BSEIF’s Energy division has published Financing Battery Energy Storage: Revenue Models, Risk Allocation and Bankability, the fifth piece of official divisional research released by the association and the first full paper to follow the four initial statements. It was written by Antonio Puliafito, Head of Energy, with Marco Frizzele, Matteo Mascaretti, Simone Zordan, Gaetano Pinho and Alfonso Santojanni, and it covers the revenue models of battery energy storage systems (BESS), the risks attached to them, the instruments that improve bankability and the state of the Italian market.
The paper starts from the growth of the asset class. According to the International Renewable Energy Agency, the total installed cost of utility-scale battery storage fell from $2,571/kWh in 2010 to $192/kWh in 2024, a decline of approximately 93%, and the International Energy Agency reports that 108 GW of new battery storage capacity was installed worldwide in 2025, 40% more than in 2024. Falling costs have not settled the financing question, however. The paper asks how a project can attract long-term debt when both its revenues and its operational performance are uncertain.
It answers first by taking the revenue model apart. A battery can earn from energy arbitrage, ancillary services and capacity markets, but capacity committed to one stream is unavailable to the others. A worked example puts the mechanism in figures: a 100 MW, 400 MWh battery with 85% round-trip efficiency that charges at €50/MWh and discharges at €150/MWh earns a gross margin of approximately €36,471 per cycle, before degradation, trading fees and other operating costs. The paper then names two risks. The first is cannibalisation, since more batteries in the market compress arbitrage spreads and ancillary-service prices. The second is the high upfront capital cost and the operational exposure of lithium-ion technology, from fire to degradation.
The financing section follows the lender’s view. Debt is sized on the debt service coverage ratio, so a project generating €10 million of cash flow available for debt service under a 1.30x minimum can carry at most €7.69 million of annual debt service. Revenue predictability therefore sets the capital structure. The paper reviews three ways of transferring market risk: tolling agreements, such as ECO STOR’s five-year contract with Alpiq for the Schuby battery, which supported financing from NORD/LB without public subsidies; revenue floors, such as Econergy’s two ten-year contracts with EDF for the Immingham battery; and TBx swaps, which hedge an arbitrage spread index without the battery itself, at the cost of a hedge that diverges from the asset’s actual performance.
Italy is the case study. Cumulative storage capacity exceeded 19.3 GWh in 2026, and Terna’s MACSE mechanism pays successful bidders a fixed annual premium for 15 years in exchange for building and making available new storage. The first auction, held on 30 September 2025, procured 9,968 MWh at an average premium of approximately €13,000/MWh-year, with supply more than four times demand. The second is scheduled for 24 November 2026, with a maximum premium of €27,000/MWh-year set by ARERA. The paper then traces how capital reaches the sector, from Enel, which secured 6.7 GWh in the first auction, and Eni’s battery plant at Brindisi, to Sosteneo’s purchase of a 49% stake in Enel Libra Flexsys for nearly €1.1 billion. Its conclusion is that bankability depends less on how much revenue a battery generates than on how that revenue is structured and how its risks are allocated.
The full paper is available under Insights, in the Energy section. It can be read on the website, opened separately or downloaded as a PDF.