The Southeast European day-ahead electricity market started 6 August 2026 with a divide between a tightly connected Hungarian–Romanian–Slovenian–Croatian price zone and more discounted pricing in Greece, Bulgaria and North Macedonia. Higher regional consumption and reduced conventional generation availability kept pressure on central European prices, despite stronger solar output and lower gas, carbon and forward power prices. Hungary’s HUPX base price rose to €182.42/MWh, while Romania settled at €182.90/MWh.
Within the central cluster, Slovenia and Croatia posted the highest prices at €183.34/MWh and €183.35/MWh. The spread across Hungary, Romania, Slovenia and Croatia stayed below €1/MWh, indicating convergence across the northern and western part of Southeast Europe. Beyond that group, pricing diverged into separate national and cross-border outcomes.
Austria traded at €174.16/MWh, Serbia at €175.41/MWh, Montenegro at €173.91/MWh and Albania at €176.88/MWh. Bulgaria cleared at €170.56/MWh and North Macedonia at €158.52/MWh, while Greece fell by €10/MWh to €141.63/MWh. Germany remained significantly cheaper at €99.51/MWh, whereas Italy recorded the region’s highest price at €198.35/MWh.
The Hungary–Germany day-ahead spread widened to €82.91/MWh, up by more than €17/MWh versus the previous session. Hungary also traded €40.79/MWh above Greece and around €16/MWh below Italy. Differences of this scale were linked to transmission limitations, uneven generation availability and restricted cross-border flexibility.
Evening demand drives the hourly pattern in HUPX
The hourly price profile pointed to evening demand as the main source of pressure in the region’s central market hub. On HUPX, prices ranged from a noon low of €102.80/MWh to a peak of €298.20/MWh at hour 21. Hungary’s peak-hour average was €164.60/MWh, while off-peak averaged €200.20/MWh.
Germany followed a similar shape but at a lower level, with prices reaching minus €1.40/MWh during hour 14. The German peak-hour average stood at €46.10/MWh. The contrast between negative German midday pricing and Hungarian evening levels approaching €300/MWh highlighted the role of cross-border capacity and balancing resources for renewable volatility.
Romania tracked Hungary closely, with a base price of €182.90/MWh and an evening peak of €301.60/MWh. Slovenia and Croatia showed near-identical intraday movements, with daily maximums of €285.30/MWh and €288.80/MWh respectively at their highest hours . The similarity indicated shared constraints affecting the central European price zone during evening periods.
Serbia’s imports rise as SEEPEX reaches higher intraday levels
Serbia’s SEEPEX price eased by €1.3/MWh to €175.41/MWh while its peak-hour average increased to €153.90/MWh; off-peak prices remained elevated at €197/MWh . Although the market reached €326/MWh during hour 20, other hours were priced lower enough for the daily average to remain below HUPX.
Serbia’s average electricity consumption forecast fell by 92 MW to 3,918 MW, while generation decreased by about 180 MW to 3,400 MW . Net imports were therefore estimated at 518 MW, around 13% of average demand . Commercial schedules showed larger inflows from Bulgaria and North Macedonia, with smaller volumes arriving from Hungary and Bosnia and Herzegovina.
Serbia also continued exporting electricity toward Romania and Montenegro, maintaining its role as both a deficit market and a regional transit hub . Peak-hour imports increased to 858 MW, which corresponded with SEEPEX reaching €326/MWh despite a lower daily average than Hungary .
Regional balance: higher demand meets limited conventional availability
Across the wider Hungary and Southeast European region, average consumption was forecast at 34,728 MW, up 518 MW from the previous day . Regional generation increased by only around 290 MW to 32,585 MW, leaving net imports at 2,143 MW . Import dependence therefore rose despite slightly cooler weather conditions.
Hungary remained the largest structural deficit market within the central cluster, with consumption forecast at 5,249 MW against generation of 2,949 MW for a net import requirement of 2,300 MW . Domestic generation declined by 179 MW while nuclear output was particularly low at 171 MW compared with 872 MW on 31 July . Imports covered much of the shortfall from Slovakia (about 1,229 MW), Austria (922 MW) and Romania (657 MW).
Solar production averaged 1,508 MW in Hungary alongside gas supply of 913 MW and coal generation of 257 MW . Dependence on imports increased significantly during evening hours when solar output disappeared .
Greece exports on renewables; Bulgaria supplies regional demand
Greek generation rose to 8,971 MW while consumption reached 7,499 MW, supporting average exports of 1,472 MW . Exports were directed toward Bulgaria, Italy, North Macedonia, Albania and Turkey . Greek day-ahead prices declined to €141.63/MWh supported by strong renewable generation.
In Greece’s generation mix for the period cited in the report, solar accounted for 31% of output and wind for 21%, with gas at 36%, hydropower at 8% and coal at only 4% . While high renewable production reduced daytime prices and supported exports, grid constraints prevented full regional price convergence .
Bulgaria remained among the strongest exporters relative to domestic demand: generation reached 5,285 MW versus consumption of 3,990 MW for exports of 1,295 MW . Bulgaria supplied Romania, Serbia and North Macedonia while its price increased to €170.56/MWh due to demand pressure from northern markets .
Croatia deficit widens; forward prices fall alongside fuel costs
Croatia’s electricity deficit widened to 1,151 MW as consumption increased and domestic generation declined . Imports from Slovenia and Hungary helped cover demand while Croatia’s price converged almost completely with Slovenia and Romania at €183.35/MWh .
Forward electricity markets moved in the opposite direction from day-ahead pricing in Hungary: September 2026 power fell by €8.50/MWh to €157/MWh while the Week 33 contract dropped by €7.50/MWh to €173.50/MWh . The Hungary–Germany Week 33 premium narrowed to €45.50/MWh as the September spread declined to €32.50/MWh .
The decline in forward prices coincided with weaker commodity markets including Austrian CEGH gas falling to €55.37/MWh and Greek gas declining to €51.06/MWh; EU carbon allowances eased to €81.09/t . September gas traded around €54/MWh while coal dropped to $114/t . The report also cited lower nuclear availability in Hungary alongside Serbian import needs and congestion across central Southeast Europe as factors keeping evening prices elevated.
