Good morning, everyone, and warm welcome to Fortum's joint webcast and news conference for the investor community and media on our full year 2023 financial results. My name is Ingela Ulfves, and I'm the Head of Investor Relations at Fortum. This event is being recorded, and a replay will be provided on our website later today. With me here in the studio are our CEO, Markus Rauramo, and our CFO, Tiina Tuomela. Markus and Tiina will present Fortum's financial statements for 2023 and the group's performance. This morning, we also provided some clarifications to our strategy focus, and Markus will also go through that. After the presentations, we open up for questions. Okay, I now hand over to Markus to start.
Thank you very much, Ingela. A warm welcome to our investor call also from my side. I will start by going through our performance, then talk about our strategy and execution, including the clarifications we have announced this morning, as well as market fundamentals and development. After that, Tiina will tell you more in detail how this turned into results in the fourth quarter and for the full year 2023. Let me now start with the highlights of the year 2023. Last year was very much about stabilizing Fortum's operations. Despite the volatile market environment, we strengthened our financial position, and our financial performance was solid. Our hedging provides visibility and stability against the very volatile prices, and we have developed our risk management through a new risk framework. Our balance sheet is strong, with very low leverage.
In May, we returned to the bond markets, which normalized our funding structure and balanced our debt maturity profile. We closed our books on our Russian operations for good. Due to the Russian authority's unlawful seizure of our Russian assets, we lost control, impaired the assets in full, and deconsolidated the Russia segment. As Russia's actions are a crude violation of the International Investment Protection treaties and deprive Fortum of its shareholder rights, we sent a notice of dispute to initiate claims against Russia. Our generation fleet ran well, and we got Olkiluoto 3 online in May. Following good availabilities and higher generation volumes from our power generation and lower share from condensing generation, our specific emissions for power generation decreased to 16 g per kWh from previous years' already low level of 25 g per kWh.
With this measure, we now rank number two as the second cleanest utility in Europe. Following the Uniper exit, we launched our new strategy, a new operating model and business structure, as well as a new leadership team and fully new organization in March. I will come back to more details on strategy execution later on. With the strong financial foundation and good results for the year, our board of directors proposed to the AGM a dividend of EUR 1.15 per share. This corresponds to a 90% payout based on our dividend policy of a 60%-90% payout ratio of comparable EPS. Despite the very busy year with a turbulent market environment, we managed it well, and big thanks naturally goes to our committed personnel, who have made this possible. Next, I will go through our main figures very shortly.
What you see here are the comparable headline KPIs for Fortum Group's fourth quarter and full year 2023 continuing operations. The fourth quarter comparable operating profit was below previous year's result, but due to the very strong result in the first quarter, our full-year result was only slightly lower than a year ago. Our comparable EPS was lower in the fourth quarter, but for the full year, we exceeded the 2022 performance. The operating cash flow decreased in the fourth quarter, but for the full year, it was at the good level seen in the previous year. Finally, the balance sheet and, most importantly, our leverage. Defined as financial net debt to comparable EBITDA, it was at 0.5x , a slight improvement from 0.6 times previous year. The low leverage provides us a solid platform to continue to develop Fortum.
I'm especially satisfied with the performance of our generation segment, as our outright power generation shows all-time high comparable operating profits. Then over to the strategy execution. In March 2023, we launched our new strategy. After that, we have continued full speed with our strategy execution. Let's take a look at the strategic development during the year 2023. First, on our priority to deliver clean energy reliably. We announced several projects in 2023 that enhance our best-in-class operations, such as the Loviisa Nuclear Power Plant lifetime extension until 2050 and upgrades of our hydropower plants, for example, Untra in Sweden. A hugely important event was the start of commercial power generation of the Olkiluoto 3 nuclear power unit, of which Fortum owns 25%.
The acquisition of Telge Energi, one of the 10 largest clean energy providers in Sweden, is a very good fit with our consumer business, increasing our consumer and enterprise customer base by 150,000, and further strengthening our position as the largest retailer in the Nordics. The construction of our Pjelax 380 MW wind farm, Finland's third-largest wind farm, is progressing on time and budget and will be commissioned in second quarter this year. During the winter months, Finland's last coal-fired condensing plant, Meri-Pori, operated on commercial basis to support security of supply in the Nordic power market. We signed an agreement with a National Emergency Supply Agency, NESA, to transfer it to production reserve for emergency situations from March 2024 until end of 2026. As mentioned, 98% of our total power generation was carbon-free.
So for the small part of our operations that are still not decarbonized, we continue our efforts. One example is building of sustainable waste heat solutions. Last year, we decided to invest EUR 225 million in decarbonization of our district heating as part of the ongoing Espoo Clean Heat program. This means that we would be off-takers for Microsoft's waste heat from data centers that they plan to build in Espoo and Kirkkonummi. The target is to cover approximately 40% of the heat demand in the Espoo area by this carbon-free waste heat. The total capital expenditure of the Espoo Clean Heat program amounts to approximately EUR 300 million. In 2023, EUR 31 million of these investments materialized. Secondly, a few words on our priority to drive decarbonization in industries.
In the second quarter, we signed new cooperation agreements within the scope of our new nuclear feasibility study with the Korean KHNP and the US-based Westinghouse Electric Company. In the feasibility study, Fortum explores the prerequisites for investing in new nuclear in Finland and Sweden. We examine the commercial, technological, and societal, including political, legal, and regulatory conditions, for both Small Modular Reactors, i.e., SMRs, and conventional large reactors. We have gained a very good overview of the new nuclear vendors during the first year of our feasibility study. We have evaluated 11 different plant designs, both large nuclear power plants and small modular reactors. We continue the study this year, and we will focus on identifying potential new build sites, de-risking measures, shortlisting potential vendors, as well as the pre-licensing process.
And finally, a few words on the priority to transform and develop that mainly relates to ongoing internal changes. Our target is to build an efficient operating model that fits Fortum's changing operating environment and our new scope and purpose. At the same time, we develop our culture and leadership to best support strategy execution. The full reorganization was completed last year, and now we implement our new governance processes. In the summer, we also initiated a strategic review of our circular solutions businesses, which is expected to take up to a year. As a part of the ongoing transformation, we launched the efficiency improvement program to cut fixed costs by EUR 100 million to improve efficiency. Then a couple of words about the commodity markets. You see the main drivers of the commodity markets on this slide, but my intention is not, not now to go through these.
Instead, I would like to raise a couple of facts about Nordic power market, as there has been quite vivid discussions lately, also in the public domain. In 2023, Nordic power consumption was 386 TWh, while the power generation was clearly above 400 TWh, leading to power exports of 41 TWh from the Nordics. Consequently, the Nordic power market, which basically already is decarbonized, is exporting clean and cheap power to neighboring countries, enabled by the interconnectors. So the Nordic market is oversupplied and does not need any new power capacity at the moment. This is also reflected in the Nordic forward prices, which currently are at the level of 40 EUR per MWh.
