Capstone believes investors will prioritise the contracted and hybrid battery energy storage markets of the UK, Italy, and Poland, delivering our estimated 12%-17% unlevered returns, backed by policy support and leverage. The merchant-driven markets of France, Germany, and the Netherlands are volatile and offer tactical opportunities. The key is to scale into the bankable markets before colocation and tariff harmonisation from 2027 crimp returns.
- Fragmented policy has led Europe’s battery energy storage system (BESS) space to split into contracted and hybrid markets in Italy, Poland, and the UK, anchored by long-term capacity or tolling contracts and 12%-17% unlevered internal rates of return (IRR); and merchant-exposed markets in Germany, France, and the Netherlands, where grid fees, construction taxes, and permitting costs suppress returns and widen the financing gap.
- Installation of utility-scale batteries costs €90–€100/kWh, ~35% lower than in 2023. These declines have pushed French and German merchant IRRs near breakeven but still below the weighted average cost of capital (WACC) without tariff reform. Contracted markets enable scaling and leverage; merchant markets approach cost-of-capital viability only when colocated or hedged to power purchase agreements. This pushes developers to prioritise hybrid projects, lenders to focus on contracted revenue stacks, and PE-backed independent power producers to concentrate equity on the bankable cluster while treating merchant exposure as tactical.
- We expect photovoltaic (PV)-BESS colocation will remain the main way to mitigate grid fee exposure, while France moves towards hybrid bankability under its tariff for using its public electricity networks that starts in 2026. However, capex declines and emerging PV-BESS hybridisation will likely shrink IRR spreads between the contracted markets and their merchant peers over the next five years.
- By 2030, as reforms align tariffs and participation rules, returns will normalise to 8%–10%, and the arbitrage between contracted and merchant markets will close.
The BESS investment landscape is shifting: merchant risk vs. contracted bankability
With technology costs becoming broadly similar across markets as battery module and balance-of-system prices fall, grid fees now drive BESS returns more than hardware efficiency. Europe has effectively split into two profiles: contracted/hybrid systems with long-term revenue floors, which support high leverage and stable IRR spreads above WACC, and merchant assets exposed to volatility and grid charges, where returns sit at or below the cost of capital and non-recourse debt remains scarce.
Utility-scale two-hour lithium (Li)-ion systems currently cost €90–€100/kWh, with annualised levelised cost of storage of around €80K/MW, down roughly a third from that in 2023. This brings merchant projects closer to but still below their cost of capital in most markets. At 3%-5%, unlevered IRRs in merchant-driven markets have fallen 300 bps-500 bps below the target WACC, even after capex declines.
The merchant model (Germany, France, Netherlands): arbitrage-driven, trading-intensive
Germany
Across Germany, France, and the Netherlands, developers are structurally exposed to the merchant-driven BESS model. Ancillary service revenues are plateauing as frequency response markets saturate and arbitrage opportunities drive profitability. These markets are volatile, of short duration, and dependent on trading sophistication rather than long-term contracts.
Germany illustrates this dynamic clearly. The market is Europe’s largest by power traded, yet ancillary services account for as much as 67% of income for a typical two-hour battery. However, we expect the prequalified capacity to exceed total Frequency Containment Reserve (FCR, i.e., primary frequency response) demand by 2026, forcing the marginal asset to depend increasingly on energy price spreads. These spreads have narrowed to an average of €80–€90/MWh in 2025 from €120/MWh in 2022.
Under these conditions, a 100 MW two-hour system operating 1,500–1,800 full-cycle hours generates gross revenue of around €80,000/MW, of which roughly €70,000/MW is from arbitrage. With annualised costs of around €75,000–€80,000/MW (capex: €90–€100/kWh; WACC: 8%–9%), the unlevered IRR is approximately 3% (sub-WACC). Non-recourse debt remains limited to around 40%–50%.
If implemented as planned, Germany’s Inertia Market could provide a small, predictable revenue layer (< 1 pp), but its design and pricing remain uncertain. More than 200 GW of projects await grid connection approval, creating a severe execution bottleneck even when the investment case improves.
France
France exhibits a similar pattern but is transitioning faster towards wholesale arbitrage. The country’s ancillary service market is already saturated, with batteries providing 40%–50% of primary reserve capacity despite representing only about 1 GW of installed capacity. At the same time, volatility is surging: 359 hours of negative prices were recorded in 2024, up from 144 in 2023, driven by accelerating solar deployment and limited dispatchable generation beyond nuclear baseload. At present, typical merchant batteries earn around €110K–€115K/MW, only slightly above annualised costs. This results in thin unlevered IRRs of 5%–7%, confirming that standalone projects remain unbankable in 2025.
An experimentation under Tarif d’Utilisation des Réseaux Publics d’Électricité 7 (TURPE 7), the latest version of the French grid tariff, will take effect on August 1, 2026. This tariff reform introduces an optional component rewarding storage operators for discharging during local system stress, especially in southern regions with high solar output. Early modelling suggests IRRs could rise by up to 2 pp, but outcomes depend on implementation and site selection. Even with this uplift, IRRs for post-2026 projects are likely to stay near WACC until land and construction costs stabilise.
