Day-ahead electricity markets across South-East Europe opened the trading week with a pronounced bullish correction on 4 May, as a combination of stronger demand, reduced import availability and tightening thermal generation pushed prices back above the €100/MWh threshold across most hubs. The move marks a decisive shift from the negative and low-price episodes seen in recent sessions, confirming the region’s return to a structurally volatile, weather- and flow-driven regime.
Prices on Hungary’s HUPX climbed to €114.4/MWh, up €41.1 day-on-day, setting the tone for the wider region. Romania’s OPCOM followed at €110.9/MWh (+€38.5), while Croatia’s CROPEX cleared at €110.4/MWh (+€39.3). Serbia’s SEEPEX reached €103.0/MWh (+€24.0), and Bulgaria’s IBEX and Greece’s HENEX settled at €102.2/MWh (+€30.5) and €98.9/MWh (+€30.7) respectively. Even structurally lower-priced markets such as Albania and North Macedonia moved higher, though still lagging the core SEE cluster.
The synchronized nature of the move highlights a regional rather than localised tightening event, with all major interconnected markets responding simultaneously to system-wide fundamentals.
Behind the price surge, demand provided the most immediate trigger. Total system consumption rose to 28,127 MW, an increase of 2,767 MW day-on-day, reflecting a combination of post-weekend industrial rebound and gradually rising temperatures across the region. The scale of the increase—approaching double-digit percentage growth—placed immediate pressure on the supply stack, particularly as generation failed to scale accordingly.
Total generation increased only marginally to 24,837 MW, effectively flat on the previous day. This divergence between demand and supply created a structural gap that had to be covered either by imports or higher-cost marginal units. However, import dynamics moved in the opposite direction.
Net imports dropped sharply, with the region shifting toward near-balanced conditions at -315 MW, compared to a positive import position the previous day. Core inflows from Central Europe also declined significantly, with AT/SK to HU/SEE flows falling by several hundred megawatts. This contraction in cross-border supply coincided with a widening price spread between Hungary and Germany, with the HU-DE spread reaching -€16.7/MWh, indicating that Hungarian prices were trading above the German benchmark and reducing the economic incentive for west-to-east flows.
This decoupling from the Central European price formation zone is a critical feature of the current market structure. When SEE markets lose access to competitively priced imports, local fundamentals dominate pricing, often resulting in sharp upward corrections as the system moves up the merit order.
On the generation side, the composition of supply further reinforced bullish conditions. While renewable output showed moderate gains, it was insufficient to offset declines in conventional baseload generation. Solar generation increased to 4,695 MW (+221 MW) and wind output rose to 1,715 MW (+142 MW), benefiting from stable weather conditions. However, coal generation dropped sharply by 566 MW to 3,669 MW, removing a key source of mid-merit capacity from the system.
Hydropower output also softened slightly, while gas-fired generation increased only marginally to 2,257 MW, indicating limited flexibility or economic constraints in ramping thermal capacity. Nuclear generation remained stable at approximately 5.4 GW, continuing to provide baseload support but without the ability to respond dynamically to short-term demand spikes.
The net effect was a tightening supply-demand balance exceeding 3 GW, a level sufficient to trigger sharp price escalation across interconnected markets. In such conditions, marginal pricing shifts rapidly toward higher-cost generation or scarcity pricing, particularly during peak evening hours.
Intraday price structures confirm this dynamic. Hourly profiles show strong evening peaks, with maximum prices consistently occurring around hour 21 across multiple exchanges. At the same time, midday prices remained relatively suppressed due to solar generation, though not to the extent seen in previous sessions with deeper negative pricing episodes. This widening intraday spread underscores the increasing importance of flexibility assets, including storage and fast-ramping thermal units.
Recent volatility patterns remain evident. Data from preceding days shows minimum prices dropping as low as -€500/MWh in certain markets, highlighting the persistence of oversupply conditions during high renewable output periods. The coexistence of extreme negative pricing and triple-digit peaks within short timeframes illustrates the structurally imbalanced nature of SEE power markets.
Cross-border flow data further reinforces the picture of regional stress. Romania and Bulgaria continued to act as key exporters toward Hungary, Serbia and Greece, but overall volumes were insufficient to offset reduced inflows from Central Europe. The SEE region is increasingly behaving as a semi-isolated pricing zone during tight conditions, with internal redistribution of supply unable to fully compensate for external constraints.
Fuel and carbon markets provided additional upward pressure. Austrian gas hub prices rose to around €19/MWh, marking a notable daily increase, while EU carbon allowances remained broadly stable in the €70–80/t range. Higher gas prices directly impact marginal generation costs, particularly in systems where gas-fired plants are required to balance variability in renewable output.
Taken together, the day’s developments reflect a clear transition in market regime. The SEE region is moving away from the oversupplied, renewable-driven conditions that characterised much of early spring and into a more balanced but highly sensitive environment where demand fluctuations, cross-border flows and thermal availability jointly determine price formation.
Short-term expectations point to continued volatility. Price direction in the coming days will depend heavily on import availability from Central Europe, the evolution of wind and solar output, and temperature-driven demand patterns. With interconnector constraints already evident, any further tightening in flows could sustain elevated price levels.
At a structural level, the data reinforces three dominant trends shaping the SEE power market in 2026. First, the growing penetration of renewable generation is increasing intraday volatility, with sharp divergences between peak and off-peak pricing. Second, the gradual erosion of coal capacity is reducing system flexibility and raising dependence on gas and imports. Third, grid constraints and limited interconnection capacity are amplifying regional price separation from core European markets.
Under these conditions, SEE markets are likely to remain prone to abrupt price swings, with liquidity and flexibility becoming increasingly valuable in both trading and asset operation strategies.