Hungarian electricity prices jumped nearly 12% for Tuesday delivery, leading a broader rise across Southeast Europe as a sharp forecast decline in wind generation and higher demand increased regional import requirements, while German power prices fell.
Hungary’s HUPX day-ahead price reached €326.57/MWh, up €34.20/MWh, while Serbia’s SEEPEX rose €16.90/MWh to €317.08/MWh. Montenegro’s BELEN gained €18.50/MWh to €294.77/MWh. All three recorded their highest daily averages in the seven-day comparison period ending October 20.
The divergence from Germany was particularly pronounced. German day-ahead power fell €12.80/MWh to €195.66/MWh, widening Hungary’s premium by €47/MWh to €130.91/MWh. That increase, despite additional electricity scheduled into the region, pointed to persistent price separation between the Hungarian and Southeast European markets and the cheaper German benchmark.
Romania rose to €307.24/MWh, North Macedonia to €306.44/MWh and Bulgaria to €299.98/MWh. Prices were lower farther west, at €271.33/MWh in Croatia and €260.99/MWh in Slovenia. Greece increased to €247.82/MWh, while Albania moved against the regional trend, falling about 9.1% to €255/MWh.
Wind decline outweighs stronger solar production
The principal change in the regional supply outlook was a steep reduction in wind generation.
Average wind output across Hungary and Southeast Europe was forecast at 1,067 MW, down 1,847 MW, or approximately 63%, from the previous day. Solar generation was expected to increase 411 MW to 5,534 MW, replacing less than a quarter of the lost wind output.
At the same time, average electricity demand was forecast to rise 963 MW, or 3.1%, to 31,849 MW.
Together, higher consumption and lower combined wind and solar production increased the requirement for other generation and imports by approximately 2,399 MW. Demand remaining after wind and solar rose from 22,849 MW to 25,248 MW, an increase of about 10.5%.
That shift helps explain the strength of the price response. The additional requirement extended beyond the increase in consumption: the system also needed replacement supply for the expected wind shortfall.
Regional net imports were scheduled to increase 571 MW to 3,794 MW, equivalent to nearly 12% of forecast demand. Imports through the Austrian and Slovak interfaces rose 173 MW to 3,571 MW, while net imports from Italy increased 305 MW to 422 MW. A 93 MW reduction in exports towards Ukraine and Moldova accounted for the remaining improvement in the external balance.
The October 20 demand figures and commercial flow schedules describe the expected delivery-day balance. Detailed generation observations by fuel extend through October 19.
Romania’s import swing tightens the regional balance
Romania showed the most substantial deterioration among the larger national markets.
Its balance shifted from 213 MW of net exports on Monday to 1,183 MW of projected net imports on Tuesday, a swing of 1,396 MW. Forecast generation fell to 4,874 MW from 6,250 MW, while demand increased by just 20 MW to 6,057 MW.
The change therefore reflected a much weaker supply position. Imports were expected to cover approximately 19.5% of Romanian consumption.
Scheduled Hungarian deliveries to Romania increased to 1,030 MW from 406 MW, while Bulgarian deliveries rose to 643 MW from 72 MW. Romania also reduced its scheduled exports to Serbia to 168 MW, compared with 278 MW the previous day.
The regional wind forecast provides context for Romania’s weaker generation balance, although the available figures do not isolate Tuesday’s Romanian output by fuel sufficiently to attribute the entire production decline to wind.
Hungary consequently faced stronger demand for onward deliveries while remaining dependent on imports itself. Its projected net imports increased 113 MW to 1,549 MW, covering approximately 31% of forecast domestic demand.
Farther south, Greece provided a partial counterweight. Its projected net export surplus increased to 1,011 MW, from 723 MW, with scheduled deliveries towards Bulgaria, North Macedonia and Albania reaching a combined 1,170 MW.
The additional southern supply helped meet regional requirements, but the Hungarian premium to Greece still widened to €78.75/MWh. Daily average prices and commercial schedules show continued market separation, although they do not establish which individual transmission constraints were binding during particular hours.
Serbia’s smaller deficit fails to prevent a price rise
Serbia illustrated how an improving national balance can coexist with rising wholesale prices.
Its projected net imports declined 217 MW to 1,009 MW, as the generation balance improved to 2,820 MW and demand increased only modestly to 3,829 MW. Imports nevertheless represented approximately 26% of expected consumption.
