Day-ahead electricity prices across Southeast Europe eased during Week 33, with declines recorded in most markets. The move was linked to stronger solar generation and weaker weekend demand that reduced baseload averages. Despite the fall in headline levels, nuclear and hydropower constraints continued to tighten evening supply, leaving the region at a premium versus western European markets.
Between 10 and 16 August, Hungary averaged about EUR 145/MWh, broadly in line with Croatia and Slovenia, while Romania averaged around EUR 143/MWh. The central Southeast European cluster remained roughly EUR 24–26/MWh above the broader European average. Bulgaria averaged approximately EUR 129/MWh, Serbia about EUR 126/MWh, and Greece near EUR 102/MWh. Italy stayed the main high-price neighbouring market at around EUR 172/MWh, supporting exports from Southeast Europe.
Weekly averages fell sharply despite higher price levels in several markets. Hungarian prices dropped by around 7%, while Romania and Croatia declined by about 8%. Bulgaria fell by roughly 11%, Serbia by almost 19%, and Greece by approximately 25%. The weekly headline figures masked tighter conditions during evening hours.
Solar-driven midday falls widen intraday spreads
The price pattern during Week 33 increasingly reflected a split between low-priced solar hours and more expensive post-sunset electricity. Strong photovoltaic output pushed prices down around midday before solar generation fell and evening ramps accelerated. In Hungary on Thursday, prices moved from about EUR 84/MWh during the solar-rich period to nearly EUR 339/MWh in hour 21. A similar dynamic appeared on Friday, when Hungary traded around EUR 30/MWh near midday before rising above EUR 260/MWh during the evening.
The intraday range widened further on Sunday. In Hungary, prices fell to roughly EUR 27/MWh in the middle of the day before increasing to above EUR 206/MWh later on. Bulgaria moved from around EUR 16/MWh to more than EUR 205/MWh, while Serbia ranged from about EUR 10/MWh to above EUR 180/MWh. Greece saw some of the strongest solar-driven compression, with several consecutive daytime hours trading close to zero followed by evening prices above EUR 200/MWh.
This structure affected how peakload indicators tracked system conditions. In Hungary, peakload prices fell below off-peak averages on several days because conventional peak blocks captured solar-rich daytime hours. Off-peak periods increasingly included expensive evening intervals.
Nuclear availability and Danube hydrology support the evening premium
Nuclear and hydropower constraints were a key driver of the persistent evening premium during Week 33. Hungary faced reduced availability at the Paks nuclear power plant, which normally provides close to 2 GW of capacity and around half of domestic electricity production. Several Paks units were affected by exceptionally low Danube water levels, although the gradual return of Unit 2 improved availability during the week. During tighter supply periods, Hungary relied heavily on imports, with flows approaching 2 GW on average early in the week.
A similar situation affected Romania’s nuclear fleet at Cernavodă. Unit 1 had already been disconnected due to exceptionally low Danube levels, while operator Nuclearelectrica initiated a controlled shutdown of Unit 2 on 13 August. With both Cernavodă reactors out of service, Romania removed about 1.4 GW of low-variable-cost nuclear capacity from its system. That shift increased reliance on coal, hydropower, renewable generation and imports during periods of elevated demand.
13 August
Tight coupling across central SEE; cross-border flows continue
Hungary, Romania, Croatia and Slovenia maintained strong price convergence throughout Week 33. On six of seven days, the spread between the highest and lowest prices within the four-market cluster stayed below about EUR 3/MWh. The close coupling limited sustained country-to-country spreads inside the central SEE block, while larger differentials persisted between central markets and Greece, Bulgaria, Serbia and Italy.
Cross-border electricity flows provided balancing support during the week. Hungary imported close to EUR 2 GW during parts of early-week trading before stronger renewable generation improved the wider regional balance. By Wednesday, increased wind and solar output shifted the combined SEE system toward a small net-export position even though Hungary remained a significant importer.
Thermal cost floor and forward curve point to regional tightness beyond spot averages .
Certain market dynamics also reflected a relatively high thermal generation floor. Central European gas traded at approximately EUR 57–62/MWh while EU carbon allowances were around EUR 82–83/t. These input costs imply short-run generation costs for modern gas-fired plants broadly consistent with central SEE baseload prices near EUR 140–160/MWh. However, they did not account for evening prices above EUR 250–300/MWh.
The source of those higher evening levels was linked to scarcity of flexible generation, transmission constraints and rapid withdrawal of solar capacity after sunset. Forward pricing continued to reflect regional tightness beyond spot outcomes. The Hungarian forward curve priced elevated power costs beyond Week 33: Week 34 traded around EUR 157/MWh late in the week and September contracts were near EUR 161/MWh.
The forward spread kept Hungary roughly EUR 25–27/MWh above comparable German contracts. Early trading for Monday, 17 August, indicated a recovery after weekend declines: Hungarian day-ahead power rebounded to about EUR 184/MWh. Slovenia and Croatia were both near EUR 181/MWh while Romania was around EUR 173/MWh; Bulgaria rose to roughly EUR 170/MWh and Greece reached around EUR 153/MWh.
Evolving price structure highlights flexibility needs for short-term trading .
The rebound suggested that Week 33’s lower baseload averages were driven primarily by stronger renewable generation and weaker weekend demand rather than a fundamental improvement in regional supply balance. For short-term Southeast European power trading, differences between solar-rich hours and evening periods became more important than baseload direction alone. Nuclear availability in Hungary and Romania, Danube hydrology, wind forecasts and cross-border transmission capacity were identified as key variables shaping the evening curve.
The same conditions pointed to increasing downward pressure on daytime prices as photovoltaic expansion continued. Near-zero midday pricing combined with evening settlements above EUR 200/MWh supported intraday spreads relevant to batteries and other flexible assets even when headline baseload averages appeared stable. As solar penetration rises alongside weather-exposed nuclear and hydro availability, flexibility value was expected to remain a defining feature of Southeast Europe’s power market pricing structure.
