Ladies and gentlemen, thank you for standing by. I'm Natalie, your Chorus Call operator. Welcome, and thank you for joining the EnBW's Investor at Analyst Conference call of the first three months, 2023. Throughout today's recorded presentation, all participants will be in a listen-only mode. The presentation will be followed by a question and answer session. If you would like to ask a question, you may press Star followed by one on your telephone. Please press the Star key followed by zeero for operator assistance. I would now like to turn the conference over to Marcel Münch, Senior Vice President of Finance, M&A and Investor Relations. Please go ahead.
Yeah, welcome, ladies and gentlemen. Thank you for joining us for today's Investor and Analyst conference call on EnBW's results for the first three months of 2023. Our CFO, Thomas Kusterer, will provide you with details on the developments in our business in a minute. Afterwards, as always, we look forward to your comments and questions. Without further ado, I'll hand it over to Thomas. The floor is yours.
Thank you, Marcel. Ladies and gentlemen, a warm welcome from me, too. Today, we published our final figures for the first three months, 2023, confirming our announcement of May 4th that we expected adjusted EBITDA at group level of EUR 2.8 billion, which is significantly higher than last year's. More on this in a moment. Let me start with some developments at EnBW, which have taken place since our last investor and analyst conference call. Following the publication of our results for 2022 at the end of March, S&P announced the upward revision of EnBW's credit ratings outlook to stable, confirming our credit rating at A minus. S&P stated that EnBW has a good track record of delivering its strategy on or ahead of time.
In this context, the following aspects are crucial from the agency's perspective: Our solid financial performance, our accelerated coal exit, which is now scheduled for 2028, and the SBTi-approved CO2 reduction path, characterized by the alignment with a 1.5 degree path for our own emissions approved by SBTi and the addition of an SBTi-approved reduction target for our indirect emissions in Scope 3. Acknowledging this benefit of our integrated setup, S&P expects that EnBW's transformation will position it among the strongest integrated European utilities in the long term. Ladies and gentlemen, as outlined in our last call, the triangle of the energy transition is decisive for a successful transformation of the energy system. This means expanding renewable energies as well as grid infrastructure and ramping up low CO2 dispatchable power generation simultaneously.
On March 31st, EnBW launched its EUR 1.6 billion fuel switch investment program for the 1st of 3 new gas-fired power plants in Baden-Württemberg. We intend to completely phase out coal-fired power generation in the Neckar, central Neckar region by 2026 and significantly reduce carbon emissions. All fuel switch sites are expected to run on hydrogen by the mid-2030s. This will further reduce carbon emissions, making the plants part of a climate-neutral electricity generation infrastructure with a high level of security of supply. In Stuttgart-Münster, two Siemens gas turbines will be installed with a total electrical output of some 124 megawatts. When they are delivered in 2024, they will be able to handle a blend of up to 75% hydrogen, the potential upgrade of the plant to 100% hydrogen.
Currently, on the German-Swiss border, our subsidiary, Energiedienst, is building the largest production capacity of green hydrogen in Southern Germany. From 2025 onwards, up to 720 metric tons of green hydrogen per year will be available to supply industrial and other customers in the border region of Germany, Switzerland, and France. By requesting proposals for these quantities, EnBW is already taking the first step towards marketing hydrogen as an energy carrier of the future. The development of a national hydrogen infrastructure is of great importance for the competitiveness of the German economy and central to achieving our climate targets. We are systematically evaluating the potential of hydrogen along the entire value chain in various hydrogen projects.
Please allow me a couple of words on the final phase-out of nuclear power in Germany, which took place on April 15th, 2023, when EnBW shut down Unit 2 in Neckarwestheim as one of the last 3 stations in the country. I think, to be precise, we were the last nuclear power station in Germany being disconnected from the grid. During a short lifetime extension in 2023, Neckarwestheim 2 produced its last 1.9 terawatt hours of electricity. Having received a license to dismantle Neckarwestheim 2 already at the beginning of April, EnBW is now the first operator of nuclear power plants in Germany to obtain all licenses for the dismantling of the entire fleet of nuclear power plants.