Wind and solar, with LCOE or levelized cost of electricity at this level, are not economically viable, as they, because of their generation profile, get only approximately 80% of the average price or slightly above EUR 30 per MWh in this example. It is good to note that wind and solar have the lowest LCOE of all generation technologies at the moment. The Nordic spot market works as it was designed for. Extreme and volatile prices are not a consequence of a dysfunctional market. High prices are a consequence of imbalances in supply and demand and lack of capacity, especially with peaking prices. The main reason is the increasing share of intermittent wind power and lower share of firm and flexible capacity. This causes extreme price volatility, even with negative prices during windy days, but also temporary constraints regarding security of supply.
On the other hand, wind capacity does not help if the wind is not blowing. This has been the case lately when we have had days with prices up to EUR 900 per MWh as a daily average. Currently, the market does not need more capacity. However, the current high price volatility is not beneficial for producers, suppliers, or consumers of electricity. We do not see-- We do see that over time, decarbonization through electrification of other sectors, heating, transport, and industrial companies, will create more demand for power. We need to solve the issues with the current market model, and this requires broad societal discussions on how to incentivize investments for base load and flexible power to have a balanced energy system when demand increases. To conclude, the Nordic power market is already decarbonized.
Fortum is almost decarbonized already today, does not have fossil capacity to be replaced, and will be carbon neutral by 2030. As our strategy is to supply clean energy reliably and drive decarbonization of other sectors, this shows that we are well-positioned and in line with our strategic ambitions. Now, let's take a look at our business portfolio and how we think about it in more details. As we announced this morning, we have specified our business portfolio further. I want to go through this to explain what the clarifications mean. Fortum Core is our core businesses in hydro and nuclear, customer business, and heating and cooling, i.e., our generation segment and consumer solutions segment. We have an established market position, and these generate almost the entire group EBITDA.
Based on our core competencies, we run these businesses in an efficient way, with the aim to constantly develop the performance and develop the asset base. The geographical scope is mainly the Nordics. We will strengthen and selectively grow these core areas while capitalizing on the market volatility. Demand-driven renewables means that we could build new onshore wind and/or solar capacity if there is demand from customers. We will not build new capacity without the customer offtake agreement, i.e., PPAs or LTCs. For now, we do not have any intention to invest in new capacity as the market currently is oversupplied. However, we develop a ready-to-build pipeline to have the preparedness to meet future customer demand when demand picks up.
It is good to note that PPA-supported projects allow slightly lower weighted average cost of capital, and that the power demand needs to be in the same price area as the potential supply in order to manage the price area exposure. With Explore, we mainly refer to research and development potential. These are potential future-shaping businesses, such as hydrogen or innovation and venturing, that need further studying and validating before they can be developed into economically viable business opportunities. Annual costs in this area are limited to a maximum of EUR 20 million per year. Non-core businesses are not in the core of Fortum's strategy. As we announced last year, the Circular Solutions business. Businesses are under strategic review. Then over to how we look at the timeline of our strategy execution. The world around us is currently uncertain, volatile, and unpredictable.
The supply-demand balance will change over time, and also market prices and building costs will change over time. This low visibility is the reason why we have split our strategy execution in two phases. As we do not see profitable new investment opportunities in the near term, sharpened focus is put on the core businesses to optimize the existing best-in-class operations, especially the generation portfolio, as well as managing business risks, for example, to decrease the share of merchant exposure. Fortum continues to be prudent and disciplined in its capital allocation to maximize value creation from flexibility, efficiency, and cash flows. During this phase, we prepare for future growth to be ready when demand picks up. With these actions, Fortum continues to build preparedness for long-term growth, which will be driven by decarbonization through electrification of other sectors.
With its already decarbonized generation portfolio, Fortum will partner and over time grow with industrial customers in clean energy, with focus on efficient capital allocation, attractive returns, balanced risk exposure, and sustainability. While we closely follow the market development, at the same time, we continue our disciplined capital allocation. As said, our priorities are linked to how we use our balance sheet, make investments, and distribute dividends to shareholders, the balancing of these with focus on cash flows. Our key objective is to ensure a credit rating of at least BBB flat. As we have outlined, our maximum leverage can be 2x-2.5x . Currently, our balance sheet is very strong, with leverage closer to zero.
The logic of our capital allocation is that if there are limited investment possibilities and we do not make any sizable investments, we will allocate more capital on shareholder distribution, and if and when there are good investment projects, we would allocate less capital to shareholder returns and more to attractive projects. Tiina will go through the details on our CapEx. As I today have also explained, we do not see that there in the near term are new attractive investment opportunities that meet our investment criteria, and as demand currently is sluggish, the demand situation does not support investments into new capacity. When it comes to investments, it is always about building profitable megawatts. It is also good to acknowledge that our dividend policy does not aim for stable dividends between the years.
The payout ratio of 60%-90% will be used so that the upper end of the range of the payout ratio is applied in situations with a strong balance sheet and low investments, while the lower end of the range would be applied when leverage is higher and/or making significant investments, and we have high capital expenditure. Consequently, our current priority is to pay dividends. This is also reflected in the dividend proposal to pay 90% of comparable EPS, i.e., at the top of the payout ratio of 60%-90%. Today, we have also disclosed new strategic targets with clear KPIs to measure our progress and actions. We have set targets for four key strategic areas to be developed in order to ensure optimal performance and risk management.
First, to strengthen our Nordic leadership, we need to ensure that our nuclear and hydro fleet has high availability. This is also supporting the security of supply. Our fleet availability has a very good historical track record, and now we set targets to further improve and to keep it constantly at the high level. Our target is to keep our nuclear fleet availability above 90 and our hydro fleet availability above 95. Second, our flexible hydro assets are a clear competitive edge for us, and we generate additional margins depending on how we run the assets. This optimization premium we have guided to be between EUR 6- EUR 8 per MWh, compared to the historical level of EUR 1- EUR 3 per MWh.
This margin comes on top of the hedge price and is included in the achieved power price, so it is a significant result driver, steadily adding to our income streams. Third is the aim to stabilize income streams. We manage our power price exposure by hedging our outright portfolio to have predictable and stable cash flows. As we have said before, we aim to increase the share of long-term, more than five years, power supply agreements, i.e., PPAs or long-term contracts. Now we have set a target to have a minimum of 20% of rolling 10-year outright volumes locked in by the end of 2026. At the moment, we have hedged 15% for the years 2024, 2033. The fourth KPI is related to preparedness for longer term growth when demand picks up. We are developing a ready-to-build pipeline for onshore wind and solar.
Our target is to have more than 800 MW ready to build by the end of 2026. At the moment, we have a pipeline in various stages, which is much larger than the target. However, they are not ready to build yet, which also is in line with the current market sentiment. This was a short run-through of our strategic actions until now and new strategic specifications, how we will proceed. Now, I would like to hand over to Tiina to go through our financial performance in more detail.
