Southeast European power markets experienced a sharp price increase as higher temperatures boosted electricity demand, weaker wind generation reduced supply flexibility and the evening ramp exposed renewed limitations in transmission capacity and flexible generation. The HUPX market rose by €17.3/MWh to €151.07/MWh, although the regional movement was uneven. Prices reached €161.42/MWh in Slovenia, €157.15/MWh in Croatia and €150.05/MWh in Romania, while Albania remained significantly lower at €112.50/MWh.
The regional baseload spread widened to €53.41/MWh, measured between Italy at €165.91/MWh and Albania. However, the most important market signal came from hourly price differences rather than average daily prices. During the evening peak, Slovenia reached €372.60/MWh at H20, Croatia climbed to €340.40/MWh, Romania to €287.80/MWh and Hungary to €275.80/MWh. These extreme levels contrasted sharply with midday prices, which fell to €30.50/MWh in Greece, €49.20/MWh in Albania, €51.00/MWh in Bulgaria and €90.10/MWh in Hungary.
The market therefore displayed two very different operating conditions within the same delivery day: comfortable midday supply supported by solar generation and a much tighter evening system once photovoltaic output declined. The widening gap between daytime and evening prices highlights the increasing value of flexibility, storage and fast-response generation in Southeast Europe.
Hungary’s premium increasingly reflects evening flexibility constraints
Hungary’s baseload premium compared with Germany widened by €4.9/MWh to €14.65/MWh, while HUPX traded €14.68/MWh above Greece, €11.68/MWh above Serbia, €24.48/MWh above Montenegro and €38.57/MWh above Albania.
The average price difference, however, does not fully capture the structure of the market. Hungary’s peakload price reached €136.50/MWh, compared with €109.10/MWh in Germany, creating a peak-period premium of €27.40/MWh. Off-peak prices were almost identical, at €165.60/MWh in Hungary and €163.70/MWh in Germany. This indicates that Hungary’s higher prices were driven primarily by the cost of evening flexibility rather than by a continuous shortage throughout the day.
HUPX moved from €90.10/MWh at H13 to €275.80/MWh at H20, creating an intraday spread of €185.70/MWh. Such volatility creates significant theoretical value for battery storage, although actual revenues depend on efficiency losses, market liquidity, imbalance exposure and access to balancing services.
The western part of the region experienced even stronger volatility. Slovenia recorded an hourly spread of €274.70/MWh, while Croatia reached €243.20/MWh. Their sharp evening price increases suggest localized scarcity conditions in the Slovenia-Croatia corridor rather than a broader regional fuel-cost shock.
Italy remained the most expensive baseload market at €165.91/MWh, although its hourly volatility was more limited, ranging between €142.40/MWh and €198.30/MWh. The country therefore maintained the highest average price but avoided the extreme evening spikes seen in several Southeast European markets.
Higher demand absorbed additional solar generation
Regional electricity consumption increased by approximately 1,540 MW, or 4.8%, reaching 33,397 MW. The increase was supported by warmer weather, with regional average temperatures around 25.7°C, contributing to stronger cooling demand.
The largest demand increase came from Romania and Bulgaria, where combined consumption rose by 839 MW to 9,690 MW. Greece added 307 MW, reaching 7,503 MW, while Slovenia and Croatia together increased demand by 363 MW to 9,804 MW. Hungary remained relatively stable at 4,878 MW.
Forecast solar generation increased by 450 MW to 7,574 MW, but wind output declined by 249 MW to 1,816 MW. Solar generation improved daytime supply conditions but could not eliminate the evening flexibility challenge. Lower wind production intensified the ramp once solar output declined.
Total regional generation increased by approximately 1,248 MW to 32,547 MW, slightly below the growth in consumption. As a result, net imports increased by 292 MW to 850 MW, rising by more than 50% compared with the previous day. Increased inflows from Austria and Slovakia into Hungary and Slovenia supported regional balancing.
The daily balance shows that the system remained adequately supplied in overall energy terms, while still experiencing severe hourly price spikes. The key issue was not total electricity availability but the timing and location of flexible capacity.
Hungary and Croatia remain key import-dependent markets
Hungary’s electricity balance weakened despite stable demand. Consumption increased slightly to 4,878 MW, while domestic generation declined by 320 MW to 3,692 MW. Net imports therefore increased from 824 MW to 1,185 MW.