As of today, we continue to expect that dismantling the two power stations in Neckarwestheim, as well as the two units in Philippsburg, will take around 10-15 years in total. Ladies and gentlemen, let's now have a closer look at our figures for the first three months, 2023. I would like to start with our operating earnings on slide three. With an adjusted EBITDA of EUR 2.8 billion, we had a very strong performance in the first three months of 2023. This marks an increase of some 140% compared to last year. This increase was largely driven by a strong performance, mainly from thermal power generation and trading activities. Based on the adjusted EBITDA development, adjusted group net profit increased by almost EUR 1 billion.
The higher adjusted EBITDA is offset primarily by higher adjusted income taxes, which were roughly EUR 400 million above last year's level. Let's now dive deeper into our operating segments, starting on slide four. Adjusted EBITDA in Smart Infrastructure for Customers stabilized and rose from minus EUR 60 million to zero in the first three months of 2023. This improvement in earnings was due to lower seasonality in procurement prices than in previous year. Compared to the previous year, adjusted EBITDA in our segment System Critical Infrastructure on slide five, increased by 62% to EUR 585 million. The increase was largely driven by two effects. Firstly, a significant growth in revenues as a result of increased investments in grid expansion. Secondly, the fact that this year's grid usage charges include the expenses expected for grid reserve and redispatch.
On slide six, let me turn to Sustainable Generation Infrastructure, the segment in which we saw the most significant increase in earnings compared to 2022. adjusted EBITDA increased significantly to EUR 2.351 billion in the three months, 2023, compared to the prior year period. Let's look in more detail at the result of the two components of this business segment, starting with renewable energies. Here, adjusted EBITDA decreased slightly by 3.6% to EUR 282 million. This slight reduction in earnings was mainly due to the declining power prices compared to the three months, 2022, and hence reduced earnings from direct marketing of renewable power generation. Adjusted EBITDA in thermal generation and trading increased sharply in the three months of 2023.
Compared to the first three months, 2022, adjusted EBITDA from thermal generation and trading rose to EUR 2.069 billion. On the one hand, generation volumes are sold at significantly higher prices compared to the previous year on the back of the hedges we had entered into. Secondly, we recorded large positive valuation effects on trading transactions. Lastly, the remaining volatility on commodity markets was very beneficial for our trading activities in the first quarter. When looking at the development of net debt on slide seven, I would like to comment first on the development of our retained cash flow. Compared to the first three months, 2022, retained cash flow in Q1, 2023, rose by EUR 2.2 billion to EUR 3.083 billion.
This improvement was mainly driven by an increase in adjusted EBITDA, especially in Sustainable Generation Infrastructure, as I explained a moment ago, as well as cash-relevant effects in our non-operating results. During Q1 2023, this improvement in retained cash flow was largely offset by an increase in working capital of roughly EUR 3.1 billion. About half of this increase was rather temporary in nature and can be attributed to the following three effects. An increase in receivables as a result of implementing the electricity and gas price brakes. Other energy-related seasonalities, mostly the build-up of inventories for carbon allowances for the generation in our power plants in 2022. Furthermore, we ended Q1 with above-average gas storage levels and hence higher inventory.
This was a positive development from a security of supply perspective and a consequence of reduced consumption of natural gas overall during last winter. Last but not least, we made net cash investments of EUR 711 million. We invested around EUR 365 million in System Critical Infrastructure, in the expansion of capacity and renewal of the distribution grid, as well as in realization of the Electricity Network Development Plan. EUR 275 million were invested in Sustainable Generation Infrastructure. More than EUR 200 million in renewables, mainly our offshore wind farm, He Dreiht, in the German North Sea, for which the final investment decision was taken in March.
The rest was mainly spent on our fuel switch project in Baden-Württemberg. Summing all these effects up, net debt amounted to about EUR 11.5 billion as of March 31, 2023, which is some EUR 700 million above the level in December of 2022. Ladies and gentlemen, let me conclude today's presentation on slide eight by confirming that the previous forecast for adjusted EBITDA for the full year 2023 is being maintained from today's perspective. A key reason is that Q1 results were positively impacted by substantial valuation effects, whose further development depends on movements in the market prices, and hence they may at least partially unwind. For the segment Smart Infrastructure for Customers, we forecast an adjusted EBITDA of between EUR 400 million-EUR 500 million since we expect that volatility will decrease and the market will return to more normal levels.
