South-east European day-ahead electricity prices rose sharply for delivery on Friday, 21 August, with Serbia recording by far the largest daily increase, while a tightening prompt balance in Hungary and firmer German and regional markets pulled most of central SEE back towards the €170-175/MWh range.
The move was broad but highly uneven. HUPX rose €12.7/MWh to €174.06/MWh, while SEEPEX Serbia surged €35.8/MWh to €167.74/MWh, an increase of about 27% in a single session. Bulgaria gained €15.3/MWh to €169.08/MWh, Greece rose €16.2/MWh to €162.73/MWh, Croatia increased €12.5/MWh to €173.82/MWh, and Slovenia climbed €11.3/MWh to €173.18/MWh.
Germany strengthened even more rapidly than Hungary, rising €21.3/MWh to €169.56/MWh. This compressed the Hungarian premium over Germany to only €4.50/MWh, from around €13/MWh a day earlier. Austria at €173.42/MWh, Croatia at €173.82/MWh and Slovenia at €173.18/MWh effectively converged with HUPX, creating a tightly priced Central European-Adriatic block.
The picture south of this core remained markedly different. 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.
The result was another clear demonstration that SEE is not trading as one homogeneous price zone. Instead, Friday’s session effectively divided the region into three layers: Italy and the Hungary-Croatia-Slovenia-Austria cluster near €173-181/MWh; Romania, Bulgaria and Serbia around €168-170/MWh; and the increasingly discounted southern Balkan markets below €163/MWh.
The most striking move was Serbia.
SEEPEX base-load jumped from €132.0/MWh on Thursday to €167.7/MWh on Friday. More importantly, the move was not simply the result of one or two expensive evening hours. Serbia’s peak block rose from €127.3/MWh to €160.2/MWh, while off-peak increased from €136.7/MWh to €175.3/MWh.
The minimum hourly price also moved dramatically higher, from €75.3/MWh to €130/MWh, while the maximum rose from €200/MWh to €231/MWh. The Friday minimum occurred around hour 11, while the maximum came at hour 20.
That pattern suggests a fundamental tightening of the Serbian curve rather than an isolated evening scarcity event. The entire price floor shifted upwards.
Interestingly, this happened even though Serbian consumption declined. Average demand was around 3.735 GW, down from 3.981 GW a day earlier, while generation fell more strongly, from about 3.609 GW to 3.344 GW. The lower domestic generation therefore outweighed the reduction in demand, leaving Serbia a net importer of roughly 391 MW, slightly more than the previous day’s 372 MW.
Scheduled commercial flows illustrate the increasingly interconnected nature of Serbian pricing. Serbia imported around 349 MW from Bulgaria, 203 MW from North Macedonia and approximately 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 underline one of the structural features of the Balkan market: commercial schedules do not always follow the simple direction implied by neighbouring day-ahead price differentials. Serbia was importing from more expensive Hungary and Bulgaria while exporting towards cheaper Montenegro. Legacy capacity rights, bilateral positions and uncoupled borders continue to prevent the region from behaving like a fully integrated spot market.
Hungary remained the central price anchor.
HUPX base-load at €174.1/MWh was accompanied by an unusual curve structure. The peak block averaged only €169.9/MWh, compared with €178.3/MWh off-peak. The lowest hourly price was still a relatively high €135.7/MWh, while the evening maximum reached €222.7/MWh.
The inversion between peak and off-peak prices is increasingly characteristic of summer trading in markets with large solar fleets. Traditional daytime peak hours are depressed by photovoltaic generation, while the post-sunset ramp moves some of the day’s most expensive hours into what was historically regarded as the off-peak block.
Hungary’s underlying system balance remained tight. Consumption was around 4.137 GW, against domestic generation of only about 2.882 GW, leaving the country dependent on approximately 1.255 GW of net imports.
The most important fundamental remains the restricted availability of Paks nuclear power plant following exceptionally low Danube levels. Hungary expects the offline units gradually to restart from 23 August, with full output potentially restored by 27-28 August following emergency works designed to raise cooling-water levels.
