Earning with batteries in Europe

In the week to 23 September 2026, three separate stories made the same point from three directions: the money in European battery storage is still there, but the rules for capturing it are getting stricter, and who sets those rules is changing. Traders and financiers are pricing battery revenue in new ways, grid operators are deciding which batteries get to run, and national regulators are handing out the contracted revenue that makes projects bankable. Every figure below links to its source.

1. The easy money is over, and battery revenue just became something you can hedge

Two developments this week bookended the same shift. On the trading side, Norway’s Statkraft and the UK’s SSE completed what they describe as the first financial swap of its kind, tied to Modo Energy’s ME BESS GB (2H) Index, a benchmark that tracks the average revenue earned by operational two-hour batteries in Great Britain. In plain terms, SSE swaps uncertain battery revenue on part of its portfolio for a fixed amount, while Statkraft takes on the risk and the upside of how the index performs against an agreed strike. Statkraft pays SSE when the index falls below the strike, and SSE pays Statkraft when it rises above it, with the settlement measured against the index rather than either company’s own assets.

What makes this more than a one-off is the instrument. The index is FCA-regulated and captures the full revenue stack, including wholesale trading, the balancing mechanism, frequency response and reserve, and the capacity market, which its administrator says roughly halves the basis risk compared with hedging against a simple day-ahead spread. Statkraft said it expects to do more of these across its 9,000 MW portfolio. A shared, regulated benchmark is exactly what lets banks, insurers and trading desks price battery-linked contracts, which is how an asset class matures.

The reason a hedge is suddenly worth having is the other story. Volue’s head of trading and optimisation, Helmut Spindler, put it bluntly in a new white paper: “the easy money is over.” Just parking a battery in FCR, the trade everyone in Germany and the UK made early on, has saturated. Profitability now depends on combining wholesale, intraday, balancing and imbalance and moving capacity between them through the day, with continuous intraday repeatedly among the strongest single streams in Germany this year. His sharper point is about control: in an aggregation pool you get the pool’s strategy and the pool’s result, and the biggest difference in outcomes comes from the decision of where to place capacity and how to price the degradation cost of each cycle.

If you own or manage BESS, this is a here-and-now change to the business case, not a distant one. First, stop underwriting a project on a single revenue line, because the simple ancillary plays are the ones saturating first and a case built on them is the most exposed. Second, treat wholesale and continuous intraday as the core and ancillary as a top-up, and look honestly at whether a revenue floor or an index hedge now belongs in your capital stack, given one exists. Third, dispatch continuously rather than once a day, shifting capacity between day-ahead, intraday, balancing and imbalance as prices move, and price the wear of every cycle into the trade.

That last part is what we do at Fusebox. We integrate and dispatch BESS, PV, EV chargers, HVAC systems and C&I industrial loads on a single platform, across 15 European markets and 9 TSOs, so a portfolio can chase the best-paying service at any hour instead of sitting in one saturating market. Talk to Fusebox about multi-market dispatch →

2. In the Netherlands and Germany, grid access is deciding which batteries earn

The strongest single project news of the week was also a congestion story. RWE took a final investment decision on a 400 MW / 1,100 MWh battery at its Moerdijk power station in the Netherlands, one of the country’s largest. The notable part is not the size but the job: through capacity-steering agreements with transmission operator TenneT, the battery will be dispatched to relieve congestion in the Noord-Brabant region, freeing grid space for customers stuck on the waiting list. TenneT and regional operator Enexis will factor it into their reassessment of the area’s congestion-management study in December 2026, and the battery will also provide inertia. Commissioning is planned for the second quarter of 2028.

The same logic showed up in a German study. Fraunhofer IEE, working for the solar association BSW-Solar, found that 1,313 rural substations could host around 150 GW more solar and 60 GW of batteries simply by using existing transformers better, with storage absorbing generation peaks. The association ties this to Germany’s grid-package debate, arguing against designating large regions as long-term bottleneck areas where new renewables face a redispatch reservation, and for using existing capacity first with grid-supporting storage placed at the pinch points.

