Hello everyone, and welcome to our H1 2026 earnings call. I'm here with Leo and Nadia, who will present our half-year results.

As with every occasion, we will leave enough room at the end for your questions. With that, I hand over to you, Leo.

Thank you, Iris. A warm welcome to all of you also from my side.

Today, again, we have an overall simple message and what you're actually used to from E.ON. We keep delivering our operational and financial promises, and the momentum and outlook for electrification and grid infrastructure remains positive.

First, we have strong H1 results. We are fully on track to deliver our full-year 2026 guidance.

Second, grid capacity is the key enabler for the next phase of the energy transition. Rising demand from changing customer behavior, renewables, batteries, data centers puts especially the distribution grid at the center of the energy transition, a positive for E.ON.

Third, operational excellence is a prerequisite for sustainable growth at scale. Our standardization, digitization, and innovation measures enable efficient capital deployment and higher grid utilization, which supports an efficient system and therefore an affordable electrification, again, a positive for us.

Fourth, policy direction is shifting from target-setting to actual implementations, supporting the outlook for our growth case. On my first messages, a few details.

H1 results came in strongly with an adjusted EBITDA of €5.4 billion and an adjusted net income of €1.9 billion. CapEx momentum continued with investments substantially exceeding depreciations.

As always, Nadia will walk you through later through the details of our financial performance. As usual, also let me now point out a few examples of our operational delivery in the last months.

In our Energy Networks business, we connected additional 5 GW of renewables to the E.ON grids in the first 6 months of this year in Germany, and we further accelerated the smart meter rollout, up 25% over the same period. By the way, the expansion of renewables is not limited to Germany.

We had a similar number outside Germany also connected to our grids. In our Energy Retail business, our bidirectional charging product for electric vehicles, which we offer together with BMW, won an energy award in the category Innovative Energy Infrastructure Projects.

The product marks the first commercial offering for end customers in Germany to integrate vehicles in as steerable components into the energy market, or said differently, we turn household flexibility into a scalable grid asset. On my second message, the rising demand for grid connections from further electrifications, connection of renewables, batteries, and data centers highlights the progressing need to expand, modernize, and reinforce the power distribution grid.

Again it's a clear positive for E.ON. Energy security objectives to achieve geopolitical independence from fossil fuels accelerate and broaden the electrification demand and add to the energy transition objectives, and we see that also on the European legislative scale.

Whilst the first phase of the energy transition was about building renewable generation, the second phase is about integrating it, which means ensuring that every kilowatt-hour produced can actually be used. That is a different task.

It's more complex, more decentralized, more digital, and it puts the distribution grid at the center of the energy transition. Let me give you two examples which illustrate the continuously growing demand for network connections.

Let me start again with battery storage. Requests across our German business for battery storage connections increased by more than 30% in the first half of this year from an already very high base.

In this very period alone, we have committed 10 GW of additional battery capacity to be connected to our grids. This lifts our total commitments to 26 GW, around 1/4 of Germany's peak load.

As a second example, changing customer behaviors, also supporting demand for grid infrastructure. German EV registrations are up 50% and heat pumps applications around 35% year-over-year, driven by continued geopolitical uncertainty and improving economics of such solutions for our customers.

The economics are becoming increasingly compelling. EVs already often advantage in total cost of ownership of around 30%, and heat pumps can reduce heating costs by up to 19%.

This brings me to my third message. Operational excellence is a prerequisite for sustainable growth, and E.ON is all focused on delivering that.

Considering the scale of the required infrastructure investments for electrifications, the necessary grid buildout needs to be executable and efficient to ensure that the energy transition stays affordable. The task is to manage execution on an industrial scale within a complex system and with efficient use of the capital and the resources.

That requires consistent standardization, process optimization, digitization, and innovative ideas. We have put our focus exactly on these aspects.

We operate in a complex system, and the scale of the digital transformation and process optimization is significant. This means continuous optimization and learning remain integral part of the execution process.

Let me share a few examples here as well. Scarce grid connection capacity requires a more efficient allocation approach.

Some of our regional DSOs are working intensively on a new pilot project. They look for ways how connection capacities can be allocated in a more targeted and system-serving approach for connection requests with large power consumption needs.

We will communicate in more detail about this approach very soon. For batteries, our flexible connection agreements enable faster connections while aligning storage operation with actual grid conditions.

This is important as batteries need to be connected in a controlled, system-serving way. Without prioritization, local signals, and the consideration of grid constraints, they can also block capacity for years.

Therefore, we have developed a pilot concept for a flexible connection agreement together with our partner Eco Stor, and we are now rolling it out across our German network operators during 2026. What this shows you that innovation can also happen in the way that we actually run our processes, and obviously this needs support also from the regulator and from the legislator.

We are doing even more. We are also harmonizing and modernizing our network control systems across our German grid companies.

System operation is the digital brain of the grid. A standardized and smarter SCADA landscape enables us to make faster, more secure, less-dependent operations without external providers, and we are better able to scale new functionalities.

The first companies will go live on the new system starting January 2027. At the same time, we are making our grids more observable and more controllable.

