The Southeast European electricity market entered Friday with a clear divide between the tightly interconnected Hungary–Romania–Slovenia–Croatia market zone and the lower-priced southern Balkan markets. The main catalyst was the deteriorating availability outlook for Hungary’s Paks nuclear power plant, where exceptionally low Danube water levels increased the possibility of a complete shutdown. The resulting supply risk was reflected across spot prices, cross-border flows and forward markets, with the strongest reaction visible on the Hungarian week-ahead curve.
Hungarian day-ahead electricity prices settled at €157.81/MWh, increasing by €25.70/MWh compared with Thursday. Romania followed at €155.33/MWh, while Slovenia and Croatia cleared at €157.65/MWh and €156.49/MWh, respectively. The four markets effectively converged within a range of just over €2/MWh, showing that regional price formation was being shaped by the same factors: tightening Hungarian supply, higher import requirements and expensive thermal replacement generation.
Germany also strengthened to €148.59/MWh, but Hungary maintained a premium of €9.22/MWh. Austria cleared at €155.61/MWh, only €2.20/MWh below HUPX. The relatively narrow western spreads indicate that Hungary remained closely connected to the Central European electricity market, despite declining domestic generation forcing the country to absorb significantly larger volumes of imported electricity.
Hungary’s average domestic generation was forecast to fall to 2,667 MW, compared with 3,209 MW on Thursday and more than 20% below Monday’s level. At the same time, electricity consumption increased to 4,871 MW, pushing the country’s net import requirement to approximately 2,203 MW, compared with 1,599 MW one day earlier. Import dependence became particularly visible during off-peak periods, when the average net deficit reached 3,285 MW.
The underlying vulnerability was already visible in Thursday’s generation mix. Output from Paks declined to an average of only 961 MW, compared with around 1,830–1,850 MW during the previous weekend. Nuclear generation supplied approximately 31% of Hungarian electricity output on 30 July, while solar generation accounted for 51%. This structure leaves the system exposed after sunset, when solar production disappears while cooling demand and evening consumption remain elevated. At the same time, reduced nuclear availability removes the stable baseload capacity normally used to support the transition into evening demand.
The hourly profile on the HUPX electricity exchange reflected these conditions. The daily minimum remained unusually high at €83.30/MWh during hour 16, while the evening maximum reached €268.60/MWh during hour 20. HUPX peak-hour prices averaged €136.00/MWh, while off-peak prices averaged €179.60/MWh. The unusual off-peak premium reflects the inclusion of expensive evening and overnight hours, while strong solar output continued to suppress daytime prices. The pattern highlights the growing importance of battery storage, flexible generation and hydro balancing capacity.
Romania experienced a similar price movement, with the OPCOM day-ahead market rising by €25.20/MWh to €155.33/MWh. Prices ranged from €83.30/MWh to €271.20/MWh during the evening peak. Romania’s net position weakened from imports of 376 MW to 480 MW, despite a slight increase in domestic generation to 5,228 MW. Electricity consumption increased to 5,708 MW.
Cross-border trading flows underline Romania’s role in covering Hungary’s supply deficit. Average exports from Romania to Hungary increased to 1,605 MW, reaching 2,301 MW during peak hours. At the same time, Romania imported around 2,088 MW from Bulgaria, effectively transferring Bulgarian surplus generation northwards into the Hungarian deficit area. The Bulgaria–Romania–Hungary corridor became one of the most important regional electricity trading routes.
Bulgaria increased electricity generation from 4,516 MW to 5,242 MW, allowing net exports to rise to 1,379 MW despite higher domestic consumption. Demand increased by 531 MW to 3,863 MW, while exports averaged 2,088 MW to Romania and around 297 MW to Serbia. These flows were partly offset by imports of approximately 1,101 MW from Greece.
Despite stronger exports, Bulgaria’s IBEX market remained below the northern regional cluster, clearing at €124.75/MWh. The Bulgarian market traded at a discount of €33.06/MWh compared with HUPX, with prices ranging from €40/MWh to €180.70/MWh. The wider spread indicates that renewable generation availability and transmission congestion continued to prevent full price convergence with Romania and Hungary.
Serbia remained among the cheaper electricity markets in the region despite stronger demand. The SEEPEX day-ahead price increased by €8.30/MWh to €113.07/MWh, maintaining a significant discount of €44.74/MWh compared with Hungary. Serbian electricity consumption increased by 327 MW, or around 9%, reaching 3,940 MW. Forecast generation rose more strongly from 3,053 MW to 3,400 MW, reducing the net import requirement slightly from 560 MW to 540 MW.