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 for our continuing operations. So let me now first comment on some of the comparable KPIs for our continuing operations. In the fourth quarter, our comparable EBITDA declined and amounted to EUR 459 million. For the full year 2023, it totaled EUR 1.9 billion, also slightly down. The comparable operating profit also declined and was EUR 359 million in the fourth quarter, while the comparable net profit decreased from EUR 370 million to EUR 317 million. Comparable net profit for the full year increased to EUR 1,150 million. As you can see, our comparable EPS in Q4 was EUR 0.35, somewhat lower than the previous year.
But for the full year 2023, comparable EPS stood at EUR 1.28 and was higher than in previous year. Comparable EPS is the base for the dividend proposal. Looking at the cash flow, the net cash from operating activities declined from EUR 451 million to EUR 149 million. The main reason was lower comparable EBITDA. For the full year, net cash from operating activities was in line with the previous years, despite EUR 122 million lower comparable EBITDA. The main reason for this was the positive impact from the change in working capital. Our balance sheet strengthened somewhat with the slight improvement in our leverage. The ratio for financial net debt to comparable EBITDA was at 0.5x . Now, over to the segment overview.
Let's look at the waterfalls for comparable operating profit for all our segments, starting with Q4. Compared to the previous year, all segments were lower. The main reason for the decline in the generation segments are lower active price, lower condensing generation from Meri-Pori Power Plant, and higher cost in co-owned production companies. These negative effects are partly offset by higher hydro and nuclear volumes, and lower depreciation due to the lifetime extensions of the Loviisa Power Plant. It is good to remember that the district heating business is also reported in the generation segment. The renewables and district heating business was loss-making in the fourth quarter. The result of the district heating business was negatively impacted by clearly lower power prices and higher fixed cost. Comparable operating profit in our consumer solution segment more than halved.
This was mainly due to the lower electricity sales margin and regulated electricity price cap set for end users by the Polish government for the year 2023. The reason for lower electricity margin resulted from customers migrating to lower margin spot products. There was also positive impacts from the high sales margin in value-add services and lower fixed cost. Comparable operating profit of other segment decreased by EUR 5 million, mainly due to development cost for the new operating model and higher cost in enabling functions, the negative effect of which was partly offset by improved performance of the circular solution business, especially in the metal business. Now, let's move to the waterfall of the full year. This picture shows that the result was relatively stable. However, only the generation segment improved.
The higher result in the generation segment came from the higher achieved power price, higher hydro volumes, and lower depreciation for the Loviisa Nuclear Power Plant in the power generation business. This was partly offset by lower generation of condensing power from Meri-Pori Power Plant, as well as higher cost in co-owned production companies. The Meri-Pori Power Plant ran clearly less hours during 2023 compared to 2022, which meant that it was loss-making. The renewables and district heating business was clearly loss-making. The result of the district heating business was negatively impacted by lower power prices, and higher fuel and CO2 emission allowance prices, and higher fixed cost. The year 2022 result included approximately EUR 36 million from the divested Norwegian district heating operation, and tax-exempt sales gain of EUR 9 million from the divestment of the 250 MW Rajasthan solar plant in India.
In 2023, the achieved power price of generation outright portfolio was EUR 63.1 per MWh. This is a new record, the highest ever achieved. Comparable operating profit for the consumer solution segment decreased by EUR 59 million and was EUR 38 million. The main reason was lower sales margin, which was partly offset by higher sales, gas margin, and lower fixed cost. The lower electricity sales margin were, to a large extent, the result of losses from customer outflow in certain hedge customer contracts because of very volatile and high-price market condition, especially during the first half of the year. The regulated Polish power price cap for the year 2023, set for end users by the Polish government, also had a negative impact on result. Comparable operating profit for other segment decreased by EUR 57 million and amounted to minus EUR 173 million.
The main reason were lower result in the recycling, and waste, and battery businesses, especially from higher cost from largely arising from the expansion of the battery recycling business, write-downs of certain IT project, development cost for the new operating model, and higher cost in enabling functions. The comparison period included structural changes in the circular solution business and one-time positive impact from changes in pension fund arrangement in Sweden, affecting group's enabling functions. As part of the efficiency improvement program to reduce fixed cost and turnaround loss-making businesses, this segment is now under special attention to address the result performance and increased fixed cost level. So let's take a closer look on the efficiency improvements and capital expenditures. In the third quarter, we launched our efficiency improvement program. We target to reduce our annual fixed cost by EUR 100 million gradually until the end of 2025.
As we said in Q3, the efficiency program includes strategic prioritization and evaluation of resources, as well as turnaround actions for underperforming and loss-making businesses. As we reported, both the renewables and decarbonization business and circular solutions were loss-making in 2023. Actions will also include personnel reductions. At the end of January 2024, just a couple weeks ago, we announced the start of the change negotiation in our consumer solutions business and in IT. We said that this could result in redundancies of a maximum of 130 job positions. Total CapEx expenditure for the years 2024 to 2026 is expected to be EUR 1.7 billion. This is EUR 200 million lower compared to the previous guidance for the years 2023 to 2025. The guidance includes maintenance CapEx of EUR 900 million, which is roughly EUR 300 million per year.
As Markus already said, the investment sentiment is currently weak. Investments are not profitable, and at the same time, the market is oversupplied. These are the main reasons for our lowering the CapEx. However, we do have some large investments ongoing. On the right-hand side, you can see an indicative split of the CapEx per segment. The main ongoing projects are the Pjelax Wind Farm, Loviisa lifetime extension, and the waste heat recovery project from data centers. Pjelax Wind Farm, with a total of 380 MW , should be ready in Q2 2024. Currently, the operational capacity of this wind park is 245 MW. In our CapEx guidance, we have approximately EUR 300 million of uncommitted CapEx for potential new investment decisions. As Markus also said, we prepare a ready-to-build project pipeline for renewables to have the preparedness when demand picks up.
So the investment decisions will depend on how demand will develop and what kind of project there will be. We are not forced to spend it. Then a few comments on our balance sheet, debt, and liquidity. Maintaining a solid credit rating still continues to be a key objective for us. When balancing between leverage, investment, and dividend, this is what we keep in mind. Fortunately, our balance sheet is currently very strong. Let's go through the reconciliation of our financial net debt in the fourth quarter. The opening balance sheet at the end of third quarter, we had financial net debt of EUR 474 million. In the fourth quarter, the operating cash flow was EUR 149 million. This effect was slightly offset by investment of EUR 141 million.
