Day-ahead electricity prices increased across most Southeast European markets for delivery on 14 July 2026, but the upward movement did not result in regional convergence. Instead, the market remained divided into three distinct pricing areas: a high-price Hungary–Slovenia–Austria zone, a mid-range Romania–Bulgaria–Greece–Croatia group, and a lower-priced southern Balkan cluster consisting of Serbia, Montenegro, Albania and North Macedonia.
Hungary’s HUPX day-ahead baseload price increased by €7.90/MWh to €133.75/MWh. Slovenia recorded a nearly identical settlement at €133.65/MWh, while Austria reached €135.72/MWh. The close alignment between these markets shows that Hungary remained strongly connected to the Central European pricing area despite ongoing dependence on cross-border electricity imports.
Germany continued to trade below Hungary at €123.97/MWh, leaving a Hungarian premium of €9.78/MWh, which was €3/MWh higher than in the previous session. Imports from Austria and Slovakia into Hungary and Slovenia averaged approximately 1,496 MW, down by 438 MW compared with the previous day. Stronger Hungarian demand combined with reduced Central European imports contributed to the wider price gap.
Despite the premium over Germany, Hungarian prices remained below the Italian benchmark. Italy’s day-ahead price reached €151.89/MWh, creating an €18.14/MWh premium over Hungary. The broader Southeast European region continued exporting electricity toward Italy, with average flows of approximately 1,025 MW, supporting prices in Slovenia, Croatia and western Balkan markets.
Eastern European interconnected markets remained below Hungary. Romania settled at €121.72/MWh, while Bulgaria and Greece both reached €118.40/MWh. Hungary therefore traded €12.03/MWh above Romania and €15.35/MWh above Bulgaria and Greece. The identical Bulgarian and Greek prices indicate relatively efficient price transmission between the two coupled markets despite possible hourly congestion.
Croatia occupied an intermediate position with a day-ahead price of €126.65/MWh. The country traded around €7.10/MWh below Hungary but remained significantly above Montenegro. Croatia continued to rely heavily on imports, receiving approximately 587 MW from Hungary during baseload hours and 745 MW during peak periods, while imports from Slovenia reached around 503 MW in baseload and 456 MW during peak hours. Total Croatian net imports reached approximately 1,214 MW, making it the largest importing market in the analysed region.
The lowest prices were recorded further south. Serbia’s SEEPEX price increased by €10.60/MWh to €108.15/MWh, but remained €25.60/MWh below Hungary. Montenegro settled at €103.97/MWh, Albania at €103.77/MWh, and North Macedonia at €104.74/MWh. These four markets formed a closely aligned southern Balkan price zone, trading within a range of less than €4.40/MWh.
Albania recorded the strongest daily increase, rising by €19.50/MWh, although it remained the cheapest market in the region. Montenegro increased by €8.70/MWh, while North Macedonia remained almost unchanged. Serbia traded slightly above its southern neighbours, with prices only €4.18/MWh above Montenegro and €4.38/MWh above Albania.
The continued differences between regional markets highlight the remaining fragmentation of Southeast Europe’s electricity system. Bulgaria exported approximately 1,498 MW, Greece around 541 MW, while Romania remained close to balance. Hungary imported around 864 MW, Serbia approximately 489 MW, and Croatia approximately 1,214 MW.
Cross-border schedules also showed that commercial flows do not always follow daily average price signals. Bulgaria continued exporting electricity toward Serbia despite having a higher daily price, reflecting the influence of bilateral agreements, transmission rights, hourly price differences and incomplete market coupling across several borders. Daily averages therefore do not fully capture the economic value of interconnection capacity.
Montenegro maintained strong links with neighbouring systems, receiving approximately 229–233 MW from Bosnia and Herzegovina. Serbia supplied Montenegro with around 163–183 MW, while Albania provided approximately 94 MW during baseload hours and 141 MW during peak periods. These exchanges helped maintain the close price relationship between Montenegro and Albania.
