South-east Europe’s electricity market remained caught between two sharply different price regimes on 5 August 2026. Solar output pushed several exchanges towards relatively low midday prices, but the regional system tightened rapidly after sunset, sending evening contracts as high as €411.04/MWh in Serbia. The resulting volatility reinforced a market structure in which the daily average reveals only part of the underlying supply risk.
SEE average electricity consumption increased by approximately 714 MW, or 2.1%, to 34.39 GW. Generation rose by only 328 MW, or 1.0%, reaching 32.58 GW. The combined regional shortfall consequently widened from around 1.43 GW to 1.82 GW.
That deterioration matters because it occurred even as day-ahead prices declined in Hungary, Romania, Croatia and Slovenia. Lower daily averages did not reflect a material easing of the region’s physical balance. Instead, they largely resulted from softer prices during solar-intensive hours and lower evening peaks compared with the exceptionally expensive previous session.
Hungary’s HUPX market settled at an average €176.27/MWh, falling 5.7% from €186.90/MWh a day earlier. Prices ranged from €73.73/MWh in hour 12 to €338.35/MWh in hour 20. Although the maximum was substantially below Tuesday’s €418.88/MWh, Hungary remained one of Europe’s most expensive wholesale markets.
The country’s physical position became more dependent on imports despite weaker demand. Average Hungarian consumption declined by 5.8% to 4.95 GW, but domestic generation fell much more sharply, dropping 16.4% to 2.66 GW. The average import requirement therefore increased from 2.07 GW to 2.29 GW, equivalent to roughly 46% of total consumption.
This deep import dependence kept Hungary closely connected to developments in Romania, Slovakia and Austria. Scheduled electricity from Slovakia towards Hungary averaged approximately 1.19 GW, compared with 993 MW during the previous session, while Austria-to-Hungary schedules increased from 633 MW to 842 MW. Flows from Romania were considerably less stable, averaging approximately 432 MW towards Hungary, down from 888 MW, with substantial hourly reversals.
Romania’s OPCOM market remained almost fully aligned with Hungary. Romanian baseload averaged €177.07/MWh, only €0.80/MWh above HUPX, after declining by 5.9% day on day. The hourly price ranged from €73.12/MWh at midday to €342.12/MWh during hour 20.
Romanian demand increased by 3.6% to 6.06 GW, while production was effectively unchanged at 5.49 GW. The country’s average import requirement expanded from 381 MW to approximately 574 MW, an increase of more than 50%. Romania was therefore unable to provide the same level of net support to Hungary as during the preceding day, even though the two markets remained closely coupled in price terms.
Serbia moved in the opposite direction. SEEPEX baseload increased by 1.2% to €176.73/MWh, bringing Serbia almost exactly into line with Hungary and Romania on the daily average. The similarity concealed a much more volatile Serbian hourly curve.
SEEPEX fell to €69.95/MWh in hour 11 before rising to €411.04/MWh in hour 20, the highest hourly price among the markets covered. Serbia consequently recorded an intraday spread of more than €341/MWh. The hour-20 premium over Hungary reached almost €73/MWh, indicating a particularly tight Serbian post-solar ramp and limited access to incremental imports at the point of maximum evening demand.
Serbia’s domestic balance nevertheless improved. Average consumption increased by 4.2% to 4.15 GW, while generation rose by 6.7% to 3.73 GW. The average import requirement narrowed from 494 MW to 425 MW. Higher domestic production was sufficient to reduce the daily deficit but not to prevent scarcity pricing during the evening transition.
The Serbian-Hungarian border remains one of the most important constraints. For the period from 1 to 28 August, monthly allocation data show no conventional additional Serbia-to-Hungary transfer capacity beyond previously allocated rights, while only 28 MW of additional Hungary-to-Serbia capacity is available. Larger volumes of 600 MW northbound and 528 MW southbound become available only from 29 to 31 August.
This configuration limits the ability of traders to respond to the considerable hourly spreads between SEEPEX and HUPX. Serbia must rely more heavily on its other neighbouring systems, including Romania, Bulgaria, Bosnia and Herzegovina, North Macedonia, Croatia and Montenegro.
August allocations provide around 605 MW of import capacity from Romania through the middle of the month, alongside 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 allocation was relatively inexpensive at around €0.67/MWh, while capacity from Bulgaria cleared at approximately €6.95/MWh.
The value of these transmission rights is becoming increasingly dependent on the delivery hour. Daily average prices across Serbia, Hungary and Romania were separated by less than €1/MWh, suggesting limited baseload arbitrage. During individual evening hours, however, the spreads widened dramatically. The commercial value lies less in flat daily transfers and increasingly in positioning capacity around hours 18–21.
Croatia and Slovenia remained at the upper end of the regional market. CROPEX declined 6.7% to €179.13/MWh, while Slovenia’s BSP market fell 7.6% to €179.74/MWh, the highest daily baseload average in the dataset.
Croatian consumption decreased by 9.9% to 2.31 GW, reducing the country’s import requirement from approximately 1.17 GW to 959 MW. Even with the weaker load, the Croatian price reached €326.37/MWh in hour 20. Lower consumption reduced the size of Croatia’s daily deficit but did not remove its exposure to the evening regional shortage.
Slovenian demand increased to 1.46 GW, while generation eased to approximately 1.32 GW. Its average import requirement consequently widened to 147 MW. Slovenia’s evening maximum of €320/MWh was lower than the corresponding peaks in Hungary, Romania, Croatia and Serbia, but the Slovenian market maintained a comparatively high price floor across the full day.
