On 15 September 2026, Solarplaza brought together over 200 developers, IPPs, investors, lenders, traders, and grid operators for the 7th edition of the Solarplaza Summit Nordics. The mood was more sober than in previous years. Several well-known European developers have run into financial trouble, PPA volumes are falling, and battery revenues in parts of the region have dropped sharply. Still, the day kept coming back to one point: volatility is here to stay, and the players who can manage it through storage, smarter contracts, and active trading are the ones still making the numbers work.
Key takeaways
- Volatility is rising, not falling: Negative-price hours dropped in 2026, yet day-ahead spreads widened. Nord Pool now sees a North-South price gap of around €60/MWh, compared to a historical €10/MWh.
- Denmark's flexibility gap: Energinet puts Denmark's flexibility shortfall at roughly 15 GW in 2030, in a system where peak demand this year was 7.5 GW.
- BESS becomes a trading asset: Clean Horizon expects at least 80% of DK1 battery revenues to come from trading, while Finnish battery revenues have fallen from roughly €400,000–500,000/MW/year to under €100,000/MW/year.
- Contracts are harder to come by: European PPA volumes are down about 30% year on year, only two solar PPAs have been signed in the Nordics so far in 2026, and lenders now expect new solar projects to come with storage.
1. Volatility is the new baseline
The Nordic power market saw fewer negative-price hours in 2026 than in 2025, but that did not make it calmer. Rachel Locquet, Lead Consultant at Clean Horizon, opened the day by showing that day-ahead spreads actually increased. In DK2, the average daily spread rose from €123/MWh to €149/MWh, and in DK1 from €118/MWh to €142/MWh.
This is because volatility is driven more by the day's highest price than its lowest. Gas-fired plants usually set that peak, and higher gas prices in 2026 pushed it up. The move to 15-minute trading added further price swings. Zones closely tied to Germany, such as DK1, DK2, and SE4, see the most volatility, mirroring a German market where spreads reached €158/MWh this year.
Morten Pindstrup, Energinet's International Chief Engineer, described the same pattern in Denmark's daily price curve. The midday dip has stayed at 2025 levels, around €46/MWh in DK1, while evening prices have climbed to roughly €158/MWh. His conclusion: the market has to "learn to love volatility," because it is the signal that pushes demand and storage to move.
A widening North–South divide
Julien Cossé, Chief Strategy Officer at Nord Pool, closed the day with the bigger picture. Installed wind, solar, and battery capacity in the Nordics has nearly doubled since 2021, from 32 GW to 60 GW, and volatility has roughly tripled. The price gap between the northern and southern Nordics, historically around €10/MWh, now sits near €60/MWh, with futures pointing to about €120/MWh between DK1 and NO4.
Cossé also flagged low hydro reserves in southern Norway, at 54%, close to the 1996 record low. Political interventions, from Norway's Norgespris to debates over export cables, add regulatory uncertainty. Futures do suggest the North-South gap narrows after 2028, but for the next few years, he advised the audience to be ready for "a roller coaster."
2. Denmark's flexibility gap and a grid that hasn't kept up
Flexible demand is already appearing, even if it rarely makes headlines. Pindstrup showed that Danish household consumption between 2023 and August 2026 rose 61% in the middle of the night and 28% in the late evening, driven by EVs and heat pumps responding to price signals. In the energy sector, mostly district heating switching to electric boilers and heat pumps, midday consumption has more than doubled.
How much flexibility Denmark needs
It is not yet enough. According to Denmark's flexibility needs assessment, renewables would cover only 70–90% of demand in an average year without additional flexibility. Pindstrup estimated that Denmark will lack roughly 15 GW of flexibility in 2030 and about 5 GW in 2035, compared with the assumptions the system is planned on. For context, Danish peak demand this year was 7.5 GW.
The Danish Energy Agency's planning assumptions expect 21.8 GW of flexible capacity by 2030, led by co-located BESS and heating, plus about 10 GW of interconnection. Grid connection requests at TSO and DSO level go well beyond that, with around 28 GW of storage and 21 GW of data centers. Pindstrup was clear that this full pipeline will not be realized within the next decade, and said he would not be surprised if Denmark falls somewhat behind its 2030 goal.
Two further developments matter for asset owners. First, a capacity mechanism is likely on its way, partly because district heating plants are dropping around 1.5 GW of electricity generation capacity as they electrify. Second, Energinet's first round of grid connection allocations is due this autumn, while the legislation behind it is still in consultation. Morten Porse, CEO of Ænergy, called the past three years of Danish grid policy "a roller coaster."
