South-east European day-ahead electricity prices rose sharply for delivery on Friday, 21 August, with Serbia recording the strongest increase in the region. Firmer German and Central European markets, combined with tighter supply conditions in Hungary, pushed much of central South-east Europe towards the €170-175/MWh range.
The regional increase was broad but uneven. HUPX rose by €12.7/MWh to €174.06/MWh, while SEEPEX Serbia surged by €35.8/MWh to €167.74/MWh, a gain of around 27% in a single session. Bulgaria increased by €15.3/MWh to €169.08/MWh, Greece by €16.2/MWh to €162.73/MWh, Croatia by €12.5/MWh to €173.82/MWh and Slovenia by €11.3/MWh to €173.18/MWh.
Germany recorded an even stronger increase than Hungary, climbing €21.3/MWh to €169.56/MWh. This narrowed the Hungarian premium over Germany to just €4.50/MWh, compared with around €13/MWh a day earlier. Austria, Croatia and Slovenia also converged closely with HUPX, creating a tightly priced Central European-Adriatic market block.
Further south, however, prices remained significantly lower. Albania settled at €160.54/MWh, Montenegro at €153.93/MWh and North Macedonia at only €140.58/MWh. North Macedonia therefore traded almost €33.5/MWh below Hungary and more than €40/MWh below Italy, which remained the most expensive market in the observed region at €180.91/MWh.
Friday’s trading once again highlighted the fragmented nature of the South-east European electricity market. The region effectively split into three price layers: Italy and the Hungary-Croatia-Slovenia-Austria cluster at roughly €173-181/MWh; Romania, Bulgaria and Serbia around €168-170/MWh; and the southern Balkan markets below €163/MWh.
The most significant move came from Serbia.
SEEPEX base-load prices jumped from €132.0/MWh on Thursday to €167.7/MWh on Friday. The increase extended across the entire daily curve rather than being concentrated only in the evening. The peak block rose from €127.3/MWh to €160.2/MWh, while off-peak prices increased from €136.7/MWh to €175.3/MWh.
Serbia’s minimum hourly price also rose sharply, from €75.3/MWh to €130/MWh, while the maximum increased from €200/MWh to €231/MWh. The minimum occurred around hour 11, with the daily maximum reached around hour 20.
The structure points to a broad tightening of the Serbian power balance, rather than an isolated evening scarcity event. The entire price floor moved significantly higher.
The increase came despite lower Serbian electricity consumption. Average demand fell to approximately 3.735 GW, from 3.981 GW a day earlier, while generation declined more sharply, from around 3.609 GW to 3.344 GW. As a result, Serbia became a net importer of approximately 391 MW, compared with around 372 MW the previous day.
Scheduled commercial flows further demonstrate the importance of regional interconnections. Serbia imported approximately 349 MW from Bulgaria, 203 MW from North Macedonia and 110 MW from Hungary on a base-load basis. At the same time, it exported around 146 MW towards Croatia, 107 MW towards Romania and 75 MW towards Montenegro.
These flows also demonstrate why cross-border schedules do not always follow straightforward day-ahead price differentials. Serbia was importing from Hungary and Bulgaria despite their higher prices while exporting towards cheaper Montenegro. Legacy capacity rights, bilateral positions and uncoupled borders continue to prevent the Balkan electricity market from functioning as a fully integrated spot market.
Hungary remained one of the main regional price anchors.
HUPX base-load reached €174.1/MWh, although the daily curve showed an unusual structure. The peak block averaged just €169.9/MWh, compared with €178.3/MWh for off-peak hours. The minimum hourly price was still relatively high at €135.7/MWh, while the evening maximum reached €222.7/MWh.
The inversion between peak and off-peak prices reflects a growing feature of summer electricity markets with high solar penetration. Strong photovoltaic output suppresses prices during traditional daytime peak hours, while the post-sunset ramp pushes some of the most expensive periods into what was historically considered the off-peak window.
Hungary’s underlying system balance remained tight. Consumption was around 4.137 GW, while domestic generation reached only approximately 2.882 GW, leaving the country dependent on around 1.255 GW of net imports.
