German battery spreads hit their widest since the 2022 energy crisis

German day-ahead spreads in September were the widest a two-hour battery has seen since the 2022 energy crisis, and the figures reached the market in the week to 3 November. Three financings closed in the same days, in Baden-Württemberg, Finland and South Yorkshire, and each answered the same question differently: how much of a battery's income has to be contracted before a lender will fund the rest.

September's German spreads were the widest since the energy crisis

Hamburg-based trading software firm suena energy published its September numbers on 29 October, and the price formation behind them is what to copy into a model. The average German day-ahead price reached EUR 144.80/MWh, around EUR 18/MWh above August and more than 50% higher than September 2025, with spot gas averaging EUR 76.20/MWh and passing EUR 80/MWh late in the month. Renewables covered about 66% of German generation, and negative day-ahead hours fell from 55 in August to 39. Two extended low-wind spells did the rest: evening prices averaged about EUR 261/MWh during those weeks, and the monthly day-ahead top-bottom spread for a two-hour battery reached roughly EUR 220/MWh, its widest level since the 2022 energy crisis.

The revenue split is where it gets interesting. suena models a representative 10 MW / 20 MWh standalone battery, so these are simulated earnings rather than a fleet average, but the ranking is clear. Continuous intraday trading rose 36% to EUR 17.5k per MW per month, day-ahead reached EUR 13.8k and intraday auctions EUR 13.2k, both up from EUR 10.8k and EUR 10.5k in August. The stacked wholesale strategy climbed from EUR 15.4k to EUR 20.9k, the strongest single-stack result in suena's observed series. Reserve markets went the other way or stood still: FCR slipped to EUR 14.3k, positive aFRR recovered 50% to EUR 8.4k, negative aFRR fell to EUR 11.3k, and the stacked aFRR strategy held at EUR 9.9k. Cross-market optimisation still won overall at EUR 25.5k against August's EUR 25.3k, but its advantage over the combined wholesale benchmark narrowed to 22% as trading caught up.

A day earlier, a project was priced off exactly that kind of number. ADS-TEC Energy said on 28 October that the permitting authority has confirmed all application documents are complete for its battery plant at the Pulverdingen substation in Markgröningen, Baden-Württemberg, with the building permit expected shortly and grid connection targeted for 2029. The plant is planned at roughly 1 GW and 4 GWh, four hours at full output, for an investment the company puts in the high hundreds of millions to around EUR 1 billion. It intends to sell a majority stake in the project company while staying on as a minority shareholder, technology provider and long-term service operator, and it cites third-party market data putting recent German large-scale battery revenues at approximately EUR 150,000 to 250,000 per MW per year from wholesale trading and balancing markets, explicitly labelling that range as neither a forecast nor financial guidance. ESS News notes that when the project was first announced in September 2025 it was scoped at 1 GW / 2 GWh, so the energy capacity has doubled in a little over a year.

If you own BESS, PV, EV chargers, HVAC plant or C&I loads in Germany or anywhere coupled to it, the practical reading is that the revenue stack reshuffled itself inside a single month, and a contract written for last year's ranking will underperform this year's. Check whether your route to market can actually reach continuous intraday, not just day-ahead and reserve. Check how fast your bids can be re-cut when two low-wind weeks arrive. And if your asset is being financed on a benchmark, ask which strategy that benchmark assumes, because the gap between a day-ahead-only run and a stacked wholesale run was over EUR 7k per MW per month in September alone.

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Finland and Sweden put contracted revenue underneath new build

Swiss developer Delta Capacity reached financial close on 28 October on two standalone Finnish batteries totalling 250 MW / 600 MWh, split evenly between Karppio in Teuva and AKKU One in Lapinlahti. Societe Generale is the sole senior lender to both and also acts as agent, security agent and hedge provider, with Finnvera, the Finnish state export credit agency, counter-guaranteeing one of its facilities. The debt size was not disclosed. Sungrow supplies the systems, construction has started at both sites, and commercial operation is targeted for the fourth quarter of 2027. On the commercial side, Centrica Energy holds partial tolling agreements on both projects and will optimise and trade them across Nordic power markets, a structure Delta Capacity describes as giving secured revenues while keeping merchant upside. Centrica already optimises Delta's 70 MW / 160 MWh Ånge battery in Sweden, which began operating in June 2026.