Gerard Reid: a 20th-century grid for a 21st-century economy
Gerard Reid, Co-Founder and Partner at Alexa Capital, took a step back from the TSOs themselves. He argued that Europe is entering a new industrial era "with a 20th-century system," and that the problem is not generation but grid readiness, market design, and speed.
To make his point, Reid imagined a conversation with Werner von Siemens. Shown a modern control room, the company founder laughs that almost nothing has changed in 150 years. Reid's explanation for why grids lag:
- Incentives reward steel, not software: Grid operators earn returns on the assets they build, not on the intelligence they add.
- Risk aversion is built in: Operators get no reward for innovating, but can lose their jobs over a blackout.
- Fragmented regulation: Local, national, and European regulators all move at different speeds.
Reid also warned that parts of Europe's grid remain physically vulnerable, with critical transformers taking months to replace. His summary: technology moves exponentially, infrastructure moves linearly, and regulation moves "like a snail." He sees AI-driven, real-time grid optimization as the way to close that gap, and urged the industry to treat AI as an enabler rather than a threat.
3. BESS shifts from ancillary services to trading
The Nordic storage market has grown fast over the past year. According to Clean Horizon, operational, under-construction, and announced capacity in Finland rose by 402% between September 2025 and September 2026, to 6,282 MW. Sweden grew by 67% and Denmark by 49% over the same period.
That growth has changed where battery revenues come from. As batteries and prequalified renewables flooded the ancillary service markets, prices there fell. Revenues in Finland and Sweden dropped sharply, while Denmark held steady because trading made up the difference. Locquet expects at least 80% of DK1 battery revenues to come from day-ahead and intraday trading, with intraday becoming a main revenue stream rather than a side opportunity.
Ville Väre, Managing Director Nordics at NW Groupe, put the Finnish shift in numbers. A megawatt of storage there used to earn close to €400,000–500,000 per year; recent index figures show less than €100,000. Paybacks that were once counted in months are now closer to 10 years.
Storage limits its own upside
Locquet added an important caveat: storage reduces curtailment and negative prices, but it also flattens the very spreads it earns from. Enough batteries will shrink day-ahead volatility over time, which is why she stressed modeling realistic, long-term revenue stacks. Grid access and changing grid fees, which are shifting sharply in Finland, also shape how much storage actually gets built.
Risk matters more than hardware
Ruben Valiente, Managing Director at Maxxen, argued that hardware is no longer what separates good projects from bad ones. A two-hour battery now costs around €200,000/MW in equipment, with operating costs of roughly €6,000/MW/year, and most suppliers sit close together on price.
According to Valiente, risk drives a project's IRR. In his model of a two-hour battery in Denmark, a six-month delay to commercial operation cut IRR by almost 15%, but a drop in captured revenue had the largest impact by far. He pointed to Finland, where revenues of €250,000–300,000/MW/year were expected, and the market now delivers less than €100,000. Operational reliability came next, since missing a few high-value intraday spreads can hurt returns more than gradual battery degradation.
On the technical side, grid requirements are also tightening. Krisztián Gérusz, Technical Sales Manager at Sungrow, noted that Energinet already requires grid-forming capability for Type D, TSO-connected standalone BESS projects in Denmark.
4. Financing in a market under pressure
The financing discussions took place against a difficult backdrop. Several prominent European developers have gone into insolvency in recent months, and Øystein Kvarme, Senior Advisor at Capcora, noted that banks on the continent are pulling credit lines, even from existing clients.
Investors want more return for more risk
Silas Harbo, Partner and Country Manager Denmark at Infranode, explained how return expectations have moved. Infranode's early solar investments with 20-year PPAs targeted returns of around 8%. Today, with higher interest rates, investors expect double-digit returns and are willing to take on more merchant risk to achieve them.
Infranode's 162 MW Vandel III solar park shows what that looks like in practice. Built fully merchant and all-equity, it faced 8% curtailment in 2024 and 10–12% in 2025. Infranode responded with six-month summer hedges with utilities, an optimizer that shares risk rather than charging a flat fee, and a 60 MW/120 MWh battery inaugurated the week after the summit.
