Fortum Oyj

Good morning, everyone. A warm welcome again to Fortum's joint webcast and news conference for the investor community and media on our half year report January-June 2025.

My name is Ingela Ulfves, and I'm heading the Investor Relations at Fortum. As always, this event is being recorded, and a replay will be available later today on our website.

With me here in the studio are, again, our CEO, Markus Rauramo; and our CFO, Tiina Tuomela. Markus and Tiina will present the group's financial and operational performance during the second quarter and first half of this year.

After the presentations, we will take your questions in the Q&A session. So with this, I hand over to Markus to start.

Thank you very much, Ingela, and a warm welcome to our investor and media call also from my side. I will start by going through the key elements of our quarterly highlights and our financial performance.

Then I will say a couple of words about the hydro situation and the latest update of power demand projections by 2030. After that, Tiina will provide more details on the financials and how the operational performance turned into our results.

Let me now start with the highlights, starting with a reminder. In our business, the second and third quarters are typically small quarters result-wise.

This also applies to this year. Despite lower power prices, our second quarter achieved power price was almost at last year's level, EUR 48.1 per megawatt hour compared to EUR 48.6 per megawatt hour, supported by high hedge ratio and good physical optimization.

Realized market prices were 23% lower than in the second quarter last year. In her presentation, Tiina will explain in detail the dynamics of the optimization premium and hedge effect.

This year is especially characterized by low volumes, which should be seen as temporary due to hydrology and unavailabilities. When it comes to Hydro Power in Q2, Generation was record low because inflow during the quarter was low in our Generation areas.

In addition to the lower hydro Generation, we also highlighted in connection with our Q1 results that they were and still are unavailabilities in our nuclear generation fleet. This means that total Generation was record low and amounted to 8.8 terawatt hours, which is as much as 2.2 terawatt hours lower compared to the second quarter last year.

At the end of the quarter, we closed the acquisition in our Consumer Solutions business in which we bought Orange Energia, a retail business -- electricity retail business in Poland. Through the acquisition, we doubled our amount of retail customers in Poland.

As part of the agreement, Fortum will continue to sell electricity and related digital services through Orange Polska's nationwide retail sales distribution network, at least until the end of 2028. The efficiency improvement program is progressing according to plan and schedule.

Fortum targets to reduce its annual fixed cost by EUR 100 million, excluding inflation, gradually until the end of 2025. The full run rate will be effective from the beginning of 2026.

We estimate that the new fixed cost base in '26 will be approximately EUR 850 million. This excludes the increase in the Swedish property tax from 2025.

On July 23, after the reporting period, we announced the acquisition of a project development portfolio for wind power in Finland, in which we bought from the German renewables developer and constructor, ABO Energy. This acquisition strengthens our development pipeline for renewables as we prepare for future growth.

Our target is to have at least 800 megawatts of ready-to-build projects to serve our customers when demand starts to grow in the Nordics. With the acquired 4.4 gigawatt portfolio, Fortum's pipeline of onshore wind and solar projects in the permitting phase reaches approximately 8 gigawatts, with more projects in the early development phase.

Potential investment decisions of these projects will be done case by case. Each project will be linked to a customer PPA and needs to meet our investment criteria.

Currently, there is enough power supply in the Nordic area, and we can sell PPAs from our existing outright portfolio. Our financial position remains strong, also following the dividend payment of EUR 1.3 billion.

At the end of the second quarter, our financial net debt was EUR 1.3 billion. Uncertainty in the operating environment has continued due to ongoing geopolitical conflicts and U.S.

tariff plans and may pose challenges to major industrial investments in the Nordics. To support economic growth and long-term investment planning, a steady and reliable regulatory framework is essential.

This is relevant, for example, for the taxation of planned data centers. In our view, public intervention should serve to support industrial investments rather than restrict them.

Then over to our main figures and financial KPIs. Here are a familiar comparable headline KPIs for the group's second quarter and for the first half year 2025.

As you see, all KPIs decreased in all periods. This was mainly a consequence of both low generation volumes and lower power prices.

Major part of this negative effect relates to the clearly lower volumes. In Q2, our comparable operating profit totaled EUR 115 million, while EPS amounted to EUR 0.09.

On a cumulative basis, the group's comparable operating profit amounted to EUR 577 million. Our comparable EPS was EUR 0.51 per share.

The operating cash flow was at a good level, however, decreased to EUR 656 million. And on the balance sheet, our leverage, defined as financial net debt to comparable EBITDA, was at 0.9x at the end of June.

Tiina will go into more details on the results analysis in her part. Next, a few words about the market environment, especially hydro conditions.

The picture on the left-hand side shows the hydro reservoir status for the whole Nordic market area, not only Fortum's reservoirs. As we communicated earlier this year, reservoirs were record full during the winter, meaning in the first quarter.

However, the water was mainly in Norway and Northern parts of Sweden, where Fortum does not have hydro power. As the winter was mild and the snowpack was thin, this resulted in very minor spring floods.

Because of this, the reservoir levels decreased fast in the spring. And as you can see, now the reservoirs are close to normal level.

As we have said, generation volumes will be clearly lower this year. There has been quite a lot of unplanned maintenance in our nuclear fleet.

Based on announced unplanned outages, we now estimate approximately 2.9 terawatt hours lower nuclear volumes for the full year 2025. We also mentioned the risk of lower hydro volumes for the full year.

Unfortunately, this seems to be the case. You can see that for the last 12 months, hydro volumes have been 18.3 terawatt hours.

Our normal year hydro output is somewhere between 20 and 20.5 terawatt hours. It is not possible to give any estimate for the full year as hydro conditions might change, but the assumption is that our annual hydro volume will be below that of a normal hydro year.

Just to highlight how hydro volumes can fluctuate, our lowest hydro output year was with 18.1 terawatt hours in 2013, and the highest output here was 25.2 terawatt hours in 2012. On a positive note, again, the continued high volatility in the Nordic spot price supports our capability to generate a premium through optimization.

