Hungarian electricity prices jumped nearly 12% for Tuesday delivery, driving a broader increase across Southeast Europe as a sharp decline in forecast wind generation and higher electricity demand increased the region’s reliance on imports, while German power prices moved lower.
Hungary’s HUPX day-ahead price climbed €34.20/MWh to €326.57/MWh, while Serbia’s SEEPEX increased €16.90/MWh to €317.08/MWh. Montenegro’s BELEN rose €18.50/MWh to €294.77/MWh. All three markets recorded their highest daily averages in the seven-day period ending October 20.
The contrast with Germany was particularly significant. German day-ahead electricity prices fell €12.80/MWh to €195.66/MWh, widening Hungary’s premium over the German benchmark by €47/MWh to €130.91/MWh. The widening spread, despite additional electricity being scheduled into Southeast Europe, highlighted continued price separation between the Hungarian and regional markets and the lower-priced German market.
Prices also increased in Romania, reaching €307.24/MWh, while North Macedonia rose to €306.44/MWh and Bulgaria to €299.98/MWh. Croatia and Slovenia recorded lower prices of €271.33/MWh and €260.99/MWh, respectively. Greece increased to €247.82/MWh, while Albania moved against the wider regional trend, falling around 9.1% to €255/MWh.
The main change in the regional supply outlook was a sharp decline in wind generation. Average wind output across Hungary and Southeast Europe was forecast at just 1,067 MW, down 1,847 MW, or approximately 63%, from the previous day. Solar generation was expected to increase by 411 MW to 5,534 MW, replacing less than one-quarter of the lost wind production.
At the same time, average electricity demand was forecast to rise by 963 MW, or 3.1%, to 31,849 MW. The combination of stronger consumption and lower renewable generation increased the requirement for other generation sources and imports by approximately 2,399 MW. Electricity demand remaining after wind and solar generation therefore increased from 22,849 MW to 25,248 MW, a rise of around 10.5%.
Regional net imports were scheduled to increase by 571 MW to 3,794 MW, equivalent to almost 12% of forecast demand. Imports through the Austrian and Slovak interfaces increased by 173 MW to 3,571 MW, while net imports from Italy rose by 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, while detailed generation observations by fuel extend through October 19.
Romania recorded the largest deterioration among the major regional markets. Its balance shifted from 213 MW of net exports on Monday to 1,183 MW of projected net imports on Tuesday, representing a swing of 1,396 MW. Forecast generation declined to 4,874 MW from 6,250 MW, while demand increased only marginally, by 20 MW, to 6,057 MW.
The change therefore reflected a substantially weaker supply position rather than a significant increase in consumption. Imports were expected to cover approximately 19.5% of Romanian demand.
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 scheduled exports to Serbia to 168 MW, compared with 278 MW on the previous day.
The regional wind forecast helps explain Romania’s weaker generation balance, although the available figures do not provide enough fuel-specific detail to attribute the entire decline in Romanian output to wind generation.
Hungary consequently faced stronger demand for electricity deliveries while remaining dependent on imports itself. Its projected net imports increased by 113 MW to 1,549 MW, covering approximately 31% of forecast domestic demand.
Greece provided a partial counterbalance. Its projected net export surplus increased to 1,011 MW, from 723 MW, while scheduled deliveries towards Bulgaria, North Macedonia and Albania reached a combined 1,170 MW. This additional southern supply helped cover regional requirements, although Hungary’s premium over Greece still widened to €78.75/MWh.
Serbia demonstrated how an improving domestic balance can coexist with higher wholesale electricity prices. Its projected net imports declined by 217 MW to 1,009 MW, as generation improved to 2,820 MW and demand increased only modestly to 3,829 MW. Imports nevertheless represented around 26% of expected consumption.
Despite the smaller deficit, SEEPEX increased by approximately 5.6%, leaving Serbia as the second-most expensive market in the daily comparison, behind Hungary.
The price relationship between Serbia and Hungary also changed significantly. Serbia had traded around €7.80/MWh above Hungary on Monday, but moved to a €9.49/MWh discount for Tuesday as Hungarian prices increased more sharply.
Commercial schedules showed Serbia receiving electricity from several neighbouring markets while simultaneously sending an average of 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.
These flows underline Serbia’s position within the regional electricity market. A country can remain a net importer overall while simultaneously exporting substantial volumes across a particular border, while domestic wholesale prices remain exposed to developments in neighbouring markets.
Montenegro showed a similar combination of domestic import requirements and significant cross-border trading. 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. Italian electricity was therefore contributing to Montenegro’s domestic balance as well as the wider regional trading system.
BELEN remained €22.31/MWh below Serbia, but its daily average still increased by approximately 6.7%, showing that access to Italian supply did not shield Montenegro from the broader regional price increase.
Hourly prices revealed a considerably more volatile trading picture than the daily averages suggested. 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 periods were more expensive than peak periods in several markets. Hungarian off-peak power averaged €347.80/MWh, compared with €305.40/MWh during the peak block. Serbia displayed a similar pattern, with off-peak prices averaging €326/MWh against €308.20/MWh during peak hours.
Greece recorded an even wider difference, with off-peak power averaging €318.50/MWh, compared with €177.20/MWh during the standard peak period. Its hourly minimum fell to €32.90/MWh, while the maximum reached €396.10/MWh.
The pattern indicates that stronger solar generation helped reduce prices during parts of the daytime period, while electricity remained significantly more expensive outside the main solar hours. Greece’s relatively low daily average therefore did not translate into uniformly low prices throughout the day.
Albania provided the clearest example of the limitations of relying on daily averages. Although its daily price declined, its highest hourly price increased to €490/MWh, the highest among the markets examined. Its daily range extended from €100/MWh to €490/MWh.
For consumers, suppliers and storage investors, these hourly differences are commercially important because a daily average can conceal both cheaper operating periods and substantial exposure to short periods of very high prices.
The forward market also pointed to continued near-term pressure on Hungarian power prices relative to Germany. In the latest forward prices dated October 19, Hungarian week 44 power increased by €7.50/MWh to €270/MWh, while the corresponding German contract declined by €10/MWh to €174.50/MWh. Hungary’s premium consequently widened by €17.50/MWh to €95.50/MWh.
Hungarian November power rose by €3.50/MWh to €250/MWh, while the German November contract remained unchanged at €191.50/MWh, leaving a spread of €58.50/MWh.
The strength was concentrated in the nearest delivery periods. Hungarian first-quarter 2027 baseload declined by €1.50/MWh to €222/MWh, while calendar 2027 remained unchanged at €170/MWh. The forward curve therefore suggested a stronger repricing of immediate supply conditions than of longer-term electricity costs.
Fuel prices added further pressure to the cost of replacing unavailable renewable generation. Austrian CEGH gas was quoted at €90.70/MWh, up €1.10/MWh, while EU carbon allowances traded around €85.40 per tonne. These levels continued to expose gas-fired replacement generation to significant fuel and emissions costs.
Romanian nuclear availability remains another potential source of supply uncertainty. 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 rather than a confirmed operational outcome.
Romania’s rapid move from a modest export surplus to imports covering nearly one-fifth of demand demonstrates how quickly changes in generation availability can reshape the regional electricity balance. Tuesday’s higher import schedules helped cover the shortfall, but buyers across the region still faced a Hungarian premium of more than €130/MWh over Germany, underscoring the continuing strength of regional price separation.
