EnBW Energie Baden-Württemberg AG (EBK) Earnings Call Transcript & Summary

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 and Analyst Conference Call of the First 3 Months 2023. [Operator Instructions] And I would now like to turn the conference over to Marcel Munch, Senior Vice President of Finance, M&A and Investor Relations. Please go ahead.

Welcome, ladies and gentlemen. Thank you for joining us for today's Investor and Analyst Conference Call on EnBW's Results for the First 3 Months of 2023. Our CFO, Thomas Kusterer, will provide you with details on the developments in our business in a minute. And afterwards, as always, we look forward to your comments and questions. And 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 3 months 2023, confirming our announcement of May 4 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. From March 31, EnBW launched its EUR 1.6 billion fuel switch investment program for the first of 3 new gas-fired power plants in Baden-Württemberg. We intend to completely phase out coal-fired power generation in the 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 plant part of a climate-neutral electricity generation infrastructure with a high level of security of supply. In Stuttgart-Münster, 2 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. Our requesting proposals for this quantity of 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 15, 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 II produced its last 1.9 terawatt hours of electricity. Having received a license to dismantle Neckarwestheim II 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 2 power stations in Neckarwestheim as well as the 2 units in Philippsburg will take around 10 to 15 years in total. Ladies and gentlemen, let's now have a closer look at our figures for the first 3 months, 2023. I would like to start with our operating earnings on Slide 3. With an adjusted EBITDA of EUR 2.8 billion, we had a very strong performance in the first 3 months of 2023. This marks an increase of some 140% in 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 4. Adjusted EBITDA in Smart Infrastructure for Customers stabilized and rose from minus EUR 60 million to EUR 0 million in the first 3 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 5, increased by 62% to EUR 585 million. The increase was largely driven by 2 effects. Firstly, a significant growth in revenues as a result of increased investments in grid expansion, and secondly, the fact that this year's grid usage charges include the expenses expected for grid reserve and grid expansion. On Slide 6, 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 first 3 months 2023 compared to the prior-year period. Let's look in more detail at the result of the 2 components of this business segment, starting with Renewable Energies. Here, adjusted EBITDA decreased slightly by 3.6% to EUR 282 million. The slight reduction in earnings was mainly due to the declining power prices compared to the first 3 months 2022, and hence, reduced earnings from direct marketing of renewable power generation. Adjusted EBITDA in Thermal Generation and Trading increased sharply in the first 3 months of 2023. Compared to the first 3 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. And secondly, we recorded large positive valuation effects on trading transactions. And 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 7, I would like to comment first on the development of our retained cash flow. Compared to the first 3 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 3 effects: an increase in receivables as a result of implementing the electricity and gas price breaks; other energy-related seasonalities, mostly the buildup of inventories for carbon allowances for the generation in our power plants in 2022; and 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 projects 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 8 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 effect, with 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 and 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 billion and EUR 1.9 million. As already mentioned and already reflected in our Q1 numbers, the negative effect of 2022 for grid reserve and re-dispatch will no longer apply in 2023, since the empirical value from 2022 have been included in the revenue cap for 2023. And grid revenues will also increase slightly due to the high investments in projects, in the electricity and gas grid development plan. In the Sustainable Generation Infrastructure segment, we expect an increase in adjusted EBITDA to be 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 3 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. And with this, I would like to hand over to the operator to kick off our Q&A session.

[Operator Instructions] And we have our first question from Andrew Moulder from CreditSights.

A 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 re-dispatching costs and the recovery of re-dispatching costs, and in particular, they highlighted that this was really just the timing effect and actually, it would revert over time sort of over a 3-year period. And so I just wonder, within your network's EBITDA, how much of that is due to re-dispatching 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 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? So 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? And I guess my final question I just really wanted to ask, I mean, everyone is talking about power generation and power plants being hydrogen-ready. And 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, does that also cover all the rest of the plants 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 hydrogen blend of up to 75%? And then 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? And 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 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? So those are my sort of 3 main questions.

Let me get started with your first question regarding re-dispatch and recovering of re-dispatch. I think we have to differentiate actually. The 3-year period in which we get reimbursed for the 2022 re-dispatch and network reserve expenses is one part of the answer, but 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 revenues -- in the grid revenues of the first quarter part of it, and that's part of our non-operating EBITDA. And this is actually going to be offset by expenses over the course of this year when we will have to ask for capacity for re-dispatching network reserves going forward for the stabilization of the grid. So it's different, 2023 compared to 2022. In 2022, we will get in 3 years' time, 2025 to 2027, over 3 years' period, '25 to '27, reimbursed for the re-dispatch in networks we serve. In 2023, it's actually immediately reimbursed within the revenues applied. That is the first question -- the first answer. Is that okay for you actually, Andrew? Should that...

Yes, that's good. 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. And so because power prices have actually come down significantly, they were over recovering in 2023, and that, 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 20 -- that's the basis. The basis of the expenses incurred actually in 2022, because the underlying assumption was actually it could happen in 2023 again, so that's the baseline and that's the basis. And 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. So we are extremely cautious actually how much money we are asking for in that regard. Overall, it should be a net 0 impact on a full-year basis. It was positive in Q1, but 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 on a full-year basis, right? And your second question actually on Generation and Trading and the addition of -- and the result of EUR 2.1 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. I mean, last year Q4, wholesale market prices were significantly above the level in Q1. You just referred to it, 2023. And hence, actually, we had a reversal of negative valuations in the last quarter of 2022 and our positive impact in the third quarter '23. That's for one. And secondly, and that's the good news. Due to higher hedge levels, we were able to increase our underlying earnings and we also actually were able -- our trading was able to benefit from the volatility in the market. That's all in, in electricity, around -- and that's rough numbers, EUR 400 million and EUR 100 million roughly is in the gas sector. So that's kind of answering your question. I do hope so, actually.

Yes. 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?

Yes, absolutely right. And if you go -- if you look at the 1.4 -- rough numbers, EUR 1.4 billion increase compared to prior year levels. It's roughly EUR 500 million, really, improvement in underlying operating business and the rest is valuation. And as you know, I mean, that's very much depending on the future development of power prices and how the mark-to-market of these derivatives are going to play out in the course of the year.

Right. And 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. That's exactly the reason, right? And back to your third question, regarding hydrogen. Yes, absolutely right, actually. 75% hydrogen-ready means actually that from day 1 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 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 for -- 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. So in our final investment decision for the power stations, this conversion is already included and it's not substantial.

Right. And can I just perhaps follow -- just a slight follow-up on that one. 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 10% or 20%...

No, no. Yes, it's more like 20%. So this is why I said, actually, it is 75% ready, which means if and when it is -- hydrogen is available, it could accommodate 75%, which is good news. At the same time, the underlying infrastructure needs to be improved to allow 75% or even more to flow through the pipes. And it's not so much the pipes, it's more or the other components of the grid actually that needs to be reinvested.