In June, the Nordic Transmission System Operators, or TSOs, updated their projections for power demand in the Nordics. According to the update, power demand is expected to grow to 550 terawatt hours per annum by 2030.

The estimate decreased slightly from earlier and shows a postponement in expected demand for hydrogen production, but at the same time, it shows increased demand by 2030 from data centers and other sectors. At Fortum, we continue to see robust underlying customer demand from our customers in various industrial sectors, which we believe reflects power demand growth longer term.

Despite this, we have not signed any significant new long-term power purchase agreements recently. Our customers continue to focus more on short and midterm contracts over the next 3 to 5 years.

This concludes my part, and I would now like to hand over to Tiina to tell more about the business performance.

Thank you, Markus. Good morning, everyone, also on my behalf.

I will now go through our financials in more detail. Let's start with the key financials.

I will start with some of the comparable KPIs. The comparable operating profit for the second quarter amounted to EUR 115 million.

In the second quarter, both comparable net profit and comparable EPS decreased. This is reflecting the lower result in the Generation segment.

At the same time, we are very satisfied that our Consumer Solutions business generated a record high second quarter result. Our comparable net profit for the quarter declined to EUR 87 million.

Consequently, our comparable EPS for the second quarter declined to EUR 0.09 compared to EUR 0.20 last year. Comparable EPS for the last 12 months is now at EUR 0.83.

Our cash flow during the quarter declined by EUR 135 million and totaled EUR 203 million for the second quarter. Our cash flow was strong, while leverage increased due to the dividend payment in the second quarter.

Let's move over to the income statement to look at certain items in more detail. In the income statement, it's pretty straightforward, starting with our efficiency improvement program.

In 2024, our fixed cost showed a small decrease, and that trend have now continued in the first half of the 2025. In the second quarter, fixed costs were EUR 209 million.

We have earlier communicated that the 2026 fixed cost base will be EUR 850 million. This excludes the increase of EUR 30 million in the Swedish property tax.

It is good to keep in mind that we have actions in place to develop our business and prepare for future growth, which increases our development cost, and this means that the fixed cost will still increase during this year. When looking at the associated company result and financial items, there were some one-off type items mainly related to the nuclear cost updates and adjustments, which we have reported in detail in our notes in the report.

The comparable effective income tax rate was within the guided range at 19.2% in the first half year. Then over to the segment result for comparable operating profit.

Compared to the previous year, the result in our Generation segment decreased, while both Consumer Solutions and Other Operations segment improved. In the Generation segment, comparable operating profit decreased by EUR 143 million to EUR 121 million, mainly due to the lower hydro and nuclear volumes, lower hedged power prices and somewhat higher property taxes in the nuclear and hydro in Sweden.

In the comparison period, the result of the renewable business was positively impacted by a sales gain of EUR 16 million from the divestment of Fortum remaining share in the Indian solar power portfolio. The result contribution of the Pjelax wind farm was slightly negative.

The result of the district heating business decreased, mainly due to the lower sales price for power in Poland. The second quarter shows good performance in our Consumer Solutions business.

The comparable operating profit reached an all-time high second quarter level of EUR 26 million. This is an increase of EUR 14 million, which mainly relates to improved gas margin in the enterprise customers business in Poland, improved electricity margins in the Nordics and approximately EUR 5 million of cost synergies from the completed brand mergers, including Telge Energi.

We are especially satisfied that we now see the impact of cost synergies from the brand mergers from the bolt-on acquisitions that we have done. The total estimated cost synergies for this year are EUR 13 million.

In the Other Operations segment, comparable operating profit improved by EUR 11 million, showing a negative result of EUR 32 million. The main reason for the improvement was the divestment finalized in 2024 in the Circular Solutions business.

Next, I would like to highlight a few things about our value creation in our Generation fleet. Let's look at the composition of our achieved power price.

Please note that this is an illustrative picture. When breaking down our achieved power price for outright portfolio in our Generation business in a smaller components, we basically have 3 elements.

The first pillar is our area-weighted realized market price, or what we refer to as our blended price. The price area mix in our Generation fleet is 46% in Finland, 37% in Sweden Price Area 3 and 17% in Price Area 2.

This can vary depending on the market conditions and availabilities. For the second quarter, the blended market price was EUR 26.4 per megawatt hour compared to EUR 34.3 in the second quarter last year.

The second element in the optimization premium, which you add on top of the market price. It is important to note that the optimization premium applies to 100% of total volume of our generation, irrespective of the hedge ratio.

Another point, which is good to note is that the optimization premium is for the physical generation, while hedges are financial. In 2024, the premium was EUR 8.7 per megawatt hour.

And for this year, we have guided it to be in the range of EUR 7 to EUR 9 per megawatt hour. And the third component is the hedge effect.

As said, hedging is financial hedging. So hedges are settled with money, not with physical delivery.

Open hedge positions are not bought or delivered physically. If needed, we always have an opportunity to open new or close existing position.

As we closely monitor and manage our hedge position, the risk of big financial losses is rather theoretical, also in the situations with the high hedge ratios. As we disclosed in the interim report, the hedge ratio in the second quarter was high because of the low hydro and nuclear generation volumes.

At the end of the Q1, we reported a hedge ratio of 75% at EUR 40 per megawatt hour for the rest of the year. This indicates that the hedge price in Q2 was clearly higher than the blended market price of EUR 26.4 per megawatt hour.

Consequently, the hedge effect was positive for the quarter. Then let's have a closer look at how we create value in hedging and optimization premium on top of the market prices.

This picture shows how much we have created value above market price. The credit value includes both optimization premium and effect from hedging.

In the first quarter of 2024, the market price was EUR 63 per megawatt hour. In that quarter, we generated only 1 year additional value.

Then again, when you look at the last 5 years, the average market price was EUR 33 per megawatt hour, and we generated an additional EUR 18 per megawatt hour on average. Similarly, the value creation in the third quarter of 2024 was EUR 24 per megawatt hour.

In the second quarter of 2025, it was EUR 22 per megawatt hour. This is good to keep in mind when looking at achieved power prices going forward.