In Germany, we have already exceeded 1.2 million installed intelligent metering systems, and we are operating more than 30,000 smart secondary substations. The one gives us visibility on the low voltage, the other one on the medium voltage.

With this, we are on track to reach 20% controllability in medium voltage by year-end and already have more than 20% observability in the low voltage area. Why does this matter?

Because only if we digitize across all voltage levels and measure real utilization, we can use all available capacity efficiently before building new lines or new substations or new transformers. Our analysis platform, GridLens, which we built, makes this tangible.

It shows actual and historic grid utilization and helps us to allocate CapEx where it's really needed. In our Energy Retail business, our connected assets under management have doubled over the last 6 months, supported by more than 30 live partnerships.

Flex propositions constantly grow across six markets, and this expands our installed asset base and creates the foundation for future flexibility services and additional value creation so that also our customers can benefit from the energy transition. This brings me to my final message.

Policy focus is shifting from setting targets to actual implementations, and this creates a supportive outlook for our growth case, which again is a positive. A recent survey conducted by our E.ON Foundation showed that European societies support the energy transition, but they have clear expectations: it also needs to be affordable and reliable and executable, not only sustainable.

The recent policy packages on the European and on the national scale are pointing in this direction. On the European level, the EU Grids Action Plan puts faster permitting procedures, stronger recognition of grids as critical infrastructure, and clearer rules for objective and transparent prioritization of connections requests into the focus.

We think that this is the right approach. Efficient grids are the precondition for further electrification, integration of renewables, and security of supply.

The EU Electrification Action Plan published this summer targets a doubling in the share of electricity in final energy consumption from today 23% to 46% by 2040. Even if those targets are not read as literal targets, they are also not legislative, they can be seen as a signpost for the desired direction of travel and clearly supportive for our infrastructure business on the electricity side.

The same objectives can be seen in Germany. The German grid package contains provisions for capacity-restricted network areas and active grid capacity management instead of the current first-come, first-served logic.

The distribution grid package strengthens the emphasis on acceleration of permitting processes for grid buildout. The amendment of the Renewable Energy Law targets to move from pure volume growth to a stronger market integration of PV and a shift in support mechanisms towards systems efficiency, cost-effectiveness, and security of supply.

Overall, the objectives and fundamental principles of all these different legislative proposals go in the right direction. The second half of the energy transition needs to be considered in its entirety to stay executable and affordable.

We need an efficient and future-proof connection regime and effective steering incentive to avoid unnecessary complexity and costs. In any case, what is clear is that the distribution grids stay in the center of the second phase of the energy transition.

The policy direction reinforces the case for sustained grid investments, and we are now obviously looking forward to see what the final legislation will really contain. Let me conclude with the key messages you should take away from my introduction.

First, E.ON continues to deliver. Second, grid capacity is the critical enabler for the energy transition, and E.ON is all about grids and customer solutions around that.

We continue to standardize, digitize, and optimize how we execute in our growth program, and policy objectives point in the right direction, and we look forward to the final design. The momentum and the outlook continues to be positive.

A successful energy transition requires significantly more network investments. What we now need as a closing remark is obviously an appropriate policy framework and an attractive, predictable, and reliable network regulation.

We need long-term planning certainty and financial attractiveness to support this further expansion of critical infrastructure. As said, we stand ready to invest if conditions are sufficiently attractive.

With that, let me hand over to Nadia. Nadia?

Thank you, Leo, and a warm welcome to all of you from my side as well. Since we last spoke, the volatility in global energy and commodity markets has remained high as geopolitical tensions in the Middle East continued.

Against this backdrop, our strong H1 performance once again demonstrates the resilience of our business model in a world of increased geopolitical uncertainty. We are well-positioned to capture the long-term structural growth opportunities, particularly through our investments in power grids.

This resilience enables us to continue with our investments in the energy transition and to deliver on our capital market promises. With that, let me take you through our financial performance for the first half of 2026.

Here are my four key messages for today. First, E.ON delivered a strong operational and financial performance in the first half of the year.

Adjusted EBITDA reached €5.4 billion, slightly above the prior-year level, while adjusted net income amounted to €1.9 billion. With these results, we remain fully on track to deliver our full-year guidance.

Second, our investment momentum remains firmly intact. Investments continue to materially exceed depreciation, with the bulk of our investments allocated to our German power networks business.

Third, our balance sheet remains strong. Economic net debt stood at €46.7 billion at the end of H1, showing the normal seasonal pattern of our business.

It reflects the annual dividend payment and continued investments activity, partly offset by strong operating cash flow generation in Q2. Finally, we fully confirm our short- and mid-term guidance, including our dividend policy.

Let us move on to the details of our H1 adjusted EBITDA development, which increased by around €70 million year-over-year to €5.4 billion on group level. Looking at the business segments, in Energy Networks, we delivered a broadly stable earnings performance year-over-year, fully in line with our expectations.

Our continued investments in our regulated asset base provided earnings growth across all business regions. We also benefited from positive FX effects in our European markets, particularly in Sweden and Hungary.

This was partly offset by the non-negative structural effects. These included portfolio changes following the deconsolidation of one of our regional utility investments in Germany, NEW, as well as the disposal of the Czech gas network.

