Despite repeated attempts — mostly from the right of the European political spectrum — to slow down electrification to protect carmakers that failed to prepare in time, electric mobility is progressing rapidly across Europe. This was a policy-driven market, and it suddenly shifted to a customer-driven market. The 2026 fuel-price surge now acts as a key driver, independent of subsidies. Finally, the convergence with solar and storage turns the electric car from a transport object into an energy asset: the photovoltaic–battery–plug-in-vehicle triptych is not only the business model of tomorrow but also the key driver of an accelerating energy transition.
Before discussing mobility, one fact must be established, because it structures everything that follows: the European photovoltaic is hitting the physical limits of an electricity system without storage — and storage has become the key enabler for PV to keep growing.
Solar is now Europe’s cheapest source of electricity, but its economics are deteriorating precisely because of its own success. With today Eu’s PV fleet around 450 GW and the minimum power demand in the EU around 200 GW, it is obvious that most countries record negative prices on their electricity market. Germany alone recorded 573 negative-price hours in 2025, and this is developing in 2026. In addition to increased curtailment, the impact is visible on the profitability of all installations depending on merchant business models.
This is where battery storage comes in, driven primarily by utility-scale systems (but not only). Annual installations are expected to exceed 50 GWh in 2026 and will most probably triple by 2030. Storage does three things for PV: it absorbs midday surplus that would otherwise lose its value, it lifts the captured price of solar by shifting delivery to high-value hours, and it relieves congested grids. With storage, each additional solar kWh keeps a value.
But storage isn’t just about batteries, and we count three “storage fleets” in Europe. Putting the numbers side by side is revealing: stationary batteries represent around 100 GWh/20 GW in Europe, to be compared to a maximum of 1300 GWh/80 GW at least of pumped-storage hydro in Europe (including Norway), and more interestingly the roughly 10 million EVs on the road at the end of 2026 in Europe represent at least 500 GWh of energy stored, and at the current speed, the 1 TWh mark will be reached in 2027.
Three lessons emerge. First, stationary batteries are still the smallest of the three fleets. Second, the EV fleet has quietly become Europe’s second-largest storage system: the batteries already circulating in cars on European roads collectively store as much energy as all pumped-storage lakes combined — and unlike pumped-hydro, this fleet will multiply. Third, the comparison redefines the policy question: the cheapest new “storage lake” Europe can build in the 2020s is not carved into a mountain — it is the aggregation of batteries that consumers are already buying for transport, parked and plugged 95% of the time. This is precisely why V2G and the remuneration of distributed services matter more than any subsidy for dedicated utility-scale batteries.
Starting from the Nordic countries, the EV revolution progresses fast, much faster than most policy makers had foreseen. Norway has reached 98% of its market, while countries such as France or Belgium are approaching the 50% threshold. Lower-income countries such as Spain, Italy and Eastern Europe start from a lower base, but the gap is closing: in 2026, BEV registrations are progressing fast, at a relatively low level. In countries with proactive policies such as Portugal, political will demonstrates that wealth is not the decisive variable. At the same time, Italy remains the large Western European market where electric weighs the least (below 10% BEV): This is probably no coincidence: the country hosts manufacturers (Fiat/Stellantis mostly), whose strategy has been to defend combustion engines and mild-hybrid technology rather than electrify the offer. Remarkably, the companies that lobbied hardest for protection are often the ones that suffered most — not from electrification, but from their own immobility. And the harsh lobbying of Germany, Italy and the EPP group in the European Parliament to water down the CO2 emissions rules won’t change that.
Since February 2026, fuel prices have risen sharply: +29% for petrol and +40% for diesel since the start of the year, with all-time records that led to all-time records EV sales. That acceleration that is visible globally will have long-lasting consequences not only on the automotive market but also the energy system. In France for instance, orders for electric vehicles reached close to 50% in September and the trend is visible almost everywhere (except in the USA).
This is the central point of this paper. Electric mobility is not just an engine substitution; it is the third pillar of a coupled, distributed energy system: charging your car from your own rooftop PV cuts the per-kilometer cost by 50–70% versus grid charging, and makes residential/commercial self-consumption more profitable. Adding a stationary battery absorbs the midday surplus and charges the car in the evening; add now Vehicle-to-grid (V2G) with bidirectional charging, the car becomes a mobile battery that stores excess solar and returns it to the building or the grid — turning every car parc into a flexibility asset that absorbs variable renewables.
Vehicle-to-grid is no longer a laboratory curiosity. In 2024–2026 it crossed into commercial maturity. Regulation has been unblocked in several countries, such as in Germany where the latest version of the Mispel regulation will allow bidirectional charging smartly and almost on a par with stationary batteries. Mercedes-Benz launched its V2G package for private customers in Germany in October 2026, and roll-out to other countries is planned. Renault is the French pioneer: the electric R5 is the brand’s first car with a native bidirectional on-board charger. Renault France now markets the full bundle with an electricity contract with “V2G Hours” gains. Other car manufacturers such as BMW, Ford and Volkswagen/Elli and BYD are following. Notably, Renault’s roadmap also shows the regulatory asymmetry at work: the R5 launched with full V2G capability in France and the UK, but without it in Germany, which was still awaiting its regulatory framework, a perfect illustration that the market moves at the speed of policy.
