The power trading landscape in South-East Europe during January 2023 showcased a complex interplay of market forces, characterized by both scarcity and ample supply conditions. This month revealed that the region operates more as an interconnected system than as a collection of isolated national markets. Price movements were influenced significantly by transient scarcity events and the limitations of cross-border trading capabilities rather than by straightforward fuel cost adjustments.
In Serbia, the SEEPEX day-ahead market reported an average baseload price of €118.13/MWh and a peak price of €136.27/MWh. However, daily baseload prices fluctuated dramatically, ranging from €66.89/MWh to €228.29/MWh, with peak prices reaching as high as €293.84/MWh on particularly strained days. The total traded volume for the month was 404,970.3 MWh, reflecting an 18.3% decrease compared to the previous month, indicating that liquidity was not excessive and that prices were driven by acute scarcity.
Meanwhile, Croatia’s CROPEX maintained consistently higher prices throughout January, averaging €143.16/MWh for baseload and €165.66/MWh for peak demand, with a total traded volume of 658,973.3 MWh. The intra-month price volatility mirrored that of Serbia, with baseload prices ranging from €68.85/MWh to €226.64/MWh. This pricing behavior highlights Croatia’s vulnerability to import parity dynamics; prices tend to decrease when regional supply is sufficient but can spike sharply during periods of constrained imports.
Romania’s OPCOM market emerged as the highest-priced segment in the region, with average baseload prices hitting €150.51/MWh and peak prices at €176.60/MWh amid a total traded volume of 1,520,885.0 MWh, accounting for a 32.04% market share. The elevated pricing is attributed not only to increased demand but also to frequent instances where the market operated under tight thermal margins or import constraints during peak stress periods.
Montenegro’s MEPX demonstrated extreme sensitivity to liquidity conditions, reporting average daily baseload prices of €103.45/MWh and peak prices of €115.05/MWh against a total traded volume of just 39,572.2 MWh for January. The stark contrast between minimum daily baseload prices of €18.79/MWh and maximums reaching €156.24/MWh illustrates how quickly the market can transition between states of surplus and shortage due to its limited trading depth.
The alignment of national pricing patterns can be traced back to interconnector behaviors throughout January, which played a crucial role in determining whether scarcity was shared across borders or remained isolated within specific markets. Notably, on the Romania-Bulgaria border, day-ahead flows totaled 408,525.4 MWh from Bulgaria into Romania while only 131,397.9 MWh flowed in the opposite direction, indicating a predominantly one-way economic flow favoring Romania’s higher-priced market.
Conversely, the Romania-Hungary interface displayed more balanced trading volumes with 363,560.1 MWh moving from Hungary to Romania and 249,818.4 MWh in reverse flow, suggesting a dynamic where price leadership shifted depending on which market was under stress at any given time.
Bulgaria’s IBEX reported day-ahead traded volumes of 2,881,781.2 MWh in January—a 10% increase month-on-month—culminating in a record daily volume on January 27th of 107,207.43 MWh. These high trading volumes signal robust arbitrage opportunities and integration within the region; however, they also raise concerns about potential saturation during peak demand periods that could lead to local price spikes.
The overall mechanics of January’s power market reveal that it was not merely characterized by high prices but rather by significant shifts between energy-long periods and flexibility-short conditions. During energy-long hours, prices across Serbia and Croatia could dip into the €60–€70/MWh range while Montenegro experienced even lower rates; however, during flexibility-short intervals—particularly in cold evening hours—prices surged dramatically.
The winners in this environment were primarily those entities capable of managing flexible resources: hydroelectric operators with scheduling flexibility and fast-ramping thermal units benefited from shifting their output from low-priced off-peak hours to high-demand periods effectively monetizing these price differentials.
Conversely, inflexible buyers faced substantial challenges during stress intervals; industrial consumers without load-shifting capabilities and suppliers relying on fixed baseload contracts saw disproportionate costs due to the volatility in pricing driven by limited flexibility availability during peak times.
This month’s dynamics underscore that South-East Europe’s power markets are increasingly influenced by interconnector economics and the availability of flexible resources rather than being dictated solely by fuel costs or local supply conditions alone.