Until that return materialises, Hungary must replace substantial amounts of normally low-cost baseload nuclear generation with imports and higher-cost domestic output. That explains why HUPX continues to carry a significant prompt premium despite strong summer solar production.
The German move nevertheless changed the cross-border economics. With German day-ahead prices jumping to €169.56/MWh, the HU-DE spread narrowed to only €4.50/MWh. At the same time, average imports from the Austria-Slovakia core into Hungary and Slovenia declined to around 1.051 GW, approximately 261 MW lower day on day.
The wider HU+SEE system remained a net importer of about 923 MW, up from 693 MW in the previous session. Regional consumption was estimated at roughly 32.49 GW, about 358 MW higher on the day.
The combination of higher demand, reduced availability of cheap nuclear generation and a stronger surrounding European market therefore outweighed the increasingly substantial renewable contribution.
Solar output was forecast at approximately 8.35 GW, almost 0.95 GW higher than the previous day, while wind was essentially unchanged at around 1.96 GW. Yet the additional solar generation was unable to prevent a broad price increase.
Instead, solar increasingly determined the shape rather than the overall level of the curve. Prices were still compressed around midday but remained elevated before and after the photovoltaic production window.
Romania and Bulgaria converged almost completely at €169.58/MWh and €169.08/MWh, respectively.
Romania’s overall balance was almost flat, with demand of approximately 5.73 GW, generation of about 5.71 GW and net imports of only around 24 MW. But the apparently neutral national balance hides extremely large transit flows.
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, the movement was even more pronounced: exports towards Hungary reached around 2.62 GW, while imports from Bulgaria approached 1.79 GW.
Romania was therefore acting less as an isolated national market and more as a major transmission bridge moving Balkan generation northwards towards Hungary and Central Europe.
Bulgaria remained one of the region’s largest exporters. Generation of roughly 5.08 GW exceeded consumption of around 3.95 GW, producing average net exports of approximately 1.13 GW.
Flows included about 1.01 GW towards Romania, 349 MW towards Serbia and 180 MW towards North Macedonia on a base-load basis.
The Bulgarian balance is nevertheless 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, the first weather-related reduction of this type in the plant’s operating history.
The amount is relatively small compared with the overall Bulgarian generation fleet, but its importance lies in the wider regional context. Nuclear restrictions are no longer confined to Hungary. Low river levels are simultaneously affecting hydroelectric production, nuclear cooling conditions and thermal generation economics across parts of Central and South-east Europe.
Greece presented the opposite picture.
Despite gaining more than €16/MWh, HENEX remained relatively cheap at €162.73/MWh, around €11.3 below HUPX and €6.4 below Bulgaria. Greece simultaneously remained a significant exporter.
Average Greek generation reached approximately 7.87 GW against demand of about 6.90 GW, producing net exports close to 968 MW.
Commercial schedules showed around 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 the Greek-to-Bulgarian flow increased to roughly 752 MW.
The hourly HENEX profile illustrates why. Greece’s minimum fell to just €76.7/MWh around hour 12, while the evening maximum climbed to €223.6/MWh around hour 19.
A difference approaching €147/MWh between the midday trough and evening maximum shows the scale of the intraday flexibility challenge created by high solar penetration. Greece can simultaneously appear inexpensive on a daily average, export substantial electricity to neighbouring systems and still experience extremely expensive evening hours.
The same structural phenomenon is visible, although even more strongly, in North Macedonia.
MEMO remained the cheapest market in the region at €140.58/MWh. Its midday minimum dropped to only €50.3/MWh, while the evening maximum reached €208/MWh.
North Macedonia was almost balanced on a national basis, with consumption of approximately 483 MW and generation around 461 MW, but cross-border flows were large relative to the size of the system. It imported electricity from Greece and Bulgaria while exporting towards Serbia and Kosovo, reinforcing its role as a transit market connecting the cheaper southern zone with northern Balkan demand.
