Day-ahead electricity markets across Southeast Europe weakened for delivery on 17 July 2026, but the decline was highly uneven across the region. A significant improvement in forecast wind and solar generation reduced prices in Serbia, North Macedonia and several Central European markets, while continued congestion, strong evening demand and limited cross-border flexibility kept Hungary, Romania, Montenegro and Albania among the more expensive markets.
The regional price spread widened to EUR 38.23/MWh, ranging from Greece at EUR 135.94/MWh to Albania at EUR 174.17/MWh. The session was not a broad-based bearish move, but rather a market split into several price zones shaped by renewable availability, import dependence and access to lower-cost generation.
Hungary settled at EUR 156.65/MWh, down EUR 5.30/MWh from the previous session. The decline was relatively small compared with Germany, where day-ahead prices dropped EUR 19.20/MWh to EUR 140.63/MWh, and Austria, which fell EUR 16.20/MWh to EUR 144.79/MWh.
The widening Hungary–Germany price spread became one of the most notable market signals, expanding from EUR 2.10/MWh to EUR 16.02/MWh in a single day. Despite stronger renewable output in Germany and Austria, lower-cost electricity did not fully flow into Hungary due to stable north-to-south transmission patterns and limited available import capacity.
Average net imports into Hungary and Slovenia from Austria and Slovakia were forecast at around 1,835 MW, almost unchanged from the previous session. This indicates that existing cross-border capacity was insufficient to eliminate Hungary’s premium, leaving the market exposed to domestic supply conditions and evening peak demand.
Hungary’s premium over Austria reached EUR 11.87/MWh, while the gap with Romania narrowed to only EUR 1.36/MWh. Romania cleared at EUR 155.29/MWh, almost unchanged day on day, showing that the eastern part of the coupled market remained exposed to similar supply constraints despite stronger renewable availability during daylight hours.
The Hungarian hourly profile highlighted the importance of the evening peak period. Prices eased toward EUR 90–100/MWh during the solar-rich afternoon before climbing sharply after sunset, with evening prices approaching EUR 260–270/MWh. Although below the previous session’s peak above EUR 300/MWh, the evening surge remained strong enough to keep the daily average above EUR 156/MWh.
The lower evening peak was the main factor behind Hungary’s daily price decline. Additional renewable generation primarily reduced scarcity during peak hours rather than creating a significant collapse in daytime prices. Thermal generation and imports remained necessary once solar production faded, keeping gas-fired generation important for marginal price formation.
Across Southeast Europe, renewable availability improved significantly. Forecast solar generation increased by 1,634 MW to 8,132 MW, while wind output rose by 1,004 MW to 2,595 MW. Combined wind and solar availability reached 10,727 MW, an increase of 2,638 MW, or around 32.6%, compared with the previous day.
Demand growth was much smaller. Regional consumption increased by only 244 MW, or 0.7%, reaching 34,563 MW. The strong increase in renewable supply relative to demand created a softer daytime balance and reduced the need for thermal generation and imports during solar-producing hours.
Demand growth was concentrated mainly in Romania and Bulgaria, where combined consumption increased by 436 MW to 10,154 MW. Greek demand rose slightly by 31 MW to 7,694 MW, while Hungary’s consumption declined by 232 MW to 4,930 MW.
Serbia recorded one of the largest price corrections in the region. SEEPEX fell EUR 18.00/MWh to EUR 142.39/MWh, placing it EUR 14.27/MWh below Hungary. North Macedonia followed a similar trend, declining EUR 17.00/MWh to EUR 141.76/MWh.
The spread between Serbia and North Macedonia narrowed to only EUR 0.63/MWh, creating a closely aligned southern-central price zone. The move suggests these markets benefited strongly from improved regional renewable availability and greater access to lower-cost electricity. However, Serbia remained a net importer at approximately 365 MW, meaning the lower price reflected temporary supply improvement rather than structural surplus.
Bulgaria cleared at EUR 145.28/MWh, down only EUR 0.70/MWh, while maintaining a strong export position of around 1,278 MW. The market’s relatively stable price and export balance indicate competitive domestic supply conditions.