How lenders are adapting
The lending panel showed that banks are adapting, though cautiously. Anastasia Gurnell, Associate Director at NORD/LB, said baseload PPAs were long a "red flag" for lenders because they put the delivery obligation on the producer. A synthetic baseload, built from a hybrid solar-plus-storage project and wrapped into one product, shifts that risk to the offtaker and is something banks can finance.
Utku Bildik, Associate Director at ABN AMRO, said financing standalone solar has become difficult, and that the bank now expects solar projects to include BESS from the start or in their pipeline. For a standalone BESS in the Nordics, he would want around 50–60% of revenues contracted.
The lenders also explained how they build flexibility into debt:
- Cash sweeps: An upside sweep when the project earns well above plan, and a warranty sweep if the owner cycles the battery beyond its warranty.
- Target debt balance: A minimum repayment schedule plus variable payments, with a grace period of a few repayment periods before default.
- Conservative revenue assumptions: Gurnell said NORD/LB does not bank on today's high ancillary service prices, assuming they will be gone by COD.
The bankers also flagged products they are wary of. Floor contracts with clawback clauses are still being financed, but Gurnell called them "great marketing, but they're not floors." Bildik added that floors covering less than 40–50% of revenues, as well as day-ahead swaps, add risk for the project and its lenders.
Andreas Ditlev Duckert, Independent Solar & Storage Investor, argued that many sponsors contract too much. He prefers lower senior debt combined with junior debt, keeping more merchant upside. He also observed that financing has become less mechanical and more "a conversation" between sponsor and lender about how to share risk.
Valiente offered one more option: vendor finance. Under Maxxen's lease model, the supplier finances up to 100% of the equipment and service agreement, which can be roughly 70% of a BESS project's cost, without requiring a tolling agreement. The cost of capital is about 2% higher than project finance, but the sponsor keeps full merchant exposure.
5. PPAs and route to market
Mikkel Kring, Partner at Our New Energy, presented a sobering picture of the PPA market. Transaction volumes across Europe are down about 30% compared to 2025, with average monthly volumes dropping from 1,197 MW to 816 MW. He pointed to three causes: low traded power prices, corporate buyers who now understand capture rates, and uncertainty over upcoming changes to sustainability accounting rules, which may stop corporates from covering several countries with one cross-border PPA.
The Nordic market has historically transacted around 3 TWh per year, but 2026 is lagging, at about 1.4 TWh so far. Finland has seen three PPAs, Denmark four, and Sweden two. Only two of those are solar.
What Kring recommends
Kring estimates there is offtake for fewer than 10% of projects in the market, and his advice to IPPs followed from that:
- Size for the buyer: Projects below 20 MW can find single or multi-buyer offtake, and projects above 80 MW suit data centers and Power-to-X. The 20–80 MW range has the narrowest buyer pool.
- Build a product corporates can use: Combine PV and BESS to deliver a monthly baseload profile, and let a trader optimize the rest.
- Keep managing after COD: Balancing costs that were around €1/MWh five years ago now reach €5–7/MWh, and ancillary services and guarantees of origin can add value.
He also highlighted how sensitive projects are to financing costs. Citing Lazard's analysis, a one-percentage-point increase in the cost of capital raises the levelized cost of energy (LCOE) by roughly 10%.
Not everyone agreed
The panel that followed did not share Kring's outlook on every point. Liisa Rajala Malmgren, Chief Legal Officer at Alight, said Alight still sees interest in plain pay-as-produced solar PPAs. Jan Rigtrup, Director of Portfolio Management at Mind Energy, said the gap between what producers need and what buyers will pay is still too wide for 10-year deals. Ville Väre argued that co-location is driven more by grid constraints than by buyer demand. We explore that debate in a separate article.
Hedging in a volatile market
Cossé closed with practical advice for navigating the next three years: hedge beyond the front quarter, spread exposure across several bidding zones, invest in flexibility and multi-market access, and join market design discussions. Nord Pool took over the Nordic power futures business from Nasdaq in March 2026 and plans to launch German power futures next April.
Final takeaway
The Nordic market is not short on ambition or projects. It is short on grid capacity, flexibility, and long-term contracts, and the gap between the three drives today's volatility. Speakers rarely agreed on how quickly that will change, but they did agree on what works for now: pair generation with storage, secure enough contracted revenue to stay financeable, trade actively, and treat asset management as a commercial job long after COD. The developers and investors who can live with price swings, rather than trying to contract them away, are the ones still building.
Our team is already developing the 2027 edition of Solarplaza Summit Nordics, ensuring the community remains fully aligned ahead of upcoming market shifts.