This confirms both that the value creation happens, especially with the low market prices, and it also shows that a higher hedge ratio is not necessarily a negative thing. Then let's move on the cumulative result waterfall for the segments.

When looking at the waterfall for the comparable operating profit of our segments in the first half year, it shows the same pattern for our second quarter. Compared to the previous year, the result in our Generation segment decreased, while both Consumer Solutions and Other Operations segment improved.

In the Generation segment, comparable operating profit decreased clearly by EUR 221 million to EUR 556 million, impacted mainly by lower hydro and nuclear volumes, lower spot and hedge power prices and somewhat higher property taxes in nuclear and hydro in Sweden. The negative effect from the price and volume components was partly offset by high hedge ratios in the second quarter and good physical optimization.

The result contribution of the Pjelax wind farm was positive, but lower than in the comparison period due to the lower power prices. In the comparison period, the result of the renewable business was positively impacted by a sale gain of EUR 16 million from the divestment of Fortum's remaining share in the India solar power portfolio.

The result of the district heating business improved mainly due to the lower fuel and CO2 cost as well as higher heat price and volume, partly offset by lower sales price for power. The cumulative result for our Consumer Solutions business comparable operating profit increased by EUR 19 million and was EUR 73 million for the first half of this year.

The main reason for the improvement are improved gas margin in the enterprise customer business in Poland and approximately EUR 11 million cost synergies from the completed plant mergers, including Telge Energi. In the Other Operations segment, comparable operating profit improved by EUR 16 million and amounted to minus EUR 52 million, mainly due to the divestment finalized in 2024 in the Circular Solution business.

Then over to the leverage and liquidity. Our financing position continues to be strong, primarily supporting our objective to maintain a credit rating of at least BBB.

It naturally also provides a good financial foundation in this uncertain and turbulent market environment. When considering our capital allocation principles, we balance between leverage, investments and dividends while always keeping the credit rating in mind.

In June 2025, Fitch upgraded its long-term credit rating from the previous rating of BBB with stable outlook. Fortum's current long- term credit rating by both S&P Global Ratings and Fitch Ratings is now BBB+ with stable outlook.

I want to go through the reconciliation of our financial net debt in the second quarter. At the end of the first quarter, our financial net debt was EUR 13 million.

In the second quarter, the operating cash flow was EUR 203 million, and investment amounted to EUR 162 million. As mentioned several times already, the dividend of EUR 1,256 million was paid in the second quarter.

The change in interest-bearing receivables amounted to EUR 8 million, while FX and other effects were EUR 35 million. So at the end of the second quarter, our financial net debt was EUR 1,270 million, and the leverage ratio for financial net debt to comparable EBITDA was at 0.9x.

Looking at our debt portfolio and the loan maturity profile, I want to highlight a few things. At the end of the quarter, our gross debt excluding leases totaled to EUR 4.6 billion.

Bonds are and continue to be our primary source of funding. Our maturity profile is very balanced, and there are no large maturities any single year, and the next maturing bond is EUR 750 million in 2026.

At the same time, our liquidity position is strong. We have ample liquidity reserves, EUR 7.1 billion, with EUR 3.2 billion of liquid funds and EUR 3.9 billion of undrawn committed credit facilities and overdrafts.

The cost of our EUR 4.6 billion loan portfolio was 3.3%, while the interest income that we get for our EUR 3.2 billion liquid funds has come further down and is now 2.2%. With the strong liquidity position, we will continue to optimize our cash and credit lines.

The overall objective is to have sufficient liquidity, while optimizing the balance between debt and cash to minimize funding costs. Then over to the final sections, the outlook.

The outlook section comprises 4 familiar elements: guidance for outside portfolio; taxes, CapEx guidance; and our fixed cost reduction program. First, a reminder that while our normal annual outright volume is approximately 47 terawatt hours, because of announced unavailabilities in nuclear and lower expected hydro output, we will fall clearly behind the normal historical output level this year.

Based on announced outages, nuclear output for 2025 is now estimated to be 2.9 terawatt hours lower this year, of which 1.3 terawatt hours realized in the first half of 2025. Of the effect expected in the second half of the year, the majority is estimated to materialize in the third quarter.

And just note that our last 12-month hydro output is 18.3 terawatt hours compared to the normal level of 20 to 20.5 terawatt hours. About the hedges.

At the end of the second quarter, the hedge price for the rest of 2025 was EUR 41 and hedge ratio was 80%. The hedge price for 2026 is EUR 40, EUR 1 lower compared to the last time disclosed, while the hedge ratio increased by 10 percentage points to 60%.

Our annual optimization premium for this year is estimated to be between EUR 7 to EUR 9 per megawatt hour. Good to note, however, that they usually are quarterly variation, as you know from the past.

The guidance for our corporate tax rate also remains unchanged for the years 2025 and 2026. We expect the comparable effective income tax rate to be in the range of 18% to 20%.

The Finnish government plans to decrease the corporate tax from 20% to 18% from the beginning of 2027. There is, however, no official law in place yet.

Our very preliminary estimate is that this would result in a 1 percentage point decrease in the corporate tax rate from the year 2027 onwards. I also want to repeat that the Swedish property taxes are revised from 2025.

For Fortum, the increase of the property taxes is now estimated to be approximately EUR 30 million for the years 2025 to 2030. A major part of this cost increase will be recorded in our fixed costs.

Our capital expenditure remains unchanged. Capital expenditure for the years 2025 to 2027 is expected to be EUR 1.4 billion.

This includes maintenance, but excludes potential acquisitions. Finally, a few words on our fixed cost reduction program.

As you saw, our first quarter 2025 fixed costs were EUR 200 million, and second quarter 2025 fixed costs were EUR 209 million. We aim to reduce our recurring annual fixed cost base by EUR 100 million, excluding inflation, gradually until the end of 2025 with a new run rate from the beginning of 2026.

Our current estimate is that the new run rate for our fixed cost base in 2026 will be approximately EUR 850 million, excluding the increase in Swedish property tax. As mentioned before, there are additional cost for growth in 2025.