Greece remained the lowest-priced market at EUR 135.94/MWh, declining EUR 6.30/MWh. The Greek hourly curve showed significant volatility, with prices falling sharply during solar hours before recovering toward EUR 200/MWh in the evening.
With average exports of around 1,347 MW, Greece continued to support neighbouring markets by supplying lower-cost electricity. The combination of strong exports and the lowest regional price highlights the growing importance of Greek renewable and conventional generation in balancing Southeast European markets.
A separate price cluster formed around Slovenia, Croatia and Montenegro, where prices remained closely aligned. Slovenia settled at EUR 152.28/MWh, Croatia at EUR 151.32/MWh, and Montenegro at EUR 152.36/MWh, with only EUR 1.04/MWh separating the three markets.
Croatia remained one of the region’s largest importers, requiring approximately 1,162 MW of net imports. Despite this dependence, prices declined as improved northern renewable output and stable imports reduced replacement generation costs.
Montenegro remained comparatively expensive, trading EUR 9.97/MWh above Serbia and EUR 16.42/MWh above Greece. The premium suggests that access to cheaper Serbian and Greek electricity remained limited during critical hours, keeping Montenegro more closely aligned with Croatia and Slovenia.
Albania was the main exception to the regional decline. ALPEX increased EUR 4.60/MWh to EUR 174.17/MWh, becoming the highest-priced market in the region. Albania traded EUR 17.51/MWh above Hungary and EUR 38.23/MWh above Greece, indicating tighter local supply conditions and limited access to regional surpluses.
Italy also remained elevated at EUR 168.73/MWh, while Southeast Europe exported around 828 MW toward the Italian market. These exports reduced available supply within the region and contributed to maintaining higher prices along the Adriatic corridor.
Regional net imports declined only slightly, falling 60 MW to 898 MW, but the overall balance masked significant differences between individual markets. Hungary, Romania, Serbia and Croatia remained import-dependent, while Bulgaria and Greece provided major export volumes.
Hungary imported approximately 965 MW, Romania around 676 MW, Croatia 1,162 MW and Serbia 365 MW. These deficits were partly covered by Bulgarian exports of 1,278 MW, Greek exports of 1,347 MW, and inflows from Austria and Slovakia.
Forward markets remained firmer than the softer day-ahead prices suggested. Hungarian Week 30 power increased EUR 3.00/MWh to EUR 123.00/MWh, while Week 31 gained EUR 2.50/MWh to EUR 136.00/MWh. The Hungary–Germany Week 31 spread widened to EUR 21.00/MWh, signalling that traders continue to price a structural congestion premium.
Longer-term Hungarian contracts remained elevated, with the 2026 average product at EUR 140.50/MWh and the calendar product at EUR 122.50/MWh. The persistent Hungary–Germany spread indicates that the regional price separation is not viewed as a temporary one-day event.
Fuel markets continued to support higher thermal generation costs. CEGH gas increased to EUR 55.93/MWh, while the Greek gas benchmark rose to EUR 45.89/MWh. EU carbon allowances declined to EUR 79.19/t, partially reducing generation costs, but forward gas prices remained elevated near EUR 56/MWh for 2026.
At current gas and carbon levels, efficient combined-cycle gas generation remains expensive enough to support electricity prices above EUR 130/MWh during non-solar hours. This continues to explain the resilience of Hungarian, Romanian and evening Southeast European power prices.
The key market structure for the session was therefore a renewable-supported daytime market and a thermally exposed evening market. Serbia, North Macedonia, Bulgaria and Greece formed the lower-price supply zone, while Hungary and Romania maintained congestion premiums. Slovenia, Croatia and Montenegro remained tightly linked, and Albania continued to trade as the most constrained market.
The widening Hungary–Germany spread, the EUR 38.23/MWh Albania–Greece price gap and persistent evening price spikes above EUR 200/MWh continue to create opportunities for cross-border trading, flexible hydro, demand response and short-duration storage strategies.