In addition, we saw higher costs to support the continued expansion of our networks business. In Energy Infrastructure Solutions, we had strong 19% earnings growth year-over-year, mainly driven by the commissioning of new projects for industrial customers and the continued pass-through of higher procurement costs from previous years.

In Energy Retail, we saw slight earnings decrease compared to the last year. This development was expected and reflects the impact of the deconsolidation of NEW in Germany.

In the UK, the performance of our B2B business had continued to normalize, while we have seen positive effects from higher average margins compared to the prior year on fixed-price contracts in our B2C business. Let us now turn to our adjusted net income, which increased by around 5% year-over-year to €1.9 billion.

All major P&L elements below EBITDA developed in line with our expectations. As highlighted during the Q1 call, financing expenses are expected to increase over the course of the year.

This is mainly driven by two factors. First, higher net debt because of significant investments, and second, higher refinancing costs by maturing low-coupon bonds.

Looking ahead, the current development in adjusted net income is therefore expected to normalize over the remainder of 2026. Overall, we remain well on track to achieve our full-year adjusted net income guidance for 2026.

Looking at the development of our economic net debt, which increased to €46.7 billion at the end of the quarter, I would like to highlight four key points. First, the development of economic net debt was fully in line with the typical seasonal pattern.

While the dividend payment in May and our ongoing investments increased END, these effects were partly offset by strong operating cash flow and a reduction in provisions in Q2. Second, our investment spending continues to demonstrate disciplined execution.

The H1 CapEx run rate stood at around 34%, in line with our expectations. We remain on track to deliver our full-year investment guidance of around €8.7 billion.

This amount does not include the Ovo transaction. As a reminder, our network investments profile is weighted towards the fourth quarter, which typically accounts for around 40% of annual CapEx.

Third, our strong balance sheet remains a key pillar of our investment case, with all three rating agencies continuing to affirm our comfortable balance sheet position in the last few months. This validates what we have consistently communicated: our investment program is fully funded within our current balance sheet capacity, and in addition, we continue to see substantial additional headroom to fund further value-accretive growth if the conditions are right.

Fourth, this brings me back to the need for an attractive regulatory framework in Germany. The proposed 7-year averaging methodology for determining the RP5 cost of debt for existing assets would not adequately reflect current and expected refinancing costs.

For gas network investments, we expect a first draft of the WACC assumptions in the next days. The resulting cost of debt allowance will probably not cover our financing costs and will include additional low-interest years compared to power.

However, the financial impact on E.ON should remain limited as depreciation in our gas networks business exceeds investment levels, resulting in declining refinancing needs. In addition, most of our regulatory asset base relates to power networks, which have grown significantly and are expected to continue expanding.

In any case, it is essential that the regulator sets an internationally competitive remuneration for power networks, including a cost of debt allowance that covers refinancing costs. This is fundamental to attracting the investment needed for the energy transition.

Let me conclude the financial section with three key takeaways. First, we once again demonstrated the strength of our business model in a volatile environment, delivering a strong first half of 2026 with adjusted EBITDA and adjusted net income fully in line with expectations.

Second, our investment-backed growth story is progressing well. We continue to invest significantly above depreciation, with disciplined execution and a clear focus on value creation.

Third, our balance sheet remains strong and provides a strong foundation for our current investment program with additional capacity for further growth. However, realizing this opportunity hinges on obtaining sufficient certainty that the RP5 regulatory parameters in Germany will be strengthened and finalized as expected.

Finally, we fully confirm our full-year 2026 guidance and our 2030 outlook, including our dividend policy. With that, let me hand back to Iris.

Thank you, Nadia. With that, we will start our Q&A.

As always, a short reminder to please stick to two questions each. We will start today with the first question coming from Wanda from UBS.

Hi, Wanda.

Hi, hopefully you can hear me.

Yes,

two questions and one clarification, if I may. The first question is on the UK retail market.

Can you give us some numbers, color on the bad debts? This is a real issue in the B2C in the UK.

Bad debts can raise to £7 billion, and you are growing into that market following the Ovo acquisition. Your peer Centrica, they provide the market with bad debt charges, trade receivables, and provisions.

I would really appreciate if you could share some numbers around bad debts in the UK. The second question is: can you talk about the direction of travel of the talks with the German regulator?

We are waiting for the proposal for gas WACCs at some point this or next month, but any qualitative comments on the talks would be much, much appreciated. Just one clarification on the guidance.

Nadia, is the midpoint of the range still the best point, or should we look at the top half? Thanks a lot.

Thank you, Wanda.

All for Nadia.

Okay. Then I've got I think it was three questions.

Yeah. On the UK bad debt, as we have already said in some of our last meetings, the UK team and E.ON Next has been working hard on what we call account health over the last couple of years, where we are firm that we are industry-leading in the UK on our bad debt management.

What does that mean, account health? We looked at debt segmentation activity so that we say, well, what are struggling customer groups?

Then we sort of offer early interventions to help. Secondly, we also have a very active management on our direct debit payment adequacy, i.e., we look very carefully which is the right level of the bill to avoid bill shocks, which is then also, of course, helpful not to run into bad debt issues.