The dividend payment amounted to EUR 404 million in the fourth quarter, and the change in interest-bearing receivables was marginal at EUR 14 million, and FX and other effects amounted to EUR 59 million. So at the end of the year, our financial net debt was at EUR 942 million, and financial net debt to comparable EBITDA was 0.5x . Looking at our debt portfolio and the maturity profile, I want to highlight a few things. First, with the bond issuance in May, we rebalance our debt maturity profile and repaid some loans. Consequently, our maturity profile is very balanced, and there are no longer maturities in any single year. All in all, our gross debt is EUR 5.8 billion. At the same time, our liquidity position is strong.
We have sufficient liquidity reserve of EUR 7.5 billion, with EUR 4.2 billion of liquid ones and EUR 3.3 billion of undrawn committed credit facilities and overdrafts. With the strong liquidity position, we will continue to optimize our cash and credit lines to manage in any future market volatility and price situation. The overall objective is to have sufficient and optimal liquidity while trying to minimize funding cost at the same time. During the year, we developed our risk management tool and established a new risk management framework. Based on this, we are constantly monitoring and adjusting our liquidity based on various scenarios to ensure sufficient liquidity in order to meet required needs. Due to the volatile power prices and market sentiment, the required needs are higher compared to the past. Our current level of EUR 4 billion euros of cash is probably not the optimal.
However, it is good to remember that margining requirements peaked at EUR 5 billion in 2022, and there are also other uses for our liquidity, not only margining. Finally, the cost of our EUR 5.8 billion loan portfolio is 4.3%, while the interest income we get for our EUR 4.2 billion euro liquid funds is 3.9%. So with this, over to the outlook section. The outlook section comprises, in essence, three elements: guidance on hedging, tax rate, and CapEx guidance and cost reduction. At the end of 2023, the hedge price for 2024 remained at the same level, EUR 47 per MWh, and the respective hedge ratio increased by five percentage points to 70%.
Also, the hedge price for 2025 is unchanged at EUR 43, and the respective hedge ratio increased by 10 percentage points to 40%. We have today also introduced the hedge ratios for our long-term power supply agreements, mainly with industrial customers. As of the end of 2023, the hedge year outright volume for the years 2024 to 2033 is 15%. This includes the above-mentioned hedges for the 2024 and 2025. A short repetition of our guidance for capital expenditures. Our capital expenditure guidance for 2024 is expected to be EUR 550 million. This includes maintenance CapEx, but excludes potential acquisition. As said, capital expenditure for the next three years, 2024 to 2026, is expected to be EUR 1.7 billion, including maintenance and excluding potential acquisitions.
Annual maintenance CapEx will be approximately EUR 300 million, which continues to be below our depreciation level. Regarding our tax rates, we expect the comparable effective income tax rate to be in the range of 18%-20%. Just a reminder, the Finnish and Swedish windfall taxes were applied only for the fiscal year, 2023. The actual outcome was zero, and there is no new proposal for any additional taxes. Hopefully, this remains the situation, as any new taxes would not be supportive of any new investments. Also, as mentioned before, we target to reduce our annual fixed cost by EUR 100 million gradually until the end of 2025. This was all for my presentation, and then we are happy to answer your questions. Ingela, over to you.
Thank you, Tiina, and thank you also, Markus. We are now ready to take your questions, so please state your name and company before asking a question, and we also ask you to limit yourself to two questions each. Let's begin the Q&A session. Moderator, please start.
The question, please dial pound key five on your telephone keypad to enter the queue. If you wish to withdraw your question, please dial pound key six on your telephone keypad. The next question comes from James Brand, from Deutsche Bank. Please go ahead.
So hello, good morning, and thank you for the presentation. I had a couple of questions. Firstly, you've reiterated the kind of optimization guidance you've given in the past of EUR 6-EUR 8 per MWh. When you provided more disclosure on that last year, one of the factors that you highlighted was the higher Guarantees of Origin prices. Although prices seem to have come down quite a lot for Guarantees of Origin over the last three months, so I was just wondering whether you could comment. You've obviously reiterated the guidance, so I guess feel happy with it, but does that mean that you're, you know, might be more reasonable to assume you're at the kind of low end of, of the range? Does that impact your, your thinking at all? That's the first question.
And then secondly, you said you'd hedged 15% of your volumes for 10 years. Is there any disclosure you can give us in terms of roughly what price you hedged those volumes at?
... And if I can slip in a kind of second parter to that question, if that's allowed? Is it literally just 10 years that they're contracted for, or is it even longer than that? Thank you.
Okay, I can... Hi, James. Thanks for the good questions. I can start. So, with regards to the optimization premium, so, yes, we reiterated, and we're comfortable with that. Indeed, like you said, there are many factors, and there is a range. So we are comfortable to continue to guide within that range. And we have absolutely noted the price movements of the GOOs there, but continue to be comfortable. Then with regards to the hedging, the 15% now over the ten-year sliding total, the price we are not disclosing for the ten-year part. But we use both the implied forward curve and commodity prices, and so on, to then evaluate that where should the longer-term contracts be.
So that acts as a basis for our thinking. But of course, the liquidity in the market then, when you go past a couple of years, is very thin or there is no indication. But we use these different metrics to evaluate that. As you can tell from the 15%, there is not a lot done in the long term, but the customer interest varies, I would say, between five and 10 years, even longer. But as we have said earlier, investments and investment decisions are slow to materialize, so new investments are slow to come. And of course, the...
Our counterparties, the electricity buyers, are thinking hard, what are the levels they want to lock in or can lock in vis-à-vis their own production portfolios that may be of shorter-term nature.
Great. Very clear. Thank you very much.
The next question comes from Artem Beletski from SEB. Please go ahead.
Yes, hi. This is Artem Beletski from SEB, and thank you for taking my questions. First of all, I would like to ask on generation and earnings decline year-over-year. So you have been highlighting several factors. I would say outside of hydro and nuclear fleet, could you maybe provide some further color on it? So which of these items have been more significant in terms of the contribution? And what comes to the second question, very much appreciate your further color when it comes to dividend policy and 60%-90% payout ratio.
Could you maybe highlight whether there is any priority relating to stability of the dividend going forward, given the fact that normally leverage goes up when earnings are coming down, so that is likely to put a lot of volatility so on actual payout? Thank you.
Yeah. Hi, Artem. Thank you for the questions. I can start with the dividend policy and the outlook there, and then maybe Tiina, if you want to, because you gave already quite a detailed description of what are the components in the generation segment. So with regards to the dividend policy, the thinking is like I explained, that when our leverage is low and there are not a lot of investments in sight, then we would be very happy to use the higher end of the range. So that's not actually tied to the absolute level of what the earnings are, but more to the relative situation. What does the balance sheet look like, and what is the CapEx pipeline? Of course, we need...
Then in the longer term, we are thinking about exactly this, that where is the potential to generate new earnings? There is promising outlook in the long term with regards to decarbonization and electrification, so we want to be properly positioned for that, so that we can for the new large potential projects where the pipeline is rather impressive. We want to have certain readiness for that, but then we need to balance that in time. Is it happening next year or in the coming years? How is that going on? Some of these may take time, but then there are practical examples of things happening. One good case is the Microsoft data centers. So these investments are happening.
