Southeast European electricity markets opened the week with a broad and unusually sharp repricing. Day-ahead baseload prices rose by between €36/MWh and €44/MWh across most regional exchanges as weekday demand recovered, net imports declined and the market rebuilt the evening scarcity premium that had largely disappeared during Sunday’s low-load session.
HUPX settled at €127.61/MWh, up €41.70/MWh, while SEEPEX reached €131.27/MWh, the highest price among the principal Southeast European markets and €43.90/MWh above Sunday. Romania cleared at €126.66/MWh, Croatia at €126.74/MWh, Slovenia at €127.36/MWh and Albania at €126.02/MWh. Bulgaria and Greece both settled at €124.88/MWh.
Montenegro and North Macedonia remained at the lower end of the regional range. BELEN settled at €121.00/MWh, while MEMO reached €122.97/MWh. Even these markets recorded significant increases of €36.20/MWh and €38.00/MWh, respectively, confirming the broad-based nature of the regional repricing.
The result produced strong baseload convergence across central and eastern Southeast European exchanges, but it did not eliminate the structural price differences at either end of the region. Germany remained well below Southeast Europe at €103.16/MWh, leaving the Hungary-Germany spread at €24.44/MWh. Italy, meanwhile, reached €172.56/MWh, creating a premium of €44.95/MWh to Hungary and more than €50/MWh to Montenegro.
The regional baseload averages concealed a pronounced intraday split. Solar generation compressed prices during the middle of the day, with most coupled markets reaching their daily lows between H10 and H14. Prices then climbed sharply towards H20-H22, when photovoltaic output had largely disappeared and thermal generation, hydropower and imported flexibility became increasingly valuable.
On HUPX, the minimum price was €43.10/MWh at H14 before rising to €194.70/MWh at H22. The resulting €151.60/MWh daily spread was more significant than the baseload increase itself. Hungary’s peak block averaged only €97.90/MWh, while the off-peak block averaged €157.30/MWh because it captured the more expensive late-evening hours.
Greece and Bulgaria recorded almost identical price profiles, falling to €42.60/MWh before rising to €190.30/MWh. Romania moved between €42.40/MWh and €190.60/MWh, while Slovenia recorded a range of €47.90/MWh to €186.80/MWh.
Serbia’s market was structurally tighter. SEEPEX did not fall below €80.10/MWh, nearly twice the minimum prices recorded in Hungary, Romania and Bulgaria, before reaching €210.00/MWh at H21. Serbia’s peak-block average of €116.80/MWh exceeded HUPX by €18.90/MWh, even though its off-peak average of €145.80/MWh was €11.50/MWh below Hungary. The pattern suggests that Serbia’s premium was concentrated around the daytime and evening balancing window rather than distributed evenly across the delivery day.
North Macedonia recorded a range of €56.00/MWh to €207.70/MWh, Albania €63.50/MWh to €213.00/MWh and Montenegro €52.10/MWh to €179.00/MWh. Italy remained expensive even during the solar trough, with a national minimum of €147.20/MWh and a maximum of €213.80/MWh. Its narrower €66.60/MWh intraday range reflected a persistently high thermal price floor rather than an absence of evening tightness.
These price movements created a strong theoretical signal for storage. The gross HUPX minimum-to-maximum spread reached €151.60/MWh, compared with €147.70/MWh in Greece and Bulgaria, €151.70/MWh in North Macedonia and €129.90/MWh in Serbia. Actual battery returns would be lower after round-trip efficiency losses, trading fees, degradation and imperfect dispatch, but the market clearly rewarded midday charging followed by evening discharge.
Aggregate HU+SEE consumption increased from 30,910 MW to 33,502 MW, an 8.4% day-on-day rise. The increase was primarily driven by the return of weekday demand, reinforced by stronger consumption in eastern and southern markets.
Bulgaria recorded the largest proportional increase, with demand rising by 807 MW, or 23.6%, to 4,232 MW. Romania added 720 MW to reach 5,926 MW, while Greece increased by 896 MW, or 12.5%, to 8,070 MW. Croatia, Slovenia, Albania and Kosovo also recorded higher consumption.