These are related to, for example, renewables development, site development, buildup of the commercial organization and the hydrogen pilot project. This was all for my presentation, and we are now happy to answer your questions.

So with this, Ingela, over to you.

Thank you, both, Tiina and Markus, and I hope that we have been able to provide some more clarity on the quarterly results. We're now ready to take your questions, so let's begin the Q&A session.

And you are also able to ask questions in Finnish if you so wish. Moderator, please go ahead.

And 2 questions for me, please. And particularly, can you just try to help me pin down full year volumes for hydro and nuclear?

So if you look at nuclear, I think if I remember correctly, you usually do about 26 terawatt hours a year. So when you say 2.9 lower for the year, should we be thinking of about 23 terawatt hours for the full year for nuclear?

And then on hydro, it's noted that it's very hard for you to forecast the full year. I think you were 2 terawatt hours lower from the last 12 months, say, than usual range of 20 to 20.5 terawatt hours.

So would 18 terawatt hours be a reasonable estimate if you have P50 volumes, given the outlook for the rest of the year? That's the first one.

Second one is actually on Russia. I think we've got a bit immune to Russia and Ukraine and so on.

But obviously, you got the Alaska summit imminently. Where are we with the legal claims on the Russian business?

And do you think there could be any sort of improvement on the outlook there if we get a good result from the Alaska summit?

Okay. Thank you.

Maybe I'll start with Russia and comment on the hydro reservoirs. And if you, Tiina, take the nuclear volume question.

So no major news on the legal front with regards to the Russia claims. We have the arbitration against the Russian Federation concerning our equity ownership.

And then we have the legal process against our own company with regards to the unpaid loans. So we are proceeding with both of those.

Then if we could, we would sell the business also. Basically, we're looking forward to -- that there would be some relaxation of currency control being able to -- for the company to transmit money to us, so they could pay the loans.

We could recover that and the ownership and potentially sell it. We'll proceed with all of these fronts.

The thing we have said earlier is also that if we get control of the business, we will not continue our business in Russia. So then we will exit it one way or the other.

Then for the volumes, Tiina can talk more about the exact details, but what I'm focused on myself is, of course, that there has to be availability. This kind of level of unavailability is not what we are targeting, that you can tell from our strategic targets.

That goes for the nuclear. And then for the hydro, like I said in my part, if you look carefully at the hydro reservoir level, reservoirs were very high in the beginning of the year, putting pressure on the prices.

Now we are practically at the neutral level. So then the rest of the year can go any direction.

So maybe the -- like if you compare to historical outcomes, the distribution is now neutral both ways. And Tiina, on the nuclear?

Yes. Thank you very much.

So maybe first of all, it's very important to underline that this has been very exceptional quarter. So the volumes in hydro, so they were lowest ever.

And also in nuclear, unfortunately, we had many, many, many outages. So naturally, what we also indicated, that will have an impact for the yearly level for this year.

I'm not saying going to the future, but this year will be impacted. So nuclear volume, so the average usually is around 26 terawatt hours.

And what we have said that current based on the UMMs, what we have in the market, so the reduction is 2.9 terawatt hours, where the 1.3 terawatt hours already has happened. And then the 1.6 terawatt hours mostly will impact the third quarter.

So there will be some reduction as indicated. What comes in the hydro volumes?

So the record low second quarter. So based on our current estimates, so it's very difficult to catch up fully that decrease during the year.

So our normal 2025, difficult to reach because of the lower volumes. But of course, we know hydrology can change, as Markus indicated.

So we need to live with that.

20 to 20.5.

20 to 20.5, yes.

Okay. But it sounds like you lost a couple of terawatt hours in the first half, and normal second half would be sort of, I don't know, say, 10 terawatt hours-ish.

So okay, I'll go with sort of 18 -- maybe 18, 19 in my head. I mean, shout if you think that's -- if that's wide at the mark.

One thing I will note here, of course, one has to estimate what do you think for the rest of the year. Hydrology is difficult to forecast.

But the unavailabilities and the record low numbers, these are exceptional and temporary from our point of view. So nothing is indicating that we would not have a normal year, of course, making normal logical assumptions next year.

Yes. Clearly got it.

And so, yes, no impact in '26.

This is Wanda Serwinowska from UBS. Two questions from me.

The first one is on the data center tax in Finland. When do you expect a decision or a clarification on that one?

I must say, Markus, I missed your remarks at the beginning. And if it's implemented, what do you expect as an impact on the data center growth in Finland?

Because you also develop site. Is it a topic that comes out in your discussion on the PPA or the site?

So that's question number #2-- 1. Question #2 is on your onshore wind EBIT.

I was a bit surprised that it was negative in Q2. So can you please explain why is that?

And can you please remind us what the support price do you have? What is the mechanism that you have in place for this onshore wind farm?

And maybe just a very quick follow-up on Harry's question. I do understand hydro is difficult to model.

But what have you seen in July and August so far on the volume generation?

Very good. Maybe I'll leave the onshore wind and the hydro question for Tiina, and I'll comment on the data center tax.

So the proposal from the Minister of Finance came as a normal part of her work to say that where could tax revenues be collected. And as far as we understand now, that is going through the -- like on full government review on all the proposals that are on the table.

The government also set up a working group headed by Veli-Matti Mattila, who used to head Elisa Corporation for a very long time just to assess what are the benefits and impacts of data center economy for Finland. I would say that the tax is more of a detail in the big picture.

So having any kind of uncertainty is not a positive. But if you look at what are the data center operators looking for when we talk with them very tightly is that they need sites, they need grid, they need infrastructure, good competencies and clean energy.

So this is a little detail. If you look at the total cost of investing in a data center, electricity and the tax is a small fraction.

But is it a positive thing? No.

So that's a detail that, of course, also the data center hyperscalers are asking from us that what's going to come out of this. But really, the major thing is that we can provide -- when we do the site development, we can provide ready sites.

We can provide grid access right away, all the way up to 1.3 gigawatts. We can provide large amounts of existing power and new power.

