Southeast European day-ahead power prices declined across most markets during week 33, as stronger solar generation and weaker weekend demand pushed down baseload averages. However, nuclear and hydropower constraints continued to tighten evening supply, keeping the region at a significant premium to western European markets.
Hungary averaged approximately EUR 145/MWh between 10 and 16 August, broadly in line with Croatia and Slovenia, while Romania averaged around EUR 143/MWh. The closely integrated central Southeast European markets remained approximately EUR 24–26/MWh above the broader European average.
Prices were lower in southern and eastern markets. Bulgaria averaged around EUR 129/MWh, Serbia EUR 126/MWh and Greece approximately EUR 102/MWh. Italy remained the region’s main high-price neighbouring market at around EUR 172/MWh, supporting continued export flows from Southeast Europe.
Despite the elevated regional price level, weekly averages declined significantly. Hungarian prices fell by around 7%, while Romania and Croatia dropped approximately 8%. Bulgaria declined by around 11%, Serbia by almost 19% and Greece by approximately 25%.
The headline averages, however, concealed much tighter conditions during the evening hours. The regional market is increasingly defined by a sharp separation between low-priced solar hours and expensive post-sunset electricity.
Strong photovoltaic generation pushed prices sharply lower around midday before the loss of solar output triggered steep evening ramps. In Hungary on Thursday, prices moved from approximately EUR 84/MWh during the solar-rich period to almost EUR 339/MWh in hour 21.
A similar pattern emerged on Friday. Hungarian prices fell to around EUR 30/MWh around midday before climbing above EUR 260/MWh during the evening.
Sunday produced an even wider intraday spread. Hungarian prices dropped to approximately EUR 27/MWh during the middle of the day before rising above EUR 206/MWh later in the session. Bulgaria moved from around EUR 16/MWh to more than EUR 205/MWh, while Serbia ranged from roughly EUR 10/MWh to above EUR 180/MWh.
Greece experienced some of the strongest solar-driven price compression, with several consecutive daytime hours trading close to zero, followed by evening prices above EUR 200/MWh.
The development is increasingly undermining traditional peakload indicators. In Hungary, peakload prices fell below off-peak averages on several days because conventional peak blocks captured solar-rich daytime hours, while off-peak periods included increasingly expensive evening intervals.
Nuclear and hydro constraints sustain the evening premium
Supply-side restrictions remained one of the main reasons for the region’s persistent premium.
Hungary continued to deal with 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. Hungary nevertheless remained heavily reliant on imports during periods of tighter supply, with imports approaching 2 GW on average early in the week.
Romania faced a similar situation at the Cernavodă nuclear power plant. Unit 1 had already been disconnected because of exceptionally low Danube levels, while operator Nuclearelectrica initiated a controlled shutdown of Unit 2 on 13 August.
The loss of both Cernavodă reactors removed approximately 1.4 GW of low-variable-cost nuclear capacity from the Romanian system. This increased reliance on coal, hydropower, renewable generation and imports, particularly during periods of elevated demand.
Hydrological conditions also remained weak in Serbia. Generation at Đerdap 1 was running at approximately 20% of normal levels, while Đerdap 2 was operating at around 30% amid exceptionally low Danube inflows. Serbian utility EPS consequently relied on market purchases to cover part of domestic demand.
The combination of reduced nuclear availability and weak hydro generation increased the value of flexible capacity across the region, particularly during the evening ramp after solar production disappeared.
Central Southeast Europe remains tightly coupled
Hungary, Romania, Croatia and Slovenia maintained strong price convergence throughout the week. On six of the seven days, the spread between the highest and lowest prices within the four-market cluster remained below approximately EUR 3/MWh.
The close coupling limited opportunities for sustained country-to-country spreads within the central SEE block, while larger differentials remained between the central markets and Greece, Bulgaria, Serbia and Italy.
Cross-border electricity flows continued to provide an important balancing mechanism. Hungary imported close to 2 GW during parts of the early week, although stronger renewable generation subsequently improved the wider regional balance.
By Wednesday, increased wind and solar generation had shifted the combined SEE system towards a small net-export position, although Hungary itself remained a significant importer.
Italy continued to attract electricity from the region because of its structurally higher price level. Exports towards Italy exceeded 1 GW during parts of the week, limiting the extent to which additional renewable generation could push down prices across Southeast Europe.
Meanwhile, gas and carbon prices maintained a relatively high thermal generation floor. Central European gas traded at approximately EUR 57–62/MWh, while EU carbon allowances remained 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 of around EUR 140–160/MWh. However, they do not explain evening prices above EUR 250–300/MWh.
Those spikes increasingly reflect scarcity of flexible generation, transmission constraints and the rapid withdrawal of solar capacity after sunset.
Forward prices continue to signal regional tightness
The Hungarian forward curve continued to price elevated regional power costs beyond the spot market. Week 34 traded around EUR 157/MWh late in the week, while September contracts were near EUR 161/MWh. Hungary therefore remained approximately EUR 25–27/MWh above comparable German contracts.
Early prices for Monday, 17 August, also pointed to a strong recovery following the weekend decline.
Hungarian day-ahead power rebounded to around EUR 184/MWh, while Slovenia and Croatia were both near EUR 181/MWh and Romania around EUR 173/MWh. Bulgaria rose to approximately EUR 170/MWh, while Greece reached around EUR 153/MWh.
The rebound indicates that week 33’s lower baseload averages were driven primarily by strong renewable generation and weaker weekend demand rather than a fundamental improvement in the regional supply balance.
For short-term Southeast European power trading, the widening difference between solar-rich hours and the evening period is becoming more important than the direction of baseload prices alone. Nuclear availability in Hungary and Romania, Danube hydrology, wind forecasts and cross-border transmission capacity remain key variables for the evening curve, while continued photovoltaic expansion is increasing downward pressure on daytime prices.
The changing price structure is also strengthening the economics of batteries and other flexible assets. Near-zero midday prices combined with evening settlements above EUR 200/MWh are creating increasingly attractive intraday spreads, even during weeks when headline baseload prices appear relatively stable.
As solar penetration rises and nuclear and hydro availability remain exposed to weather conditions, the value of flexibility is likely to become an increasingly important feature of Southeast Europe’s power markets.