Thirdly, we've got a debt management improvement system which also allows better foresight on bad debt risk and allows early interventions. We are not disclosing the exact number, but we are confident, and we have been seen from the past couple of years, that we are industry-leading in this segment, and that is for us a sign of our operational excellence in this field, which we, of course, also intending to transfer to the overall customer base once we have closed the transaction.

Second question was with regards to the regulation. We expect the first draft of the consultation for the gas WACC in the next days.

Not that long to go. Of course, first of all, we will assess that from a gas perspective because we, as we're operating a gas networks business in Germany.

Of course, we also look into what that means for the different parts of the WACC from the power side. When you look at the cost of debt first, as gas is determined 1 year earlier than power, we will have 1 year more of the low-interest rate years, i.e., 19 to 25, whereas in power, we will have most likely then 20 to 26.

Then on the cost of equity, cost of equity is also including three three very relevant parameters. First, of course, the risk-free rate.

This is using a 5-year averaging period, i.e., for gas, that's going to be 2022 to 2025, whereas, oh, 2021 to 2025, and for electricity, that's going to be 2022 to 2026. We will also see improvements there.

On the market risk premium, we expect to actually get some certain read-across from the determination because that's looking back 100 years, and to have 1 year more or less in 100 100 years for market risk premium shouldn't swing the needle. On the beta factor, we don't know yet at all how both the peer group or the time series will compile, and therefore we also don't know what kind of read-across possibilities they're going to be on power.

As you highlighted, that's going to be quite interesting, first of all, for our small gas business, what that means for that, and secondly, not from the nameplate numbers because there we see quite a bit of differences, but maybe also from the subtext, from the publication, we might get some insights into the power determination, but we don't know at this point in time.

It's maybe fair to add it's the beginning of the consultation,

and

then at the end of the year, beginning of the next year, we will know a little bit more on all the stuff that you just mentioned.

Exactly. It's a typical pattern: first consultation and the final determination for the gas WACC is then after we and the whole industry have fed in our feedback, is going to be at the back end of the year.

Then to your third question, as you know from the past, as long as we don't specifically highlight, you could always assume that the midpoint is the best estimate from the very small guidance range that we gave.

Thank you, Nadia.

Thank you very much.

With that, we come to the questions from Harry. Hi, Harry.

Hello everyone. Hi, thanks for taking my questions.

Two. First one's on the German government distribution package, which, Leo, you talked a little bit about in the opening remarks, but I wanted to dig into it a bit more.

I think from the coalition agreements, it focused on two things: permitting, which you mentioned, and it also mentioned financing, and we were all trying to figure out what that actually means. I wondered if you could flesh out a bit, what do you actually expect from the German government distribution package, and when do you expect that it's likely to be passed?

If the financing elements applies to you, could that change anything, or if it applies perhaps to the municipal operators, could that create some more opportunities for you to provide services to them if they're able to raise their CapEx? Just interested in a bigger exploration of that package.

Then following on from or developing on Wanda's question, the gas draft, Nadia, you mentioned that there might be some elements of it which read across to power. Could you just be a little bit more explicit about what parts of the gas draft you're most focused on to read across to power?

Is it the allowed return? Is it statements in there on how they're going to treat OpEx, etc., just to help us a little bit when it's released on what's important for you and what might drive your views on it apropos power?

Thank you.

Harry, I take the first question on the distribution package. Since it's actually quite confusing, all these different packages on the European and national level, we have, I think, on page 16 in the pack, we have put you the timeline of the different packages so that you have an idea when it might materialize.

The first message is that the German distribution grid package is a second package which should happen after the German grid package. Actually, we as E.ON, we advocate strongly for doing step one first and then step two, rather than discussing everything forever and never getting to a conclusion on anything.

In the German distribution grid package, you rightly pointed out speed and financing as the two let me call it subtopics. Permitting, we think what happens here is that there's an acknowledgment that the speed of permitting needs to be accelerated not only on the transmission system operator level, but also on the especially high-voltage level, the 110 kV, which is part of the distribution actually in most European markets.

If we do not accelerate the high-voltage level, we will actually struggle to follow the dynamic development in the energy transition. I give just one example: the data center boom that we have seen over the last 5 years happens mostly in the 110 kV level.

Now, if we have a speed of development which is accelerating year-over-year, and we have an average permit time of 8 years, we're just not going to be able to react fast enough to the needs of our customers. The fact that now also the high-voltage level is being included in making it faster, not only so far the acceleration was mostly focused on transmission, is a clear positive and will enable us to react faster to the need of our customers.

On the financing side, actually E.ON has low expectations. We do not want state money.

We want a regulation which is sufficient to attract the private capital, which is clearly out there, and if we can actually make that work, then we are fine. Now there are other players in the market which have no direct access to capital markets, and for them, there might be financing opportunities provided by the state in whatever structure.

Now, for us, the only thing is we as E.ON, we do not want to have a distortion of competition by the state offering conditionalities which are better than what we can achieve in the capital markets. I'm actually confident that this will be the case, and if not, then we will either apply for the money ourselves, which would certainly trigger some reactions, or we will sue against that, which would also trigger some reactions.

