Insights

What Makes a BESS Project Bankable in Southeast Europe in 2026

The battery works. The question is whether the project can carry debt.

Elevat Solar Consulting · October 2026 · 8 min read

The BESS market in Southeast Europe has moved past the phase when installed megawatts were the main headline. The technology is mature, projects are multiplying and capacity is growing fast. The next question is harder. Which of these projects can be financed with a reasonable level of debt and stay resilient when revenues, contracts and technical assumptions are put under stress?

That is where bankability begins.

Around mid-2024, Bulgaria had about 200 MWh of installed batteries. By May 2026, ESO, the transmission system operator, reported 3,432 MW of storage capacity (Emerging Europe, 10.08.2026). Ember puts installed capacity at 8.6 GWh as of May 2026 (Ember, 12.08.2026). Aurora Energy Research cites 1.28 GW of battery power by 2030 in Bulgaria's Integrated National Energy and Climate Plan (TaiyangNews, 13.05.2026). According to the European Commission's assessment, the final plan contains no storage targets (SWD(2025) 140). The market is already ahead of that figure.

According to Ember, the batteries added in 2025 are theoretically sufficient to shift 77% of Bulgaria's new daily solar generation into the hours without sun. That is the highest share among the markets analysed, ahead of Chile at 76% and Australia at 60%. The figure is a theoretical maximum and does not reflect energy actually shifted day to day. Even so, it shows the scale of the change.

In the fifth edition of Aurora Energy Research's ranking of European battery market attractiveness (23.02.2026), Bulgaria and Romania are among the top ten of the 28 countries covered. I am inclined to think that grants, EU recovery funds and the support schemes already completed have accelerated a market that barely existed a few years ago.

But building a battery and financing a battery are two different tasks.

What bankability means

Bankability is a project's ability to generate cash flow predictable enough, over the life of the loan, to service the debt with the required headroom even when some of the assumptions turn out worse than expected.

A project with first-class equipment, a strong EPC contractor and a good site may still fail to reach financial close if its revenue structure does not convince the lender.

The reverse holds too. A fairly ordinary project with stable contracted revenue, reasonable delivery risk and protected technical parameters can be considerably more financeable.

That is why I would start a BESS assessment from the risk.

The revenue structure

A BESS asset can combine several sources of revenue.

Energy arbitrage. The battery charges at low prices and sells at higher ones. In Bulgaria and Romania the typical daily profile combines cheap solar hours around midday with higher evening prices.

Ancillary services. Frequency regulation, balancing and reserves can earn high revenues, especially in the early phases of a market. But these markets are limited in size, and as more batteries enter, revenues in them should normalise.

Capacity payments. Where capacity mechanisms exist, a BESS can be paid for availability. Such mechanisms exist, for example, in Italy, Poland and Belgium. Italy also has MACSE, a separate mechanism for long-term storage capacity. Its first auction, held by Terna on 30.09.2025, awarded 10 GWh for delivery from 2028.

Combining markets. I think value increasingly comes from optimisation across the day-ahead market, the intraday market, ancillary services and the other markets available.

The European BESS Index shows how wide the revenue gap between individual European markets can be. According to the index, professional optimisation of market bidding delivers a result 30 to 50% better than a simple strategy (updated 29.03.2026).

These figures cannot be carried over mechanically to Bulgaria and Romania. In my view, they show that the value of a BESS now depends as much on the trading and optimisation strategy as on the equipment itself.

The core conflict: the lender wants predictability, BESS sells volatility

This is the central tension in financing batteries.

A lender prefers contracted, predictable cash flow. Most BESS revenue, however, is merchant. It depends on exchange prices and markets that nobody can guarantee ten years ahead.

A fully merchant project carries the highest risk. It may offer a high return on equity, but it supports less debt, at a higher cost.

That is why the market has developed contract structures that turn part of this volatility into more predictable cash flow.

Tolling agreement. A creditworthy counterparty pays a fixed or contractually structured fee for the right to operate the battery and capture its market revenue. The fee replaces market risk with the counterparty's credit risk. The owner keeps the availability and performance risk under the contract. I think that, for a lender, a long-term tolling agreement with a reliable counterparty is among the strongest instruments for turning merchant revenue into predictable cash flow.

Revenue floor. An optimiser or trader guarantees a minimum revenue, while the owner keeps part of the revenue above the agreed level. The structure gives less protection than a full tolling agreement, but leaves more room for additional return.

Fully merchant model. The owner takes all of the market risk and all of the upside. It is the purest commercial model and the hardest to finance with debt.

As far as I can see, long-term tolling agreements and revenue floors are still less developed in Southeast Europe than in the UK or Germany. That makes the quality of the project's other elements even more important.

