Southeast European electricity prices could ease in Q4 2026 and Q1 2027 if nuclear capacity returns and hydro inflows improve, according to a regional assessment tied to conditions on 4 November 2026. The outlook matters for power buyers and generators because gas costs and constrained transmission are expected to preserve a premium during tight periods.
The base case assumes a relatively mild European winter, gradually improving hydrology, the scheduled return of Romanian and Bulgarian nuclear capacity, and broadly normal operation at Paks and Krško. Short cold spells and prolonged periods of low wind remain possible.
For Hungary, average day-ahead baseload prices are assessed at €225 to €295/MWh in Q4 and €195 to €265/MWh in Q1. Romania is put at €215 to €290/MWh in Q4 and €185 to €255/MWh in Q1.
Bulgarian prices are assessed at €210 to €280/MWh in Q4 and €180 to €245/MWh in Q1. In Serbia, the corresponding ranges are €210 to €285/MWh and €185 to €255/MWh, with thermal availability and hydro inflows determining the import requirement.
Montenegro is assessed at €215 to €295/MWh in Q4 and €185 to €265/MWh in Q1. The assessment applies the same ranges to North Macedonia, reflecting its exposure to imports and regional scarcity.
Croatia and Slovenia are both put at €205 to €275/MWh in Q4 and €175 to €245/MWh in Q1. Greece has the lowest Q1 range, at €160 to €230/MWh, with Q4 prices assessed at €185 to €250/MWh.
These country price ranges are analytical bands, not traded forward quotations. The assessment expects gas costs and transmission constraints to support a premium when the regional market is tight.
Weather and generation shape the outlook
Wind is expected to make a stronger seasonal contribution, but with substantial daily volatility. Lower winter solar output may improve capture rates by reducing midday oversupply; that pressure could return as generation rises in February and March.
Batteries are expected to continue earning from price differences and balancing, although growing competition is putting pressure on margins. Hydro recovery depends on rainfall and reservoir refill, while nuclear availability remains a major determinant of import needs.
When renewable output is insufficient, gas and carbon costs keep marginal thermal generation expensive. Transmission congestion can also prevent cheaper electricity elsewhere in Europe from fully meeting Southeast European demand.
A cold winter combined with weak wind, low hydro and delayed reactor returns could bring repeated daily averages near €300/MWh in the Hungary-Romania-Bulgaria cluster, with Western Balkan evening prices above €400/MWh.
By contrast, a mild, wet and windy winter with full nuclear availability could keep average prices below the base ranges for extended periods. Physical variables to monitor include Danube levels, reactor restart schedules, EPS plant reliability, Montenegrin reservoir conditions and Hungarian import capacity.
Gas prices, carbon allowances, battery dispatch and the cost of exporting Western Balkan electricity into the EU will also influence realised price spreads. For investors, the assessment points to rising value for dependable delivery during scarce hours; secure connections, diverse production profiles, storage duration and market access will determine how much of the regional premium an asset can capture.
The forecast is based on conditions assessed on 4 November 2026 and should change if those conditions shift.