In the segment System Critical Infrastructure, we expect a significant increase with an adjusted EBITDA between EUR 1.6 million and EUR 1.9 million. As already mentioned and already reflected in our Q1 numbers, the negative effect from 2022 for grid reserve and redispatch will no longer apply in 2023, since the empirical value from 2022 have been included in the revenue cap for 2023. Anchorage revenues will also increase slightly due to the high investments in projects in the electricity and gas grid development plans. In the Sustainable Generation Infrastructure segment, we expect an increase in adjusted EBITDA to between EUR 2.9 billion and EUR 3.2 billion. Firstly, renewable energies business is expected to be level with the previous year at over EUR 1 billion.
Secondly, we expect a significant increase in earnings in the thermal generation and trading business in 2023. Against the background of a high share of regulated business and hedged margins for up to three years in advance in our competitive business areas, sales and generation, our full year guidance at group level for 2023 is a significant increase in earnings to between EUR 4.7 billion and EUR 5.2 billion. With this, I would like to hand over to the operator to kick off our Q&A session.
Thank you. Ladies and gentlemen, at this time, we will begin the question and answer session. Anyone who wishes to ask a question may press star followed by one on their touch-tone telephone. If you wish to remove yourself from the question queue, you may press star followed by two. If you're using speaker equipment today, please lift the handset before making your selections. Anyone who has a question may press star and one at this time. One moment for the first question, please. We have our first question from Andrew Moulder from CreditSights . Please go ahead.
Hi, Thomas, Marcel. Good to speak with you both, and thanks for the results presentation. Couple of sort of results-related questions first. On the networks, listening to the E.ON presentation, a couple of days ago, or maybe it was last week, but they made quite a lot about the redispatching costs, and the recovery of redispatching costs, and in particular that they highlighted that this was really just a timing effect and that actually it would revert over time, sort of over a three-year period. I just wonder, within your networks EBITDA, how much of that is due to redispatching recoveries, if you like, or excess recoveries this year, and how much of that will revert, I guess, in subsequent years?
Secondly, on the generation and trading part of the business, EUR 2.1 billion sounds like, you know, it is a great result. I just wonder how much of that is actually due to generation where you've sold power at higher hedged prices, and how much of that is due to the volatility that you've seen in the trading business. Kind of how much is not really related to your generation, but is more related to trading, as opposed to just selling power at higher hedged prices. I guess my final question I just really wanted to ask, I mean, everyone's talking about power generation and power plants being hydrogen-ready. You talked about your hydrogen plants potentially taking a blend of up to 75%, or at least you said the turbines could do that.
I just wonder, you know, does that also cover all the rest of the plant and the equipment? It could all take up to 75%, so you're effectively saying that when those plants are commissioned for the very first time, they could take a hydrogen blend of up to 75%. I wonder just how much would it cost to upgrade that to 100%? I mean, relative to the cost of the plant up to 75%, is it another 20% cost or something like that?
Finally, I think I asked you this question on the call before, but I don't know if you've got any more information you can give on, you know, where would power prices have to be for it to be economic to be generating power with hydrogen as opposed to generating power with natural gas. Those are my sort of three main questions. Thank you.
Hi, Andrew. Actually, great to talk to you again. Let me get started with your first question regarding redispatch and recovering of redispatch. I think we have to differentiate actually, the three-year period in which we get reimbursed for the 2022 redispatch and network reserve expenses is one part of the answer. That's not applying actually to 2023. In 2023, actually, we are actually getting these expenses immediately reimbursed. Effectively, we have already got in the grid revenues of the first quarter, part of it, that's part of our non-operating EBITDA.
This is actually going to be offset by expenses over the course of this year when we will have to ask for capacity for redispatch and network reserves going forward for the stabilization of the grid. It's different, 2023 compared to 2022. In 2022, we will get in three years' time, 2025-2027, over a three years period, 2025-2027, reimbursed for the redispatch and networks reserved. In 2023, it's actually immediately reimbursed within the revenues applied. That's the first question. The first answer. Is that okay for you, actually, Andrew? Is that understood or?