Regional electricity demand was forecast at 32,728 MW, representing an increase of 1,384 MW or around 4.4% compared with Monday. Hungary’s consumption increased by 215 MW to 4,712 MW, while Greek demand rose by 398 MW to 7,470 MW. Combined demand in Romania and Bulgaria reached 9,677 MW, while western Balkan consumption increased by approximately 471 MW.
Higher temperatures continued to support electricity consumption. The regional average temperature excluding Greece increased by 1.7°C to 23.5°C. Forecast temperatures reached approximately 25.5°C in Hungary, 24.6°C in Serbia and 29.1°C in Montenegro. Further warming expected later in the week, with Montenegro approaching 30.9°C, Serbia 27.1°C and Hungary 26.9°C, is likely to maintain elevated cooling demand.
Renewable generation growth helped absorb part of the additional electricity demand. Forecast solar production increased by 350 MW to 6,782 MW, while wind generation rose by 576 MW to 2,498 MW. Combined wind and solar output reached approximately 9,280 MW, covering around 28.4% of forecast regional consumption.
The additional 926 MW of wind and solar generation covered roughly 67% of the daily increase in demand. The remaining balance required approximately 458 MW of additional dispatchable generation or adjustments in other renewable and cross-border positions.
Regional net imports decreased by 204 MW to 635 MW, covering less than 2% of total forecast consumption. Based on demand and import levels, regional generation would need to reach approximately 32,093 MW, around 1,588 MW above Monday’s output. After accounting for renewable increases, hydro, thermal, nuclear and other sources would need to provide approximately 660 MW of additional generation.
Monday’s generation mix showed the importance of flexible domestic production. Total regional output reached 30,505 MW, increasing by 4,246 MW compared with Sunday. Solar contributed 6,432 MW, coal 6,187 MW, nuclear 5,561 MW, hydro 4,940 MW, gas 4,065 MW, wind 1,923 MW, and other sources approximately 1,398 MW.
The return of weekday demand was supported mainly by higher domestic generation rather than additional imports. Hydro output increased by 877 MW, solar by 847 MW, wind by 788 MW, gas by 519 MW, coal by 213 MW, and other generation by 1,034 MW. Nuclear production remained broadly stable, while imports declined by 952 MW, demonstrating sufficient regional flexibility.
Hourly price movements revealed stronger volatility than daily averages suggested. HUPX prices dropped toward €75–90/MWh during midday solar production before rising above €200/MWh during evening peak hours. Similar patterns were observed in Romania, Greece and Slovenia, where solar generation created midday price pressure followed by expensive evening demand periods.
The spread between midday and evening prices exceeded €120/MWh in Hungary. Comparable volatility appeared in Greece and Romania, maintaining strong potential value for battery storage, flexible hydro assets and demand-response solutions. These price differences demonstrate the increasing importance of flexibility as renewable penetration rises.
Fuel markets also supported higher evening electricity prices. Austrian CEGH gas increased by €2.30/MWh to €52.05/MWh, Greek gas reached €44.20/MWh, and EU carbon allowances climbed to €80.11/t. These levels place the variable cost of modern gas-fired generation in the range of approximately €124–136/MWh, depending on efficiency and emissions intensity.
Hungarian forward markets showed mixed expectations. Week 30 prices declined by €8/MWh to €120/MWh, while Week 31 increased by €4.50/MWh to €133/MWh. The difference suggests expectations of short-term easing followed by tighter market conditions later in the curve. The Hungarian premium over Germany also widened for later delivery periods, reflecting concerns over congestion and import availability.
The Southeast European electricity market remains characterised by cheap midday renewable production, expensive evening flexibility requirements and significant geographic price differences. Southern Balkan markets continue to trade near €104–108/MWh, but transmission limitations prevent these lower prices from fully reaching Hungary, Slovenia and Italy. The combination of Hungarian import dependence, Croatian supply deficits and Italy’s high electricity prices continues to increase the value of transmission capacity, battery storage and flexible generation across the region.