So these are the big ticket items and then the taxes detail. We would wish that there would be certainty and that there would not be tax changes.

And this we communicated also in the report. And Tiina?

Yes. Then going back to the onshore wind.

So they're our major power plant, the Pjelax. So in the second quarter, the result was slightly negative, but it is good to underline that, cumulatively, it's still positive.

I think the second quarter, the low spot prices impacted the results. So majority of the project is hedged with the PPA.

But nonhedge part, so the price was lower. And what we have learned that during -- when it's very, very windy, so also the capture rate, so what is the average spot price, so the wind even gets the lower price.

So this was the lower price impact of the nonhedge part, which make the result negative. Then I think there was a question about the -- what we have seen in July and August with the hydro reservoirs and the hydro situation.

So the reservoir levels, they were close to normal at the end of second quarter. So 5 terawatt hours above the normal in the Nordic level in August, so they decreased to 2 terawatt hours.

So I would say fairly normal kind of profile and the situation so far from the end of second quarter.

If I just may follow up, because I still don't understand how onshore wind farm can be negative if you secured part of -- majority of your output with PPA. And only the merchant, I mean, capture rate, it's low, but it's -- will be still above EUR 1 -- I mean, EUR 0 per megawatt hour.

How can this asset is EBIT negative?

I think the capture rate, I think, in June was even below 50%. So it was extreme.

So maybe there was a lot of wind in June, which makes the prices for wind even lower.

Then we get to the O&M cost and so on. So indeed, very low capture rates and very low prices for those capture rates.

I had two questions. So I think on the spot prices in second quarter, obviously, hydro was lower, but also you have so many outages.

Despite that, why was the spot price so weak? Even if I look regionally within Finland because in the past, whenever you had low volumes, usually, spot prices are higher, and they offer a hedge.

So could you point out towards anything unusual? You mentioned wind, but was demand also particularly weak?

And how do we square the circle with low volumes and low prices? And second question is the -- in Fingrid's kind of first half reporting, they -- they have talked about almost 35 gigawatts of data centers having applied for grid connections in Finland.

In your view, how realistic -- what proportion of this realistically could translate into real data centers? And when do you see the power demand of these kind of coming in from your experience?

Yes. Maybe I'll take the Fingrid point on the data centers.

And you can, Tiina, take the spot price realization. So the way we triangulate the information is that we look at the TSOs, Fingrid, SvK, Statnett information, and their revised forecast is saying 400 terawatt hours up to 550.

So from that, we can back calculate that there will not be 35 gigawatts of data centers, obviously, so that they're referring then to a gross amount of what are the applications they get. And with regards to their methodology, so when they get this gross number, then they do a haircut -- actually, a massive haircut on what they then put in their forecast.

But the gross amount is based on the connection inquiries they are getting. So then we look at the TSO forecast and we look at our own customer pipelines or customer by customer, when they indicating that they would make investment decisions and when would these investments start to consume energy.

So that resonates well. I'm not saying it's exactly the same as their 550, but that resonates well with what we see from the different customer segments.

Then for the data -- coming back to the data center. So when we are talking with the data centers, what they need, like I said before, is sites, so land availability, grids and clean power.

And the beauty with Fortum, with Finland and with the Nordics is that we have been developing and permitting sites that actually you can locate right away. And there is grid connection all the way up to 1.3 gigawatts.

And we have, if you go, let's say, 5 years forward, we have a largely unhedged portfolio. So we can sell massive amounts of energy to the data centers.

So we are very attractive from that point of view. But then it's normal sales work, which we are doing.

But I'm positive of the -- very positive of the characteristics of Finland and the Nordics as a place to locate data centers. We have the cleanest and cheapest energy in Europe, land availability and grid availability.

So really a fantastic platform. And Tiina?

Yes. Then going to the spot price in second quarter.

So if we look at the spot price in our areas, so the blended spot price was EUR 26.4 per megawatt hour. And if we look at the different areas, so the price really varies.

It varies from EUR 10 to over EUR 30 per megawatt hour. The lowest prices were in Sweden Price Area 2.

So they were EUR 10.5 per megawatt hour, so really low. And that reflects the -- still the hydro situation.

So the reservoirs were very high. They decreased during the quarter, but very, very high.

And then of course, the wind. Whereas the Sweden Price Area 3, the price was EUR 31.6, and that's quite a bit higher than compared to the Northern part.

And I think there, the Oskarshamn 3 outage will show the tightness in this price area. And Finland, EUR 28, so lower to the Price Area 3.

So outages and then the hydro and wind situation and also, of course, summer, summer when usually the -- it is a bit warmer.

I have to come back to -- I didn't comment on the point that when would the demand come. So this, of course, are long projects, and we started the site development in the capital region for the sites that then became Microsoft sites in Espoo, Kirkkonummi and Vihti.

It's been -- from initiation of our work all the way up to the data centers starting to operate, it's many years. So now Microsoft has done the groundbreaking on these sites.

So we are expecting that we will then get -- this will start operating in 2027. And then we will start to get the -- also the heat -- excess heat from these plants.

Our own electric boilers, air to water heat pumps, water to water heat pumps, this will be operational already for the next heating season. So we are ready then to connect these plants to our district heating system, and then the data center excess heat will come later on.

But as we see now, like recent announcements of new data center in Lahti, so it will be several years before that would be up and running. Google announced massive land acquisitions, a few thousand hectares in Kajaani and Muhos.

Also several years lead time to then get to production. But the potential, like you referred to, it's very big.

Okay. So is 5 years a reasonable expectation, in general, from your -- obviously, there's a lot of urgency for the technology companies to get ahead on the AI game.

But is 5 years a reasonable assumption or longer or shorter?

Yes. That very much depends on the land and grid availability.

And again, the strength that we have is that we can cut the lead time from the site development and grid access. So it is years, in any case.

It could be longer than 5 years if you start from scratch, but our point is exactly to speed that up and make it only a few years.

It's Ajay Patel here from Goldman Sachs. Just a couple of questions, please.

