The shift to 15-minute electricity pricing is reshaping the economics of BESS in Europe, expanding arbitrage opportunities and improving long-term return prospects.
How 15-minute pricing is transforming BESS in Europe
BESS in Europe are entering a new economic phase following the EU electricity market reform, in force since October, which introduced 15-minute price intervals instead of hourly settlement in the day-ahead market.
The reform affects the day-ahead market and broadens arbitrage opportunities for battery energy storage systems. According to analysis by Rystad Energy, the arbitrage potential across European power markets has increased on average by 14%.
In some countries the increase exceeds 20%, while in others it remains marginal. Overall, the reform improves profitability prospects for BESS, with measurable effects on long-term investment returns.
Why moving from hourly to 15-minute pricing favours storage
Historically, European electricity markets set prices on an hourly basis. With the introduction of 15-minute Market Time Units, the market now provides four pricing windows within each hour.
This creates more opportunities for storage operators to buy electricity at low prices and sell when prices rise, capturing faster and more frequent fluctuations. Intraday trading at shorter intervals proves more profitable than traditional hourly arbitrage.
In Lithuania, for example, shifting energy over 15-minute intervals generated revenues of 263 dollars per MWh, around 14% higher than hourly arbitrage. In Germany, quarter-hour arbitrage profitability is approximately 16% higher compared to the previous hourly scheme.
Intermittent renewables and volatility: where arbitrage grows most
The benefits are not uniform. In power systems with high shares of non-dispatchable renewables such as wind and solar, production can fluctuate rapidly even within the same hour.
This results in sharper price swings that BESS can better exploit under shorter market intervals. The largest increases in arbitrage potential are recorded in these systems. By contrast, in countries with highly flexible generation mixes, price variability is more contained.
In Norway, supported by hydropower, and in Portugal, where hydropower and gas stabilise the system, the differential between 15-minute and hourly arbitrage is significantly smaller.
How new margins affect returns and investments
Higher arbitrage opportunities directly influence plant profitability. The analysis indicates that a roughly 20% increase in annual revenues linked to the new pricing dynamics may translate into a 3% rise in overall return on investment over a 20-year horizon.
Rystad Energy compared two scenarios: one based on 15-minute markets and another on hourly markets. In the former, a single arbitrage cycle requires four charging and four discharging phases, compared to one charge and discharge cycle in the hourly model. This results in more opportunities to monetise stored energy, even with the same installed capacity.
High margins are not guaranteed in the long term
The analysis cautions against excessive optimism. Current arbitrage margins, estimated at around 150 dollars per MWh, are considered exceptional and unlikely to persist.
Over a 10–20 year horizon, a more realistic average is around 60 dollars per MWh, corresponding to an internal rate of return of roughly 6% for pure arbitrage.
Greater market granularity could lift average revenues to around 70 dollars per MWh, adding approximately three percentage points to IRR, but without removing structural uncertainty linked to price volatility.
Lessons from non-European markets
Australia provides a useful benchmark. When markets shifted from 30-minute to 5-minute pricing in 2021, arbitrage revenues increased steadily. In New South Wales, annual revenues rose by about 20%, while in Victoria hourly arbitrage revenues increased by around 15%.
However, even for BESS in Europe, arbitrage represents a theoretical maximum rather than guaranteed revenue. Efficiency losses, plant availability, market liquidity and hedging strategies all reduce actual revenues compared to theoretical potential. The new pricing structure improves conditions, but it does not eliminate structural risks linked to electricity price volatility.
Also read: “The recipe to halve Europe’s gas and coal use? Next-generation geothermal“
