cap and Markus can pick up on the Solar -- 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. But I mean, looking at commodity markets, what you 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. 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 didn't have a big impact, yes. So what I'm saying is it's 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 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.

Yes. 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 projects in the U.K., 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 the 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. And 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. 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. 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. But of course, that was already known under the new supply constraints. So we have factored that into our bid, that we ensure if we build, we can build successfully. So I can also put it differently. I mean when we put together the company is now going back a couple of years, we were disappointed that we did not have a huge pipeline, especially in the years to come. And now you can say, okay, 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 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 there with the OEMs selling us turbines at fixed prices but not buying the stuff they need to produce it. And 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. We'll take our next question from Ahmed Farman at Jefferies.

I actually just have a follow-up again on the offshore wind market, particularly in the U.S. and East Coast. So Markus, taking your point about sort of the challenges in the CapEx inflation, does the economics of sort of the projects require that we see meaningfully higher tariffs in the New York round 3 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 phaseout? And anything you can share on the current state of debate around the coal lignite foundation in Germany?

Yes, Ahmed, thanks for the question. I mean 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, LCOE, so cost base -- the cost of electricity may go up. And I'm not talking nominal terms. Even without correcting for inflation, we see that LCOE 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 buildup 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, yes, even in real terms. State aid, yes, it's a very painful long process, but the assessment has not changed. I think the recent announcement from the European Commission reopening or readjusting it after the new agreement with the government. We 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 of 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. So I think if we meet for Q3 results, it should be banked in. 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 -- 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, I mean, an update there every here and there. So if there is news, we're going to update you, but all other discussions are confidential.

We will take our next question from Sam Arie at UBS.

Thank you very much, everybody. Thanks for a great presentation and a great set of results. Forgive me, I wanted 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 in particular, 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 overbudget, 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. 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, I would 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. And yes, 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 revenues or the supply but not procure everything. Of course, that is not a nice situation you are in. But looking forward, I think nobody will develop and build an offshore project without decent returns. So 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 had renewable 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. 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 returns should be fine. I mean the numbers you have pulled out with 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've taken FID, we not only want to have procured the CapEx, we also lock in our financing costs and 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 a demand supply. And then on the supply side, relative attractiveness of the different technologies that, in our view, has not changed.

[Operator Instructions] We'll now take our next question from Wanda at Credit Suisse.

Wanda Serwinowska 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 Iran. What do you think about it? Is there anything that is missing in both proposals?

Yes. Thank you, Wanda. What a nice sequence, the 2 Swiss banks in a row. So also all the best for you. 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. Because overall, the market is still very functioning -- it's functioning very well and has actually also delivered very -- a very good price signals. So I think the overall theme when it comes to the generation, I now leave out the retail regulation they want to impose on the suppliers, but on the generation side, the overall theme seems to be less incentivized, more longer-term offtake agreements, be it state organized like CfDs or be it PPAs in the private markets 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 -- of offtake. Of course, the level 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 probably -- you better go for 2 different kinds of inflation adjustment and more CapEx-based until FID, so auction until FID and the more CPI, so operating cost related one, when it comes to the operating phase of projects. Let's see how the trial look 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? I mean the Europe's response to IRA because there are -- I mean, Markus, any thoughts on that, including the share of the green technology being produced in Europe by 2030? Do you see it as a 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 ] percent of solar panels produced in Europe. It's a target, 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 levels or the government, the federal government in the countries. And 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. And that is not a surprise because there is no -- nothing they can tap. I mean the taxes are on national level. So what the U.S. do with IRA incentivizing, giving additional incentives when you procure locally is simply not possible on a European level. Of course, that can be done on a national level and then you have to relax 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.

We'll now take our next question from Harry Wyburd at Exane.

Two quite quick ones. So first is just a follow-up on the European IRA response, sort of a very specific focus on state aid. I think there's sort of 2 avenues that the commission's proposed to state aid firstly under the how market reform, there's a mention of state folk 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? I'm interested if you've got any thoughts on whether you think Germany or one of the 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. I'm just interested, is there anything specific there that's driving that higher development expenditure? I wondered if you could quantify whether there's anything structural there that's driving that change?

Thanks for the question. I mean CfDs, I would distinguish 2 levels of that. If you run a CfD auction like we know the Polish one or the U.K. one, probably you 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 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. And I have no visibility how the discussions on European level are, how far 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 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. And what the European Union wants to prevent is a competition among the member states who gets what kind of jobs. And 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 [ DevEx ] side, I mean, the higher DevEx Michael mentioned in his speech for the different renewable segments, is driven, of course, one, by inflation. So 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 a growing Green CMD. And of course, if we now want to deliver higher megawatts, at least gross, let's see how much we can find as we put the figures together for year-end. But if we want to develop, development is always a value, it comes at higher costs in the beginning. So this is actually additional investment in additional growth.