Hungary received average scheduled inflows of approximately 1,073 MW from Slovakia, 796 MW from Romania, 256 MW from Serbia and 136 MW from Austria. At the same time, it supplied around 646 MW to Croatia and 466 MW to Slovenia, maintaining its role as both a major importing market and an important regional transit hub.
Croatia remained the largest net importer in the region at 1,222 MW. Consumption increased to 2,537 MW, while domestic generation reached only 1,315 MW. Average scheduled imports included approximately 646 MW from Hungary, 426 MW from Slovenia, 63 MW from Serbia and 88 MW from Bosnia and Herzegovina.
Slovenia recorded net imports of 329 MW, relying heavily on cross-border flows from Austria and Hungary while supplying electricity toward Croatia and Italy. These transit requirements help explain why high hourly prices emerged even without an extreme national supply deficit.
Bulgaria and Greece strengthen regional supply support
Bulgaria remained the largest net exporter at 1,372 MW. Although consumption increased by 678 MW to 3,862 MW, generation rose by 652 MW to 5,234 MW, allowing the country to maintain its export position.
Bulgaria supplied approximately 1,307 MW to Romania, 289 MW to Serbia and 181 MW to North Macedonia, while receiving electricity from Greece and Turkey. The country continued to act as a key redistribution point between Southeast European markets.
Greece increased its export position from 568 MW to 769 MW as generation growth exceeded demand growth. The country exported electricity toward Bulgaria, Albania, North Macedonia and Italy, reinforcing its role as a regional energy gateway.
The Greek market also showed a strong solar-driven price curve, falling to €30.50/MWh at H13 before rising to €196.70/MWh at H22. This reflects the growing importance of flexibility solutions as renewable penetration increases.
Romania remained a central part of regional electricity flows. Despite continuing exports toward Hungary, the country moved from a small net export position into net imports as domestic demand increased and generation declined. Strong imports from Bulgaria helped balance the system.
Serbia narrows its import requirement as prices converge with the region
Serbia recorded the largest daily baseload price increase among monitored markets, with SEEPEX rising by €31.2/MWh to €139.39/MWh. The price gap between Serbia and Hungary narrowed significantly.
Consumption increased to 3,620 MW, while generation rose more strongly to 3,352 MW, reducing net imports from 489 MW to 269 MW.
Serbia adjusted its regional position by increasing exports toward Hungary during peak hours, while continuing imports from Bulgaria, North Macedonia, Bosnia and Herzegovina and Romania. The stronger connection with Hungary reflected the higher HUPX price environment.
SEEPEX remained less volatile than Hungary, moving from €80.50/MWh at H13 to €215.00/MWh at H22. The later Serbian peak illustrates the southward movement of evening scarcity conditions across the region.
Montenegro and North Macedonia face tighter domestic balances
Montenegro’s BELEN price increased by €22.6/MWh to €126.59/MWh as domestic generation declined and import dependence increased. Consumption reached 442 MW, while generation fell to 291 MW, expanding net imports.
Despite its domestic deficit, Montenegro continued significant transit flows toward Italy, highlighting the complexity of regional electricity exchanges. Prices ranged from €80.00/MWh at H12 to €200.00/MWh at H22.
North Macedonia moved from a small export position to net imports as demand increased and generation declined. Its market price rose to €125.72/MWh, remaining below Hungary but reflecting tighter regional conditions.
Albania remained the regional exception. Stable generation slightly above consumption allowed a small export position, while prices increased only modestly. The country continued to show a strong solar-shaped curve, with low daytime prices followed by stronger evening conditions.
Fuel markets support higher power prices but forward markets remain cautious
Thermal market conditions became slightly more supportive. Gas prices increased, with CEGH gas rising to €54.44/MWh, while EU carbon allowances climbed to €81.39/t. Coal prices softened slightly, leaving gas and carbon as the main marginal cost drivers.
However, forward electricity markets did not fully price in the day-ahead volatility. Hungarian Week 30 and Week 31 contracts remained below current spot levels, suggesting that traders view the extreme price spike as partly temporary.
Longer-term Hungarian contracts continued strengthening, reflecting structural concerns related to import dependence, thermal availability and transmission constraints. The market is distinguishing between short-term scarcity events and deeper changes in regional electricity system flexibility.
The key message from 15 July is the widening value gap between midday renewable generation and reliable evening electricity supply. Solar growth is improving daytime energy availability, but the commercial value of electricity after sunset is increasingly determined by battery storage, flexible generation and available cross-border capacity. Southeast Europe’s next phase of renewable development will therefore depend not only on adding generation capacity, but also on building the flexibility needed to manage a more volatile electricity system.