P415 and its equivalents across Europe

Key findings

• A battery can reach wholesale prices in one of two ways: through a supply contract that passes the price through, or by letting an independent aggregator trade it. The second needs a market rule to exist.
• Of the ten European markets examined here, only Great Britain and France have a route an aggregator can use in practice.
• Belgium has written the rule and recorded no use of it. Ireland has been designing one since 2019. Germany requires the supplier's agreement. The Netherlands, Spain, Portugal, Italy and Switzerland have nothing.
• Great Britain's rule works by spreading the cost of compensating suppliers across everyone's bills. That has proved open to abuse, and from 24 August 2026 generators exporting more than 10 MW have been shut out of it.
• For a commercial or industrial site, the practical route in eight of the ten markets remains the supply contract.

The importance of accessing wholesale electricity pricing

A battery largely earns money by charging when electricity is cheap and discharging when it is expensive. To do that it has to either:

• be used at a building which has a contract that passes the half-hourly market price straight through to the end user, or
• allow a third party to trade the battery on the wholesale market, leaving the supply contract alone. This route requires permission from the market's rules.

While full pass-through tariffs are widely available across Europe, they are rare in practice because of the perceived risk of being entirely at the mercy of the wholesale market. That risk is real: the most expensive half hour of 2025 in Great Britain settled at £1,353 per MWh, roughly seventeen times the year's average of £80.

In this article, we explore the second of these two options, exploring the state of play across ten European markets, and demonstrating that it is only in the UK and France where this second route is widely accessible.

Route one: Great Britain, where everyone shares the bill

Since November 2024 an independent aggregator can register with the electricity settlement system in its own right and trade flexibility without the site's supplier taking any part in the trade.¹

However, this creates an upstream issue as the supplier buys electricity in advance expecting the consumer to use it and if an aggregator turns demand down, the supplier is then holding energy it has paid for and cannot sell. It is therefore necessary for the supplier to be compensated, and in Great Britain that compensation is spread across every supplier in the market, which ultimately means consumers.²

That is a fair arrangement when the site really did use less. The difficulty is that the payment is calculated against a baseline, which is an estimate of what the site would have done anyway. Nobody can observe what would have happened. It has to be predicted, and this leaves the scheme open to abuse. Ofgem said as much before the rule went live, warning in its own analysis of the potential for an aggregator to “beat the baseline” without deploying any flexibility at all.³

How the scheme was exploited

Between September 2025 and February 2026 about 19 million pounds went through the compensation pot, and most of the growth came from large generators rather than from the consumer-led flexibility the route was built for.⁴

To put that in perspective, The Demand Flexibility Service, the national scheme that pays households and businesses to shift their demand, provided £1.2 million of rewards to consumers across the whole of winter 2024/25, with almost two million meters signed up. The compensation pot paid out roughly sixteen times that figure in six months, purely for squaring the books after a trade.

Consequently, as of 24 August 2026, a site whose largest half-hourly export over the past year was above 10 MW is now shut out of the route. If the largest export is under 2 MW, it remains in the scheme, and for those that sit between the two thresholds, if the site imported more than it exported over the past month, it can remain in the scheme. As such, for commercial and industrial battery storage, where exports are much lower than these thresholds, nothing has changed.

Route two: France, where the aggregator pays the supplier

Since 2014, in France an approved operator can sell a site's flexibility into the wholesale market, and RTE is explicit that the supplier's agreement is not required.⁵ However, as opposed to moving the cost to consumers, France publishes the price payable by an aggregator to a supplier. In 2025 an aggregator moving a remotely-metered site paid its supplier 62.00 euros per MWh in winter off-peak hours and 98.91 euros in winter peak hours, falling to 50.40 and 51.60 euros over the summer.⁶ Everyone can price the deal in advance, and there is much less room for manipulation, but equally trades are more expensive and consequently there are fewer of them.

Why it matters who pays the supplier back

You would expect an aggregator to prefer the version where it pays nothing. However, in March 2026 Flexitricity, an aggregator, formally asked to be made to pay.⁷ The reason for this is chiefly that a shared pot rewards flexibility in one direction only. An aggregator that turns a site's demand down sells the electricity that was not used and keeps the proceeds, while the shared pot pays the supplier back. An aggregator that charges a battery during periods of oversupply, when wholesale prices are low, receives nothing, because the supplier then takes the full benefit by billing the site at the retail price. Flexitricity's proposal would make the compensation run both ways, so that whoever gains from an action is the one who pays for it.