Firstly, I just want to go back to Slide 6, where you talk about -- talked to power demand and potential for strong growth, as you highlighted the TSO report. Could you talk to the scale of grid investment that is going to be needed to cater to that demand?

And to what degree that could be a bottleneck? And then the second question I had was around the renewable pipeline that you're developing.

I think you mentioned 8 gigawatts. Under what type of time frame could you start to see fruit from this pipeline and, therefore, CapEx attached to it?

Okay. So I can take the TSO part, if you want to talk to the renewable pipeline.

So the way -- when we discuss with Fingrid, how they plan their grid expansion is that they take this -- the gross number, which is much, much bigger than what you see actually on the Page 6. So it's multiple times bigger.

But when they are planning their grid investments, they take this whole gross pipeline, attach certain probabilities and then make their own investment plans. If you were just -- without any planning, you would start to look at where is land available without consideration for the grid, then I would say, yes, grids would be a serious bottleneck.

In our case, when we develop sites, we actually listen to our customers, be it steel, chemicals, data centers, battery factories, look at what type of sites they need, is it grid infrastructure, fiber, ports, railroads and so on, and go to places where grid is already available or the connection line that you have to build for distribution of transmission scale that these are something that you can manage very quickly. So for this 550 expansion in a Finnish case, I don't see that it would have been highlighted that grids as such would be the bottleneck.

As long as the customers kind of -- we can identify which customers are going forward, Fingrid can then mirror that with the grid investment. So it has not come as a bottleneck up to me.

Yes. And about our renewable pipeline of 8 gigawatts, so as indicated, so this includes many projects which are in different phases.

So of course, not all the project will end up to the build or even to the ready-to-build phase. I think it is very important that from this portfolio, we can really pick and concentrate the most competitive sites and also reflecting where the customers are having their operations.

One of our internal target is that by end of 2026, we would have 800 megawatts of ready-to-build renewable project. So that, in a way, indicates that, that's the amount and the possibility, assuming that there is a customer demand would start to build up.

But of course, this is based on how also demand and the PPA pipeline is going along.

So firstly, I would start with some more operational and this year's related topics. So firstly, when it comes to district heating business within Generation, so you mentioned that earnings were down year-over-year.

And I think last year, we have seen quite substantial improvement on this front. So what is the outlook for full year when it comes to district heating?

And of course, I do acknowledge that [ Vaasan ] is playing a role on how Q4 will pan out there. Then secondly, on Consumer Solutions, so you made record Q2, and the H1 has been quite strong for this business.

LTM EBITDA is at EUR 96 million. What is, in your view nowadays, this type of normal earnings potential for this segment?

And the last question is just continuing on power demand outlook topic and, indeed, EBITDA estimates from peers also, basically high single-digit demand growth by the end of this decade. But could you maybe talk about the outlook for next, let's say, 3 years?

Because in this case, we -- the projects which would contribute to power consumption should be basically ongoing and so on. So how is the picture looks like for next 2 to 3 years?

Should we anticipate this type of, let's say, mid-single-digit growth in terms of our consumption in Nordics?

Thank you. Maybe I'll take the 2 latter questions, the cost and demand growth.

And if you want to comment on the district heating. So on Consumer Solutions, indeed, the business and division have done very good work, both getting internal synergies, improving processes, combining brands, taking out cost, unifying our customer systems and then getting synergies from the acquisitions that we have done.

That is now reflective in the results. We have earlier said that the business would do, under normal circumstances, EUR 80 million to EUR 100 million result.

Now of course, the numbers are pointing to the higher end of that scale. Second and third quarter typically are the lower quarters.

So that applies, of course, for the outlook as well. Now we don't give exact guidance, but things are looking positive, and the business is doing very well at the moment.

Then for the demand growth outlook, so indeed, a little bit reflecting also on the previous questions and the TSO forecasts. So like I said, we look at all of our incoming customer inquiries, try to calibrate that, okay, when are they -- when do we assume that they will make investment decisions and when will the energy consumption come.

And if you think of -- let's say, take a practical example of Microsoft. So 3 sites with a sizable consumption.

It's going to start in the middle of this period, '25, '30. So this will be back-end loaded.

And if investments are announced today, typical lead times are 2 to 3 years. So we're talking about '27, '28, '29 when the demand is picking up.

But the pipeline is so big that, that also gives us the comfort to make the investments into the optionality of growth. So this is why we are -- why we bought the ABO Energy wind and solar pipeline, why we bought Enersense.

We built the optionality, so that when customers are making their tenders for new energy, then we can respond to that. So this, we have calibrated very carefully.

Tiina referred to the question on the 8-gigawatt pipeline. So when do we make investments?

And when does the cash flow start going out? So we try to match exactly, so that we have ready-to-build projects.

Let's say, for argument's sake, if we would have a 300- megawatt project, roughly EUR 300 million spend. So that is for wind distributed over 2.5 years.

For solar, it would be -- the CapEx would be lower than that and distributed over about 1.5 years. So that ties together, the customer demand, a little bit loaded to the back part of the '25, '30 period and then matching that with new supply.

And Tiina?

Then about the district heating business, so second quarter was a bit weaker one, and that was mostly because that the power prices in Poland were also fairly, fairly soft. But if we look at the cumulative basis, so the trend, what we started last year is continuing.

So better, better results. And the one big driver is the lower fuel and CO2 prices.

And also the heat price and the volume being better this year. We do not give any guidance for the full year, but maybe you could remember that the second and third quarter in the heating business is not the big quarters.

But then the last quarter, usually when the winter starts, so of course, then our products and services are needed.

I had a couple of questions. The first is on nuclear.

You mentioned that you had many outages in the second quarter and obviously expecting quite a few in the third quarter. Can you give us any more details in terms of what's causing this?

Is this just some -- just kind of random issues? Or is there anything that's more common across the plants?

I think you've had securities at Oskarshamn 3. So maybe you could give us some more details as to what's been happening there.