Hungarian demand moved in the opposite direction, declining by approximately 175 MW to 4,219 MW, while Serbian consumption fell by 130 MW to 3,441 MW. These reductions moderated the increase in northern and central parts of the system but were insufficient to prevent the broader regional repricing.
Total generation increased from 28,312 MW to 31,465 MW, a rise of 11.1%. Generation therefore expanded faster than consumption, allowing net regional imports to decline from 2,598 MW to 2,037 MW. Imports covered approximately 6.1% of aggregate demand, compared with 8.4% on Sunday.
Solar production was forecast at 8,518 MW, up by 2,532 MW, while wind generation was expected to fall by 290 MW to 1,467 MW. The resulting net renewable increase of approximately 2.24 GW covered much of the weekday demand recovery but did not eliminate the evening deficit. Solar generation reduced prices during the middle of the day, while weaker wind output and the disappearance of photovoltaic production shifted the market back towards hydropower, thermal generation and imports after sunset.
The regional generation mix remained relatively balanced, with coal supplying approximately 21%, solar 21%, nuclear 19%, hydropower 16%, gas 14%, wind 6% and other sources around 2%. This structure left the system exposed to both solar-driven midday price compression and thermal-driven evening marginality.
Hungary continued to operate as an important import and redistribution hub. Imports from Austria and Slovakia into Hungary and Slovenia averaged 3,520 MW, down 363 MW day on day but still well above the region’s final net import position. Slovakia supplied Hungary with an average of 1,829 MW, rising to 2,309 MW during off-peak hours, while Austria supplied a further 627 MW.
Hungary simultaneously exported 799 MW to Romania, 690 MW to Croatia and 310 MW to Slovenia. Its overall position therefore changed significantly depending on the time of day: Hungary was a net exporter of 621 MW during peak hours but a net importer of 1,974 MW during off-peak periods.
This profile confirms Hungary’s role as a temporal and geographic redistribution market. Electricity entered from Slovakia and Austria during lower-load periods, while flows moved east towards Romania and south towards Croatia and Slovenia as those systems became tighter. The physical pattern also explains why the daily HUPX price cannot be interpreted solely through Hungary’s domestic generation balance.
Hungary’s full-day net imports fell from 1,299 MW to 676 MW, a reduction of almost 48%. Domestic generation increased from 3,095 MW to 3,543 MW, while consumption declined. The combination materially improved the national balance even as HUPX prices rose above €127/MWh.
Serbia generated 3,038 MW against consumption of 3,441 MW, leaving an average import requirement of 403 MW. Although the deficit was smaller than Sunday’s 585 MW, the hourly distribution was considerably tighter. Net imports increased to 725 MW during the peak block, compared with only 81 MW off peak.
The usual Bulgarian supply route was absent, with the recorded Bulgaria-Serbia flow falling from 331 MW on Sunday to zero. Serbia instead imported approximately 300 MW from Bosnia and Herzegovina, 233 MW from Croatia and 214 MW from Romania. Peak imports from Romania alone reached 410 MW.
At the same time, Serbia continued exporting 234 MW to Montenegro and 118 MW to North Macedonia. The country was therefore balancing a domestic generation deficit while maintaining southbound deliveries. Together with the missing Bulgarian flow, this supported the €3.66/MWh SEEPEX premium to HUPX and the €6.39/MWh premium to Bulgaria and Greece.
Serbia’s generation mix remained dominated by coal at approximately 80%, with hydropower contributing 18% and wind and gas around 1% each. Limited wind output and reduced hydropower flexibility left the market particularly sensitive to thermal availability and cross-border nominations during the evening ramp.
Bulgaria remained the region’s largest net exporter at 1,010 MW, supported by total generation of 5,241 MW against consumption of 4,232 MW. The country delivered an average of 639 MW to Greece and 408 MW to North Macedonia, while the Romania-Bulgaria border was close to balance, with 51 MW flowing towards Romania.
The Bulgaria-Greece flow rose to 1,596 MW during H20, coinciding with the regional evening price escalation. Despite the large physical transfer, Bulgaria and Greece cleared at exactly the same baseload price of €124.88/MWh, indicating strong daily convergence across the border. Hourly congestion, however, remained relevant even though the daily averages were identical.
