On 25 August 2026, the day-ahead session showed a power market that was expensive but increasingly segmented. Liquid Central and Eastern European SEE markets converged around €174-176/MWh, while Serbia, Montenegro and North Macedonia traded at discounts. Germany remained far cheaper, and Italy kept a regional premium.
HUPX settled at €175.37/MWh, up €5.1/MWh day on day. OPCOM followed at €174.99/MWh, with Bulgaria at €173.75/MWh, Greece at €173.73/MWh, Croatia at €175.08/MWh, and Slovenia at €175.67/MWh. The HU-RO-BG-GR-HR-SI cluster stayed within a narrow €1.94/MWh band.
Serbia was the outlier at €157.95/MWh, a discount of €17.42/MWh versus Hungary. Montenegro traded at €164.58/MWh, North Macedonia at €165.53/MWh, and Albania at €170.63/MWh. Germany was quoted at €141.43/MWh, creating a €33.94/MWh HU-DE spread, while Austria was at €177.64/MWh. The Italian headline reference stood at €190.54/MWh.
Demand rises faster than generation, lifting net imports
The key driver was not a regional generation collapse but a sharp increase in demand covered mainly through imports. HU+SEE consumption rose from 32,510 MW to 33,505 MW, up 995 MW. Aggregate generation increased by only 327 MW, from 30,421 MW to 30,748 MW.
Net imports therefore rose by the remaining amount, from 2,089 MW to 2,757 MW. Imports from the AT+SK core reached 3,000 MW, up 144 MW. Exports toward Italy fell to 713 MW, from 1,187 MW the previous day.
The flow pattern indicated heavier reliance on Central Europe while continuing to send significant volumes toward the higher-priced Italian market.
Hungary’s balance tightens and widens the HU-DE premium
Hungary accounted for a large share of the tightening seen in the session data. 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. The resulting net import requirement rose from 935 MW to 1,325 MW, a deterioration of 390 MW in one session.
In effect, about 28.5% of Hungarian demand was covered through net imports.
The HUPX increase of €5.1/MWh aligned with a widening premium versus Germany as the domestic balance tightened when Germany stayed much cheaper. The HU-DE spread expanded to €33.94/MWh compared with roughly €27/MWh previously.
Flow data showed support entering Hungary from the north, including through Slovakia and Austria, but those inflows were insufficient to remove the price differential.
Northern inflows and forward spreads keep the premium in focus
The forward market indicated traders did not treat the Hungary-Germany premium as purely short-lived. The Hungarian Week 36 contract was indicated at €146.50/MWh, while the HU-DE Week 36 spread reached €28.50/MWh.
The September Hungarian contract stood at €163/MWh with a €26.50/MWh premium to Germany. Even the Calendar 2026 spread remained around €19.50/MWh.
SERBIA trades lower despite improved physical fundamentals on SEEPEX
The largest trading dislocation involved Serbia’s pricing relative to other core exchanges. While essentially every core regional exchange gained €4-6/MWh, SEEPEX slipped by €1.9/MWh to €157.95/MWh.
Serbia’s physical balance improved: consumption eased from 3,602 MW to 3,579 MW, total generation increased from 3,037 MW to 3,167 MW, and net imports fell from 565 MW to 412 MW.
About 153 MW of Serbia’s previous-day import requirement disappeared based on those changes.
A deeper intraday trough drives Serbia’s decoupling signal
The daily average did not capture how pronounced Serbia’s decoupling became across hours. SEEPEX peak prices fell from €143.9 to €138.2/MWh, while off-peak prices increased slightly to €177.7/MWh.
The minimum hourly price collapsed from €100 to €54.1/MWh around H12, while the maximum fell from €240 to €211/MWh.
The difference between Serbia’s €138.2 peak average and its €177.7 off-peak average was €39.5/MWh.
SCHEDULED flows limit arbitrage between Serbia and Hungary pricing zones
A cross-border implication appeared in scheduled flows between Serbia and Hungary despite Serbia trading about €17/MWh cheaper than Hungary on the daily base.
Scheduled Serbia-Hungary flow averaged approximately 40 MW toward Serbia rather than northward toward HUPX; peak flow was around 81 MW from Hungary into Serbia.
Border allocations and nominations were cited as factors that can dominate daily-average signals when hourly price shapes differ and full coupling is absent.
The HUPX curve shows inverted peak and off-peak pricing patterns
A similar intraday pattern appeared on HUPX though less sharply than in Serbia’s case. 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 was €122.8/MWh around H12 versus a maximum of €225.7/MWh around H19.
The session also reflected forecasted renewables conditions: regional solar output was forecast around 7.9 GW, about 1.27 GW higher day on day, while wind was expected at about 1.94 GW down roughly 805 MW as demand increased by almost 1 GW.
BELEN falls after an extreme prior-day evening scarcity event
Montenegro recorded the largest headline decline as BELEN dropped by €22.1/MWh to €164.58/MWh following an exceptional event on 24 August.
Montenegrin peak power fell from an extraordinary €220.4/MWh to €151.3/MWh and the maximum hourly price dropped from €450.2 to €230/MWh; off-peak power rose from €153 to €177.9/MWh.
Consumption increased from 473 MW to 485 MW while generation rose more strongly from 330 MW to 363 MW, reducing net imports from 144 MW to 122 MW.
MONTENEGRO acts as a transit corridor into Italy during higher-priced hours
Montenegro also functioned as a transit market into Italy based on base-load averages received and sent across borders.
It received approximately 306 MW from Bosnia and Herzegovina, 144 MW from Serbia and 112 MW from Kosovo plus smaller flows elsewhere while sending around 452 MW toward Italy.
With southern Italy around €190.5/MWh against BELEN’s €164.6/MWh, corridor economics remained visible in the session pricing relationship.
Romania tightens into OPCOM pricing despite lower net imports than before
Romania showed an opposite physical direction compared with Serbia’s decoupling pattern in terms of net position changes during the session window described in the data.
Romanian consumption increased by 154 MW while generation rose by 262 MW, allowing net imports to fall from 540 MW to 430 MW.
Despite that improving domestic balance, OPCOM increased by €4.6/MWh to €174.99/MWh only €0.38/MWh below HUPX.
Intraday flows reverse between peak solar hours and off-peak tightness periods
The intraday flow structure showed Romania moving between import and export roles depending on time blocks described in the data set.
Romania was an importer on a full-day average basis but became a net exporter of about 191 MW during peak hours while importing more than 1 GW off-peak.
Romania-Hungary flows reversed more strongly: Romania exported around 939 MW to Hungary during peak hours then imported approximately 1.34 GW during off-peak hours.
CegH gas higher alongside carbon support for forward power prices
Fuel markets were also described as more supportive rather than providing relief for power prices in the forward view referenced in the report data set.
CEGH gas was around €69.15/MWh up by €1.7; Greek gas increased by more than €5/MWh; and EU carbon was around €83.8/t up by €1.2.
Hungarian September power gained around €4/MWh while September and Q4 gas forwards moved higher; coal remained comparatively stable based on the same dataset references.
Tighter convergence across SEE core contrasts with persistent spreads versus Germany and Italy
Across the wider period shown in the report data set, CEGH September gas had increased around 10.