South-East Europe’s battery storage market is expanding rapidly, but investors remain divided over one critical question: should storage projects in the Balkans operate as fully merchant assets exposed to market volatility, or should they depend on regulated support structures and contracted revenue mechanisms?
By 2026, this debate is becoming one of the defining financial battles shaping the region’s energy transition.
The answer matters because battery energy storage systems are no longer niche infrastructure. Across Serbia, Greece, Romania and Bulgaria, gigawatt-scale pipelines are emerging as renewable penetration rises and electricity markets become increasingly volatile. Batteries are moving into the center of the power system. Yet unlike traditional generation assets, storage economics remain highly dependent on market design.
The financing framework chosen now will influence which projects get built, which investors dominate the market and how quickly South-East Europe develops a functional flexibility economy.
The merchant argument is increasingly attractive because volatility itself is growing.
As solar deployment accelerates across Greece and Bulgaria, midday prices weaken sharply during high-irradiation periods. Wind generation in Serbia and Romania creates sudden balancing swings. Cross-border congestion intensifies during synchronized renewable events. The spread between low-price and high-price hours widens.
This is exactly the environment batteries monetize.
A merchant battery absorbs cheap electricity during oversupplied periods and discharges power during balancing shortages or evening peaks. Revenue comes from arbitrage, ancillary services, balancing participation and congestion management rather than fixed tariffs or capacity-style payments.
In theory, a sufficiently volatile market should support storage commercially without heavy regulatory support.
This is why commodity traders, infrastructure funds and some utilities increasingly favor merchant BESS models in SEE markets. They believe volatility will deepen as renewable penetration rises, making flexibility increasingly valuable. In their view, batteries should function like active trading infrastructure rather than quasi-regulated utility assets.
Serbia is one of the most important testing grounds for this thesis.
EMS agreements linked to roughly 4.54 GWh of planned storage indicate that the market is preparing for structurally higher volatility. Wind growth in Vojvodina, expanding solar pipelines and Serbia’s central transmission position between Central Europe and the Balkans all create conditions where batteries could potentially capture substantial intraday and balancing value.
For aggressive investors, this is highly attractive.
A well-positioned battery near congestion zones or renewable clusters can effectively operate like a physical trading desk. It can arbitrage volatility, support balancing and optimize renewable output dynamically. If volatility continues increasing, merchant storage revenues could become substantial.
Greece reinforces the same logic.
Its solar-heavy system already produces widening intraday spreads. Midday solar oversupply weakens prices, while evening balancing demand creates sharp ramps. Batteries fit naturally into this structure because they transform solar timing mismatches into tradable value.
This is why Greece’s storage market increasingly attracts merchant-oriented capital.
Romania presents a more diversified case. Nuclear baseload, hydropower, wind and future offshore wind development create multiple layers of volatility and balancing opportunity. Batteries connected near strategic interconnectors toward Hungary, Serbia and Bulgaria may gain additional value through congestion management and cross-border optimization.
The merchant case therefore rests on one central assumption: volatility will continue increasing faster than market saturation.
Yet many lenders remain cautious.
Traditional project finance prefers predictable revenue streams. Wind and solar projects historically relied on feed-in tariffs, contracts for difference or long-term PPAs because lenders wanted visibility. Merchant batteries, by contrast, depend on uncertain future spreads, balancing prices and market conditions.
This creates financing tension.
Infrastructure funds and trading-oriented investors may tolerate merchant exposure because they believe flexibility scarcity will increase. Commercial banks and conservative lenders often prefer partially contracted structures reducing volatility risk.
This is where regulated-storage models enter the debate.
Under regulated or semi-regulated structures, batteries receive some form of stable revenue support — capacity payments, ancillary-service contracts, TSO-backed procurement frameworks or hybrid revenue guarantees. The logic is that storage provides system stability and resilience benefits that are difficult to monetize fully through merchant markets alone.
Supporters argue that without clearer long-term revenue certainty, SEE markets may underbuild storage precisely when renewable volatility is accelerating.
This concern is especially important because South-East Europe still lacks fully mature balancing architecture.
Intraday liquidity remains uneven. Ancillary-service frameworks differ by country. TSO coordination is incomplete. Revenue stacking is often unclear. Grid fees and charging rules can materially alter project economics.
Under these conditions, pure merchant exposure may appear too risky for large-scale financing.
The debate therefore becomes philosophical as much as financial.
Should batteries behave like infrastructure utilities supporting system stability? Or should they behave like market assets monetizing volatility?
Western Europe increasingly provides examples of both approaches.
The UK and parts of Germany have seen aggressive merchant battery deployment driven by balancing and intraday spreads. Other markets rely more heavily on capacity mechanisms or regulated support structures.
SEE now faces the same decision, but under more fragile market conditions.
The answer may ultimately differ between countries.
Greece’s volatility profile increasingly supports merchant economics because solar penetration already creates large spreads. Serbia may initially require hybrid frameworks while balancing markets mature. Romania’s diversified system may support mixed structures combining merchant optimization with ancillary-service contracts.
The strategic implications are substantial.
If markets rely too heavily on regulated support, storage deployment may become slower and more utility-centered. If markets move entirely toward merchant models too quickly, financing costs could remain high and deployment uneven.
The ideal structure may involve hybridization.
Many investors increasingly favor mixed revenue models combining merchant arbitrage with contracted balancing or ancillary-service components. This reduces financing risk while preserving upside exposure to volatility growth.
Hybrid renewable-storage projects increasingly follow this structure as well.
A solar-plus-storage platform can combine contracted renewable revenues with merchant battery optimization. Wind-storage portfolios can reduce imbalance costs while participating in balancing markets simultaneously.
This improves bankability relative to standalone merchant batteries.
Transmission infrastructure further complicates the picture.
The Trans-Balkan Corridor, Greece–Bulgaria links and wider SEE interconnections increasingly determine where storage becomes most valuable.
A battery near a strategic congestion node or interconnector may generate substantially higher revenues than a poorly located asset because it can monetize regional balancing spreads more effectively.
This means storage financing increasingly depends not only on market rules but also on geography.
Hydropower adds another layer.
Albania, Montenegro and Romania already possess substantial flexibility through reservoir systems. Batteries may complement rather than replace this hydro balancing. Together, they create layered flexibility systems where hydro manages longer-duration balancing while batteries capture short-duration volatility.
This interaction may reduce the need for heavy regulated storage support in some markets because flexibility scarcity becomes structurally monetizable.
The Energy Community’s latest data already reflects how rapidly structural pressures are reshaping regional electricity economics. Q1 2026 saw commercial electricity exchanges between the EU and Western Balkans fall significantly despite substantial price differences, highlighting how carbon exposure, congestion and balancing constraints increasingly influence market behavior.
This trend likely strengthens the case for storage.
As renewable penetration rises and cross-border flows become more volatile, flexibility assets should become progressively more valuable.
Yet the financing path remains uncertain.
The biggest risk for SEE markets may not be insufficient storage demand. It may be uncertainty around how storage revenues will actually be monetized over the long term.
Without clearer frameworks, investors may hesitate precisely when the region needs flexibility infrastructure most urgently.
Still, the broader trajectory is increasingly unmistakable.
Battery systems are no longer peripheral renewable-support tools.
They are becoming core market infrastructure determining whether renewable-heavy electricity systems remain stable, tradable and commercially functional.
The financing battle between merchant and regulated storage models will therefore shape far more than battery deployment alone.
It will help determine how South-East Europe’s entire electricity market evolves during the next decade.
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