A major factor remains the restricted availability of nuclear generation at Paks following exceptionally low Danube water levels. Hungary expects the affected units to gradually restart from 23 August, with full output potentially restored by 27-28 August following emergency works aimed at increasing cooling-water levels.
Until additional nuclear capacity returns, Hungary must replace a significant amount of normally low-cost baseload generation with imports and more expensive domestic production. This continues to support HUPX prices despite strong summer solar generation.
The stronger German market nevertheless changed regional cross-border economics. With German day-ahead prices reaching €169.56/MWh, the HU-DE spread narrowed to just €4.50/MWh. At the same time, average imports from the Austria-Slovakia core into Hungary and Slovenia fell to around 1.051 GW, approximately 261 MW lower than the previous day.
The wider Hungary and SEE system remained a net importer of around 923 MW, up from 693 MW in the previous session. Regional consumption increased by approximately 358 MW to around 32.49 GW.
Higher demand, reduced nuclear availability and stronger neighbouring markets therefore outweighed the growing contribution from renewable generation.
Solar output was forecast at approximately 8.35 GW, nearly 0.95 GW higher than the previous day, while wind generation remained broadly unchanged at around 1.96 GW. Despite the additional solar output, prices increased across most markets.
Solar generation is increasingly influencing the shape of the price curve rather than its overall level. Midday prices remain compressed, but prices rise sharply before and after the main photovoltaic production period.
Romania and Bulgaria almost completely converged, with prices at €169.58/MWh and €169.08/MWh, respectively.
Romania’s national balance was close to neutral, with demand of around 5.73 GW, generation of approximately 5.71 GW and net imports of only about 24 MW. However, the national balance masks substantial cross-border activity.
Romania was scheduled to export around 1.06 GW to Hungary on a base-load basis while simultaneously importing approximately 1.01 GW from Bulgaria. During peak hours, exports towards Hungary increased to roughly 2.62 GW, while imports from Bulgaria approached 1.79 GW.
Romania is therefore increasingly functioning as a major transmission corridor, moving electricity from the Balkans towards Hungary and Central Europe rather than simply balancing its own domestic market.
Bulgaria remained one of the region’s largest exporters. Generation of approximately 5.08 GW exceeded domestic consumption of around 3.95 GW, resulting in average net exports of roughly 1.13 GW.
Base-load commercial flows included approximately 1.01 GW towards Romania, 349 MW towards Serbia and 180 MW towards North Macedonia.
However, Bulgaria’s balance is becoming more sensitive to hydrological conditions. Kozloduy Unit 5 was scheduled to reduce output by around 120 MW on 21 August because of exceptionally low Danube water levels, marking the first weather-related reduction of this type in the plant’s operating history.
Although the reduction is relatively small compared with Bulgaria’s overall generation fleet, it highlights a broader regional issue. Low river levels are simultaneously affecting hydropower production, nuclear cooling conditions and thermal generation economics across parts of Central and South-east Europe.
Greece presented a different market profile.
Despite rising by more than €16/MWh, HENEX remained relatively inexpensive at €162.73/MWh, around €11.3/MWh below HUPX and €6.4/MWh below Bulgaria. Greece also remained a significant electricity exporter.
Average Greek generation reached approximately 7.87 GW, compared with demand of around 6.90 GW, resulting in net exports of close to 968 MW.
Commercial schedules showed approximately 308 MW flowing towards Bulgaria, 184 MW towards Albania, 354 MW towards North Macedonia and 171 MW towards Italy on a base-load basis. During peak hours, flows from Greece to Bulgaria increased to around 752 MW.
The hourly HENEX curve highlights the impact of solar generation. The minimum price fell to just €76.7/MWh around hour 12, while the evening maximum reached €223.6/MWh around hour 19.
The resulting spread of almost €147/MWh between midday and evening illustrates the scale of the intraday flexibility challenge created by high solar penetration. Greece can remain relatively inexpensive on a daily average, export significant volumes and still experience very expensive evening hours.
A similar pattern is visible in North Macedonia.