Microsoft is going ahead, and, and we, like I, like I explained, we are already building heat pumps and, and electric boilers, and, water storage, investing in Loviisa, et cetera. So, so many things are happening. But it's really the, the balance between the short term and the long term. For the time being, the, and for, for last year, the higher end looks like a, like a good position to be in. And then to Tiina for the generation.
Thank you. Thank you, Markus. So, generation result, if we look at the overall, the full year, so generation made a record-high result, so highest ever comparable operating profit level. Also, the achieved power price was the highest ever, so this EUR 63 per MWh. If we look at the quarter, so the last quarter, so however, that was lower than in the previous year, and this is mostly explained that the prices in 2022, they were extremely high. That was the most volatile time, very, very high prices. So in average, in our price area, so the price level in the spot market was EUR 100 per MWh, roughly lower than in 2023. So, of course, this impacted the last quarter.
Hydro and nuclear, both, they had a higher volume, so that was a very, very positive element. Then Meri-Pori, what we mentioned. So this was probably the biggest deviation. So in last year, when the power supply was very tight, so we ran the Meri-Pori with the high prices. The Finnish area prices even been even, even higher, so of the level of EUR 180 per MWh. So very, very high levels with the high production hours. Whereas this year, we hardly run Meri-Pori, so higher coal cost impacted that, no running hours was possible. The high coal cost was also the reason for our heating and cooling business, which is part of the generation segment.
So, the heating, of course, customers needed heat and power. We produced, but the coal cost and CO2 cost were higher, which made our renewable and decarbonization business also negative this year.
The next question comes from Harry Wyburd from BNP Paribas Exane. Please go ahead.
Hello, morning, everyone. So, a couple from me, please. So firstly, just coming back to the dividend. I've noted the new dividend policy, or the clarification of it, but I guess your balance sheet is probably as strong as it will ever be right now, and you haven't done a special dividend or a share buyback. So, would you rule out now doing a special dividend or a share buyback, in the future, i.e., should we just assume that the highest level of dividends we'll get will be the 90% upper end of your payout range? And then separately, second question on, the government and their stake in you and the board. So I noted some of the board changes, which I don't think were unique to Fortum.
Does that herald any change in the government's approach to their stake in Fortum? Has anything changed in the last six months or year that might cause them to change, reduce, or make any other changes for their stake? Thank you.
Thank you. Hi, Harry, and thank you for the question. So, with regards to the dividend question, so the dividend policy is, is, clear, 60%-90% of the EPS. With regards to any consideration around any special dividend or, or share buybacks, that would be a separate consideration, for the Fortum board to do. And right now, that, that has... as, as you have seen, such, such discussions are not, not taking place. And, I have to say also that, that we are still coming back, and stabilizing the business, from a very turbulent 2022. Geopolitics, the whole market environment continues to be quite, quite fragile. So I'm happy, to be on the prudent side at the moment.
I'm very happy about how we have been able to stabilize the business, have very good availabilities and good performance for 2023. So we take it step by step, and we will also see then what does the future bring us with regards to the decarbonization and electrification investments? At the moment, we're focusing on strengthening the company, developing our competencies, developing the optimization, but then also looking forward to the future that what possibilities are there. Okay, but the dividend policy, we are now working with these parameters. Then for the government stake, indeed, there were some changes with regards to government civil servant representation on stock-listed companies.
So that was a change, and we are actually waiting, and then, I mean, not only Fortum, but broader. We are waiting for the new ownership policy statement or ownership policy revision to come out somewhere in the spring. So that has been pending, and I think we'll hear then what kind of a position Finnish government takes on their shareholdings in different companies. I cannot preempt that at the moment, but I think the indications are that policy revision should be coming out somewhere in the near future.
Okay. That's very clear. Thank you.
The next question comes from John Campbell from Bank of America. Please go ahead.
Hi, good morning. It's John from BofA. Thanks for taking my question. I wanted to ask you about the new Olkiluoto 3 nuclear power plant and whether you see perhaps any risks in 2024 of disruption or any costs related to that, and perhaps if you can clarify whether any issues with the asset in the fourth quarter. That was my first question. The second question relates to your balance sheet headroom. How should we think about that, perhaps in the context of potential new nuclear investments? Thank you.
Okay, thank you. So, I can give a kind of more general answer on Olkiluoto 3, and then Tiina, Tiina, for sure, can give more color on that, and then on the balance sheet headroom as well. But overall, in my experience, really long time in different industries and startup of large equipment, the Olkiluoto 3 startup, after it was finalized, which of course we know was really late, but the startup has gone really well, in my view. And then there have been a couple of situations, which in my view are very normal startup issues. So I think Olkiluoto 3 has ran well and TVO has done a splendid work actually, and the plant supplier also in getting it up and running.
So once it was finished, with all of the testing that has been done, it has run really well. And I do not see for 2024, of course, the normal maintenances; they have been UMM to the market, so that is our assumption when we think about also our hedging optimization and all of that. So we work according to these announced schedules. Then with regards to the balance sheet headroom, like I said, I put that more in the general context of that, that we're thinking that what kind of customer demands could there be?
I think to, to give the, the scope of how we are thinking, a good, good indicator is that, that we said that we are developing the 800 MW ready-to-build pipeline of renewables for 2026. So that gives the scale of what is the type of promise we want to give to, to our customers, that we are here with our capacities today. We produce 45 TWh of CO2-free, flexible, reliable energy. We can do more of that in, in renewables in the short term. And then for the supply of ... potential supply of new nuclear or flexible capacity, like Kemijoki is investigating pump storage, that will require larger societal discussion on is a capacity element needed? What kind of state participation in Finland or Sweden would be needed for this to happen?
So that's still some time away, and we will give more color on this discussion once we finalize our new build nuclear study, the feasibility study. So we gave the halfway report now just a couple of weeks back, and we continue to work, and we'll be more detailed then towards the end of the year or turn of the year 2024, 2025, when we are ready with the study. So then we can give more color on what is needed if the society wants new nuclear to happen. And then, Tiina, if you wanna fill in on TVO and Olkiluoto.
Thank you, Markus. I think you well summarized the overall situation. So if we look at the overall, when the plant started to operate, so I think it has been exceptional how the running has gone in 2023. I think the overall availability, even 75%, taking account that there was a test running in the early part of the year. In the last quarter, however, the plant was down a couple times. The one reason was that there was a one measurement system in a way failure, and that was corrected, so the plant worked as planned. So this was also a very good proof. The other one was that it was purposely taken down to test the network.
So in that way, no worrying indications. This year, Olkiluoto 3 will have the first annual outage, and of course, this is a longer one, because this is the time also when all the punch lists work, the remaining work will be done. So it will be like, UMM, given a bit longer over the month length outage, but otherwise, no concerns.
