Day-ahead electricity prices increased across most Southeast European markets for delivery on 14 July 2026, but the move did not bring regional convergence. Instead, pricing remained split into three areas. A high-price zone covered Hungary–Slovenia–Austria, a mid-range group included Romania–Bulgaria–Greece–Croatia, and a lower-priced southern Balkan cluster comprised Serbia, Montenegro, Albania and North Macedonia.
Central European linkage lifts Hungary, Slovenia and Austria
Hungary’s HUPX day-ahead baseload price rose by €7.90/MWh to €133.75/MWh. Slovenia settled at €133.65/MWh and Austria at €135.72/MWh. The close alignment kept Hungary strongly connected to the Central European pricing area while Hungary continued to depend on cross-border electricity imports.
Germany traded below Hungary at €123.97/MWh, leaving a Hungarian premium of €9.78/MWh. The premium was €3/MWh higher than in the previous session. Imports from Austria and Slovakia into Hungary and Slovenia averaged about 1,496 MW, down by 438 MW versus the prior day.
Higher Hungarian demand combined with lower Central European imports contributed to the wider price gap versus Germany. Despite the premium over Germany, Hungarian prices stayed below Italy’s benchmark. Italy’s day-ahead price reached €151.89/MWh, creating an €18.14/MWh premium over Hungary.
Italy flows support higher prices in Slovenia and Croatia
The region continued exporting electricity toward Italy, with average flows of approximately 1,025 MW. Those flows supported prices in Slovenia, Croatia and western Balkan markets. Eastern interconnected markets remained below Hungary on the day-ahead curve.
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. Bulgaria’s and Greece’s identical settlements pointed to efficient price transmission between the coupled markets despite possible hourly congestion.
Croatia posted an intermediate day-ahead price of €126.65/MWh. It traded around €7.10/MWh below Hungary but stayed significantly above Montenegro. Croatia continued relying on imports, receiving about 587 MW from Hungary during baseload hours and 745 MW during peak periods.
Croatia remains the largest importer as southern Balkan prices fall
Imports into Croatia from Slovenia were around 503 MW in baseload hours 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. Prices were lowest further south across the southern Balkan cluster.
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 traded within a range of less than €4.40/MWh.
Albania recorded the strongest daily increase, rising by €19.50/MWh while remaining the cheapest market in the region. Montenegro increased by €8.70/MWh and North Macedonia was almost unchanged on the day-ahead basis. Serbia traded slightly above its southern neighbours, with prices only €4.18/MWh above Montenegro and €4.38/MWh above Albania.
Cross-border schedules diverge from daily average price signals
Bilateral trade patterns continued to show that commercial flows do not always track daily average price signals across borders. Bulgaria exported electricity toward Serbia even though Bulgaria had a higher daily price on the day-ahead basis than Serbia. The pattern reflected bilateral agreements, transmission rights, hourly price differences and incomplete market coupling across several borders.
Bulgaria exported approximately 1,498 MW and Greece around 541 MW while Romania stayed close to balance on net positions reported for the day-ahead period. Hungary imported around 864 MW and Serbia about 489 MW, while Croatia imported approximately 1,214 MW as net flows.
Montenegro maintained links with neighbouring systems through imports from Bosnia and Herzegovina of roughly 229–233 MW. Serbia supplied Montenegro with around 163–183 MW, while Albania provided about 94 MW during baseload hours and 141 MW during peak periods to Montenegro’s system connections.
Demand forecast rises; solar output increases alongside wind
Regional electricity demand was forecast at 32,728 MW, up by 1,384 MW or about 4.4% compared with Monday. Hungary 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, with western Balkan consumption increasing by approximately 471 MW.
Temperatures were expected to support higher consumption levels across parts of the region. The regional average temperature excluding Greece increased by 1.7°C to 23.5°C with forecast temperatures of about 25.5°C in Hungary, 24.6°C in Serbia and 29.1°C in Montenegro.
Further warming later in the week was forecast with Montenegro approaching 30.9°C, Serbia at 27.1°C and Hungary at 26.9°C, supporting cooling demand expectations for electricity use.
Wind and solar cover part of demand growth; net imports stay low
Renewable generation growth helped absorb part of the additional electricity demand forecast for Tuesday delivery day conditions described for Monday-to-day comparison inputs in the dataset used here. Solar output was forecast to rise by 350 MW to 6,782 MW, while wind generation increased 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 described in the same forecast set of inputs here for Tuesday delivery conditions relative to Monday output levels used in calculations provided by the dataset.
The remaining balance required approximately 458 MW of additional dispatchable generation or adjustments involving other renewable output or cross-border positions referenced in those same calculations.
Generation mix changes; hourly volatility reflects solar timing
Regional net imports decreased by 204 MW to 635 MW, covering less than 2% of total forecast consumption based on those inputs only here for balancing calculations provided in the dataset narrative flow used for this rewrite task set of facts.
Total regional generation would need to reach approximately 32,093 MW, around 1,588 MW above Monday’s output after accounting for demand levels described earlier in this input set here only as factual figures provided for calculation context.
The generation requirement after renewable increases implied hydro, thermal, nuclear and other sources would need to provide approximately 660 MW of additional generation beyond Monday levels referenced in those same inputs.
MIDDAY solar pressure contrasts with evening peaks; gas costs rise
The dataset also reported that hourly price movements showed stronger volatility than daily averages indicated for HUPX and other markets referenced together in that section of inputs here only as factual statements about observed patterns within delivery-day hours described in that narrative flow.
HUPX prices dropped toward €75–90/MWh during midday solar production before rising above