PV-BESS colocation is a clear trend to watch across Europe because it turns otherwise marginal merchant projects into viable hybrids by sharing grid infrastructure and improving revenue stacking. PV-BESS colocation means batteries are installed behind the same grid connection point as a solar plant, sharing grid infrastructure and using PV output to charge the battery, which reduces grid fees and volatility exposure. The pending ICPE 2925 rule — the French environmental permitting regime for BESS that includes 12-metre spacing and 5-metre emergency lanes — could raise civil costs by 10%–15%, partly offsetting the benefit. Until finalised in early 2026, France remains a transitional market offering tactical entry opportunities for sophisticated operators able to model execution risk.
The Netherlands
The Netherlands faces a more structural challenge rooted in grid economics. Although merchant price spreads can generate €140K-€150K/MW in gross revenue, annual grid fees are as high as €56K/MW. These fees, which quadrupled in a single year due to severe transmission congestion, now absorb around 40% of total potential income. Once opex and debt service are included, standalone projects yield only 4%–5% IRRs — well below the 10% WACC. Colocated projects charging behind the meter (BTM) from solar or wind currently provide the only positive risk-adjusted returns.
Severe congestion compounds the problem, with 70 GW of projects waiting for 9 GW of connection capacity. Until the government legislates exemptions for double-charging (storage pays network fees both when charging and discharging) and connection fees, expected after 2027, the standalone storage model remains unviable. Only colocated projects, charging BTM with solar or wind generation, currently offer positive risk-adjusted returns.
TenneT, the Dutch transmission system operator (TSO), has proposed a dynamic grid fee structure and non-firm connection model under which fees could be reduced by 65%–75% in exchange for 15% access curtailment. This model could improve project economics if the curtailment periods do not coincide with high-revenue dispatch hours. However, bankability will remain constrained until full exemptions are enacted.
Conclusion
Overall, merchant markets offer operational upside for sophisticated traders capable of managing complex revenue stacks and volatility exposure. However, these markets lack the policy stability and leverage conditions required for institutional capital to scale at the pace needed to meet EU storage targets.
PV-BESS colocation is likely the way forward, particularly in France and the Netherlands, as this enables colocated assets to avoid double-charging and reduce grid-exposure risk. Its potential to become dominant will depend on network-tariff reform and exemptions that determine whether standalone assets continue to face higher grid costs.
The contracted/hybrid model (UK, Italy, Poland): How to secure bankability
In contrast to merchant systems, Italy, the UK, and Poland have adopted frameworks that translate policy certainty into financial leverage. Each market offers a form of long-term contracted revenue that allows projects to be underwritten on a debt-leveraged basis, enabling faster capital deployment and more predictable returns.
Italy
Italy’s Meccanismo di Approvvigionamento della Capacità di Stoccaggio Elettrico (MACSE) remains the backbone of the country’s bankable storage market. The scheme provides 15-year capacity contracts awarded through competitive auctions, giving standalone batteries a contracted revenue floor that covers most fixed costs. As a result, even non-colocated systems operate in a hybrid revenue structure, combining stable capacity payments with merchant spreads.
With total installed costs of around €400K/MW (€220K/MW for power, €190K/MW of energy capacity (two hours at ~€95/kWh)) and project finance leverage close to 70%, projects deliver ~12% unlevered IRR against ~5% WACC, supported by low debt costs (~4%) and limited grid exposure. This makes Italy one of Europe’s few genuinely bankable hybrid markets, combining contract stability with merchant upside.
TSO Terna’s 2030 target of 70 GWh of storage indicates long-term visibility, consolidating Italy’s position as the anchor of Europe’s hybrid BESS model.
The United Kingdom
The UK represents Europe’s most mature and liquid BESS market, underpinned by long-term tolling or floor-price contracts that allow project financing at scale. These agreements provide stable, quasi-contracted revenues complemented by wholesale and balancing income.
With total installed costs near €420K/MW and leverage of around 70%, projects reach ~12% unlevered IRR versus a ~5% WACC, with strong lender appetite for tenors of 10–15 years.
The rise of colocated PV plus BESS systems improves economics by avoiding double grid costs and capturing daytime spreads. The government’s new Cap-and-Floor mechanism for long-duration storage adds another support layer, making the UK Europe’s most scalable and financeable BESS market.
The recent Review of Electricity Market Arrangements (REMA) decision to retain a single national price rather than adopting zonal pricing reinforces long-term stability by ensuring uniform balancing costs and preserving market liquidity.
Poland
Poland combines high returns and higher risk as a first-mover market. The capacity market provides 10- to 17-year indexed contracts that underpin long-term cash flow visibility, complemented by merchant and ancillary services revenues.
With total capex of around €420K/MW, leverage near 60%, and cost of debt around 5%, projects deliver ~17% unlevered IRR for a ~7% WACC. These strong returns reflect both early scarcity and robust contract support.
We expect returns to normalise as capacity prices decline and competition increases but believe that Poland will remain a top-quartile BESS market offering a premium over merchant alternatives through the late 2020s.