MEMO remained the cheapest market in the region at €140.58/MWh. Its midday minimum fell to only €50.3/MWh, while the evening maximum reached €208/MWh.
North Macedonia was broadly balanced domestically, with consumption of approximately 483 MW and generation of around 461 MW. However, cross-border flows remained substantial relative to the size of the system. The country imported electricity from Greece and Bulgaria while exporting towards Serbia and Kosovo, reinforcing its role as a transit market between the southern and northern Balkans.
Montenegro provided another example of the value created by regional price fragmentation.
BELEN settled at just €153.93/MWh, more than €20/MWh below HUPX and almost €27/MWh below Italy.
Montenegro remained a modest net importer, with consumption of around 478 MW, generation of 368 MW and net imports of approximately 109 MW. Nevertheless, commercial exports towards Italy remained around 387 MW.
The country was therefore importing electricity from several Balkan markets while moving significant volumes through its submarine interconnector towards the considerably more expensive Italian market. Base-load flows included imports from Bosnia and Herzegovina, Serbia, Albania and Kosovo alongside exports towards Italy.
This highlights Montenegro’s role not only as a domestic market but also as an important transmission and arbitrage corridor between the western Balkans and Italy.
Croatia showed a contrasting profile. Despite CROPEX almost fully converging with HUPX at €173.82/MWh, Croatia remained a major importer, with approximately 950 MW of net imports against demand of around 2.54 GW. Imports came from Hungary, Slovenia, Serbia and Bosnia and Herzegovina.
Slovenia was also a net importer at approximately 335 MW, despite its nuclear generation base, and traded at a level almost identical to Hungary and Croatia.
Italy remained the regional price ceiling at €180.91/MWh. As a result, most of SEE moved closer to Italy rather than Italian prices moving higher. The Italian premium over HUPX narrowed to around €6.85/MWh, while the premium over Montenegro remained close to €27/MWh and over North Macedonia exceeded €40/MWh.
Fuel markets provided additional support for electricity prices. CEGH Austrian gas increased by €1.7/MWh to €66.25/MWh, while Greek gas rose to €55.4/MWh and EU carbon allowances advanced to approximately €82.45/tCO₂. September API-2 coal also increased to €125.5/t.
At these levels, flexible thermal generation remains relatively expensive, supporting power prices well above the levels typically associated with a high-renewables August market. Higher gas costs are particularly relevant as reduced nuclear and hydro availability increases the likelihood of gas-fired generation setting the marginal price during evening periods.
The forward market, however, remains significantly below prompt prices.
Hungarian Week 35 traded at around €147.50/MWh, Week 36 at €148/MWh and September at €159/MWh, compared with day-ahead HUPX above €174/MWh. The spot market therefore carried a premium of roughly €26.5/MWh over Week 35 and around €15/MWh over September.
This suggests that traders continue to view the current price strength primarily as a prompt-market tightening rather than a permanent structural shift.
The expected return of additional Paks capacity is the clearest potential bearish catalyst. If the affected units restart from 23 August and the plant approaches full output by 27-28 August, Hungarian import demand should decline significantly, potentially releasing electricity into neighbouring markets and reducing HUPX premiums.
However, Bulgaria’s Kozloduy reduction, persistent low hydrology and elevated gas prices continue to limit the downside.
Friday’s session was therefore driven less by a simple increase in regional demand than by the interaction of reduced dispatchable availability, expensive fuel, cross-border constraints and changing renewable output.
Serbia’s €35.8/MWh daily increase is the clearest example. Prices surged despite lower domestic consumption because Serbian generation declined more sharply, neighbouring markets strengthened and the minimum hourly price increased from €75/MWh to €130/MWh.
At the same time, Greece, North Macedonia and Montenegro retained significant discounts, preserving large north-south and east-west price spreads across the region.
For traders, the key prompt indicators are therefore not limited to outright HUPX or SEEPEX prices. Paks availability, Danube water levels, Greek renewable generation, Romanian-Bulgarian transit flows, the Montenegro-Italy spread and the midday-to-evening solar ramp are increasingly determining where the next major regional price divergence will emerge.