And do you expect any of these problems to kind of drag into 2026 or you're expecting all to be resolved in the second half of this year? That's the first question.

I guess, it's a 2-parter. And then my other question was on demand growth.

The forward curve for the Nordics goes out quite far to 2031. Not sure how liquid it is out that far, but it's basically flat.

Whereas if you get anywhere near the demand growth that's forecasted by TSOs, I would imagine the power price to go up quite meaningfully. So I was wondering whether you could maybe help us rationalize what you think the power market is thinking.

I know you don't like to talk too much about power prices, but is the kind of power market sentiment just very skeptical that the demand growth will come through, and that's why power prices are not going up in the forward curve? Or is it something else?

Thanks for the questions. Maybe I'll take the first one, and if you want to, Tiina, add something.

What a very good question about the forward market. So we -- as a backdrop, we are doing now big majority of our hedging bilaterally with customers.

So when we think about, okay, what is really our view on the price, it is the hedge pricing that we actually communicate that reflects the short-term pricing. Then the liquidity on the exchange is so thin that, okay, you can trade some megawatts or maybe some tens of megawatts.

But if you want to do bigger PPAs, then it has to be done bilaterally. And we would have appetite to do longer PPAs, 5 years even further.

But then we do start -- we think that there will be demand growth, and there will be scarcity of supply unless there's new supply coming. So our price indications are upward sloping.

And that's why we see also that very little is done in the long end of the curve, say, between 5 and 10 years. So the sweet spot where we -- where our minds meet with the customers is somewhere around the 3 to 5 years.

So we do think that there will be more demand, and new supply will not come online with today's prices. That is also clear from our point of view.

That's the fundamental. If you want new additional energy, it will command a higher cost than where the forwards are today.

Then for the nuclear unavailability, so I would emphasize that these are temporary. So there is no trend, there is no pattern.

The unavailabilities, of course, are not something we accept. So we will work to make sure that these don't repeat themselves.

But these are one-off cases, which are not -- it's not a pattern. If I take Oskarshamn 3 long outage, quite a simple problem, actually, wherein a -- wearing in a pipe connection.

The thing with the nuclear plant is that when something unexpected, unplanned happens, then you need to certify the working methods. You need to certify first the equipment and the way of working, do the fixing and then get the radiation authorities to check that.

So in another type of power plant, this would not take so long. But the problem was something that should not have happened under normal conditions, but there was a pipe defect that had developed faster than we had anticipated.

We have hundreds and thousands of these kind of points. So this was unusual.

And like I said earlier, we do not -- this do repeat itself. So when we get to 2026, by and large, it should be a normal nuclear year.

Are there -- is there anything now heading out to 2026 unusual?

Well, I think that based on the UMM, so there are some normal -- a bit longer outages. So like in Loviisa, so one of the unit will have a bit longer outage, but that's normal pattern.

Also Oskarshamn 3 is -- they have a UMM that they have a bit longer outage. But nothing extraordinary, more kind of the normal cycle of the maintenance.

I would like to go maybe into the auction and the new capacity -- new flexible capacity mechanism that is currently under discussion in Finland. Apparently, there is 800 megawatts that could eventually come.

There is some discussion on this topic. We see that it could be indeed needed.

I would like to know, in your current portfolio and the future development, what kind of a project and where do you see you could eventually benefit from this potential development going forward? And if you could provide also a bit more details the actual framework that could be put in place for this flexible capacity mechanism in the country.

Maybe my second question would be more regarding potential evolution of your thinking regarding the market. Until the past few years, we've seen a lot of disposals, and you have refocused into your regions.

You have also put in place a reduction program plan in terms of efficiency measures, et cetera, that is coming to an end in 2025. Now we see some development, notably in Poland, in the customer business.

We see also new development into the pipeline, acquiring a pipeline into the renewables over the past few months. And you are coming to an end for the efficiency program.

Do you think that starting next year, you will be -- maybe able to be a bit more growth oriented into your investment and into your potential development because you consider that the future demand growth is now starting to be definitely visible and you are now clear to start accelerating into this development going forward?

Okay. Thank you.

Good questions. So first of all, we think that the non-fossil flexibility reserve is something that the market will need.

So with the increased amount of renewables and intermittency from a market adequacy point of view, something in this scale is needed. So we support the idea.

The terms and conditions are not finalized and not known yet. We are preparing various alternatives, but the features are such that we assume that it will have to be something that can be ramped up quickly and that also has duration.

So these are the kind of features that we are using for planning. Our target is that we can participate in an eventual auction.

We're developing for that, but we cannot yet really say that, okay, what exactly would it be. But we are working on different alternatives, both for new investments, also potentially looking at can we then modify something to work for that.

But the idea is good. Then for the market development, we will continue the cost focus.

So we are targeting the EUR 100 million cost reduction on a comparable basis, run rate reached this -- end of this year, and that's going really well. But we will continue our cost scrutiny.

But that goes hand-in-hand with the possibility then for the future to be able to supply new capacity for our customers if and when they need it. It will be PPA backed, but we provide the optionality.

So that part of our development cost is going there today. Then as you correctly highlighted, we have been active on the M&A front in Consumer Solutions, in the wind and solar development.

Areas that we are interested in are electrified heating, heating and cooling. So Consumer Solutions, the heating business, the whole transition to electricity and renewables.

So operating renewable assets also are a possibility on the M&A front. Typically, they are high priced, so that's why we see few transactions happening there.

But indeed, we are looking for growth regardless of what is happening with the underlying market growth.

I have two questions. The first question would be on this PPA with data center customers and your expectations for the future to evolve.

So when you strike these PPAs and when you have a demand, I mean, how much of a premium you actually see on this 3- to 5-year view versus the market? Like when the Google or Microsoft, whatever other hyperscalers comes to you and wants to enter in a deal like this, what kind of magnitude of a premium you could get?

And should we expect that volumes to pick up? Because, previously, I remember you tried to hedge your portfolio on the long-term basis, and it wasn't that successful in terms of volume.

And second question I have from the supply side impact on the pricing. So what is the levelized cost of energy you see for your 8- gigawatt wind pipeline development in Nordics?