Despite the smaller deficit, SEEPEX rose about 5.6%. Serbia remained the second-most expensive market in the daily comparison, behind Hungary.
Its relationship with Hungary also changed. Serbia had traded roughly €7.80/MWh above Hungary on Monday. For Tuesday, Serbia moved to a €9.49/MWh discount, as Hungary’s price increase outpaced its own.
Commercial schedules showed Serbia receiving electricity from several neighbouring markets while sending an average 601 MW towards Hungary. Deliveries into Serbia included 421 MW from Bosnia and Herzegovina, 387 MW from Bulgaria, 355 MW from North Macedonia and 209 MW from Montenegro.
Those exchanges underline Serbia’s role in regional electricity trading. A national net import position can sit alongside substantial exports over an individual border, and domestic prices remain exposed to changes in neighbouring markets.
Montenegro displayed a similar combination of domestic import needs and larger cross-border exchanges. Its projected net imports increased to 42 MW, while scheduled imports from Italy rose to 399 MW, from 316 MW.
At the same time, Montenegro continued to schedule 209 MW towards Serbia. The Italian interconnection was therefore contributing electricity to Montenegro and the wider regional trading balance on this delivery day.
BELEN’s daily average remained €22.31/MWh below Serbia, but its roughly 6.7% increase showed that access to Italian supply did not insulate Montenegro from the broader regional rise.
Hourly prices reveal a different trading pattern
The daily averages concealed large differences between delivery hours.
Hungary’s hourly day-ahead maximum reached €451/MWh, up from €396.60/MWh on Monday. Serbia’s maximum increased to €450/MWh from €404/MWh, while Montenegro’s rose to €395/MWh from €360/MWh.
Standard off-peak blocks were more expensive than peak blocks in several markets. Hungarian off-peak power averaged €347.80/MWh, compared with €305.40/MWh for the peak block. Serbia showed the same pattern, at €326/MWh off-peak against €308.20/MWh peak.
Greece recorded an even larger difference: €318.50/MWh off-peak compared with €177.20/MWh during the standard peak block. Its hourly minimum was €32.90/MWh, while its maximum reached €396.10/MWh.
The pattern is consistent with solar generation easing prices during part of the daytime block while supply remained expensive outside the main solar hours. Greece’s relatively low daily average therefore did not represent uniformly cheap electricity throughout the day.
Albania provided the clearest example of the limits of a baseload headline. Although its daily average fell, its highest hourly price increased to €490/MWh, the highest among the markets listed. Its daily range stretched from €100/MWh to €490/MWh.
For consumers, suppliers and storage investors, these differences make the delivery profile commercially significant. A daily average can conceal both cheaper operating periods and substantial exposure during individual high-price hours.
Forward premiums extend the near-term pressure
The forward market also showed stronger Hungarian pricing relative to Germany, particularly for nearby delivery.
In the latest forward prices, dated October 19, Hungarian week 44 power increased €7.50/MWh to €270/MWh, while the corresponding German contract fell €10/MWh to €174.50/MWh. The Hungarian premium widened €17.50/MWh to €95.50/MWh.
Hungarian November power rose €3.50/MWh to €250/MWh, against an unchanged German November price of €191.50/MWh, leaving a spread of €58.50/MWh.
The strength was concentrated in nearer delivery periods. Hungarian first-quarter 2027 baseload eased €1.50/MWh to €222/MWh, while calendar 2027 remained unchanged at €170/MWh. The curve therefore showed a sharper repricing of immediate supply conditions than of longer-term electricity costs.
Fuel prices added to the cost of replacing unavailable renewable output. Austrian CEGH gas was quoted at €90.70/MWh, up €1.10/MWh, while EU carbon allowances were around €85.40 per tonne. These levels left gas-fired replacement generation exposed to substantial fuel and emissions costs.
Romanian nuclear availability remains a further supply risk. The latest generation figures showed no Romanian nuclear output, while Nuclearelectrica’s revised financial plan assumed both Cernavoda reactors would return on November 1. That date remains a planning assumption.
Romania’s move from a modest export surplus to imports approaching one-fifth of demand shows how quickly a change in generation can reshape the regional market. Tuesday’s higher import schedules helped cover the shortfall, but buyers still faced a Hungarian premium to Germany of more than €130/MWh.