Serbia’s exposure to imports remained concentrated during peak hours. Net imports averaged 906 MW during peak periods, compared with only 174 MW outside peak hours. The largest scheduled inflows came from North Macedonia (374 MW), Bulgaria (297 MW), Hungary (115 MW) and Bosnia and Herzegovina (41 MW). Serbia exported electricity to Montenegro and Croatia, with average flows of 121 MW and 105 MW, respectively.
The SEEPEX daily minimum reached €60.10/MWh during hour 13, while the evening maximum climbed to €250.10/MWh during hour 20. The relatively low daily average therefore hides significant intraday volatility. Serbia traded more than €44/MWh below Hungary on average, but evening scarcity prices approached levels recorded in Hungary, Romania and Montenegro. This strengthens the value of short-duration storage, hydro flexibility and intraday hedging strategies.
Southern Balkan markets remained structurally cheaper. Greece declined by €2.60/MWh to €89.96/MWh, creating a record daily discount of €67.85/MWh compared with HUPX. Greek generation increased to 9,008 MW, exceeding consumption of 7,222 MW and supporting net exports of 1,787 MW. Greece exported approximately 1,101 MW to Bulgaria, 469 MW to North Macedonia and 200 MW to Albania.
The HENEX market recorded a zero-price hour during hour 16, while the daily maximum reached only €154.80/MWh. Strong daytime renewable availability and high export volumes kept Greece structurally cheaper, although limited interconnection capacity prevented the country’s surplus from fully relieving supply pressure in Hungary and central Southeast Europe.
Albania moved in the opposite direction, rising by €70.10/MWh to €158.09/MWh after settling at only €87.99/MWh on Thursday. Montenegro declined by €5.30/MWh to €146.43/MWh, although off-peak prices remained elevated at €181.20/MWh, with the maximum reaching €250/MWh during hour 21. Montenegro’s consumption increased to 461 MW, while generation reached only 326 MW, leaving net imports of 135 MW.
North Macedonia remained the second-cheapest market after Greece, declining by €12.40/MWh to €105.31/MWh. Its net balance improved to a modest 18 MW export position, although commercial flows continued to highlight its role as a regional transit market connecting Bulgaria, Greece, Kosovo and Serbia.
The combined SEE and Hungarian electricity system consumed 33,397 MW, an increase of 1,129 MW, or approximately 3.5%, compared with Thursday. Forecast generation reached 32,080 MW, leaving net imports of 1,317 MW. Imports from Austria and Slovakia into Hungary and Slovenia averaged 1,858 MW, while exports from Southeast Europe towards Italy declined to 765 MW. Lower exports to Italy helped retain more electricity within the region, although Italy recorded the highest national day-ahead price at €186.23/MWh.
Confirmed Thursday generation data show the supply transition behind Friday’s market conditions. Regional wind generation increased by 746 MW to 3,191 MW, while nuclear output declined by 323 MW to 4,143 MW. Solar generation decreased by 376 MW to 7,331 MW, coal output increased by 355 MW to 5,821 MW, and gas-fired generation fell slightly to 4,597 MW. A published renewable forecast for 31 July contained a spreadsheet error, meaning aggregate generation and country balances remain usable, but detailed renewable technology splits should not be treated as fully validated.
The forward electricity market carried a much stronger risk signal than the spot market. Hungarian Week 32 prices jumped by €70/MWh in a single session to €282/MWh, creating a premium of €155/MWh over Germany and €105.50/MWh over Italy. Week 33 increased to €184.50/MWh, while Hungarian August power rose to €184.50/MWh, gaining €20.50/MWh on the day and nearly 18% over the previous seven sessions.
By comparison, German Week 32 declined to €127/MWh, while Italian Week 32 stood at €176.50/MWh. The extreme Hungarian premium therefore reflects a specific regional adequacy and nuclear availability risk, rather than a broader European electricity market rally.
CEGH gas prices strengthened to €61.44/MWh, while EU carbon allowances eased to €81.29/tCO₂. At these levels, an efficient gas-fired power plant faces an estimated clean variable generation cost of around €140–145/MWh before operational and balancing costs. HUPX baseload prices of €157.81/MWh provide a positive but narrow margin for efficient combined-cycle generation, while evening prices above €260/MWh strongly reward flexible thermal capacity, storage and hydro resources.
The next market direction will depend primarily on Paks availability and Danube cooling-water restrictions. Regional temperatures are expected to rise over the weekend and into early next week, with Hungary moving above 30°C, while reported Danube flow at the relevant location stood at approximately 4,692 cubic metres per second. Continued nuclear restrictions would keep Hungarian import demand elevated, support Romanian and Bulgarian exports towards the north and maintain strong evening price premiums across interconnected Southeast European markets. Serbia is likely to remain relatively cheaper as long as domestic coal and hydropower availability remain stable, but the convergence around evening peak hours shows that the Serbian market is not isolated from regional scarcity conditions.