Bulgaria was one of the few large markets to record a day-on-day price increase. IBEX baseload rose by 5.9% to €166.37/MWh. Bulgarian demand surged 16.5% to 4.00 GW, while generation increased by 8.7% to 5.22 GW.
The country retained a substantial exportable surplus, but it declined from 1.37 GW to 1.22 GW as domestic consumption absorbed a larger share of production. Bulgaria remained one of the principal sources of surplus electricity for the region, although its ability to moderate prices elsewhere weakened as its own demand climbed.
Greece remained the least expensive major market. HENEX averaged €151.59/MWh, down 2.2% from the previous session. The country nevertheless recorded one of the most extreme hourly price ranges, moving from only €6.26/MWh in hour 11 to €289.33/MWh in hour 20.
Greek consumption increased to 7.40 GW, while generation eased slightly to 8.71 GW. The average export surplus declined from 1.48 GW to 1.32 GW, but Greece remained one of the region’s two largest surplus systems alongside Bulgaria.
The Greek price curve illustrated the growing division between solar hours and the evening ramp. The conventional peak-period average was only €109.15/MWh, compared with an off-peak average of €194.03/MWh. This apparent reversal results from the off-peak product including the expensive overnight and late-evening hours, while the conventional peak block captures the heavily solar-supplied middle of the day.
The same pattern appeared across the northern markets. HUPX peak averaged €144.96/MWh, while Hungarian off-peak electricity reached €207.58/MWh. SEEPEX peak averaged €148.01/MWh, against €205.45/MWh for the Serbian off-peak product.
Traditional peak and off-peak classifications are becoming less effective descriptions of the commercial risk. Midday is increasingly the cheapest part of the delivery profile, while evening hours that historically sat within a conventional baseload or off-peak structure now carry the greatest scarcity premium.
Albania and Montenegro registered the strongest baseload increases. ALPEX rose 11.4% to €171.03/MWh, even though Albania moved into an average export position of approximately 69 MW. Albanian generation increased to 1.17 GW, while demand eased to 1.10 GW.
Montenegro’s BELEN market increased 6.0% to €169.15/MWh. Domestic generation more than doubled from 142 MW to 305 MW, cutting the average import requirement from 308 MW to 183 MW. The improved power balance did not translate into a lower market price, demonstrating Montenegro’s continued exposure to regional price formation and constrained western Balkan transmission corridors.
North Macedonia’s MEMO market declined 3.3% to €159.95/MWh. Demand increased by almost 12% to 451 MW, while generation remained stable at 557 MW. Its export surplus narrowed from 156 MW to 106 MW.
Bosnia and Herzegovina retained a surplus of approximately 218 MW, while Kosovo’s deficit widened to 165 MW. Slovenia, Croatia, Hungary, Romania, Serbia, Montenegro and Kosovo were net importers during the session, while Greece, Bulgaria, Bosnia and Herzegovina, Albania and North Macedonia remained net exporters.
The clearest regional trading signal was the widening premium to Germany. Hungary’s baseload premium over the German market increased to €65.75/MWh, compared with €37.11/MWh on Tuesday. The Hungarian peak premium expanded to €85.62/MWh.
The move indicates that the decline in HUPX did not represent broader European price relief. German prices fell faster, leaving Hungary and the wider SEE region exposed to their own generation limitations, transmission congestion and evening flexibility shortage.
The forward market continues to price this structural difference. Hungarian September baseload was quoted at €165.50/MWh, compared with €130/MWh in Germany and €162.50/MWh in Italy. Hungary therefore carried a September premium of €35.50/MWh to Germany but only €3/MWh to Italy.
Hungarian week 33 traded at €181/MWh, or €50.50/MWh above the equivalent German contract. Week 34 stood at €164.50/MWh, maintaining a €42.50/MWh premium to Germany. These values remain below the daily HUPX-German differential, suggesting that the forward market expects some moderation but not the disappearance of SEE scarcity.
Further along the curve, Hungarian calendar 2027 baseload was priced at €122/MWh, against €101.50/MWh in Germany and €116/MWh in Italy. Calendar 2028 stood at €101.50/MWh, preserving premiums of €16/MWh over Germany and €8/MWh over Italy.
The persistence of these premiums points to a deeper regional problem than a short-lived heatwave. Hungary and the surrounding SEE markets remain dependent on cross-border imports during periods when neighbouring systems are experiencing similar cooling demand, declining hydro flexibility or lower thermal availability. Available transmission capacity cannot always move sufficient energy towards the highest-priced market during the most valuable hours.
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. 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 consequently remains distinct from solar even when both technologies are grouped within broader renewable generation targets.
Battery storage and flexible hydro assets face the strongest immediate opportunity. Intraday spreads exceeded €260/MWh in Hungary and Romania, €283/MWh in Greece and €341/MWh in Serbia. A battery able to charge during the solar trough and discharge during hours 19–21 could capture a substantial gross spread before efficiency losses, degradation, balancing costs and grid charges.
Industrial buyers face the opposite exposure. A flat baseload hedge may reduce the average cost but can leave an offtaker exposed to the most expensive evening hours, particularly where consumption continues after sunset. Hedging structures will increasingly need to distinguish solar hours, evening ramps and overnight demand rather than relying solely on traditional baseload and peak products.
The regional market is no longer simply divided between exporters and importers. Greece and Bulgaria possess daily surpluses, but their ability to stabilise Serbia, Hungary, Croatia and Montenegro depends on the availability and direction of cross-border capacity at the precise hour of scarcity. The widening German premium, persistent forward-curve differential and repeated evening spikes show that transmission access and flexibility are becoming as important as the volume of energy generated.