Thank you for taking my questions.
The next question comes from Louis Boujard from ODDO BHF. Please go ahead.
Yes, thank you, and, good morning, everyone. Two questions on my side. Maybe the first one, I would like to see, because I understand that you don't see that much development capacity for a new power generation at this stage, but at the same time, it's still a very volatile market. And I see some of your competitors that start to invest quite heavily in battery systems in your region. Why don't you want to be a bit more aggressive into this field? Is there something that will be into the regulatory environment that you would need, such as capacity remuneration, in order to take this kind of decision? Or, do you plan eventually to make it an additional element for your future CapEx in your short-term plan?
My second question would be regarding Olkiluoto particularly. Can you try to eventually help us to understand what would be... what has been the impact and what could be the impact of this nuclear power plant into the equilibrium of the market going forward? And is it related to your target to eventually try to hedge a bit more on the longer term and to have a 20% hedging on the next 10 years? Is it also related to the Olkiluoto 3 outputs? Thank you very much.
Okay. Thank you. Thanks for the questions, Louis. Good morning, and thank you very much for the first question, actually. It's a very good point. So, what you're implying is exactly how we are thinking, and that's why we bring the flexibility, optimization, and storage up now, and we had it earlier also, but we highlight that in the core of Fortum. So this is something we think is needed and very much like to do. So flexibility and storage has already been in the core of our operation through our flexible hydro, with sizable storage. And with regards to our investments, what are we doing at the moment?
So in addition to Loviisa, obviously, that where we have the lifetime extension and Pjelax for the wind, we are the third leg. The very sizable investments are actually going into this flexible and storage part, and that is in the district heating businesses. And a great example of that is what we—where we just laid the ground stone in Kolabacken in Kirkkonummi, just outside of Helsinki, where we are working then to connect the Microsoft data centers and the waste heat into the Espoo district heating system. But that heat does not come straight to the district heating system, but we are building electric boilers, we are building water storage, and we are building heat pumps, air-to-water heat pumps, which will upgrade the waste heat.
We have electric boilers of 100 MW in this site alone, and water storage. And both the water storage and the electric boilers actually have exactly this huge flexibility. So these are like the size of mid-sized or large hydropower plants. And this is a great fit now with the more inherently volatile power market, with the increasing intermittent power. So yes, this is something that does not require for the demand to grow massively. We already have a volatile situation, so this is a good fit. And it's not only Fortum, but other, for example, district heating companies are doing the same. So yes, interesting area. Then in the longer term, pumped hydro storage and pumped hydro has potential.
Kemijoki, where we are the largest water shareholder, announced already last year that they are investigating the possibilities. The pumped hydro, that then requires broader societal discussion. So it's a question also that, does this require some kind of capacity element? But the electric boilers and zero to 100 flexibility, that is already there. Then for Olkiluoto 3, yes, it does definitely have an impact. So Finland has become, if you look at the total volume of electricity consumed and electricity generated, Finland now is roughly at the level of demand and supply equilibrium, but of course, not on a daily basis. So we see that Finland is importing or exporting very large amounts of power.
So the integration of the Nordic market and integration of Europe as a whole, makes it possible to have these different features: huge, flexible Norwegian hydro, nuclear in Finland and Sweden, growth in renewables in Finland and Sweden, and of course, the different decisions that European countries are doing. So this integrated market is very important to enable all of these different factors to come in. With regards to, back to Olkiluoto 3, couple of years back already, there were questions that what happens to the pricing and so on when it comes online? And we continued to answer that the market already assumes that this will come online at the announced timetable. So I don't see anything dramatic having happened when the unit has started. So that was already anticipated many years ahead.
Of course, always iterating with the delays that came, but anyway, no drama in that coming into the market. What Olkiluoto 3 enables us to do is that our share, 25% of it, means that we have 400 MW more of reliable base load power actually to sell to our customers. So that was a very welcome addition to our portfolio with regards to decarbonizing and electrifying various industries and electricity consumption.
The next question comes from Ingo Becker, from Kepler Cheuvreux. Please go ahead.
Yeah, thank you. Good morning. I had a question also on the optimization premium, and I was wondering if you could share a little more detail here. At the time, you've given that last year, November, apparently at very different state of power markets, and we've seen quite a material change since then. And you gave us the three drivers of your premium being the spot price, the spot price volatility, and the guarantees of origin. The spot price was already low at the time, but I understand the guarantees of origin have fallen. And I was just wondering, did your view on how you achieve that premium change since November? Do you maybe expect greater volatility than at the time, or has it been basically the same?
If possible, what is your expectation going forward in these markets? Would you think that volatility increases further, or also taking the hydrological situation into account, might that change again? And my second question would be on your 10-year rolling forward hedge. Maybe could you share your experience with clients and your discussions with them so far, how demand for LTCs and PPAs is developing, A, with regard to the demand volume you're seeing, or the number of clients approaching you? And B, with regard to the prices, how do your clients think about the prices over the long term, and are you theoretically willing to sell or engage in a long-term contract right now at these market prices? Thank you.
Okay, thanks. Hi, Ingo. Thanks for two good questions. So, when we... It's a good question. So when we announced the optimization premium, we thought about the longer term. So we were not thinking of the next 12 months, but rather looking years ahead so that, like, we had EUR 1-EUR 3 there for quite a long time. The market changed quite a lot, and that's why we did not change our guidance or communication around that in 2022, because we felt that, well, this is an overshoot, and this is not normal. So the market was so disrupted.
So when things stabilized and we got a bit more visibility, then we said that, "Okay, now we're in a position to give better guidance on that." So there are indeed these three elements actually, the spot volatility, the GOOs, and the grid services. And so it is the physical optimization, like, longer term, in intra-week, intra-month even, and the grid services. And as you have seen, I'll just highlight one thing, that if the GOOs have softened somewhat, we have seen high down regulation and high up regulation prices in the recent months in the market. So these elements, they can vary between quarters and years. So we are comfortable with the guidance as it stands today. Then I think longer term, the question is: Where will the market develop?
So as it looks like right now, there is, there isn't a flexible capacity come, like production capacity coming to the market. There isn't baseload coming to the market with the current knowledge today. We think it would be a good idea to have those, and they may then, in the longer term, have impact on where the optimization premium would be. But with today's knowledge, to the midterm future, we are happy with this EUR 6-EUR 8. Then with regards to the discussion with the client, so the pipeline of demand that we have been referring to that continues to be to look solid. So these projects are very tangible. They're based on strong fundamentals in steel, aluminum, hydrogen, hydrogen derivatives, battery factories, data centers.
