By 2025, balancing and flexibility revenues emerged as one of the most underestimated profit drivers for renewable electricity producers in Southeast Europe. For most of the past decade, balancing markets in the region were treated as technical necessities rather than commercial arenas. Renewable producers focused on energy volumes and incentive-backed prices, leaving flexibility value largely to legacy thermal and hydro operators. That separation no longer holds. As wind and solar penetration increased, the ability to manage deviations, ramp output and respond to system imbalances became monetisable in its own right, creating a new earnings layer that sits alongside energy sales.
The structural reason is straightforward. Renewable generation growth has outpaced grid reinforcement and market design reform across much of SEE. This mismatch has increased forecast errors, intraday volatility and balancing costs. In 2025, imbalance prices across Romania, Greece and Bulgaria routinely diverged from day-ahead prices by €20–60 per MWh during stress periods, particularly in weather-driven events. For producers capable of managing their position actively, these spreads represented opportunity rather than penalty.
Hydropower operators were the first to recognise this shift. In Croatia, Bosnia and Herzegovina and parts of Romania, reservoir-based hydro plants increasingly shifted their operating strategy away from maximising baseload output toward maximising flexibility value. By withholding generation during low-price hours and releasing water into evening peaks or balancing windows, hydro assets captured price premiums of €15–30 per MWh above day-ahead averages. In 2025, this strategy lifted total hydro revenues by 10–18 percent without increasing annual output volumes.
What changed in 2025 is that renewable portfolios beyond hydro began to participate meaningfully. Wind producers, traditionally viewed as passive price takers, improved forecast accuracy and intraday nomination practices. In Romania and Greece, wind forecast errors narrowed to 5–7 percent for well-managed fleets, down from double-digit levels earlier in the decade. This reduced imbalance penalties and, in some cases, enabled producers to sell balancing capacity indirectly through aggregation platforms.
Solar producers faced a different challenge. Forecast accuracy is high, but temporal concentration creates system stress. Midday overgeneration and steep evening ramps increase balancing needs. Producers that combined solar with limited storage or contractual access to flexible hydro were able to monetise this dynamic. In 2025, solar-heavy portfolios with access to flexibility captured €3–7 per MWh in net balancing-related revenues, either through avoided penalties or participation in upward and downward regulation markets.
Greece provided the clearest example of flexibility monetisation beyond hydro. As renewable penetration climbed, the transmission system operator increasingly relied on fast-response resources to maintain frequency and voltage stability. While dedicated ancillary service markets remained relatively small, flexible renewable portfolios participated through indirect mechanisms. Wind and hybrid assets that could curtail or ramp quickly earned premiums during stressed intervals, contributing 5–10 percent of total annual revenue for some portfolios. This contribution was modest in absolute terms, but highly accretive to margins due to negligible incremental cost.
Romania’s balancing market evolved rapidly in 2025 as cross-border flows with Hungary and Bulgaria intensified. Price volatility increased, but so did liquidity. Aggregated renewable portfolios with access to multiple balancing zones reduced exposure to local congestion and captured value from geographic price spreads. In practical terms, this meant shifting balancing responsibility from the single asset to the regional portfolio. For producers, the result was a reduction in net imbalance costs from €4–6 per MWh to €1–2 per MWh, equivalent to a €3–5 per MWh uplift in realised prices.
Bulgaria illustrated both the risk and opportunity. Rapid solar expansion created frequent midday surpluses and evening deficits. Unoptimised producers paid heavily for imbalances, particularly during sudden cloud cover events. By contrast, portfolios with access to hydro flexibility or contracted reserve capacity stabilised revenues and, in some cases, earned net balancing income. In 2025, the spread between best- and worst-performing solar portfolios in Bulgaria exceeded €10 per MWh, driven largely by balancing outcomes rather than energy prices.
Serbia’s balancing market remains more constrained, but trends are clear. Wind capacity growth increased system sensitivity to forecast errors, particularly during low-demand periods. While formal ancillary service revenues for renewables remained limited in 2025, avoided imbalance costs already functioned as a de facto flexibility revenue. Well-managed Serbian wind portfolios reduced balancing penalties by 30–40 percent compared with early operational years, translating into several million euros of incremental EBITDA across the fleet.
From a financial perspective, flexibility revenues are attractive because they are largely uncorrelated with energy prices. They peak precisely when systems are stressed, which is often when energy margins are under pressure. This counter-cyclicality enhances portfolio resilience. In valuation terms, assets with demonstrated flexibility participation command higher confidence in cash-flow forecasts, even if headline revenues are similar.
The capital intensity of flexibility monetisation is also low. Improved forecasting systems, intraday trading desks and aggregation agreements require investments measured in hundreds of thousands or low single-digit millions of euros, not tens of millions. Where physical flexibility is needed, such as limited storage or turbine control upgrades, CAPEX remains modest relative to generation assets. Returns on these investments often exceed 20 percent, driven by avoided penalties and incremental market access.
Critically, flexibility revenues change the strategic role of renewables in SEE power systems. They are no longer just sources of energy volume. They are becoming active system participants, capable of absorbing volatility rather than creating it. This shift has implications for regulators and TSOs, who increasingly view aggregated renewable portfolios as part of the solution to system stability rather than as a destabilising force.
By 2025, balancing and flexibility revenues had not yet overtaken energy sales as the primary income source for renewable producers in Southeast Europe. But they had become material enough to influence operating strategies, investment decisions and asset valuations. As renewable penetration deepens and price volatility increases, this revenue layer will expand. For producers who build flexibility into their portfolios early, balancing markets offer not just protection from risk, but a durable source of incremental profit.
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