January trading across South-East Europe unfolded as a single winter-stress system rather than a mosaic of isolated national markets. Price formation across the region was driven far less by smooth fuel-cost pass-through and far more by the interaction of short-lived scarcity intervals, evening ramp constraints, and the practical limits of cross-border coupling. Monthly averages, while high, mask a much more important reality: a relatively small number of hours and days set the economic tone for the entire month, redistributing value sharply between flexible and inflexible market participants.
Across the region, the defining characteristic of January was the coexistence of calm, energy-long hours and violent repricing during tight ramps. Serbia’s SEEPEX day-ahead market illustrates this clearly. The month cleared at an average baseload price of €118.13/MWh and average peak of €136.27/MWh, yet within that same month baseload daily prices ranged from a low of €66.89/MWh to a high of €228.29/MWh, while peak prices reached an extreme €293.84/MWh on the most stressed delivery day. Total traded volume of 404,970.3 MWh, down 18.3% month-on-month, underlines that these price signals were not diluted by excessive liquidity; rather, the market repeatedly repriced scarcity when flexibility ran thin.
Croatia’s CROPEX sat structurally higher through the month, with average baseload at €143.16/MWh and peak at €165.66/MWh on traded volumes of 658,973.3 MWh. The intra-month range mirrored Serbia’s volatility, with baseload days as low as €68.85/MWh and as high as €226.64/MWh. Croatia’s pricing profile reflects a system more persistently exposed to import parity and corridor economics; when regional supply is ample, prices soften quickly, but when imports tighten during evening ramps, the marginal unit shifts rapidly into a higher-cost band.
Romania’s OPCOM day-ahead market emerged as the regional high-price anchor. January averaged €150.51/MWh baseload, €176.60/MWh peak, and €124.42/MWh off-peak, with traded day-ahead volumes of 1,520,885.0 MWh and a market share of 32.04%. Romania’s premium is not simply a question of higher demand or fuel exposure; it reflects how often the system cleared on tight thermal margins or import parity during stress intervals, lifting the monthly mean even though off-peak hours remained materially cheaper.
Montenegro’s MEPX provided the most extreme illustration of liquidity-driven sensitivity. Average daily baseload prices of €103.45/MWh and peak of €115.05/MWh appear modest next to Romania or Croatia, but total monthly traded volume was just 39,572.2 MWh, with average daily volume of 1,276.5 MWh. In such a thin market, January produced a baseload minimum day of €18.79/MWh and a peak minimum of €26.12/MWh, while maximum days reached €156.24/MWh baseload and €186.38/MWh peak. These are not contradictory signals; they are the natural outcome of a system that flips quickly between import-available hours and import-constrained hours, with each regime amplified by limited depth.
The reason these national price patterns aligned so closely in timing lies in the behavior of the coupling corridors. January was a month where interconnectors repeatedly determined whether scarcity was shared or isolated. Romania’s cross-border data is particularly revealing. On the Romania–Bulgaria border, executed day-ahead flows totaled 408,525.4 MWh from Bulgaria into Romania, compared with just 131,397.9 MWh in the opposite direction. Utilization of offered capacity stood at 31.64% for Bulgaria-to-Romania versus only 6.75% for Romania-to-Bulgaria, a clear indication that the economic flow direction was predominantly one-way for much of the month. In practical terms, Bulgaria’s structurally cheaper baseload stack was repeatedly feeding a higher-priced Romanian system until constraints elsewhere became binding.
On the Romania–Hungary interface, the pattern was more balanced in volume terms, with 363,560.1 MWh flowing from Hungary to Romania and 249,818.4 MWh from Romania to Hungary. This two-way movement signals a market where price leadership flipped several times during the month, depending on which system faced marginal stress. Such corridors tend to show intermittent convergence: hours of near-parity punctuated by sharp divergence when congestion rents spike and each side clears against its own marginal scarcity cost.
Bulgaria’s IBEX data adds an important layer to this picture. January day-ahead traded volumes reached 2,881,781.2 MWh, up 10% month-on-month, with a new daily record of 107,207.43 MWh on 27 January. High coupled volumes during a volatile winter month are a double-edged signal. On one hand, they reflect aggressive arbitrage and strong integration, which should dampen price spreads in unconstrained hours. On the other, they increase the likelihood that interconnectors saturate precisely during the most valuable periods, leaving residual scarcity to be priced locally and often violently.
When these elements are combined, January’s SEE market mechanics become clear. The month was not defined by persistently high prices across all hours, but by repeated regime shifts between energy-long and flexibility-short conditions. In energy-long windows, prices across Serbia, Croatia, and even Romania could soften toward the €60–€70/MWh band, while Montenegro could collapse into double-digit prices. In flexibility-short windows, particularly evening ramps under cold conditions, the system repriced rapidly into scarcity, with Serbia touching nearly €300/MWh on peak days and Romania maintaining the highest sustained peak averages in the region.
The distributional consequences were sharp. The primary winners in January were holders of controllable flexibility: hydro operators with scheduling discretion, fast-ramping thermal units, portfolio traders with cross-border optionality, and any asset capable of shifting volume from low-priced off-peak hours into high-priced ramps. The repeated spread between off-peak levels such as €124.42/MWh in Romania and peak averages of €176.60/MWh, or between Serbian minimum baseload days at €66.89/MWh and peak extremes near €293.84/MWh, created consistent monetization opportunities for shape rather than flat energy.
The clearest losers were inflexible buyers and suppliers structurally short during stress intervals. Industrial consumers without load-shifting capability, district heating systems exposed to evening peaks, and suppliers relying on flat baseload hedges all faced a month where a relatively small slice of hours drove disproportionate cost. Croatia’s higher peak average of €165.66/MWh compared with Serbia’s €136.27/MWh underscores how corridor exposure and import dependency can magnify that penalty, while Romania’s combination of the highest mean and the highest peak averages created one of the most challenging procurement profiles in the region.
Viewed as an integrated system, January confirms that South-East Europe is increasingly priced by the intersection of interconnector economics and flexibility scarcity rather than by any single fuel benchmark. Corridor asymmetries such as Bulgaria feeding Romania at more than three times the reverse flow, coupled with thin liquidity in smaller markets like Montenegro, explain how the same month can contain both €18.79/MWh baseload days and €293.84/MWh peak days. The cost embedded in January’s averages is not simply the cost of energy; it is the cost of fragmentation during the hours when the system most needs flexibility, and it is that cost which ultimately defined who paid and who earned in the SEE power markets over the month.
By virtu.energy