Furthermore, the pot ballooned to 19 million pounds in six months and the response from Ofgem was to exclude an entire class of asset from the scheme. An aggregator whose business depends on this scheme would rather pay a fair price and ensure that it remains open.

No clear route: Germany, the Netherlands, Spain, Portugal, Italy and Switzerland

Germany recognises independent aggregators, and they can prequalify for the balancing markets. For the wholesale market an aggregator needs a compensation agreement in place with the site's supplier, which brings the supplier's consent back in through the side door. One per cent of German customers are on a dynamic tariff and four per cent have a smart meter, against a target of twenty per cent by 2025 that was missed.⁸

The Netherlands recognises independent aggregators but gives them no wholesale access. The revised Energy Act, in force since January 2026, obliges suppliers to offer dynamic tariffs, which strengthens the supply-contract route. Four per cent of households and nine per cent of business customers are on dynamic contracts, on 89 per cent smart meter coverage.

Spain does not recognise independent aggregation at all. The framework that would have introduced it was written after the Iberian blackout of April 2025, and Spain's Congress rejected it in July, repealing the decree after 28 days.⁹ The replacement passed in November left the provision out. Spanish sites do have the retail route: smart metering is complete, 40 per cent of households are on the regulated hourly tariff and 19 per cent of business customers are on dynamic contracts, which is the highest of the ten markets here.

Portugal is earlier still, with a national flexibility assessment due in 2026 and demand-side response described by the International Energy Agency as at an early stage of development.

Italy allows aggregation in its balancing markets under the UVA framework but not in the wholesale market, and new aggregators could not even join the balancing markets between the end of 2024 and February 2026. Italian smart metering is near universal at 98 per cent, and dynamic tariff take-up is zero among households and three per cent among business customers.

Switzerland sits outside all of this. It is not in the European Union, so none of the rules above apply to it, its retail market is open only to sites using more than 100 MWh a year, and an aggregator working for retail customers is confined to the balancing market.

Belgium and Ireland, where it is still being designed

Belgium's Transfer of Energy framework has the same design as France, allowing an independent aggregator reach the wholesale market, with regulated compensation to the supplier. However, no activation has ever been recorded in those markets.⁸ The principal reason for this is that the framework reaches only medium and high voltage customers, so the addressable market is relatively narrow. From 2026 the framework extends to smaller assets, which may encourage a greater level of adoption.

In Ireland, a route for participation exists, but it is designed for large blocks of demand rather than individual buildings. An aggregator has to assemble at least 4 MW before it can bid anything in, so no single site qualifies on its own. Furthermore, the payment side was never settled: the scheme pays for energy only in the relatively rare hours when prices climb above a set threshold which has not proven to be sufficiently enticing for most aggregators. Irish regulators proposed a fix in March 2026 and closed the consultation on it in July, without reaching a decision.

How much price movement there is to work with

The value of any of this depends on how far prices move within a day, which varies more across Europe than the regulatory picture does. We measured the 2025 day-ahead year in all ten markets: the widest daily spreads sit in the Netherlands and Germany, and Great Britain, which has the most developed access rules of the ten, has one of the narrowest. The figures, and what they mean for how a battery should be sized in each market, are set out separately in what a battery has to work with: day-ahead price spreads in ten European markets.

What this means for a site owner

The UK and France stand out as the only markets in Europe with an established approach to letting a party other than the supplier trade a site's flexibility. In every other country in Europe, that route is either unbuilt or unused.

Outside those two markets, a behind-the-meter battery still makes sense when it is paired with a time-of-use tariff, even one that does not fully reflect the wholesale price. A tariff with three to five bands can still often earn a good return, especially when stacked with other sources of revenue.

However, batteries really come into their own where there are import capacity restrictions, or plans to increase a site's load substantially. In those cases the battery is not chasing a price at all. It is buying headroom on a connection, and the value of that does not depend on any of the market rules described above. We have worked that case through on a real meter in how battery storage can facilitate heating electrification and commercial fleet charging.

Common questions

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