Yeah, that's good. I mean, I thought I understood from what E.ON said that actually the money they were getting in 2023 was calculated on the power prices in 2022. Because power prices have actually come down significantly, they were over-recovering in 2023, and that would have to be returned over time. Is that not the case for you?
It's actually not on the power price. It's actually on the expenses incurred in 2020. That's the basis. The basis is the expenses incurred actually in 2022, because the underlying assumption was actually it could happen in 2023 again. That's the baseline, and that's the basis. You can ask for it on a monthly basis to get reimbursement. However, you should make sure that you don't get over reimbursed because that would be negative for us. We are extremely cautious actually how much money we are asking for in that context.
Oh, okay. Okay. That makes sense.
Overall, it should be a net zero impact on a full year basis. It was positive in Q1, actually now we are looking at how much of it do we need in the next couple of months to make sure that we are not over reimbursed and on a full year basis, right?
Yes. Okay.
Your second question actually on generation and trading and the result of EUR 2.11 billion in that area. The improvement compared to last year is EUR 1.4 billion in this area. The better part of it is valuation impact, a reverse valuation from prior year. You know, I mean, last year, Q4, wholesale market prices were significantly above the level in Q1. You just referred to it, 2023. Hence, actually, we had a reversal of negative valuations in the last quarter of 2022 and now a positive impact in the first quarter 2023. That's for one.
Secondly, that's the good news. Due to higher hedge levels, we were able to increase our underlying earnings. We also actually were able. Our trading was able to benefit from the volatility in the market. That's all in electricity around, that's rough numbers, EUR 400 million and EUR 100 million roughly is in the gas sector. That's kind of answering your question. I do hope so, actually.
Yeah, I guess so. You're saying really the best part of the improvement is due to valuation effects, not actually selling power in the market?
Yeah. Absolutely right. If you go, if you look at the rough numbers, EUR 1.4 billion in increase compared to prior year levels, it's roughly EUR 500 million really improvement in underlying operating business and the rest is valuation. As you know, I mean, that's very much depending on the future development of power prices and how the micro market of these derivatives are going to play out in the course of the year. Yeah.
Right. I guess that kind of sort of leads into the fact of why you didn't actually increase your guidance despite the very good first quarter. Okay. That's great.
Exactly, Andrew. That's exactly the reason. Right? Actually, to a third question, regarding hydrogen. Yeah, absolutely right, actually. 75% hydrogen ready means actually that from day one on, it would be possible to accommodate 75% of hydrogen as fuel. However, having said that, and I think we are all aware of that's theory because the volume of hydrogen is just not available at that point in time. What we assume is actually that it's going to take at least until the beginning of the 2030s to have hydrogen of substantial volume available actually for our power stations.
Your follow-on question on that was actually, what is actually the additional cost to get it 100% hydrogen ready? First of all, it's already included in our investment into the power plant, and it's not substantial. In our final investment decision for the power station, this conversion is already included, and it's not substantial.
Right. Can I just slight follow-up on that one?
Absolutely.
Your plant is 75% ready. What about the gas grid for transporting gas to the plant? Would that take 75%? I mean, most of what I've seen is only talking about a 10% or a 20% blend.
It's more like 20%. That is why I said actually it is 75% ready, which means if and when hydrogen is available, it could accommodate 75%, which is good news. At the same time, the underlying grid infrastructure needs to be improved to allow 75% or even more to flow through the pipes. It's not so much the pipes, it's more all the other components of the grid, actually, that needs to be reinvested.
Anything on how much power would have to cost if you were using hydrogen to generate it?
I mean, that's very much depending on, as you said, power prices. I mean, if you were to generate it in Germany, at least, the German power market. Secondly, question of power prices. The CO2 price is also not just to be taken into account in that equation. To get it, to get it really economically viable, I think the production cost of hydrogen need to come down significantly. Currently, what we are doing is we are involved in projects across the overall along the value chain of hydrogen, so from production to sales. It's more like being on a learning curve and being involved in everything to be sure that we are in the market if and when this market is going to be economically viable.