This will reshape distributed storage: a parked EV is a 60–100 kWh battery that sits idle 95% of the time. Even at low participation rates, the aggregate flexibility of a European EV parc of tens of millions of vehicles dwarfs any conceivable stationary fleet. The aggregation of captive fleets turns each charging session into a dispatchable resource. The system consequence is profound: the marginal cost of flexibility collapses, and the need for dedicated grid-scale batteries in dense urban areas falls accordingly. This could even challenge significantly the business of stationary batteries.
For solar investors, the era of “generate and collect” is ending. As negative-price hours multiply and captured prices fall, the value of a PV asset will increasingly be created by stacking several remunerated services on the same physical asset — and storage is the enabler.
The stack, from the fastest to the slowest timescale:
The numbers validate the model: revenue for a battery in Europe ranges from €40–65k per MW-year in single-market arbitrage configurations to €105–160k+ per MW-year with full multi-market stacking (FCR, aFRR, mFRR, fast frequency response, capacity payments). Germany’s Innovation Tenders go further still, paying a 20-year fixed premium on energy injected from hybrid solar+storage plants. The “solar+storage hybrid” is thus becoming the default design for new utility-scale PV: co-location shares interconnection and balance-of-plant costs, storage lifts the captured price, and grid services provide contracted, financeable income on top of merchant energy sales.
The revenue-stacking figures quoted above are a snapshot, not a trajectory — and the early evidence says unit revenues fall as batteries deploy. The perfect example is Great Britain: frequency services usually made up 80% of the BESS revenue mix in 2022, collapsing to 20% by 2024, with frequency-response prices falling roughly sevenfold as installed capacity outgrew the bounded technical need (the GB grid requires only 0.6–1.5 GW of Dynamic Containment at any time). The same arithmetic is now visible in continental Europe: battery capacity is on the verge of surpassing total FCR demand. Capacity markets are themselves a policy variable, not a constant: Poland’s December 2025 auction downgraded battery availability factors and cut total awards; Germany’s BNetzA grid-fee draft decisions still create uncertainty; and Spain’s brand-new capacity market (€800–900 million per year) has yet to prove that new batteries, rather than incumbent plants, will win the auctions. The decline in capacity prices could cause a sharp drop in BESS revenues, and that the capacity market “is not the definitive solution” for bankability.
Two implications follow for PV-plant strategy: business cases must be built on declining per-MW revenues from existing services, offset by falling battery costs and by the opening of new remunerated services (reactive power, inertia, congestion management which are precisely the ones not yet saturated). This uncertainty is one more argument for integrating EV flexibility into the stack: adding V2G capacity expands the serviceable market without adding dedicated capex, and demand-side participation grows as legacy stacked revenues decline.
The bankability imperative is clear: services to the grid must be remunerated. Today, most system services (frequency control, voltage regulation, inertia, black start, congestion management) are still not properly remunerated across most of the EU.
The solar–storage–mobility trio must be designed increasingly as one system and will soon provide enough assets to levelized electricity prices throughout the day. The current imbalance between consumption of PV electricity at midday is a temporary situation: with low or negative prices, the market will adapt, and the fast development of BESS is clearly a consequence of that situation. The fast development of EV in Europe will accelerate this rebalancing and it is most probable that PV+BESS+EV will generate and dispatch most of the electricity needed during half of the year in Europe.
The winter challenge requires to further develop wind power, interconnections in Europe and long-term storage of energy, while PV will benefit at that time of the year, of high market prices, that BESS+EV will allow to be bankable.
The question of the bankability of PV+BESS might be helped significantly by EVs while the regulatory situation to support a clear remuneration of the PV and BESS fleet needs to progress fast. The creation of value for every kWh generated will be at the core of all discussions on PV+BESS business models in the coming years, with a fast evolving development of complex revenue stacking business models, having to be adapted locally, regionally and nationally with the increasingly diverse grid services remunerations put in place.
Author: Gaëtan Masson, CEO and Founder, Becquerel Institute.
Becquerel Institute is a strategic consulting and applied research company specialising in solar photovoltaics, storage and energy transition. Founded in Brussels in 2014, with regional offices in France, Italy and Spain, it provides strategic advice across all segments of the PV value chain including market trends, analysis of development conditions and political and regulatory frameworks, assessment of production costs, etc. Becquerel Institute applies this expertise to support companies in Europe, America, Asia and Africa, and is a recognised partner in European and international research projects. The company also actively supports international organisations and associations
The views and opinions expressed in this article are the author’s own, and do not necessarily reflect those held by pv magazine.
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