January highlighted a shift in South-East Europe’s power market signals, with day-ahead prices no longer reflecting the main stress point. The marginal indication increasingly comes from balancing energy and ancillary services, where scarcity appears earlier and clears at higher implied prices. Value also redistributes more asymmetrically than in the headline day-ahead market.
Across Serbia, Romania, Bulgaria, and Croatia, repeated evening ramps in January followed a consistent pattern. Day-ahead markets on SEEPEX, OPCOM, and CROPEX cleared at high but finite peak prices. At the same time, balancing markets operated close to their technical limits.
Price behaviour provided an indirect indicator of this condition. When day-ahead market (DAM) peaks reached €170–300/MWh repeatedly without fuel shortage, it suggested the system was already using a large share of its available balancing headroom. The observation pointed to constraints showing up first in real-time services rather than in the auction.
Reserve depth limits fast upward balancing during winter peaks
The key issue described for most SEE systems is reserve depth. Less than 5–10% of installed capacity is effectively available as fast, fully controllable balancing reserve during winter peak hours. Hydro is identified as providing most of this flexibility, followed by a smaller number of gas and CHP units.
Other resources contribute differently to upward reserve availability in January conditions. Wind and solar are described as not meaningfully contributing to upward reserves during winter peaks. Demand response is also characterized as marginal in most markets.
This configuration results in balancing scarcity appearing before energy scarcity. It also means the marginal MWh in real time is far more expensive than the marginal MWh in the day-ahead auction. The gap between these two signals shows up during stress intervals.
Imbalance costs rise above day-ahead peaks during tight hours
The economic impact is reflected in imbalance pricing relative to DAM outcomes. Imbalance prices frequently exceed DAM prices by wide margins during periods of stress. Published imbalance price levels vary by jurisdiction and settlement design, but January conditions imply effective imbalance costs in the €300–500/MWh range during the tightest hours.
The implied cost level can apply even when DAM peaks remain below those figures. For traders and suppliers short in real time, the result can be a position that becomes loss-making after settlement. The shift changes how exposure to day-ahead price levels translates into realized outcomes.
Romania illustrates the contrast using OPCOM market outcomes alongside balancing reliance. OPCOM cleared January with an average baseload of €150.51/MWh and a peak of €176.60/MWh. During evening ramps, the system relied heavily on a narrow pool of hydro and thermal balancing providers.
Nuclear supports baseload while hydro and thermal cover short-term balancing
The role of generation differs between baseload needs and short-term balancing capability in Romania’s description. Nuclear is described as critical for baseload but contributing almost nothing to short-term balancing. As a result, the effective marginal price of system security was described as far above the published DAM peak.
The same structural pattern is described for Serbia using SEEPEX figures alongside balancing constraints. SEEPEX peak days approached €294/MWh, which already signalled stress. However, the balancing system is described as thinner than in Romania.
Serbia’s hydro fleet is characterized as large but with highly concentrated balancing capability. When hydro is withheld for water management or already dispatched into DAM, the residual balancing stack becomes extremely steep. This concentration is described as creating a convex risk profile for suppliers where imbalance hours can erase profits from high DAM prices.
Croatia’s flexibility depends on interconnector availability and ramp absorption
In Croatia, balancing outcomes are linked to cross-border constraints. When imports are available, balancing pressure is described as muted. When interconnectors bind, Croatia’s domestic balancing resources must absorb the full ramp.
January’s CROPEX pricing is presented alongside this constraint effect. The market recorded an average peak price of €165.66/MWh, which is described as understating the true cost of flexibility under binding conditions. Instead, that cost is reflected through reserve activation and imbalance settlement.
Balancing-capable assets earn premiums not visible in day-ahead trading
The environment described has led to a repricing of value for asset owners based on balancing capability. Balancing-capable assets are said to earn a premium that is not visible in day-ahead prices. Hydro units with fast response and gas units with flexible dispatch rights are identified as examples.
The ability to offer specific services also affects monetisation opportunities in January conditions. Assets able to offer aFRR or mFRR are described as monetising scarcity beyond pure energy trading. The text also states that risk-adjusted returns from balancing participation often exceeded those from DAM arbitrage, particularly in smaller systems where reserve depth is minimal.
Bidding positions can remain exposed if portfolios lack real-time optionality
For buyers and traders, January conditions are described as showing a structural exposure difference between markets. A portfolio that appears hedged in the day-ahead market can still be structurally short in the balancing market. The description attributes this to balancing risk becoming a dominant hidden risk across SEE.
The text further links mitigation to physical capability rather than financial hedging approaches. Managing this risk is described as requiring physical optionality rather than financial hedges. Markets that do not deepen balancing participation are expected to continue experiencing extreme DAM peaks even when energy scarcity is not the driver, due to pricing off concerns about losing control in real time.