Again, Andrew, from my perspective, I think Germany will, to a large extent, import hydrogen going forward. We will not be able to really produce hydrogen at significant volumes, at least not for the next 15 to 20 years here in Germany. We need to import hydrogen and the question is actually where is it produced and at what cost. That's totally unclear yet. I think when it comes to economics, when you talk about hydrogen, there's a lot to be learned, and it's going to take a while before we can really talk about economics here.
Okay. That's great. Thanks very much, Thomas. Thanks Marcel.
Welcome.
Ladies and gentlemen, as a reminder, if you would like to ask a question, please press star and one on your telephone. One moment for the next question, please. It seems like there are no further questions at this time. I hand back to Marcel Münch for closing comments.
Yeah. Thank you, Thomas, for your-
Excuse me. We just received a follow-up question-
Oh, okay.
From Andrew again. Andrew, please go ahead.
Yes. Thank you. Sorry, I didn't wanna jump in before anybody else has had a chance.
Always welcome, Andrew.
Yes. Sorry. I just have two more sort of follow-up questions.
Okay.
There have been lots of proposals in Germany about sort of capping power prices, about increasing renewable generation, about making it easier to build renewables and to plan renewables and sort of the whole authorization process. It's not really clear to me that anything concrete has been decided yet. I mean, maybe I've missed it, but could you just give me, maybe everyone on the call, an update on where we are actually in terms of the legislation in Germany with regard to sort of price caps for industrial customers and also legislation around accelerating renewable development? And my second question, I just wanted to sort of touch base on where you are with the TransnetBW transaction, if you've got any more news you can share on that. Thank you.
Andrew, let me get started actually with your second question, the TransnetBW process. We're well on track with this process. I think I can be open in as regards to the fact that we've received binding offers, and we are currently in the process of evaluating these binding offers. Yeah, let me put it that way. I think over the next couple of weeks, we will be able actually to provide more information, as regards to the overall process. Not able to share more information at this point in time with you, Andrew, but bear with me a couple of weeks and we'll have more clarity around that.
Great.
As regards to legislation in Germany, I don't think you have missed anything, to be honest with you, Andrew. Regarding renewables, I mean, we have seen legislation last year, so-called Easter Package and follow-on legislation to speed up the expansion of renewables. We do see actually on the ground some improvements, to be honest with you. Not to the extent we would love to when it comes to accelerating permissions, because I mean, that's the bottleneck still, to get the permitting process and get permissions. We do see some progress here. However, having said that, we need to speed up significantly to really achieve the renewables goals we've set ourselves as a country until 2030.
As regards to price caps for industrial customers, honestly, I think that's extremely early days following the discussions. Yes, of course, it's understandable that the government is contemplating how to protect the German economy from elevated power prices. On the other hand, I think it's also fully understood by everyone, if we wanna look at a system with lower electricity prices going forward, there's only way to achieve this, by expansion of renewable energies, increase in flexible power generation, expansion of transmission, as well as distribution networks. I mean, one thing is very clear. That's only going to be to happen if the risk-return relation is attractive enough to attract international capital, and I think that's understood.
As regards to industrial customer price caps, as I just said, it's even less than a first proposal from my perspective, and we need to see how these discussions are going to develop going forward. We're following it. As I just said, I mean, we need to ensure that the energy transition is going to happen, it's going to happen fast. I think politicians are aware and those who are not yet should be aware this is absolutely needed on a long-term basis. Does that answer your question?
Yep, that does. I mean, that's kind of where I thought we were with the situation.
We are.
I just wanted to confirm that. Thank you very much.
No, absolutely. Thank you, Andrew.
Right now there are no more questions, and I hand back to Marcel Münch.
I'm gonna give it another shot. Thank you, Thomas, for your answers and comments. Thanks to all of you on the call for taking the time. We look very much forward to welcoming you again when we present our figures for the first six months of 2023 on our next conference call on August 11th. Until then, all the best and goodbye.
Ladies and gentlemen, the conference is now concluded and you may disconnect. Thank you very much for joining and have a pleasant day. Goodbye.