We'll take our next question from Robert Pulleyn at Morgan Stanley.

One new question and a quick follow-up. So the first one is on nonorganic 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. And secondly, if you 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.

So Rob, thanks for the question. I mean we always set 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 in which market we are not that big in solar. But don't expect anything big. So 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. But we are constantly screening the market. And currently, I don't see anything which might happen in the next months, maybe not even this year. The markets where we are still -- and if we cannot get hold of a 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 1 or 2 countries on the European map where we would -- if we can accelerate a solar development, but not more.

Yes. And Rob, on your question on hedging, you correctly recall that we have had stopped hedging our gas assets. I mean we talk about U.K., Netherlands and Germany, you may have heard that in the U.K., 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 hedging also of gas assets in U.K. But you're also aware that the liquidity of the forward markets in U.K. markets is not so high, especially if you go to outages, so. But we have resumed hedging there. On Netherlands and U.K., 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 level, is it attractive to hedge?

We'll take our next question from Olly Jeffery at Deutsche Bank.

And three questions for me, please. So 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. And looking back at your previous results, from 2019 to 2021, you had similar results in 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 guide to '23, Hydro/Biomass/Gas at EUR 2 billion, Supply & Trading at EUR 450 million. I mean really should read be here that by historic relationship of expecting good profitability in Hydro/Biomass/Gas because of volatility that in Supply & Trading you also could have a very good result here by but just being conservative? Is there anything in that historic relationship? And on that, I don't know if you could say anything qualitatively on trading year-to-date, how things have gone there. And then my last question is just looking at the -- when I look at the guide for 2023, and as a midpoint for Hydro/Biomass/Gas, that is probably where the biggest delta was against consensus guide around EUR 2 billion, company called consensus of EUR 1.7 billion. Looking ahead in 2024, company called consensus is at EUR 1.3 billion. So it makes me wonder, given the visibility you have on the market and the volatility and potentially having locked in some profit to '24 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?

Olly, good question. I mean, first of all, you are right that, both businesses, Supply & 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 this segment is benefiting from. On the Supply & 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. So that is clearly something where we need to see how the year progresses. Obviously, if there is more volatility there, there could potentially also be more upside, but needs to be seen where it's getting. And on Hydro/Biomass/Gas, I mean, 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 might also be somewhat upside, but that needs to be seen. I mean quality of Q1, that's something -- although we are already close to quarter end, so 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 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.

Next question comes from Deepa at Bernstein.

I have two questions. So the first one is on offshore wind. So obviously, we're seeing higher inflation, higher LCOE. Yet it seems like governments haven't necessarily woken up. So we saw in the U.K the latest CfD parameters are quite disappointing. In Germany, the cap for offshore wind is EUR 10 below onshore. And it seems like there is a tendency to go down negative bidding. So this is moving, obviously, industry to seek PPA. 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, then at Netherlands, not even including France, easily talking more than 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 side? And my second question is on U.S. solar panel sourcing. I think you've seen delays -- this year we've seen some delays. And given this is going to be more relevant with the Con Ed deal, 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 is no policy looking from [indiscernible] ?

Thank you, Deepa. We see that the PPA market is much broader and deeper than years before. So there is much more activity now. And also, especially now with a bit more normalized prices. Is it sufficient to back all 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 then 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 build-out of this huge offshore capacity range which is in front of us. But PPA markets are much more active in terms of volume and tenor. U.S. Solar, what we are doing is we are now entering also -- have entered discussions with local suppliers who build local supply chain to back capacity build-out but also secure delivery there. But we have also identified non-U.S. suppliers which currently 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 results. And we're going to sort it out over the next months. 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 this sort of strike prices, double-sided, but that isn't all the problem, right?

Yes. I mean, I'm not -- we are not in the auction yet. It's 2012 prices. I mean I haven't seen the number fully escalated to the build-out here. So...

58, 59, something like that.

58, 59 today's prices.

In '28 price?

In?

2028 price.

That looks very challenging. But Deepa, I mean I wouldn't rule out that it needs one wake-up call, that maybe we get a totally undersubscribed or no offer at all auction. And maybe one of the big offshore projects were withdrawing. But in the end, for the offshore 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 there, I already commented, we don't see that. We more or less see [ SUEs ] going up more or less across the technology. That doesn't mean that if you have a bad project and bad timing and has not procured correctly, that it's bad for an individual project. But I don't see it for the overall industry.