And is my understanding correct that basically that is price equilibrium in the longer -- in the long term for Finland and for the region? Because you have indefinite, it's not just you having a large pipeline, but there could be plenty of supply mobilized on the 3-year forward basis that could come.

And I wanted to ask you, like, what is the price you would really be happy with on this development?

Okay. So on the data center demand, so I think what we have observed is that when the hyperscalers have entered into PPAs, they are to fulfill their own clean or additionality requirements.

And then there's not necessarily even matching in the price area. So it may be that a hyperscaler buys a PPA from Europe somewhere and says that we generated additional supply.

For the data centers, as I referred earlier today, that majority of the investment is into the infrastructure and chips, and very small part goes into the energy. So if we look at the U.S.

there, why PPAs are being done is to support the availability of power. Availability is not the bottleneck here.

So when demand comes, the data centers seem to be still quite okay with -- they're ready to take the risk of being open for quite long. Then to the actual point about the premium.

So when we talk -- when we look at the forward curve and what kind of premiums have we had in PPAs or PPA indications, depending on what profile, what characteristic additionality, RFNBO character or so on you want. Then it's from low single-digit to high single-digit euros on top of the implied forward price.

So it depends very much on what the customer wants. And I come back to my earlier comment that the forward curve is indicative of some megawatts being traded.

And if we talk about 100, 200 megawatts, then it's a very tailor-made price. So it depends on what we can do.

And that gets me to the second point of the LCOE of wind and solar. Nordics are very competitive.

So we have done projects where LCOEs are lower -- way lower than today's market, so competitive. Now equipment prices are higher, rates are higher and so on.

So LCOEs also have come up. But we see not very much demand for pay-as-produced wind and solar.

So when referring to what price would be needed to create hybrid products with renewables and flexibility and storage, then we talk about significantly higher price than what we see today, even with the very competitive LCOE for wind and solar. But on a European scale, the Nordic and Finnish good projects are in -- the very best that you can find in Europe from an LCOE point of view.

Most now answered, but maybe one clarification was to your answer on a previous question on discussions on PPAs. I mean, you say in the report you're having lots in that kind of sweet spot of 2 to 5 years.

When you look beyond that, is it a case that there isn't demand? Or is it that you -- there is a disconnect in your pricing and what you will achieve or want to achieve, I guess?

So the first question. And then the second one, looking at your Slide 11 and the positive hedge effect that you've been reporting.

Is this because -- simply because you've had historically higher prices at which to hedge, and so this should normalize going forward and should be around 0? Or is it more structural than that?

And maybe you can clarify why it's so much higher in summer months. That would be useful, please.

If you, Tiina, take the hedge effect, but that's relating to the first question also. So we -- you could categorize that we have 2 type of customers.

So ones who have -- basically have a rolling order book where you reprice your product every 3 months or 6 months or annually, like a lot of the heavy industries today, steel and chemicals and pulp and paper in the Nordics. So order books are not very long, and price resets.

So then even if you would have a long-term view that something is a good price to fix, you typically don't because you create the basis risk. So this is something that for many industries, it's just not feasible for them.

It doesn't make sense to do long-term contracts because they need to worry about the -- or they need to look at their margin. So where the long-term hedges are relevant is if you take large new steel, new aluminum or other businesses where the business is based on that, that our customer does long-term contracts with their customers, you do 5- or 10-year contracts on steel supply or clean steel and so on, then they have a big interest to do also long-term hedges.

So that's one segment. The other one is the, indeed, sectors which want to secure that they get the power.

And for example, for data centers, this is a relevant question. We have seen that big time in the U.S., where the availability is the issue.

So these are the type of characteristics that we see. Data demand is there.

It's going to grow. Availability is the key thing.

You don't want your data center to stop under any circumstances. Tiina?

All right. Yes.

Then to the positive hedge effect, so basically, I think we mentioned that our achieved power price was EUR 48.1 per megawatt hour compared to the market blended spot price of EUR 26.4. And there was 2 main reasons why we achieved so high achieved power price.

And the first one is the hedge effect. So our hedge price, what we have indicated last quarter that for the rest of the year, it was EUR 40 per megawatt hour.

So clearly, not telling the exact profile in that quarter, but giving the indication of the level. So the hedge price was high.

But more importantly, in the second quarter when the volumes were low, the hedge ratio was high. So basically meaning that we get this hedge price for the most of our volumes, and we only sold very minor part to the spot market.

So this increased our price. Then, of course, the second very important element was the optimization premium.

There was -- even though the prices were low, there was volatility, and we can see that volatility has remained quite high. So we were able to optimize our portfolio and do the value creation part there.

Elias Huuhtanen from Montel News. I just wanted to ask about the Swedish government's new financing model for new nuclear.

They recently approved the plan to finance up to 5 gigawatts of new nuclear through contracts for difference. So I just wanted to ask if Fortum is planning to apply for these subsidies.

And if not, then why?

Yes. Thank you.

So we think that when we have been doing the feasibility study for nuclear, so we identify that you need visibility on cash flows, construction time financing and then the risk mitigation in -- for example, in the form of loans. The Swedish government is ticking all of these boxes.

We have not put in an application at the moment. We don't either have a place in Sweden where we could start such a project.

So we are part owner in Oskarshamn as well as Forsmark. But we are doing the feasibility study on a technical side, looking at long term if there are customer interests and if there is need for the new supply coming, but this is not acute at the moment.

So like we said, when we announced the results of our feasibility study with today's market prices, today's conditions and technology, there isn't today right now a case for new nuclear. So more work has to be done by all parties to make this happen.

And of course, there needs to be demand for the product. But I think the Swedish direction is correct.

So this is -- they have identified the right things.

Thank you so much. Thank you, moderator, and thank you all for all your very good questions.

This was a very good discussion, I think. On behalf of Fortum, we wish you all a very nice rest of the day, and thank you for participating here with us today.

Thank you very much, everybody. Have a good day.

Thank you. Bye-bye.