The day before, Swedish developer Ingrid Capacity and Swiss energy company Alpiq signed a framework agreement to explore long-term offtake structures for up to 500 MW of battery projects, primarily in the Nordics. It builds on a concluded offtake for the 45 MW / 90 MWh Pedersöre project in Finland, which Ingrid owns jointly with French asset manager Mirova, and it covers a portfolio Ingrid puts at 950 MWh across development, construction and operation. Ingrid chief revenue officer Amanda Niklaus said financing and commercial agreements are becoming as important to the Nordic battery market as technology and operational performance. The agreement is a framework rather than a set of signed offtakes, which is the caveat to hold onto.

For scale, Finnish grid operator Fingrid counted about 1,050 MW of connected storage back in February, of which 44% sits on the transmission grid and 57% of the capacity comes from units above 10 MW. Fingrid also made a point in that release that has not gone away: a storage system reserves grid capacity in both the charging and the discharging direction, so the TSO actively steers where new storage connects to avoid blocking consumption projects that cannot move.

For developers and portfolio managers in the Nordics and Baltics, the template on display is specific. A partial toll, held by an optimiser who already runs a sister asset in the same price areas, was enough to get a single senior lender comfortable on 600 MWh. If you are building toward a financing, the question to answer early is not only who will contract your megawatts but whether your control and reporting layer can prove delivery to that counterparty and to the TSO at the same time. That is the bit that tends to surface late. If you would rather poke at the idea before talking to anyone, our knowledge bot Fusie will take the question.

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One grid connection in South Yorkshire, two different contracts

UK developer OnPath Energy announced financial close on 28 October for Common Farm Solar Park near Dinnington, east of Sheffield, its first co-located solar and storage project. The site pairs a 49 MW solar farm with a 50 MW two-hour battery. NatWest provided bilateral project financing covering construction and operating life through a term loan and ancillary facilities, and construction is due to finish by mid-2027. AECOM is lead consultant and Grupotec is handling engineering, procurement and construction as well as later operations and maintenance.

The structure is the story. As ESS News reported on 30 October, OnPath separated the commercial offtake arrangements for the two assets to get the debt away: the 49 MW solar farm sits on a subsidy-free, long-term route-to-market contract with an unnamed global technology company, while the 50 MW / 100 MWh battery trades under a third-party optimisation agreement. One grid connection, one lender, two entirely different risk profiles underneath. Finance director Oliver Hartley framed the co-location itself around the connection, saying that few UK sites are co-located at this scale and that putting both technologies in one place allows efficient use of the available grid connection.

For anyone sitting on a solar site with spare headroom in its connection agreement, this is a pattern you can copy. The generation leg can be sold long, the storage leg can stay in the market, and a lender can still price the whole thing, provided the two legs are contractually separable and the metering and dispatch logic can keep them apart in operation. That last condition is a software problem before it is a legal one, and it is the one that stops a co-located site behaving like two assets on paper and one tangle in practice.

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Watch list

• Germany.ADS-TEC Energy's building permit for Pulverdingen is the gate: the company says the financing and the majority-stake sale are concluded only once it is issued, and it expects it shortly.
• Finland.Fingrid's yearly-market appendices for frequency containment reserves expire on 31 December 2026, and from 2027 domestic FCR will be bought on the hourly market only, which the TSO says will significantly increase hourly volumes around the turn of the year.
• Finland, siting. Fingrid's position that a storage system reserves grid capacity in both directions is worth tracking as connection decisions tighten, because it shapes where new Finnish projects are allowed to land.
• Nordics. Whether the Ingrid Capacity and Alpiq framework for up to 500 MW converts into signed project offtakes, and on what tenor.
• Great Britain. Common Farm is targeted for completion by mid-2027, and the battery leg runs on a third-party optimisation agreement, so it will be an early read on whether split offtake holds up once a co-located site is operating.