IN Brief:
- Volue argues that converging battery hardware costs are reducing the commercial differentiation available from equipment specification alone.
- European day-ahead trading moved to 15-minute products in October 2025, increasing daily periods from 24 to 96.
- Forecasting, capacity allocation, execution, and continuous replanning are becoming more tightly coupled as storage competes across multiple markets.
Volue has published research arguing that European battery returns are increasingly being determined by trading and optimisation performance rather than equipment specification alone as storage fleets grow and electricity markets become more granular.
The company’s From Asset to Algorithm white paper says falling differentiation between battery hardware packages is shifting attention towards grid access, market access, and the quality of trading decisions. Volue’s central argument is that otherwise similar projects can produce materially different commercial results because their available capacity is forecast, allocated, and dispatched differently.
The conclusion should be read as the position of a company that supplies energy-market software and optimisation services rather than as an independent market benchmark. The underlying pressures it identifies, however, are established features of an expanding storage market: finite ancillary-service requirements, changing wholesale price spreads, more frequent trading intervals, and the physical cost of battery cycling.
Frequency response illustrates the problem. Batteries entered several European markets through services that placed a premium on very fast changes in output, but the requirement for those services is limited. As more storage competes for the same procurement volumes, prices can fall and individual projects have to find a larger share of their income elsewhere.
That pushes attention towards wholesale arbitrage, intraday trading, balancing mechanisms, and combinations of services. These markets expose batteries to a larger number of possible dispatch decisions, while each action alters the capacity and energy available for the next opportunity.
The European day-ahead market has also become more granular. Trading moved from hourly to 15-minute products on 1 October 2025, increasing the number of daily periods from 24 to 96. Shorter intervals allow market prices to reflect changes in generation and demand more closely, but they also multiply the decisions required from trading and optimisation systems.
A battery is particularly sensitive to that increased decision rate because it cannot sell the same stored energy into several markets simultaneously. A discharge changes state of charge immediately, while subsequent opportunities depend on whether the asset can recharge in time and whether connection, warranty, or operational constraints permit another cycle.
Round-trip efficiency adds another cost. Energy bought for charging is greater than the electricity eventually returned to the grid, while repeated cycling contributes to degradation of the cells and associated equipment. A strategy that maximises gross trading revenue without pricing those losses can therefore reduce lifetime project value.
Volue’s proposed operating model treats forecasting, capacity allocation, execution, and replanning as a continuous loop. Price and imbalance forecasts guide the initial position, available battery capacity is divided between markets, orders are executed, and the plan is recalculated as prices, forecasts, or plant availability change.
The software layer consequently becomes part of plant operation rather than a separate commercial system. Trading instructions depend on accurate telemetry, state-of-charge information, power limits, communications, market connectivity, and battery management data. A fast optimisation engine working from incorrect plant information simply produces incorrect decisions more quickly.
Portfolio operation makes the problem larger again. Operators controlling several batteries can coordinate capacity across sites and markets, while co-located projects introduce renewable-generation forecasts and shared grid-connection constraints. Longer-duration systems add more possible charging and discharging patterns because their energy capacity can be distributed across a greater number of trading intervals.
Automation is therefore becoming more prominent, although it does not remove engineering limits or commercial accountability. Algorithms can evaluate more market combinations than a manual desk can process continuously, but people still set risk tolerances, contractual constraints, degradation assumptions, and broader trading strategy.
The change in market structure also affects project finance. Revenue forecasts based heavily on one ancillary service become less persuasive once that service is crowded, increasing the importance of assumptions around merchant trading, optimisation performance, and contractual revenue floors. Owners and lenders therefore have to distinguish between the physical capability of a battery and the commercial strategy used to monetise it.
Hardware remains fundamental to power, energy duration, efficiency, safety, degradation, and reliability, so trading software cannot turn a poorly specified asset into a technically different machine. Volue’s argument is narrower: once projects with similar equipment compete in the same markets, the way those physical capabilities are scheduled can become a larger source of variation in realised revenue.
Europe’s growing storage fleet makes that distinction increasingly visible. Connecting the battery establishes what the asset can do; market saturation and shorter trading intervals are making the operating system, forecasts, and dispatch decisions increasingly important in determining how much of that capability earns money.
