South-east European day-ahead electricity prices rose for delivery on Friday, 21 August, with Serbia recording the strongest increase in the region. Firmer Germany and Central European markets, alongside tighter supply conditions in Hungary, pushed much of central South-east Europe into the €170-175/MWh range.
The regional move 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, up about 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’s increase was stronger than Hungary’s, climbing €21.3/MWh to €169.56/MWh. That 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, forming a tightly priced Central European-Adriatic block.
Lower prices persist in the southern Balkan markets
Further south, prices remained lower than in central Europe. Albania settled at €160.54/MWh, Montenegro at €153.93/MWh and North Macedonia at €140.58/MWh.
North Macedonia traded almost €33.5/MWh below Hungary and more than €40/MWh below Italy, which stayed the most expensive market in the observed set at €180.91/MWh.
The day-ahead pattern again reflected fragmentation across the region, with trading effectively splitting into three price layers. Italy and the Hungary-Croatia-Slovenia-Austria cluster traded at roughly €173-181/MWh, Romania, Bulgaria and Serbia around €168-170/MWh, while southern Balkan markets were below €163/MWh.
Serbia drives the largest single-session move
The biggest shift came from Serbia’s day-ahead curve on Friday . SEEPEX base-load prices increased from €132.0/MWh on Thursday to €167.7/MWh on Friday.
The rise extended across the full daily curve rather than being concentrated only in the evening hours . The peak block moved from €127.3/MWh to €160.2/MWh, while off-peak prices increased from €136.7/MWh to €175.3/MWh.
Serbia’s hourly range also widened sharply, with the minimum increasing from €75.3/MWh to €130/MWh and the maximum rising from €200/MWh to €231/MWh . The minimum occurred around hour 11, while the daily maximum was reached around hour 20.
The higher price floor coincided with lower Serbian system activity . 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 showed imports of about 349 MW from Bulgaria, 203 MW from North Macedonia and 110 MW from Hungary on a base-load basis.
Cross-border flows diverge from simple price spreads
At the same time, Serbia exported around 146 MW towards Croatia, 107 MW towards Romania and 75 MW towards Montenegro . The flows illustrate that cross-border schedules do not always align with straightforward day-ahead price differentials.
The source of that divergence was linked to legacy capacity rights, bilateral positions and uncoupled borders preventing full integration of the Balkan electricity market as a spot system . Those factors can keep trade patterns from matching relative price levels between neighbouring markets.
Hungary’s curve shows solar-driven inversion
Hungary remained one of the main regional price anchors on Friday . HUPX base-load reached €174.1/MWh, with an unusual daily shape showing peak averaging at just €169.9/MWh versus off-peak averaging at €178.3/MWh.
The minimum hourly price was still relatively high at €135.7/MWh, while the evening maximum reached €222.7/MWh . The peak/off-peak inversion was associated with summer conditions where high photovoltaic output suppresses traditional daytime peak pricing and post-sunset ramps lift prices into what is historically treated as off-peak hours.
Hungary’s underlying balance stayed tight as consumption was around 4.137 GW against domestic generation of approximately 2.882 GW . That left Hungary dependent on about 1.255 GW of net imports.
A key factor was restricted nuclear availability at Paks following exceptionally low Danube water levels . Hungary expected affected units to restart gradually from 23 August, with full output potentially restored by 27-28 August after emergency works aimed at increasing cooling-water levels.
Nuclear constraints and fuel costs support higher prompt pricing
The tighter prompt conditions were reflected in regional spreads despite additional solar output . With German day-ahead prices reaching €169.56/MWh, the HU-DE spread narrowed to just €4.50/MWh.
Average imports into Hungary and Slovenia from the Austria-Slovakia core fell to around 1.051 GW, about 261 MW lower than the previous day . The wider Hungary and SEE system remained a net importer of roughly 923 MW versus 693 MW in the prior session.
Regional consumption increased by about 358 MW to around 32.49 GW . 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 higher solar availability, prices increased across most markets.
Bilateral schedules shape Romania and Bulgaria’s role
Romania and Bulgaria were close on average day-ahead pricing at €169.58/MWh and €169.08/MWh, respectively . Romania’s national balance was near neutral with demand of around 5.73 GW, generation of approximately 5.71 GW and net imports of about 24 MW.
Cross-border activity remained substantial even with that near-neutral domestic position . Romania was scheduled to export about 1.06 GW to Hungary on a base-load basis while importing approximately 1.01 GW from Bulgaria; during peak hours exports towards Hungary rose to roughly 2.62 GW and imports from Bulgaria approached 1.79 GW.
Bulgaria continued as one of the region’s largest exporters . Generation of about 5.08 GW exceeded domestic consumption of around 3.95 GW, producing 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 . Kozloduy Unit 5 was scheduled to reduce output by around 120 MW on 21 August, citing exceptionally low Danube water levels; it marked the first weather-related reduction of this type in its operating history.
Greece stays cheaper on average but peaks remain high
HENEX rose by more than €16/MWh, but remained relatively inexpensive at €162.73/MWh, about €11.3/MWh below HUPX and €6.4/MWh below Bulgaria . Greece also remained a significant exporter with average generation of approximately 7.87 GW, demand near 6.90 GW, and net exports close to 968 MW.
Commercial schedules showed base-load flows of about 308 MW towards Bulgaria, 184 MW towards Albania, 354 MW towards North Macedonia and 171 MW towards Italy . During peak hours flows from Greece to Bulgaria increased to around 752 MW.
The hourly HENEX curve reflected solar-driven volatility . The minimum price fell to just €76.7/MWh around hour 12 while the evening maximum reached €223.6/MWh around hour 19.
Macedonia and Montenegro remain discounted versus central Europe
A similar intraday pattern appeared in North Macedonia as MEMO stayed cheapest in the region at €140.58/MWh, with midday minimum at just €50.3/MWh. The evening maximum reached €208/MWh, while domestic consumption was about