So I'm comfortable that the demand, the kind of inherent demand is there. But then we can all think that, well, how long does it take to develop these projects? From the initial question to ask that is there X terawatt hours of electricity available for five years or 10 years or something around that to a project materializing? If it's a new project, it does take time. So it's an iterative process. And how I see where the dilemma for the incumbents in any of these businesses is that order books for heavy industries don't tend to be multi-year long, so products are sold with shorter pricing intervals than multiple years.
So then the question is: when, when do you want to lock in, and how do you want to lock in your, your cost inputs? A difference to the new projects is that, we can see that the type of new steel, new aluminum, they're the, like, newcomers into the market. They do actually lock in for the long term, their own customer contracts, and thereby they need to lock in also the input costs, because you don't want to have the basis risk. So it, it will take some time. Not all projects will materialize, but, I think the fundamentals are pointing to that. Nordics will, will see, heavy decarbonization and heavy electrification investments coming. When exactly that will happen, we will then see.
Thank you very much. Can I just briefly inquire: The six to eight euros, which you stated is a midterm view, but it is already applicable right now, right? So just an example, if the system price after EPADS is, let's say, EUR 40, we should expect you to be making EUR 46-EUR 48 right now already in these markets?
Yeah, that's exactly how we, how we think about it. Of course, then adjusting for already done hedges, et cetera, et cetera, but the, but the math is exactly like that, and it is valid today, and it is valid, for us now in the foreseeable future.
Excellent. Thanks, thanks very much.
As a reminder, if you wish to ask a question, please dial pound key five on your telephone keypad. The next question comes from Wanda Serwinowska from UBS. Please go ahead.
Hi, it's Wanda Serwinowska from UBS. Two questions from me. The first one is on the cost cutting. From what I remember, you said that you expect a EUR 100 million benefit on the 2022 cost base. Would you be able to quantify the increase in your fixed cost base in 2023, given the inflation? So basically, what is the net benefit that we should expect going forward? What is the associated one cost on your PNL that you expect? Because usually when there's a cost cutting, there is a cost associated with it. And the second, on the Meri-Pori, you said it was loss-making, but would you be able to help us to quantify the impact, low, medium, high, double, triple digits, so we can basically understand the impact? Thanks a lot.
Okay, so I can start with the cost cutting. I think, Tiina can answer the second question and if you want to give more detail also then on the cost-cutting program as such. But, it's a good point about the inflation. So we are saying that, our target is that, on a like-for-like basis, we reduce the cost base by EUR 100 million. So we're not saying EUR 100 million plus inflation. So we don't know where the inflation will be in 2024 or 2025, so that remains to be seen. But this is really, from my point of view, the key is that, what we're doing is going through our activities and looking at what does Fortum need?
What is needed to have good availabilities to produce what our customers need in a group, in a group of companies that does not have any more Russia and Uniper. So different different setting and need to prioritize. Then we have a tighter strategy, tighter strategic focus than we had before. So clearly, we have now non-core areas where our focus will not be. So also the... Within the more limited scope, there will be even tighter focus on things. So this is the kind of general answer on how we're thinking about it. So it is like-for-like, minus EUR 100 million, and then inflation will be what it is. But Tiina, if you want to continue on these two points.
Yes, very good. Yes, so, the reference point, as we indicated, is 2022 cost level, so roughly, EUR 1 billion. So this is, where we benchmark the numbers, so roughly 10% reduction. And I think it is important that, of course, when we do all the activities and improvements, so there might be one of cost also on the way when we go there, but on the rolling basis, we should be at the end of 2029, is this EUR 100 million achieved.
Then, what comes to Meri-Pori, so maybe to put it in perspective, so of course, our most of our production comes from the hydro and nuclear, so we are discussing nearly 45 TWh, whereas Meri-Pori overall in 2022 it was a few hundred GWh. So not of course in relation smaller volume, whereas this year hardly very moderate hours. It is this year, I think the negative impact mainly comes from that there are certain fixed costs we need to carry in any way to keep the plant ready for operation. And this is the reason why actually we will now put the plant to this national emergency supply system to in a way get away about the fixed cost.
I think the big difference and magnitude comes that the prices in Q4 2022, so they were really high, so EUR 185 in Finnish price areas. And of course, the role was to bring the security of supply to the system.
Can I quickly follow up on the cost cutting? I recall the EUR 1 billion fixed cost base for 2022, but we are already in 2024 with a high inflation last year. Would you be able to tell us what the fixed cost base was in 2023? Because most of us take 2023 as a starting point. And on the generation, would you be able to help us to understand the magnitude of the kind of losses from district heating and Meri-Pori in general, very high-level guidance? Because I think looking at where consensus was versus what you reported, there was a substantial miss.
Yeah. Well, on the inflation, I can say in general that the inflation in Finland and Sweden has not been at the same levels as continental Europe, so we're talking about much more modest numbers. What that was exactly for our 2023 cost base, that I cannot actually say right now, but we're not talking about as high levels as we have seen in some other areas. Then, with regards to cost cutting, I'm not sure, Tiina, if you said 2029, but 2025 is the-
Sorry. Yes.
Yeah.
Did I say?
2025 is the-
Sorry
... run, run rate.
Yes, 2025.
I saw Tiina looking worried-
Ah, okay
... that, are we tracking this now?
No, no, no, no, no, no, no. I prefer to have end of 2024, but I, I know that it is not possible, so thank you for noting.
Yes. And I think, in general, the good question that, okay, so what was the impact of, of, of Meri-Pori and the district heating, activities and, and their level? So we have the EUR 100 million, cost-cutting, program, fitness program. We will turn around also the, the businesses that are making losses. So on Meri-Pori, we have already acted so that there we will not have the costs anymore as it is in the, security of supply, reserve. And for the district heating, that was indeed hit by the, by the fuel costs. So we had procured fuels at the higher prices, now electricity at lower prices. So this was, I would say, very unusual that, that we had a loss-making Q4.
That—I mean, normally, that would not happen. And now these investments that we are doing to the electrification, these will turn on a like-for-like basis, they will have a massive impact on the profitability, because then we will not have the expensive fuels, we will not have the CO2 costs, but we will have a CO2-free, electrified, and flexible district heating system in the Espoo area, which is the big part now of the part that made the losses.
Thank you very much.
Thank you.
The next question comes from Pasi Väisänen from Nordea. Please go ahead.
No. Okay, thanks. This is Pasi from Nordea. Coming back to this, optimization gain, so, what is actually the biggest component inside this optimization margin? And will it be seasonally a bit lower during the summer period? And secondly, if it really happens that we are going to see a kind of a massive increase in wind power in the Nordic system, so is there kind of, anything which would prevent the average system price to come down to, let's say, EUR 30 per MWh for quite a long time before these capacity payments are, are issued for the base load, load producers or before Fortum is able to kind of convert the, the portfolio to PPA agreements?
My second question is kind of that, are you going to lose the battle in next two, three, or four years period? Thanks.