The flip side arrived the same week, and it is a warning. A newly opened 69 MW solar-plus-storage plant in Brandenburg had its import capacity withdrawn by distribution operator Eon Edis, leaving its 76.5 MWh battery able to store only power generated on site. The operator had planned 6.8 MW of import for battery operation and commercialisation, positioned containers at the substation to use it, and now has no power purchase or flexibility agreement in place while lawyers try to restore the connection. Same technology, very different returns, decided entirely by the grid.

For BESS and hybrid owners in congested markets, the connection terms are now as important as the revenue model. A battery contracted to relieve congestion can be a revenue stream and a reason to get connected faster. A battery that cannot import when it needs to is stranded. Pin down whether you can charge from the grid, under what conditions, and whether a congestion or capacity-steering arrangement is on the table before you finalise the case. That is the kind of setup we help design and then operate. Let’s connect your assets where they can actually earn →

3. Southern Europe is writing contracted revenue into the rulebook

While northern grids argue over access, the south is handing out the contracted revenue that underwrites new build. Spain published the ministerial order for its first unified capacity market on 17 September, covering generation, storage and demand in one framework worth up to 9 billion euros through 2036, which the regulator estimates at 800 to 900 million euros a year. Capacity is awarded through technology-neutral, pay-as-bid auctions on firm capacity, with a 550 g CO2/kWh emissions limit that means new-build contracts, worth up to 15 years, are open only to renewables, storage and demand. The design also adds a secondary market for capacity rights and, on the demand side, loads the cost onto the small share of hours when the system is most stressed to nudge consumption away from peaks. It lands alongside a grid investment plan raised above 17 billion euros to 2030, in a market where curtailment has been climbing fast.

Italy kept clearing pipeline in parallel. Its energy ministry authorised roughly 2.3 GW of projects in September, including two Sardinian battery plants totalling about 110 MW that were pushed through despite negative opinions from local and regional offices. That comes ahead of the second MACSE storage auction on 24 November, which targets 16 GWh of contracted capacity. The through-line with Spain is the same: regulators are building bankable revenue floors and forcing projects through the queue, tilted toward clean flexibility.

For portfolio managers eyeing Iberia and Italy, this is the moment to line up eligibility rather than wait for the first auction results. Map which of your assets clear the emissions and firmness tests, decide whether a capacity contract or a merchant-plus-ancillary route fits each site, and design for both so a contracted floor and market upside can stack. Not sure which market and service mix fits your assets? You can sketch the options with our knowledge bot, then bring the shortlist to us. Map your Iberian route to market with Fusebox →

Regulatory and market watch

• Nordic FCR-D, go-live this week. The Nordic TSOs’ volume limit on static FCR-D upward regulation goes live on 29 September with delivery day 30 September, initially capped at 50% of Nordic demand for the product (Fingrid’s own share at most 308 MW), which protects the dynamic share that batteries deliver. Method to be refined by March 2028. Fingrid implementation plan.
• Italy MACSE-2, 24 November. Second storage auction targets 16 GWh, with the pre-auction guarantee window shortened to 35 days and the final quota trimmable by any capacity-market 2028 awards in MACSE zones before 4 November. DLA Piper on the 2026 rules.
• Spain capacity market, auctions pending. The order is live, but the first auction calendar and allocation rules are still to come, with analysts flagging incumbent capture as the risk that decides whether new storage actually wins volume. ESS News.
• Netherlands congestion review, December 2026. TenneT and Enexis will reassess the Noord-Brabant congestion-management study, with the RWE Moerdijk battery feeding in, a template worth watching for congestion-relief contracts elsewhere. Energy Global.
• EU flexibility timetable. National flexibility needs assessments feed indicative non-fossil flexibility targets due by January 2027, alongside the Grids Package and permitting files moving through Brussels. ACER flexibility.
• Baltic Q3 balancing review. Litgrid, Elering and AST are due to submit their third-quarter 2026 analysis of balancing services, including the phase-out of demand-reduction reserve, to Baltic regulators. Elering.