Montenegro displayed perhaps the clearest example of cross-border value created by regional price fragmentation.
BELEN settled at only €153.93/MWh, more than €20/MWh below HUPX and almost €27/MWh below Italy.
Montenegro itself remained a modest net importer, with consumption of approximately 478 MW, generation of 368 MW and net imports of around 109 MW. Yet commercial flows towards Italy were still approximately 387 MW.
The country was effectively importing electricity from several Balkan neighbours while moving significant volumes across the submarine interconnector into the considerably more expensive Italian market. Base-load flows included imports from Bosnia and Herzegovina, Serbia, Albania and Kosovo alongside exports towards Italy.
That combination demonstrates why Montenegro’s role in the regional trading system cannot be judged from its domestic balance alone. The Italy interconnector turns the country into a transmission and arbitrage corridor between the western Balkans and one of Europe’s structurally higher-priced electricity markets.
Croatia showed the opposite structural dependence. Despite CROPEX almost fully converging with HUPX at €173.82/MWh, Croatia remained a major importer, with around 950 MW of net imports against consumption of roughly 2.54 GW. Imports came from Hungary, Slovenia, Serbia and Bosnia and Herzegovina.
Slovenia was also a net importer at around 335 MW, despite its comparatively strong nuclear base, and traded almost identically to Croatia and Hungary.
Italy remained the regional ceiling. The national price held unchanged at €180.91/MWh, meaning the rest of SEE moved closer to Italy rather than Italy moving higher. The Italian premium over HUPX therefore narrowed to only around €6.85/MWh, while its premium over Montenegro remained approximately €27/MWh and over North Macedonia more than €40/MWh.
Fuel markets provided additional support to electricity prices.
CEGH Austrian gas rose €1.7/MWh to €66.25/MWh, Greek gas increased to €55.4/MWh, and EU carbon allowances advanced to approximately €82.45/tCO₂. September API-2 coal increased to €125.5/t.
At those fuel levels, flexible thermal generation remains expensive enough to support power prices well above the levels normally associated with a high-renewables August market. The rising cost of gas is particularly important because reduced hydro and nuclear availability increases the probability that gas-fired plants set the marginal price during the evening ramp.
The forward curve nevertheless remains substantially below the prompt market.
Hungarian Week 35 traded 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 about €15/MWh over September.
That differential is a clear indication that traders continue to price the current tightness as largely prompt rather than structural.
The expected return of additional Paks output is the most obvious bearish catalyst. If the units restart from 23 August and the plant returns towards full capacity by 27-28 August, Hungarian import demand should fall materially, potentially releasing electricity back into neighbouring markets and compressing HUPX premiums.
Against that, Bulgaria’s Kozloduy reduction, persistent low hydrology and a gas market above €60/MWh continue to limit the downside.
Trading note
Friday’s market is therefore less about a simple regional demand increase than about the interaction between reduced dispatchable availability, expensive fuel, cross-border constraints and rapidly changing renewable profiles.
Serbia’s €35.8/MWh day-on-day jump is the strongest evidence. Prices rose dramatically despite lower Serbian consumption because domestic generation fell, the surrounding regional curve strengthened and the minimum hourly price moved from €75/MWh to €130/MWh.
At the same time, Greece, North Macedonia and Montenegro retained substantial discounts despite the broader rally, leaving commercially significant north-south and east-west spreads.
The market is increasingly characterised by two simultaneous signals: strong convergence inside the Hungary-Austria-Slovenia-Croatia-Romania-Bulgaria corridor, and persistent fragmentation further south.
For traders, the key prompt indicators are therefore not simply outright HUPX or SEEPEX prices. Paks availability, Danube levels, Greek renewable output, Romanian-Bulgarian transit flows, the Montenegro-Italy spread and the midday-to-evening solar ramp are becoming the variables that determine where the next €20-40/MWh regional price dislocation appears.