Okay. Thank you, Pasi, for the questions. So, on the optimization premium, the biggest is the physical optimization. So when we have physical GOOs and the grid services, today, clearly it is the physical optimization that is biggest. Then, for the good and, like, fundamental question of what's the relation between the forward prices and new capacity. So if and when the forward prices serve as some kind of a proxy for where customers are ready to make contracts and what is then catalyzing investments? So with today's LCOE construction cost and everything of new wind power, then there will not be new wind power coming if the prices were at the levels where you are indicating.
It's, it's as simple as that. So there will not be investments. You cannot make profitable investments, especially if the system price would be an indication of what is the average achieved price, then the wind will get an increasingly lower share of that. And like I said in my example, if it would be 80% of EUR 40, then it would be 32. Well, if the average price would be EUR 30, then it would be 80% of that. So way too low for what we now see from external sources that the LCOE for new wind would be in the higher 40s. So then it doesn't make sense to build new capacity. So to your question that, so what kind of structurally would happen?
Structurally, we see that if and when there is, and I think that would be a natural development, that there will be more renewables, then the relative value of base load and flexible power will increase and the relative importance. So the ones who have it will be in higher demand. And whereas if the wind power, intermittent power increases, its achieved price will continue to be lower, so it will get less percentage of the average spot, and the flexible power will get an increasing percentage. So the premium will increase for flexible, and the discount will increase for the intermittent. So we are—I think we are well in different scenarios. We feel that we have a lot to offer, and we are very well positioned with our low cost, flexible, and reliable power.
Okay, great. Thanks.
The next question comes from Pavan Mahbubani from JP Morgan. Please go ahead.
Hi, good morning. Pavan from JP Morgan. Thank you for taking my questions. I just have one, please. On looking at your balance sheet, you're significantly below your maximum net debt to comparable EBITDA ceiling of 2-2.5x . How should we think about that evolving over the future? So you talk about your current dividend payout ratio and the potential pipeline of investment opportunities. If we assume a more attractive market backdrop, is that pipeline significant enough to regear the balance sheet on its own, or do you see in the medium term that you'll be running an undergeared balance sheet, given the dividend policy and your investment plans for the next two or three years? Thank you.
Yes, so from a use of capital point of view, it's not ideal to have as strong balance sheet as we have today. So either we can use that flexibility for distributing capital back to shareholders or in investments. As I said before, I think in several questions, I think that in the longer term, the backdrop for Nordic growth in electricity demand is very positive. And we will balance then the balance sheet strength, dividend, and CapEx according to this outlook. And what we said today is that if the balance sheet is strong and we have less investments in sight, then we will use the upper end of the range for dividend payout.
If, on the other hand, there would be potential for doing more investments and, and balance sheet was closer to optimal, then we can use the, the lower end of that range. So for the time being, this is the way, way we see it. Then, then I'll, I'll take a more general point that, of course, 2022, we experienced, some extreme market conditions that were driven by many, many disruptive geopolitical and, and market events. So if today I would have to think that would I err on the aggressive or conservative side, I think we, we would like to be a little bit on the conservative side today.
So it's not only the, the outright numbers of 2-2.5 and now 0.5, but it is also that, that what do we need with regards to liquidity and so on, which are, of course, not directly relating to the net debt to EBITDA. But nonetheless, factors that give us the comfort that, that if there are sudden market movements, then, then we are not, caught in a bad spot, but rather that we can operate from a position of strength. For example, capturing, higher price peaks, have the liquidity, have the balance sheet strength, have access to capital, in these kind of situations. So we want to see a little bit, how the market develops and, and what happens on the new investment side.
We want to see what happens on the financial market and commodity markets overall.
Thank you very much.
The next question comes from Piotr Dzieciolowski from Citibank. Please go ahead.
Hi, good morning, everybody. I have two questions, please. So you helped us to understand the possible positive elements of your PNL related to the cost cutting and elimination of the losses. Can you help us quantify what is the related downside to the power price realized? Is this as easy as you will see a double-digit decline in the realized prices times 50 or just below 50 TWh? And the second part of this question would be, if you add this possible decline on the realized prices versus the positives, how do you feel about the EUR 1.6 billion 2025 to 2026 consensus? Do you think it is too ambitious, or you think you can get to this level? Thank you.
Okay, so the way I understood the question is that is there a relation between the EUR 100 million saving and turning on profitable businesses versus the power prices. And for the EUR 100 million, this is not relating. So these are structural actions and really deciding on what activities we prioritize and what is the cost level overall of what we are doing. Turning around unprofitable businesses, of course, there is some element on the power price, but mostly this is relating to, for example, the wind development activities and how these are working in time. Meri-Pori costs that we had last year in 2023, that cost base will not be there in the long run, so that will be out of our portfolio going forward.
For the heating businesses, yes, there is some power price element, but for example, the electrification, so going to electric heating or electricity-derived heating from fossil fuel and CO₂ content, actually then, lower prices are a positive because that makes electrical heating, even more competitive. Then with regards to the consensus numbers, so, the way, of course, as you very well know, how we guide our result is that we give the hedge ratios, we give our production information very in a very detailed way out. So then what you have to plug in is then the assumptions on the other businesses, and there we are not giving the exact details, but giving more like directional where this ought to be going.
So then you need to go to the details also on the cost cutting of, well, what would be the assumed inflation on this EUR 1 billion cost base minus the cost reductions and all related activities. But then we go into quite small detail. So the main thing is the outright generation, volumes, pricing, hedging. But I will not comment on exactly that, that what do we think about the consensus numbers. But we try to be as helpful as we can.
Sure. Understand. Maybe can I have a quick follow-up? How do you see the balance of power import, export in the Helsinki region over the next two, three years?
Yeah, as it looks like right now, Finland is about that self-sufficient level overall when it comes to the supply and demand. So Finland is producing the amount of electricity it uses over a year, but within the year, let's say that in now wintertime, the consumption is somewhere around 10 GW-12 GW. And we have seen that, like, in normal days, it can go up to 13, even 14 on cold days. So then the export-import balance can vary from, like, -2 GW to +2 GW, something like that. It used to be more when there was still trading between Finland and Russia. Now, it's all with Sweden, Norway, and the Baltic countries.
So this will be an important factor, and that's where, again, our flexibility, our storage plays a big role. So on days when there is little wind, the wind production can be almost zero. So it was... I think at the bottom, it was like 100 MW out of a total of 6 GW of capacity, and at the peak, it has been around 5 GW . So big swings can be expected, and it tests the transmission capacities, which are, by the way, being built more. But from our point of view, that volatility increases the value of our reliable base load and our flexible capacities and our storage capacity.
Okay. Thank you very much.
Thank you. This was actually the last question we had. So thank you, moderator, and thank you all for, for all your questions and, and for the dialogue here today. On behalf of Fortum, we wish you then all a very nice rest of the day and end the session here. Thank you.
Thank you very much.
Thank you.
Have a good day.