The 25 August 2026 day-ahead session shows a regional electricity market that remains expensive but increasingly segmented. The strongest feature is the near-complete convergence of the main Central and Eastern European SEE markets around €174-176/MWh, while Serbia, Montenegro and North Macedonia trade at notable discounts. Germany remains significantly cheaper, while Italy continues to command the regional premium.
HUPX settled at €175.37/MWh, up €5.1/MWh day on day. Romania followed at €174.99/MWh, Bulgaria at €173.75/MWh, Greece at €173.73/MWh, Croatia at €175.08/MWh and Slovenia at €175.67/MWh. The entire HU-RO-BG-GR-HR-SI cluster therefore remained within a remarkably narrow €1.94/MWh range. Serbia was the clear outlier at €157.95/MWh, a €17.42/MWh discount to Hungary, while Montenegro stood at €164.58/MWh, North Macedonia at €165.53/MWh and Albania at €170.63/MWh. Germany was much lower at €141.43/MWh, creating a €33.94/MWh HU-DE spread, while Austria reached €177.64/MWh and Italy €190.54/MWh.
The key fundamental change was a sharp increase in demand that was covered primarily through imports. HU+SEE consumption rose by 995 MW, from 32,510 MW to 33,505 MW, while aggregate generation increased by only 327 MW, from 30,421 MW to 30,748 MW. Net imports consequently increased by 668 MW, from 2,089 MW to 2,757 MW. Imports from the AT+SK core reached 3,000 MW, up 144 MW, while exports toward Italy declined to 713 MW from 1,187 MW. The region was therefore drawing more heavily on Central Europe while continuing to send substantial volumes toward the higher-priced Italian market.
Hungary represents the clearest source of tightening. Hungarian consumption increased by 285 MW, from 4,369 MW to 4,654 MW, while domestic generation declined from 3,434 MW to 3,329 MW. Net import requirements consequently rose from 935 MW to 1,325 MW, a deterioration of 390 MW in a single session. Around 28.5% of Hungarian demand was therefore covered by net imports.
This tightening helps explain both the €5.1/MWh rise in HUPX and the widening premium over Germany. Hungary was not simply following the broader SEE market higher; its domestic balance deteriorated precisely while Germany remained considerably cheaper. The HU-DE spread widened to €33.94/MWh, compared with roughly €27/MWh previously. Heavy support entered Hungary through Slovakia and Austria, but those flows were insufficient to eliminate the price differential.
Forward markets indicate that traders do not view the Hungarian premium as purely temporary. The Hungarian Week 36 contract was indicated at €146.50/MWh, with the HU-DE Week 36 spread reaching €28.50/MWh. The September Hungarian contract stood at €163/MWh, carrying a €26.50/MWh premium to Germany, while the Calendar 2026 spread remained around €19.50/MWh.
Serbia is moving in the opposite direction. While most core regional exchanges gained €4-6/MWh, SEEPEX slipped €1.9/MWh to €157.95/MWh. Serbia’s physical balance improved, with consumption easing from 3,602 MW to 3,579 MW and total generation increasing from 3,037 MW to 3,167 MW. Net imports consequently fell from 565 MW to only 412 MW.
The daily average, however, understates the extent of the Serbian decoupling. SEEPEX peak prices declined from €143.9/MWh to €138.2/MWh, while off-peak prices increased slightly to €177.7/MWh. The minimum hourly price collapsed from €100/MWh to just €54.1/MWh around H12, while the maximum declined from €240/MWh to €211/MWh.
The resulting €39.5/MWh difference between peak and off-peak averages illustrates how strongly solar generation is reshaping conventional peak and off-peak economics. Serbia is therefore not simply a cheaper market; it has a pronounced daytime trough followed by significantly more expensive evening and overnight power.
The Serbian-Hungarian border also demonstrates why daily average price spreads cannot automatically be treated as arbitrage opportunities. Despite Serbia being roughly €17/MWh cheaper than Hungary on the base, scheduled Serbia-Hungary flows averaged around 40 MW toward Serbia, while peak flows reached approximately 81 MW from Hungary into Serbia. Border allocations, hourly price shapes, nominations and incomplete market coupling can therefore override the apparent daily-average economic signal.
The same pattern is increasingly visible across HUPX. Hungarian base power settled at €175.4/MWh, but peak averaged only €159.2/MWh compared with €191.5/MWh off-peak. The HUPX minimum reached €122.8/MWh around H12, while the maximum climbed to €225.7/MWh around H19.