Much on the distribution package. Again, we think that is more end of the year.

First focus should be on the grid package. For the gas draft...

For the gas draft, that will only include information regarding the gas WACC, everything regarding cost allowance, etc. We don't assume to give specific insights into that.

Then as we try to allude to, I think we will get from the number, as thought we will only get a real insight into the MRP. Then for the other elements on the cost of equity, there is a different time series for example, for both cost of debt for existing assets and also for the cost of equity.

On the cost of debt, there is this assumption that for power, as we have an increasing amount of CapEx in the whole industry, that there will be a specific weighting that the later years will have higher weightings. On the gas side, we haven't seen an increased investment activity over the last years, there we would rather assume that this is more spread equal over the years, and that would be then also something where you cannot take the direct number for cost of debt for existing assets, but there wouldn't be that much read-across opportunities on that.

Understood. Just to clarify, it's the returns that are relevant, but you expect some quite significant modifications for power, right?

I think logically, from the methodology, but also from the different status that both power and gas have in the relevance of the energy transition.

Got it. Sorry to stretch things out, but, Leo, just to follow up on the grids package.

If you did see a significant improvement in the pace of permitting, what would that mean on the ground for you? Do you think that could allow you to get more done, to accelerate things?

Are there financial implications of that if that's passed by the end of the year?

Yeah. First, right now, we have only an intention and let me call it, what is it, 34-point plan on the table, which needs to be put into a legislative package, which then can enter the parliamentary process, which we expect only for next year.

The current timeline would indicate, as we have fleshed out in the backup, would indicate that we get this distribution grid package somewhere in 2027. Then obviously, if permitting becomes faster, that has no immediate impact because for the existing permitting processes, you probably need to finish them as you have started them.

For the next projects, it would allow us to allocate less engineering resources, probably we would have more engineers to do useful stuff rather than lengthy procedures, and it would allow us then to accelerate then in the years afterwards, and then again, especially if combined with an acceptable regulatory package. That's a bit the timeline.

Got it. Very clear.

Thank you.

Thank you. With that, we come to the next question from Alberto from Goldman.

Alberto?

Thank you, Iris. Hi, good afternoon.

Thank you for taking my two questions. The first one is on guidance.

You've done 70% of full-year midpoint already in H1. Basically, you are guiding €900 million essentially net income for H2.

Last year, you did €1.1 billion. Because you had some value-neutral timing effects last year, would you be able to provide maybe a bridge between H2 2025 and H2 2026 as you see it today?

Because I'm really struggling not to be €2.9 billion, €3 billion, let's say to see €2.9 billion, €3 billion, given what you just reported right now. I was trying to see what I'm missing.

Or is it you being overly prudent, perhaps, and then maybe you'll give us an update in November again? The second question is, again, going to this German distribution grid package.

I understood from the economic reform package that the coalition put out in the summer that there was going to be also essentially a sort of an infrastructure plan in power distribution. Should we also expect a hard CapEx number from this German package by year-end?

If so, when can we assume that you can start embedding that CapEx number in your business plan, even though the parliamentary approval is next year? Does it mean we need to wait for March '28 for you to embed all of this into your business plan, or can that happen sooner?

Do you have enough visibility sooner? Thank you.

Sure, I continue with the grid package, and then the Ernie guidance again to Nadia. First, on the infrastructure plan, we don't know what the final package will really contain, Alberto.

I just mentioned that a list of 32 points was mentioned, what should or maybe could potentially be in the distribution grids package. Actually, I do not assume that we will get a detailed infrastructure plan that provides a CapEx number from the legislative package.

I assume we will get that from the grid development plan, which we do anyway, irrespective of the grid distribution package. What we're currently doing in 2026 is that we are working on a revision of the Netzentwicklungsplan, the grid development plan, on a German level, which is deriving the development needs, the investment needs of the German grid, and it's a process run by the TSOs and really the large DSOs, especially E.ON.

It covers actually the high voltage and the extremely high voltage, the 110 kV upwards. It does not cover medium voltage and low voltage.

Now, this revision of the process will deliver a number somewhere the end of 2026. Probably that number will be higher than the number of 2024, but only for the 110 kV.

It doesn't really say something about the total investment needs of E.ON, again, as I said, because it doesn't cover the lower voltage levels. In anyway, I think the key point is investment needs are going up because requests for grid infrastructure are going up and because the grid is already experiencing, kind of being at the limits of what it can do.

For us, I can only see upside coming from that. We will incorporate the high-voltage level developments into our investment plans because we are obliged to do so.

The grid development plan is a legal basis for us for our own investment plans, we will incorporate that. On the other side, the real increase of the total investment, that depends on the regulation, and that depends on how we include the other voltage levels.

On that side, the grid development package is not as important as you might see it at first moment in time. Here comes the connection: obviously, the 110 kV is what is covered in the grid development plan, and that is covered also by the permitting acceleration that we expect.

Regarding the Ernie development, first of all, also on the EBITDA side, we have also in the past always had a stronger H1 than H2 as a part of the normal seasonal pattern. Then, as I have just said to Wanda, we are expecting the midpoint to be the best estimate.

