In January, power trading in South-East Europe demonstrated a cohesive market behavior, characterized by significant price volatility driven by scarcity conditions rather than isolated national markets. The interplay of limited flexibility, evening ramp constraints, and cross-border coupling restrictions shaped the price landscape across the region. Monthly averages obscured the reality that only a few hours dictated economic outcomes, leading to pronounced value shifts between flexible and inflexible market players.
The January trading environment was marked by contrasting periods of energy abundance and acute scarcity. Serbia’s SEEPEX day-ahead market exemplified this phenomenon, with an average baseload price of €118.13/MWh and an average peak price of €136.27/MWh for the month. However, daily baseload prices fluctuated significantly, hitting a low of €66.89/MWh and a high of €228.29/MWh, while peak prices soared to €293.84/MWh on particularly stressed days. The total traded volume decreased by 18.3% month-on-month to 404,970.3 MWh, indicating that the observed price signals were not diluted by excessive liquidity but rather reflected a market that repeatedly adjusted to scarcity.
In Croatia, the CROPEX market maintained higher pricing levels throughout January, averaging €143.16/MWh for baseload and €165.66/MWh for peak periods on traded volumes of 658,973.3 MWh. Similar to Serbia, Croatia experienced intra-month volatility with baseload prices ranging from €68.85/MWh to €226.64/MWh. This pricing behavior underscores Croatia’s vulnerability to import parity dynamics; while supply is sufficient, prices tend to decrease quickly, but tightening imports during peak hours rapidly elevate costs.
Romania stood out as the regional high-price anchor with its OPCOM day-ahead market recording an average baseload price of €150.51/MWh and peak prices at €176.60/MWh over a traded volume of 1,520,885 MWh—accounting for 32.04% market share in the region. Romania’s elevated pricing is attributed not solely to demand or fuel costs but also to frequent clearance on tight thermal margins or import parity during stress periods.
Montenegro’s MEPX highlighted extreme sensitivity to liquidity constraints with average daily baseload prices at €103.45/MWh and peak prices at €115.05/MWh from a meager total monthly traded volume of 39,572.2 MWh—an average daily volume of just 1,276.5 MWh. This thin market resulted in significant price extremes: a minimum baseload day recorded at €18.79/MWh contrasted sharply with maximum days reaching up to €156.24/MWh for baseload and €186.38/MWh for peak pricing.
The interconnector dynamics played a crucial role in aligning national price patterns throughout January as they determined whether scarcity was shared among markets or remained isolated within individual systems. Cross-border data from Romania revealed substantial flows from Bulgaria into Romania totaling 408,525.4 MWh compared to only 131,397.9 MWh flowing in the opposite direction—suggesting a predominantly one-way economic flow favoring Romania throughout much of the month.
The Romania-Hungary interface exhibited more balanced flows with 363,560.1 MWh moving from Hungary to Romania against 249,818.4 MWh from Romania to Hungary—indicative of fluctuating price leadership based on which system encountered marginal stress at any given time.
Bulgaria’s IBEX reported day-ahead traded volumes reaching 2,881,781.2 MWh—up 10% month-on-month—with a record daily trading volume of 107,207.43 MWh on January 27th. While high coupled volumes suggest strong integration and arbitrage opportunities during winter volatility, they also raise concerns about potential saturation during critical trading times leading local markets into violent repricing scenarios.
Overall, January’s market mechanics reveal that South-East Europe’s electricity pricing is increasingly influenced by interconnector economics intertwined with flexibility shortages rather than relying solely on specific fuel benchmarks or costs alone. The disparities observed—such as Bulgaria supplying Romania at rates exceeding three times reverse flows—illustrate how fragmented market conditions can lead to both exceptionally low baseload days and extreme peak pricing within the same month.
This complex interplay defines who benefits and who incurs costs in these power markets as they navigate through periods of both energy abundance and scarcity.