Next question comes from Piotr at Citi.

Probably two questions for me, please. So firstly, I wanted to ask you about the auctions positivity that are meant to be organized in Germany. There was a headline like this in press a couple of weeks ago. So when shall we expect these auctions? And how would you see a competitive landscape in this type of bidding and basically [indiscernible] in the returns on this CapEx, if it comes, could be better than in the play in the 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 division for 2023 guidance whether you can make a geographical split of the guidance or technological split 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 for Michael, but the answer is no, we don't provide a split there. Sorry for that. And the first one was it related to the offshore -- the upcoming offshore auctions in Germany?

Yes.

Okay. Good.

No, not offshore, the gas capacity.

The gas. Okay. Good. Yes, 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 a portion of hydrogen co-firing by, let's say, 2030, by [ 35% ] ? When do you achieve 100%. And then, of course, what is the split or the mix of gas plants they want to see? What -- how many CHPs? How many OCGTs? How many CCGTs? What are the location restrictions? Because, I mean... [Technical Difficulty]

And we can go back on live. Thank you.

Okay. Can you hear us?

Yes.

Okay. Excellent. So sorry for the break. I mean, Thomas is very cost conscious. So he had only booked for 75 minutes. Clearly, we are through after 75 minutes. So we had to rebook a couple of more minutes. 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 the capacity market, so an annual payment? Or is it more an investment support, so upfront payment? We expect the final -- one of the final, but we expect the consultation of this in the first half this year, and we hopefully can then have an auction early -- early next year, first half of next year. And that would be sufficient to build the plant until the end of this decade.

Next question will be from Martin Tessier at Stifel.

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 power plant? And second question on price caps and windfaIl taxes. Could you please 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 also, maybe could you communicate on how much volumes do you assume to fall under the price caps this year?

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. So what you can assume that especially say in the lignite and also in 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. So price caps are more relevant for those capacities that have come back into the market. So for example, the security reserve or 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 are talking about. But again, as I said, those are typically unhedged volumes. And 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 kind of hedged against falling prices because the moment prices fall, you also have less money taken away by the price cap. So therefore, giving a guidance for 2023 is fairly difficult. And on the Hydro/Biomass/Gas division, we already had tried to get more details on countries. I also won't reveal, so I apologize for that, return[indiscernible] -- or 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, it's also fully included in the guidance.

Laura, I understand that was the last question. Is that correct?

Yes, we will take our last question from Louis at ODDO BHF.

Indeed, maybe two questions on my side. The first one with regards to the wind, a bit conjunctural here. I think that you mentioned that you were below long-term average last year for offshore and for onshore. And you mentioned as well for your guidance that you expect the normal level of wind. Could you please tell us where you stand at the moment year-to-date on the wind maybe compared to last year in absolute terms, it would be nice. And my second question would be more structural with regards to the regulation -- ongoing regulation, the flexible generation [indiscernible]. 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 [indiscernible], the capacity remuneration in the U.K. and in Europe. If you think that both these regulations are good enough for the investment in flexible generation or if you think that the opposite, there is some geographies in which it will be better than in others.

Yes. So I pick up on the wind conditions. You are right, so 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. But I mean, you know that especially Q4 is very decisive for the wind conditions to come. So it's too early to judge based on those 2 months where we'll end up. And 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 a capacity market 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, I mean, otherwise, we would allocate capital somewhere else.

Yes. And then maybe in addition, you asked also about the regulatory environment. You asked -- I mean, we run flexible generation in the U.K., in Germany and in the Netherlands. And 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, so 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. But the biggest challenge will be Germany because here is the biggest investment need. The German government [ tops ] themselves about 20 to 30 gigawatt of new build capacity until the early 2030s. Because, I mean, no surprise, we replace coal and nuclear, and that was actually the firm capacity in Germany for the last decades. And here, we probably will see a very targeted investment support scheme. I would be surprised if you 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 U.K., our problem here in Germany is to incentivize new build, so you probably see a very targeted new approach to achieve that here.

Thank you, Louis. Thank you, Markus. Thank you, Michael. Thank you to the operator. This concludes our call for full year 2022. I shall speak to many of you over the course of the next week, we're doing our road shows across the world. And then we'll hear later again at the Q1 call in mid-May. Have a great day. Thank you. Bye-bye.

Thank you. Bye.

Bye-bye.