You have been seeing that we have been already done some significant part of our refinancing over the course of the year, and some of the low-interest rate bonds have matured, and we had to finance that at attractive, but at current market price levels. You have seen that when you look at Q1, we had an Ernie increase, adjusted net income increase quarter-over-quarter of 7%.

That has now started to normalize to go down to 5%, and we expect that to continue to be broadly flat then by year-end, mainly due to the fact that interest expenses will increase. Nadia,

sorry. If you allow me, am I wrong in understanding flat growth versus last year would be essentially over a billion, €1.1 billion though, in the second half of net income?

Or if we want to go away from numbers, are we in agreement that sticking to the midpoint, if there are no unforeseen events, most likely is very prudent?

I don't go there. I can just reiterate what I have said earlier, i.e., that, with what we know now, the midpoint is the best estimate.

I tried. Thank you so much.

Thank you, Alberto. With that, we come to the next question, which comes from James Brand from Deutsche Bank.

Hi, James.

Right. Hi.

Good afternoon. Good morning, everyone.

I'll stick to two questions, I think. Try not to make them any kind of two- or three-parters.

Just on connections, there's been a lot of discussion around connections today, and obviously I kind of note the answer to one of the earlier questions, which is it's not just about the direct cost of connection, because it puts more pressure on the overall system, and therefore that's close to capacity, and therefore you need more investment in the overall system. If we're just literally thinking about the connections CapEx, I was wondering if you could tell us roughly what proportion of your overall CapEx is directly going to connections so we can do the kind of obvious times two at some points, but again, noting that there'll be kind of tangential CapEx that will come alongside that.

That's the first question. Then there's also been quite a few questions on the gas WACC consultation.

I guess my question for you would be, obviously you've said that you are looking for kind of a clear signal from the regulator that the outcome of the regulatory review process as a whole is going to be acceptable, and you've kind of set the points that if we got that clear signal, we could step up CapEx earlier. This is obviously the focal point that people are looking at this year is this consultation on gas.

You've also said at the same time that there isn't necessarily that much read-across. My question is, is it feasible that there could actually be enough in this gas WACC consultation that would give you the visibility that you feel like you need to increase CapEx?

If that was to come, what would that mean exactly? Would that mean a really good beta and equity risk premium or something else?

Thanks.

Yeah. James, on on the connections, indeed you pointed out correctly that it's not only about the connection, it's also usually the reinforcement behind the connection point that is really the bottleneck.

For example, you take data centers. The our ability to connect data centers is less driven by the fact whether we can actually put a, a switchyard in place.

The real point is we partially need, for example, additional feed-in points from the transmission grid into the high-voltage grids to then provide power to the data center. What needs to happen beyond the connection is then a reinforcement of the 110 kV, then a reinforcement of the connection between the 110 kV and the TSO.

It's absolutely right, as you pointed it out, that, like there's more to it. Now, just a few additional numbers: when we're looking at connections, only at connections, grid connections in Germany, we are seeing that they are continuing on the high level that we have already seen last year.

We had connections around 200,000 this year in Germany of new assets, which is roughly half of what we had last year. If you look at the connection requests, we actually see an increase in connection requests, which points to a higher need going forward.

Now, we do not know what the percentage is of the pure cost the cost percentage is of the pure connection versus the the reinforcement. Let me just explain to you with an example why that is the case.

If we, for example, look at our northern German grid in Schleswig-Holstein, between the Baltic Sea and the Northern Sea, we are roughly doubling all the transforming all the transformation stations. It's clear that all these transformation stations, this doubling, is part of that is reinforcement, and part of that is at the same time providing the ability for somebody to connect.

Now, if you ask me how much of that doubling now goes to connection and goes to, I really don't know, yeah, and we do not account for it. However, if we have now more customers coming in and we are obliged to connect them, then actually the the direct connection cost would go up, but we would keep the CapEx number, stable and then do push reinforcement out.

It's not that if connection goes up by 20%, the respective cost item goes up in our investment envelope goes up. We keep our investment envelope constant in the planning period, and then we we reshuffle a little bit.

We would then, for example, do probably less modernization to make sure that we still can do the capacity expansion. Obviously, we can do that only for a limited period of time.

If you have sort of a broad ballpark, you could say grid buildout, including new connections, is approximately 2/3 of the CapEx envelope, and approximately 1/3 is replacing and risk mitigation in our current envelope. Okay.

Then,

yes, gas WACC. When you look at the gas WACC, you summarized correctly that from the nominal numbers, we expect immediate read-across only from the market risk premium, because all other numbers we might get a read-across how the methodology has been utilized, but from the number, we don't expect a direct read-across.

What we don't know, how much read-across is in the overall publication, i.e., there might be the opportunity that there are more hints on the methodology also how the electricity grid charges will be computed. As we remember, when you look back at the end of last year, we were a bit disappointed that we got less clarity on how exactly the different elements are being computed, and there might be a opportunity to get some more out of that.

To summarize, and that's, I guess, what we always said, when we increase our CapEx envelope is very much looking at the overall scheme and is very much path-dependent. At this point, we still have this one negative with the 7-year lookback period, and first then it needs to be overcompensated by some more positive elements in order for us to get security black on white that there's going to be a positive regulatory scheme in place.