This increasingly solar-shaped price curve is becoming one of the defining characteristics of the SEE summer market. The traditional assumption that daytime peak power should command a premium is becoming less reliable because the peak block includes the solar-rich middle of the day. Scarcity is increasingly concentrated in the evening ramp and, in some markets, overnight hours.
Regional fundamentals reinforce this interpretation. Solar output was forecast at around 7.9 GW, approximately 1.27 GW higher day on day, while wind generation was expected at only 1.94 GW, down around 805 MW. At the same time, demand increased by almost 1 GW. The result is therefore not a straightforward renewable-surplus market: stronger solar generation depresses midday prices, while weaker wind and higher demand maintain elevated prices outside the solar window.
Montenegro recorded the largest headline decline, with BELEN falling €22.1/MWh to €164.58/MWh. However, the hourly data indicate that this was largely the unwinding of an exceptional scarcity spike on 24 August rather than a broad collapse in power values.
Montenegrin peak power fell from an extraordinary €220.4/MWh to €151.3/MWh, while the maximum hourly price declined from €450.2/MWh to €230/MWh. Off-peak power, however, increased from €153/MWh to €177.9/MWh. The €22/MWh fall in the daily average therefore conceals a €25/MWh increase in off-peak prices.
Montenegro’s physical balance improved only slightly. Consumption increased from 473 MW to 485 MW, but generation rose more strongly, from 330 MW to 363 MW, reducing net imports from 144 MW to 122 MW.
The country also remains an important transit market toward Italy. On a base-load average, Montenegro received approximately 306 MW from Bosnia and Herzegovina, 144 MW from Serbia and 112 MW from Kosovo, alongside smaller flows, while sending around 452 MW toward Italy. With southern Italy around €190.5/MWh compared with BELEN at €164.6/MWh, the economics of the Italy-Montenegro corridor remain significant.
Romania provides almost the opposite example to Serbia. Romanian consumption increased by 154 MW, but generation rose by 262 MW, allowing net imports to decline from 540 MW to 430 MW. Despite this improvement in its domestic balance, OPCOM increased €4.6/MWh to €174.99/MWh, only €0.38/MWh below HUPX.
This shows how strongly Romania is currently being priced by the wider coupled market rather than solely by its domestic net position. Intraday flows are particularly revealing: Romania was a net importer over the full day but became a 191 MW net exporter during peak hours, while importing more than 1 GW during off-peak periods.
Romania-Hungary flows showed an even stronger reversal. Romania exported around 939 MW to Hungary during peak hours before importing approximately 1.34 GW during off-peak periods. The physical flow pattern therefore mirrors the increasingly pronounced regional price curve, with power moving in different directions between solar-rich daytime hours and structurally tighter periods.
Fuel markets are providing little relief. CEGH gas was around €69.15/MWh, up €1.7/MWh, while Greek gas increased by more than €5/MWh and EU carbon reached approximately €83.8/t, up €1.2/t. Hungarian September power gained around €4/MWh, while September and Q4 gas forwards also moved higher.
Over the broader period covered by the market data, CEGH September gas increased by around 10.3%, Q4 gas by 11.1%, API2 September coal by roughly 5% and December EUA by approximately 2.4%. The forward curve therefore provides little indication that the Hungarian premium to Germany will disappear quickly.
The principal signal from 25 August is therefore not simply that SEE electricity remains expensive. It is that the market is separating into increasingly distinct trading regimes. Hungary, Romania, Bulgaria, Greece, Croatia and Slovenia have converged around €175/MWh, while Serbia has decoupled by almost €17/MWh. Montenegro and North Macedonia remain in an intermediate discount zone, Germany is more than €30/MWh cheaper than Hungary, and Italy continues to command a substantial premium.
At the same time, the traditional baseload figure is becoming less informative on its own. Serbia at €158/MWh includes a €54/MWh midday hour and almost €180/MWh off-peak power. Montenegro’s €22/MWh daily decline masks a significant increase in off-peak prices, while Romania reverses from imports to exports between different trading blocks.
For trading desks, the most important signals are therefore the persistent HU-DE congestion premium, the un-arbitraged SEEPEX-HUPX discount, the Montenegro-Italy transit economics, and the increasingly pronounced midday-versus-evening price spread across the SEE region.
