The South-East European electricity market opened the week with a broad and unusually sharp repricing. Day-ahead baseload prices increased by between €36/MWh and €44/MWh across most regional exchanges as weekday consumption 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, an increase of €41.70/MWh, while SEEPEX reached €131.27/MWh, the highest price among the principal SEE markets and €43.90/MWh above Sunday. Romania cleared at €126.66/MWh, Croatia at €126.74/MWh, Slovenia at €127.36/MWh, Albania at €126.02/MWh, and Bulgaria and Greece both at €124.88/MWh.
Montenegro and North Macedonia remained at the bottom of the regional range. BELEN settled at €121.00/MWh, while MEMO reached €122.97/MWh. Even these lower-priced markets recorded increases of €36.20/MWh and €38.00/MWh, respectively.
The result produced substantial baseload convergence across the central and eastern SEE exchanges, but it did not eliminate the structural price boundaries at either end of the region. Germany remained well below SEE at €103.16/MWh, leaving the Hungary-Germany spread at €24.44/MWh. Italy’s national price reached €172.56/MWh, creating a €44.95/MWh premium to Hungary, €47.68/MWh to Greece and €51.56/MWh to Montenegro.
Solar compression gives way to evening scarcity
The regional baseload averages conceal a pronounced intraday divide. Solar output pushed most coupled markets to their minimum prices between H10 and H14, while the maximum shifted to H20-H22, when photovoltaic production had largely disappeared and thermal, hydro and imported flexibility became more valuable.
On HUPX, the minimum price was €43.10/MWh at H14, followed by a maximum of €194.70/MWh at H22. The resulting daily range of €151.60/MWh was more significant than the baseload increase itself. Hungary’s reported peak block averaged only €97.90/MWh, while the off-peak block averaged €157.30/MWh because the latter captured the more expensive late-evening hours.
Greece and Bulgaria displayed almost identical profiles, each 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 €47.90-186.80/MWh.
Serbia was structurally tighter. SEEPEX never fell below €80.10/MWh, almost twice the Hungarian, Romanian and Bulgarian minima, and reached €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 reversal shows that Serbia’s premium was concentrated in the daytime and evening balancing window rather than across the entire delivery day.
North Macedonia recorded a range of €56.00-207.70/MWh, Albania €63.50-213.00/MWh, and Montenegro €52.10-179.00/MWh. Italy remained expensive even during the solar trough: the national minimum was €147.20/MWh, while the maximum reached €213.80/MWh. Italy’s much narrower €66.60/MWh intraday range reflected a persistently high thermal floor rather than an absence of evening tightness.
These spreads created a strong theoretical storage signal. 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 losses, trading fees, degradation and imperfect dispatch, but the price shape clearly rewarded midday charging and evening discharge.
Weekday demand rises while import dependence falls
Aggregate HU+SEE consumption increased from 30,910 MW to 33,502 MW, a day-on-day rise of 2,592 MW, or 8.4%. The increase was predominantly a weekday effect, reinforced by sharply higher consumption in the eastern and southern markets.
Bulgaria registered the largest proportional increase, with demand rising by 807 MW, or 23.6%, to 4,232 MW. Romania added 720 MW, reaching 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 load increase in the northern and central parts of the system but did not prevent the regional repricing.
Total generation increased from 28,312 MW to 31,465 MW, a rise of 3,153 MW, or 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 was expected to fall by 290 MW to 1,467 MW. The net renewable increase of approximately 2.24 GW covered most of the weekday demand recovery but did not resolve the evening deficit. Solar reduced prices during the middle of the day, while the weaker wind profile and the disappearance of photovoltaic output forced the market back onto hydro, thermal generation and imports after sunset.
The previous day’s generation structure remained relatively balanced at regional level: coal supplied approximately 21%, solar 21%, nuclear 19%, hydro 16%, gas 14%, wind 6% and other sources around 2%. The system was therefore exposed to both solar-driven midday compression and thermal-driven evening marginality.
Hungary operates as an import-and-redistribution hub
Imports from Austria and Slovakia into Hungary and Slovenia averaged 3,520 MW, down by 363 MW day on day but still well above the region’s final net import position. Slovakia supplied Hungary with an average 1,829 MW, rising to 2,309 MW during off-peak hours, while Austria supplied another 627 MW.
Hungary simultaneously exported 799 MW to Romania, 690 MW to Croatia and 310 MW to Slovenia. Its aggregate position consequently changed dramatically by block: Hungary was a net exporter of 621 MW during peak hours, but a net importer of 1,974 MW off peak.
This profile confirms Hungary’s role as a temporal and geographic redistribution market. Large volumes entered from Slovakia and Austria during lower-load periods, while electricity moved east towards Romania and south towards Croatia and Slovenia when those systems became tighter. The physical pattern also explains why the daily HUPX price cannot be interpreted solely from Hungary’s national generation deficit.
Hungary’s full-day net import 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 rose above €127/MWh.
Serbia’s evening deficit sustains the regional premium
Serbia generated 3,038 MW against consumption of 3,441 MW, leaving an average import requirement of 403 MW. The deficit was smaller than Sunday’s 585 MW, but its 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 contractual and physical deliveries. This combination, together with the missing Bulgarian flow, supported the €3.66/MWh SEEPEX premium to HUPX and the €6.39/MWh premium to Bulgaria and Greece.
Serbia’s most recent generation mix was still dominated by coal at approximately 80%, with hydro contributing 18% and wind and gas around 1% each. Limited wind and reduced hydro flexibility left the market particularly sensitive to thermal availability and cross-border nominations during the evening ramp.
Bulgaria supplies the southern corridor
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 639 MW to Greece and 408 MW to North Macedonia, while the Romania-Bulgaria border was close to balance at 51 MW 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 that border. Hourly congestion remained relevant even though the baseload 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 absorbs virtually all western SEE export capacity
Italy imported approximately 1,318 MW from SEE, distributed almost exactly across three corridors: 557 MW from Montenegro, 532 MW from Slovenia and 228 MW from Greece. These flows totalled 1,317 MW, matching the aggregate regional figure within rounding.
The Montenegro-Italy link 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 the high-priced Italian 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 the 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 adjacent SEE 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.
Fuel economics and the forward curve
The spot repricing was principally driven by load, hourly residual demand and cross-border positioning rather than 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. The evening prices of €190-210/MWh provided materially stronger gas-fired margins.
Carbon alone added roughly €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 consequently capable of supporting the market floor, but congestion and flexibility scarcity were required to produce the evening extremes.
The Hungarian near 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, leaving 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 H10-H14, but weaker wind, declining hydro flexibility, Serbian import dependence and Italy’s continuous pull on western SEE 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.