It's the overall, and of course, we will, as very thoroughly analyze the gas publication, which is due in the next few days, and then we will take our decisions from there. Great.

Thank you very much.

Thank you, James. With that, we come to the next question from Louis from Oddo.

Hi, Louis.

Yes, hi. Good morning, and thank you for the presentation and taking my question.

Maybe the first one regarding the grid connection again. Requests increased by approximately 20% year-on-year.

What proportion of this requested capacity do you realistically expect to result in actual completed connection? Does the trend is in line with what you were expected, for instance, last year?

Maybe in parallel to this question, to what extent the flexible connection agreement can increase the utilization of existing grid capacity? Can you quantify the network investment that could be differed as a result of the flexible connection agreement?

My second question would be more straightforward on Energy Infrastructure Solutions. You delivered 19% EBITDA growth.

How much came from structural investment net growth, and how much could be seen as a temporary weather and procurement effect? Thank you very much.

Louis, on grid connection, let me rephrase, the grid connection requests that we are receiving, we are assuming that a large share of that will never materialize, either because it was speculative from the beginning, and if we can't provide the connection, then the whole project just disappears. Therefore, if I see, for example, battery requests of several hundred gigawatts, it's clear that we're not going to build several hundred gigawatts of capacity in Germany because there will be no economic case for that.

For us, the problem is that we need to process all those requests anyway, knowing that, let me say, 80% of that will just disappear, yeah? Maybe 80% is the number to take, yeah?

If we take, for example, data centers, on data centers, we have requests of around 80. We have given grid connection consent of 13 GW of that, which is then roughly 15%, and we currently have connected 1 to 2 GW.

That's the numbers: 80, 15, 1 to 2. If you look at batteries, we have requests of 700 GW.

We have given consent to connect to 26 GW, and we have connected 2 GW, with which we're, by the way, the market leader in distribution clearly in Germany. That gives you a realistic expectations.

On the FCAs, I personally expect that all batteries that will be connected in the future will need to be part of a flexible connection agreement, especially if the batteries do not pay grid fees, which is the current regulation. They should also not burden the capacity of the grid, because otherwise why would you exempt them from grid fees?

Flexible connection agreements, in the end, do exactly that. They ask the battery operators to behave in a way that they do not increase the load on the grid, but they actually really improve the situation in the grid.

We are not trying to prevent batteries from being connected. Actually, the FCAs will allow more batteries to be connected than without an FCA.

Take you an example: if you have a 100 MW battery which has no FCA, it actually needs 200 MW of grid capacity, because it can charge 100 and it can feed in and pull 100 MW, it needs 200 MW of grid capacity, whilst if you have an FCA, it needs zero, because then it's grid neutral. Obviously, grid connection will improve by the FCAs.

I cannot quantify how much CapEx that will actually then prevent. That depends on a lot, but it's the right thing to do.

Maybe one additional point: flexible connection agreements will become a topic also for non-batteries in the future if we see the current development, because clearly otherwise the ability to connect fast will be limited. I think this is a key topic.

E.ON is trying to be a playmaker here by putting standards out into the market, which then we can improve jointly together with other market participants, and I think that's for a benefit of all.

Now I will take the EIS question. This time shift in the procurement input cost effect, that's approximately €20 million give or take.

That is not a one-off effect, but it was just that in the previous years, we were not yet allowed to lift sort of pass-through, but the pass-through is a bit delayed. That is not a one-off, but an operational effect, but just compared to the baseline of last year, this shows now a more normalized earnings, which wasn't possible already in last year.

Second topic, the remainder is then approximately on organic growth, new projects coming online.

Thank you. With that, we have the question from Ahmed from Jefferies.

Yes. Hi.

Hi, Leo. Hi, Nadia.

I have two questions. Just on the gas WACC, or maybe ultimately getting to a point where you have an overall understanding of the power regulation, it seems like there will be some read-across, but then there are elements like the cost of debt approach, potentially elements of the cost of equity, such as equity beta, etc., that will have limited read-across.

Obviously there's sort of the benchmarking aspect that you have mentioned in the past. Firstly, am I right in sort of categorizing that these are some of the key parameters where still more visibility might be required post the gas WACC update?

Do you expect any sort of update on these three key parameters in the next 6 months or so? That's my first question.

Then secondly, just interested in understanding how the current weather situation that we are seeing in parts of your sort of portfolio in the UK, the heat wave, how should we think about the economic impact of that on the business, if any? Thank you.

Maybe let me start then on the gas WACC. I think we have set out the timelines when we expect more official news to come.

We will have the gas WACC draft consultation now, then final determination by the end of the year, and the next year, that's then all moved for 1 year for power. We'll expect the power draft determination also sometime around mid of the year, and then the final determination at the end of the year.

Then the final conclusion on the power side, when it comes to cost allowance, when it comes to efficiency factors, when it comes about OpEx adjustment factors, and all the respective things that are included in the benchmarking, we expect for 2028 for power. There's no change.

I think we have clearly set out the guidelines, not the timelines, in all of our IR material. Basically, I can confirm that the elements that you have highlighted are some of the very relevant topics: Xgen factor, etc., the typical factors that we have been highlighting also in the IR material.

