South-east Europe’s electricity market remained divided between two contrasting price dynamics on 5 August 2026. Strong solar generation pushed several markets towards lower midday prices, but system conditions tightened sharply after sunset, driving evening prices as high as €411.04/MWh in Serbia. The volatility highlighted a structural shift in the regional power market, where daily average prices increasingly fail to capture underlying supply risks as the most critical periods move from traditional daytime peaks to evening hours when solar output disappears and flexible generation becomes scarce.
Regional electricity consumption increased by approximately 714 MW, or 2.1%, to 34.39 GW. Generation rose by only 328 MW, or 1%, reaching 32.58 GW. As a result, the combined regional electricity deficit widened from around 1.43 GW to 1.82 GW.
The deterioration occurred despite lower day-ahead prices in several markets, including Hungary, Romania, Croatia and Slovenia. The decline in daily averages reflected weaker midday prices caused by solar production and lower evening peaks compared with the previous exceptionally expensive trading session, rather than a meaningful improvement in regional supply conditions.
Hungary’s HUPX day-ahead market settled at an average of €176.27/MWh, down 5.7% from €186.90/MWh a day earlier. Prices ranged from €73.73/MWh during hour 12 to €338.35/MWh during hour 20. Although the maximum price was below Tuesday’s peak of €418.88/MWh, Hungary remained among Europe’s most expensive wholesale electricity markets.
The country’s reliance on imports increased despite lower consumption. Average Hungarian demand declined by 5.8% to 4.95 GW, while domestic generation fell much more sharply, dropping 16.4% to 2.66 GW. As a result, Hungary’s average import requirement increased from 2.07 GW to 2.29 GW, covering approximately 46% of total consumption.
Hungary remained closely dependent on neighbouring markets, particularly Slovakia, Austria and Romania. Scheduled electricity flows from Slovakia to Hungary averaged around 1.19 GW, compared with 993 MW during the previous session, while Austria-to-Hungary flows increased from 633 MW to 842 MW. Electricity flows from Romania were less stable, averaging around 432 MW towards Hungary, compared with 888 MW previously, with significant hourly reversals.
Romania’s OPCOM market remained closely aligned with Hungary. Romanian baseload averaged €177.07/MWh, only €0.80/MWh above HUPX, after declining 5.9% day on day. Hourly prices ranged from €73.12/MWh at midday to €342.12/MWh during hour 20.
Romanian electricity demand increased by 3.6% to 6.06 GW, while domestic generation remained almost unchanged at 5.49 GW. The country’s average import requirement expanded from 381 MW to approximately 574 MW, increasing by more than 50%. Although Romania and Hungary remained strongly connected through price signals, Romania was unable to provide the same level of net support to Hungary as during the previous trading session.
Serbia moved in the opposite direction, with SEEPEX baseload prices increasing 1.2% to €176.73/MWh. The daily average placed Serbia almost exactly alongside Hungary and Romania, but the figure concealed significantly higher volatility.
SEEPEX prices fell to €69.95/MWh during hour 11 before surging to €411.04/MWh during hour 20, the highest hourly price among the analysed markets. The resulting intraday spread exceeded €341/MWh. The premium over Hungary during the 20th hour reached almost €73/MWh, reflecting tight Serbian evening supply conditions following the decline of solar generation and limited access to additional imports.
Despite the evening scarcity, Serbia’s overall electricity balance improved. Average consumption increased by 4.2% to 4.15 GW, while domestic generation rose by 6.7% to 3.73 GW. The average import requirement narrowed from 494 MW to 425 MW, showing that higher domestic production reduced the daily deficit but was insufficient to prevent scarcity pricing during the evening ramp.
The Serbia-Hungary border remains one of the key constraints in the regional market. For 1–28 August, monthly allocation data indicate no significant additional Serbia-to-Hungary transmission capacity beyond previously allocated rights, while only 28 MW of additional Hungary-to-Serbia capacity is available. Larger transfer capacities of 600 MW northbound and 528 MW southbound become available only from 29–31 August.
This limits traders’ ability to exploit large hourly price differences between SEEPEX and HUPX. Serbia must therefore rely more heavily on alternative interconnections with Romania, Bulgaria, Bosnia and Herzegovina, North Macedonia, Croatia and Montenegro.
August allocations provide approximately 605 MW from Romania, 350 MW from Bosnia and Herzegovina, 350 MW from North Macedonia, 250 MW from Bulgaria, 155 MW from Croatia and 100 MW from Montenegro. The Romanian transmission capacity was relatively inexpensive at approximately €0.67/MWh, while Bulgarian capacity cleared at around €6.95/MWh.