Greece imported 581 MW net, reversing Sunday’s 187 MW export position. Demand increased by 896 MW, while generation rose by only 502 MW. Imports from Bulgaria and North Macedonia therefore became essential, even as Greece continued delivering approximately 228 MW to Italy.
Italy absorbed approximately 1,318 MW from Southeast Europe, distributed almost evenly across three corridors: 557 MW from Montenegro, 532 MW from Slovenia and 228 MW from Greece. These flows totalled approximately 1,317 MW, matching the aggregate regional figure within rounding.
The Montenegro-Italy interconnector operated close to 600 MW through much of the day. Montenegro itself imported 283 MW from Bosnia and Herzegovina, 234 MW from Serbia, 115 MW from Kosovo and 87 MW from Albania before sending 557 MW towards Italy. Montenegro therefore continued to function as a transit platform between the Western Balkans and Italy’s high-priced market rather than as a purely national supply-and-demand zone.
Using daily average prices and flows, the three Italian corridors carried an indicative gross locational value of approximately €1.5 million for the delivery day. This is not realised congestion revenue, which depends on hourly zonal prices, losses, nomination structures and transmission-right ownership, but it illustrates the commercial scale of Italy’s €42-52/MWh premium over neighbouring Southeast European markets.
Bosnia and Herzegovina remained a net exporter of 297 MW, sending approximately 300 MW to Serbia and 283 MW to Montenegro while importing 287 MW from Croatia. Croatia imported 813 MW net, with large inflows from Hungary and Slovenia partly redistributed towards Serbia and Bosnia and Herzegovina.
The spot repricing was driven primarily by demand, hourly residual load and cross-border positioning rather than by a same-day fuel shock. CEGH gas remained at €58.29/MWh, Greek gas increased modestly to €47.15/MWh and EU carbon allowances were unchanged at €79.11/t.
At 55% CCGT efficiency, CEGH gas and carbon imply an indicative variable generation cost of approximately €135/MWh before operating costs. The comparable Greek gas benchmark produces approximately €115/MWh. HUPX therefore remained slightly below the indicative central European gas-fired threshold on a baseload basis, while HENEX retained a modest positive clean spark margin for efficient Greek units. Evening prices of €190-210/MWh provided materially stronger gas-fired margins.
Carbon alone added approximately €70-75/MWh to the variable cost of conventional coal generation. With API2 coal around 119.5, efficient coal-fired production was positioned close to the regional baseload price before plant-specific operating costs. Coal and gas were therefore capable of supporting the market floor, while congestion and flexibility scarcity were required to produce the evening extremes.
The Hungarian forward curve remained mixed. Week 30 traded at €119.00/MWh, down €4.00/MWh at the latest close and €8.61/MWh below Monday’s spot result. Week 31 stood at €135.50/MWh, creating a €16.50/MWh premium to Week 30. Hungary’s August contract reached €142.50/MWh, September €156.50/MWh and Q4 €160.50/MWh.
The HU-DE forward spread widened from €6.50/MWh for Week 30 to €20.00/MWh for Week 31, approximately €19.50/MWh for August and €25.00/MWh for Q4. Italy’s premium to Hungary narrowed from €40.00/MWh for Week 30 to €23.00/MWh for Week 31, €14.50/MWh for August and only €1.00/MWh for Q4. Hungary was priced €5.00/MWh above Italy for Cal-27, indicating that the forward market expects the immediate Italian scarcity premium to fade while Hungary retains a larger structural discount to Germany.
The active trading setup remains a pronounced midday-long and evening-short profile. Solar availability is sufficient to compress prices during H10-H14, but weaker wind, declining hydropower flexibility, Serbian import dependence and Italy’s continuous pull on western Southeast European exports keep the evening ramp exposed. Near-term Hungarian backwardation limits the incentive to chase Monday’s baseload increase, while the steep rise from Week 30 at €119.00/MWh to Week 31 at €135.50/MWh preserves a clear premium for later-summer tightness.