Public finance can change the risk

I think that in the region, public co-financing is often the factor that makes an otherwise marginal project acceptable to private capital.

Grants reduce the amount of capital exposed to market risk. They come with conditions, such as deadlines and ownership and operating obligations, which the lender checks. Guarantees and instruments from the EIB, the EBRD, InvestEU or national schemes can improve the project's credit profile and lower the demands placed on merchant revenue.

That is why any serious bankability assessment should include a map of the public instruments available, alongside the market and the technical model.

Two identical BESS projects can have radically different bankability if one of them has support that reduces its initial capital risk.

Cannibalisation: the risk a simple model misses

I think one of the most dangerous ways to overestimate a BESS is to carry the historical price spread forward unchanged.

According to Capalo AI (07.08.2026), the average price between 08:00 and 20:00 in Bulgaria was EUR 5.56/MWh below the daily average in 2024, EUR 11.63/MWh below it in 2025 and EUR 23.45/MWh below it in January to July 2026.

Negative-price hours numbered 11 in 2023, 55 in 2024, 170 in 2025 and 166 in January to July 2026 alone.

Over the same period, the average daily spread between the highest and the lowest hourly price was:

• EUR 126/MWh in 2023;
• EUR 183/MWh in 2024;
• EUR 165/MWh in 2025;
• EUR 149/MWh in January to July 2026.

This does not prove that batteries alone are causing the narrowing. The spread is also shaped by gas, cross-border flows, hydrology, demand, weather, new renewable capacity and market coupling.

But I think that as BESS grows, arbitrage itself narrows the opportunity it earns from. Charging lifts the price in the cheap hours, and discharging adds supply in the expensive ones.

That is why a model for a project entering operation in 2027 or 2028 should not assume that the spreads of 2024 or 2025 will hold.

A bankable model should have at least a base, a downside and a severe downside case for spreads, ancillary service revenue and battery utilisation.

Technical bankability

The financial model is only half of the question. The other half is whether the asset will physically produce the revenue the model assumes.

Equipment. The manufacturer should have a proven track record, financial strength, the necessary certifications and service capacity in the region. BloombergNEF's Tier 1 list measures industry acceptance. Since the methodology update of 15.08.2026, it also requires the manufacturer to have supplied projects financed with non-recourse debt from at least two commercial banks. BloombergNEF states that the classification does not measure product quality, and it does not replace technical due diligence.

Degradation and warranties. Battery capacity declines over time. The model should track the guaranteed energy retention, throughput limits, cycle count, depth of discharge, round-trip efficiency and the augmentation strategy. The lender is financing the system's ability to earn revenue over the full life of the loan. Capacity on day one is only the starting point.

EPC and delivery. A delay to the commercial operation date (COD) postpones revenue while some costs and obligations are already accruing. A bankable EPC contract should clearly allocate the risk for schedule, guaranteed performance, liquidated damages, warranties and responsibility between the battery supplier, the power conversion system (PCS), the energy management system (EMS) and the rest of the plant.

Maintenance and availability. Guaranteed availability, response time, spare parts and service have direct value for the lender. A battery that is out of the market exactly in the expensive hours can lose a disproportionately large part of its annual revenue.

Insurance. Fire and thermal runaway risk, transport damage and commissioning losses increasingly shape insurers' terms. The insurance concept should be ready before financial close.

Grid connection. The connection point, the export and import limits, curtailment risk and the date of actual energisation are fundamental. A project's position in the connection queue can have value. It can also be the reason a project stays unfinanceable.

How the lender looks at it

After all the technical and contractual work, it comes down to a few simple numbers.

Can the cash flow sustain the required debt service coverage ratio (DSCR)?

How much debt can the project realistically carry?

What do the loan life coverage ratio (LLCR) and debt service look like in a downside case?

How much of the revenue is contracted, and how much remains merchant?

What happens in one weak year, with faster degradation, or with a six-month delay to grid connection?

In my view, these questions mark the difference between a financial model and a financial model a lender would accept.

The questions I would ask before an investment decision

Before committing capital to a BESS project in Southeast Europe, I would want a clear answer to at least the following:

The conclusion

The technology is no longer the main question.

I think the value of a BESS project is determined by whether its revenues, contracts, equipment, grid connection, warranties and capital structure work together and stay resilient under one and the same downside case.

The market has moved past the phase when installed megawatts were enough for a headline.

The next phase is bankability.

I am inclined to think that the projects reaching financial close will be those where risk has been structured from the first day. The largest capacity and the most aggressive revenue forecast are not enough on their own.