Spread
Capstone’s IRR estimates are based on standardized two-hour Li-ion systems (1,500–1,800 cycles/year, 15 years of life).
Contracted markets such as Italy, Poland, and the UK now deliver high unlevered IRRs, while merchant markets like Germany, France, and the Netherlands remain below the cost of capital. The 400 bps–800 bps spread between bankable and merchant markets continues to reflect regulatory fragmentation rather than technology cost differences.
Comparative policy landscape — BESS investment bankability (as of 2025)
The table below summarizes the financial landscape across Europe’s core battery storage markets, illustrating the sustained divergence between contracted and merchant investment profiles.| Market | Model | Unlevered IRR | WACC | Spread | Bankability score |
|---|---|---|---|---|---|
| Poland | Contracted (capacity market) | 17% | 7% | +950 bps | 60% |
| Italy | Hybrid (MACSE + merchant) | 12% | 5% | +700 bps | 70% |
| UK | Contracted (tolling/floor) | 12% | 5% | +650 bps | 70% |
| France | Merchant → Hybrid (2026+) | 5% | 8% | –300 bps | 50% |
| Germany | Merchant + Inertia (2026) | 3% | 8% | –500 bps | 50% |
| Netherlands | Pure merchant (congested) | 5% | 10% | –480 bps | 40% |
Source: Capstone analysis
Why the Gap Persists
Three structural barriers prevent IRR convergence before EU-level tariff harmonisation takes effect.
The first is tariff and grid fee fragmentation.
Germany’s Bahnstromkostenzuschlag construction tax, upheld through 2029, reduces project IRRs by approximately 4 pp through unrecoverable grid connection charges. The Netherlands’ unresolved double-charging regime renders standalone storage uneconomical, as described before. France’s TURPE 7 experimental reform, effective August 2026, offers partial mitigation through countercyclical tariffs that reward locational flexibility, but the ICPE 2925 spacing rule adds 10%–15% to capex through increased land footprint requirements. Until these divergent cost structures are harmonised, merchant markets will remain structurally disadvantaged relative to contracted alternatives.
The second barrier is permitting and connection execution risk.
France’s ICPE 2925 regulation raises project construction costs and extends timelines. Poland’s 450-day average connection wait limits the buildout pace despite auction success and strong capacity market fundamentals. The UK’s 700 GW connection queue — although being addressed through Connections Reform, requiring demonstration of land rights and Financial Investment Decisions, creates legacy delays that persist even as new frameworks improve forward visibility.
The third barrier is EU-level reform lag.
The Network Code on Demand Response, expected to be adopted in early 2026 by the Agency for the Cooperation of Energy Regulators, will standardise flexibility participation rules and data exchange requirements across Member States. However, implementation remains national and gradual. Stakeholders have expressed strong concerns that starting with 27 different national models for aggregation and prequalification could perpetuate fragmentation for 2–3 additional years. The EU Battery Regulation, effective February 2024 and requiring Digital Battery Passports from February 2027, adds compliance cost before the yield benefit materialises. The forthcoming EU Grid Package, expected by end-2025, targets double taxation elimination and permitting streamlining but allows Member States’ discretion in transposition. Full harmonisation is therefore unlikely before 2028–2029, sustaining fragmented economics and leverage divergence through the rest of the decade.
Implications
Between 2025 and 2027, investors should prioritise exposure to contracted and hybrid markets, where leverage and long-term policy support enable scaling. Poland offers the highest near-term returns, although these will compress as the market matures. Italy and the UK provide steadier, more institutional-grade investment profiles.
From 2026 onward, France will offer tactical upside as the TURPE 7 tariff and market reforms raise IRRs by up to 4 pp. Germany will remain merchant and trading-driven, while the Netherlands will stay constrained until regulatory reform addresses grid costs and double-charging.
By the end of the decade, as EU-level reforms align tariffs and participation rules, returns will converge towards 8%–10%, and the current arbitrage between contracted and merchant markets will gradually close.
What’s Next
- Germany – Inertia Market (January 2026): design/price sheet finalisation; watch if contracts add 0 bps–200 bps to merchant stacks; clarity on post-2029 grid-fee exemptions.
- France – ICPE 2925 ruling (Q4 2025–Q1 2026) and TURPE 7 BESS experimentation (August 2026): spacing/civil-works cost impact vs. tariff relief; reassess IRR delta by region (south vs. north).
- Netherlands – Double-charging and congestion relief (2026–2027): track TenneT’s non-firm connections/dynamic fees; base case still sub-WACC unless colocated.
- Italy – MACSE auctions (2026): volume/strike outcomes for 15-year capacity; leverage availability at 65%–75% and pricing of merchant upside.
- Poland – Capacity market (2026): clearing price trajectory towards €60K–€70K/MW-year; IRR normalisation path (still premium vs. merchant EU).
- UK – REMA implementation (2026): tolling/floor structures and BTM access; confirm around 12% unlevered IRR as costs fall.
- EU level – Demand Response Code (2026): participation reforms gradually compress returns towards 8%–10% unlevered by decade-end.