The growing importance of solar generation is reshaping traditional electricity-market concepts. Across the region, conventional daytime peak periods are increasingly becoming the cheapest hours, while evening periods carry the highest scarcity premiums.
In Hungary, the average peak price was €144.96/MWh, while off-peak electricity averaged €207.58/MWh. In Serbia, SEEPEX peak prices averaged €148.01/MWh, compared with €205.45/MWh for off-peak products.
The traditional distinction between peak and off-peak is therefore becoming less representative of actual market risk. The most valuable hours are increasingly those between 18:00 and 21:00, when solar generation disappears, demand remains elevated and flexible capacity becomes essential.
Croatia and Slovenia remained among the highest-priced markets in the region. CROPEX declined by 6.7% to €179.13/MWh, while Slovenia’s BSP market decreased by 7.6% to €179.74/MWh, the highest daily average in the analysed dataset.
Croatian demand declined by 9.9% to 2.31 GW, reducing the country’s import requirement from around 1.17 GW to 959 MW. Nevertheless, Croatia still reached €326.37/MWh during hour 20, confirming continued exposure to evening scarcity.
Slovenian demand increased to 1.46 GW, while generation decreased slightly to approximately 1.32 GW, widening the average import requirement to 147 MW.
Bulgaria was one of the few major markets where prices increased. The IBEX day-ahead price rose by 5.9% to €166.37/MWh. Electricity demand increased sharply by 16.5% to 4 GW, while generation rose by 8.7% to 5.22 GW.
The country retained a significant export surplus, although it declined from 1.37 GW to 1.22 GW as domestic consumption absorbed more production. Bulgaria remains one of the region’s most important sources of surplus electricity, although higher domestic demand reduces its ability to stabilise neighbouring markets.
Greece remained the lowest-priced major market. The HENEX day-ahead market averaged €151.59/MWh, down 2.2% from the previous session. However, the country recorded one of the widest hourly spreads, moving from only €6.26/MWh during hour 11 to €289.33/MWh during hour 20.
Greek consumption increased to 7.40 GW, while generation slightly declined to 8.71 GW. The export surplus fell from 1.48 GW to 1.32 GW, but Greece remained one of the region’s largest electricity exporters alongside Bulgaria.
The Greek price curve demonstrates the impact of solar generation. Conventional peak prices averaged only €109.15/MWh, while off-peak prices reached €194.03/MWh because the off-peak category now includes expensive evening and overnight periods.
The widening gap between midday and evening prices is increasing the commercial value of battery energy storage systems (BESS), flexible hydropower, gas-fired generation and demand-response solutions. Intraday spreads exceeded €260/MWh in Hungary and Romania, €283/MWh in Greece and €341/MWh in Serbia.
Battery systems capable of charging during solar-heavy low-price periods and discharging during evening scarcity hours could capture significant market value, although efficiency losses, degradation costs and network charges remain important considerations.
For renewable generators, daily baseload prices above €150/MWh appear attractive, but the hourly profile creates a more complicated revenue picture. Solar assets sell their largest volumes during the weakest part of the curve, while scarcity prices occur after production has declined. The difference between baseload prices and solar capture prices is therefore likely to widen.
Wind generation has a different commercial profile, as its production is less concentrated around the depressed midday interval and can participate more effectively in evening and overnight prices when weather conditions permit. Wind’s system value therefore remains distinct from solar even when both technologies are grouped within broader renewable targets.
Industrial consumers face the opposite challenge. A flat baseload hedge may reduce average costs but can leave buyers exposed to the most expensive evening hours, particularly where consumption continues after sunset. Future hedging strategies will increasingly need to distinguish between solar hours, evening ramps and overnight demand rather than relying only on traditional baseload and peak products.
The South-east European electricity market is no longer defined only by which countries have surplus generation and which countries require imports. Bulgaria and Greece maintain daily export capacity, but their ability to support Serbia, Hungary, Croatia and Montenegro depends on whether transmission capacity is available precisely when scarcity emerges.
The widening premium over Germany, persistent forward-market differences and repeated evening price spikes indicate that grid flexibility, transmission access and storage capacity are becoming as important as electricity production itself. The region’s challenge is shifting from simply generating enough energy to ensuring that flexible resources and cross-border networks can deliver electricity exactly when the market needs it most.