Day-ahead electricity prices surged across much of Central and Southeast Europe for Thursday delivery, as higher regional import requirements and expensive evening hours outweighed a modest decline in overall electricity consumption.
Hungary recorded one of the strongest increases, with the HUPX baseload price rising by €42.7/MWh to €203.34/MWh. Romania followed at €202.46/MWh, Slovenia at €201.43/MWh and Croatia at €201.38/MWh. Serbia posted the largest daily increase among the main regional markets, with SEEPEX jumping €65.1/MWh to €174.39/MWh.
Bulgaria’s price climbed to €188.50/MWh, while Greece reached €183.60/MWh. The southern Balkan markets moved differently, however, with Montenegro falling to €154.67/MWh and North Macedonia dropping to €133.35/MWh.
The regional price rally occurred despite slightly lower demand. Combined electricity consumption in Hungary and Southeast Europe was forecast at around 31.59 GW, approximately 227 MW below the previous day.
The key shift came from the supply side. Regional generation declined to about 29.61 GW, widening the gap between production and consumption and pushing total net imports to approximately 1.98 GW, around 700 MW higher day on day.
Imports from the Central European core increased to roughly 1.99 GW, while the Hungary-Germany day-ahead spread narrowed to approximately €11.5/MWh from €17.5/MWh.
Hungary provided one of the clearest examples of the tightening regional power balance. Consumption remained broadly stable at around 4.75 GW, but domestic generation dropped to approximately 3.37 GW from 4.14 GW. As a result, Hungary’s net import requirement more than doubled to around 1.38 GW, compared with 631 MW previously.
The deterioration in Hungary’s supply balance helped lift prices across interconnected Central and Southeast European markets, with HUPX remaining a key price reference for Serbia, Croatia, Slovenia and Romania.
The strongest price pressure was concentrated in the evening hours. HUPX reached a maximum of approximately €425.7/MWh in hour 20, compared with a daily low of €124.8/MWh. Germany climbed to around €460.9/MWh, while Croatia and Austria also recorded hourly peaks above €400/MWh.
The sharp hourly swings underline the growing influence of solar generation on regional price formation. Strong photovoltaic output suppresses prices during the middle of the day, but the rapid decline in solar generation toward sunset leaves the system increasingly dependent on thermal generation, imports and flexible capacity.
Serbia experienced particularly strong price volatility. The SEEPEX baseload price increased to €174.39/MWh from €109.3/MWh, representing a rise of roughly 60% in a single day.
The maximum hourly Serbian price reached approximately €350/MWh. Off-peak electricity averaged around €188.2/MWh, above the nominal peak average of approximately €160.5/MWh.
Serbia’s physical balance changed much less dramatically. Consumption stood at around 3.55 GW, generation at approximately 3.04 GW and average imports at about 516 MW. This suggests that the sharp price increase was driven primarily by regional scarcity and cross-border price transmission, rather than a sudden increase in domestic demand.
Despite the rally, Serbia maintained a significant discount to Hungary of nearly €29/MWh. The spread illustrates the continued fragmentation of Southeast European electricity markets, where local generation mixes, interconnector availability and congestion can produce substantial price differences between neighbouring bidding zones.
Romania also remained relatively tight. Electricity consumption was around 5.66 GW, compared with generation of approximately 5.19 GW, leaving the country dependent on roughly 472 MW of net imports.
The unavailability of nuclear generation at Cernavoda remained an important factor, increasing Romania’s reliance on gas, coal, hydro, wind and cross-border electricity. Romania imported significant volumes from Bulgaria while also receiving electricity through Hungary during peak periods, helping push its OPCOM price to €202.46/MWh, almost matching HUPX.
Bulgaria continued to act as a major regional exporter, although average net exports declined to approximately 1.47 GW from 1.77 GW the previous day. Its substantial nuclear generation fleet remained an important source of baseload supply for neighbouring markets.
The southern Balkan markets moved against the broader regional trend. Montenegro’s BELEN baseload price fell to €154.67/MWh, while generation recovered to around 253 MW from 117 MW. Its average import requirement consequently narrowed to approximately 147 MW from 296 MW.
North Macedonia recorded an even stronger divergence, with its day-ahead price dropping to €133.35/MWh, around €70/MWh below Hungary. Generation increased to approximately 697 MW from 449 MW, allowing the country to move into an average export position of around 285 MW, compared with 73 MW previously.
The result was a highly fragmented regional power market, with baseload prices ranging from approximately €133/MWh in North Macedonia to more than €203/MWh in Hungary, while Italy remained significantly more expensive.
Fuel markets added another layer of pressure. Austrian CEGH gas rose to around €80.80/MWh, while European gas prices remained at their highest levels since late 2022. Hungarian Week 38 power increased to approximately €190.50/MWh, while the October contract rose to around €193.50/MWh.
October and fourth-quarter gas forwards stood at around €81/MWh and €80.50/MWh, respectively, while EU carbon allowances remained close to €85.6/t. Elevated gas and carbon costs increase the marginal cost of thermal generation at precisely the time when the region needs additional flexible capacity during the evening ramp.
The Sept. 10 market therefore highlights a power system increasingly shaped not only by overall supply and demand, but by the timing and availability of flexible generation.
The widening gap between low-cost, solar-heavy daytime periods and expensive evening hours is increasing the value of battery storage, hydro flexibility, demand response and hourly hedging. For traders and market participants, the daily baseload average is consequently becoming a less complete measure of actual commercial exposure.