You have summarized it well.

On the weather, obviously quite an interesting situation right now. Maybe I focus a little bit on our southeastern European markets in Hungary and Romania, where the situation is the most challenging one right now regarding the weather.

Why? Because those markets are impacted by the heat wave and actually less connected to the overall European grid, especially when you look at Hungary, you can clearly see it.

The impact for us is limited there. Our key business is first, obviously, distribution.

Now, as the distribution operators, we are involved into the task forces that the governments have set up to make sure that this situation stays stable. Far, it has been possible to counteract the effect of the less production, for example, by Cernavodă and by Paks, with respective demand reduction on the industrial side, voluntary reduction.

We have not been forced to make involuntary reductions, and we've been able to continue to provide power to all our customers. In so far, the situation has softened a little bit, but it will remain tense.

The solution for that is a better integration of southeastern Europe into the European market, which is something that those countries are asking for anyway because they're looking at elevated price levels. We do not see any significant financial impacts on networks.

On the retail UK, on weather, at this point, we also see no material impact. In that sense, it's more an operational challenge for us where we need to be part of the solution, but it's not that we expect any financial impact from that.

Thank you.

Thank you.

With that, we come to the last questions from Piotr from Citi before we then will close the call. Hi, Piotr.

Hi, good afternoon, everybody, and thank you for squeezing me in. I have two questions, please.

First, I wanted to ask Leo about your expectations about how quickly this battery grid connection queue will translate into the real assets on ground and what kind of implications at what point do you think these batteries could affect the power price formation and in a meaningful way that you would, I don't know, change your procurement strategy or reflect it somehow? How quickly this 26 GW which you gave essentially gets connected and then how much percentage really gets connected?

Second, I wanted to ask you, there's a new renewable law in Germany which, as I understand, gives some kind of a locational factor so that we don't place renewable assets in congested areas. Does it matter for E.ON network?

You have a majority of renewable assets connected, I guess congestions typically would happen in your network. Would that lower overall kind of requests for renewable connection in your grid?

Thank you.

Two new and great questions at the end. Piotr, pleasure to take them.

First, on the batteries, I do not expect all the projects where we have given a consent to connect to materialize, but I expect that we will see some dynamic development because the grid fee exemption that I mentioned for batteries, is tied to those projects being finished over the next 2 years. In that sense, there is a clock ticking, and so the project developers have a high incentive to either be very fast or basically they can leave the playground, yeah?

In that sense, I would expect significant capacities to be added, and they will have an impact on price formation. We can already see that they have a local impact.

If you have a battery in a local grid area, for example, the peak capacity that you need to pull from the TSO goes down, which has an impact on the DSO fees as well. Obviously, if we now add, let's say, 15 GW, which I could easily see in the next 2 years, then 15 GW would clearly have an implication, if not for the total base of price formation, for sure on the shape, and they would actually shift renewables production.

Batteries will have an impact in a very short term. Also we as E.ON are developing partially large-scale grid projects to make sure that we can use them to optimize our hedging for our customer portfolio.

In that sense, I would say they're going to come in pretty fast, also compared to data centers, for example, and they're going to be significant, and they're going to have impact on the ability to provide products to customers. On the renewables, one small correction: the locational factor for renewables with the congested area is actually part of the Grids Package already.

It's not part of the Renewable Energy Act revision that's underway. It doesn't really matter.

For us, it has impact. Obviously not a financial impact, because it has no direct impact because we're not renewable developer, as you well know.

It has no financial impact for us if we need to connect renewables in the wrong place, let me put it this way. What it does, it has no direct impact on us, but it will increase the system cost, because it will lead to additional congestion.

This congestion needs to be charged to the customers, and that's the indirect impact that we have. We then need to charge unnecessary costs to our customers, and then we will have buildout obligations afterwards, which are also unnecessary, because in the first place, we shouldn't have done it there.

I think if we get the locational signals, and if we get the change in the policy via the Grids Package, it will actually decrease the bill for our customers, and it will make sure that we allocate the CapEx where it makes most sense, which in the long term will lead to lower cost for everybody. Now, that's in our interest, it's in the interest of our customers.

It's not necessarily in the interest of the renewables developers. There will be an interesting political debate, and the lobbying is very strong to make that as ineffective as possible.

If it's completely ineffective, as I said, then we have the indirect impacts that I just mentioned. I hope that it will actually be positive, because in the long run, it's just the right thing.

If I can have just a very quick follow-up on this last point. I understand if we have a locational signal, there will be less of a demand in your congested areas.

Do I understand it correctly that it doesn't matter for your €5 to €10 billion future extra capital deployment, because you have so much demand for different grid connections that you would do some other work other than connecting renewables?

Rather than connecting assets that afterwards would be curtailed, we would connect assets that afterwards produce for customers. We would not have any reduction anywhere.

Thank you. With these last words, we close the call.

Thank you everyone for participating and your interest. If there are any further follow-up questions, please reach out to the IR team, happy to take those questions.

With that, I close the call. Thank you very much, everyone, and have a great day.

Bye-bye.

Thank you.

Bye-bye.