On March 24, 2026, electricity prices in Southeast Europe and Hungary experienced a significant decline, reversing the elevated levels observed earlier in the week. This drop was attributed to a combination of increased thermal generation, rising imports, and stabilizing demand across the region. Most markets recorded day-on-day price reductions ranging from €10 to €40 per megawatt-hour (MWh), indicating a temporary easing of market tightness rather than a fundamental shift in supply-demand dynamics.
Day-ahead prices across the region clustered within a narrow band of €109/MWh to €124/MWh. Hungary’s HUPX market registered prices at €124.33/MWh, while Serbia’s SEEPEX and Romania’s OPCOM reported prices of €113.12/MWh and €114.77/MWh, respectively. Greece and Bulgaria followed suit with prices at €109.02/MWh and €110.64/MWh. Notably, Albania’s price stood out at €84.52/MWh, reflecting localized oversupply conditions.
The scale of the daily price movement was particularly pronounced, with Hungary experiencing a drop of €35/MWh, Romania by €40/MWh, and Greece by €38/MWh. This rapid adjustment underscores the responsiveness of regional markets to short-term changes in generation mix and cross-border flow dynamics.
A key factor behind this price correction was a notable rebalancing within the generation stack. Total regional output increased to approximately 34.4 gigawatts (GW), marking an increase of over 2.1 GW compared to the previous day. This rise was predominantly driven by a surge in gas-fired generation (+1.7 GW) and hydro recovery (+1.1 GW), which helped compensate for a significant drop in wind generation (-1.4 GW).
This development highlights an ongoing structural characteristic within Southeast European markets: price formation remains highly sensitive to fluctuations in renewable energy output, particularly wind generation. The sharp decline in wind capacity—falling to around 2.5 GW—eliminated a crucial source of low-cost energy supply; however, this impact was mitigated by increased dispatchable thermal capacity stepping in to fill the gap.
While solar generation saw a modest uptick to 3.4 GW, contributing to intraday price compression during daylight hours, it was insufficient to fully offset the loss from wind generation shortfalls. Nuclear output remained stable at approximately 5.8 GW, providing essential baseload support.
Demand patterns also contributed to market stabilization as total consumption increased slightly to 34.2 GW due to cooler temperatures earlier in the week; however, temperatures are now trending upward towards 10–11°C, leading to reduced heating-related demand pressure.
Cross-border electricity flows played a critical role as well; net imports into the SEE+Hungary region narrowed to -91 MW, effectively balancing supply against previous days’ stronger import reliance. Core imports from Central Europe rose significantly to 2,132 MW as markets continued their reliance on cheaper upstream sources from Austria and Slovakia.
The widening HU-DE spread reached €47.5/MWh—an increase driven by Germany’s structurally lower prices due to enhanced renewable penetration—facilitating power flow eastward and capping potential price spikes in Hungary and neighboring markets.
Intraday pricing data revealed persistent volatility beneath daily averages: peak-hour prices surged between €150–260/MWh during evening hours when solar production diminishes and gas-fired generation takes precedence. Conversely, midday prices softened considerably with several markets recording minimum values near €0–20/MWh; Slovenia even experienced occasional negative pricing earlier in the week.
This increasing intraday spread reinforces arbitrage opportunities for flexible assets such as battery storage systems and fast-ramping gas units. Romania’s developing battery storage sector is indicative of this trend; reports suggest revenues could reach up to $500,000 per MW annually driven by volatility-driven value pools.
Looking ahead on the forward curve reveals mixed signals but generally supports expectations for near-term stability: Hungarian power forwards for April are trading around €109/MWh while Q2 contracts hover near €103/MWh—suggesting slightly softer pricing as spring approaches.
Gas markets remain stable yet elevated with CEGH forward prices around €59/MWh; carbon (EUA) prices remain steady between €60–65/t, applying continued cost pressure on thermal generation operations.
In contrast, coal prices are trending downward but provide limited relief for lignite-heavy systems prevalent in the Balkans; current carbon pricing conditions hinder any significant shift against gas within merit order considerations.
Structurally speaking, three primary factors continue shaping trading behavior: firstly, increasing renewable penetration—now nearing 47.3% of EU electricity generation—is amplifying market volatility rather than suppressing it; secondly, cross-border integration is becoming more influential in determining price formation; finally, dispatchable generation—especially gas—remains vital as a balancing mechanism during peak demand periods when renewable output is low.
The near-term trajectory will largely depend on weather patterns influencing renewable output levels moving forward; forecasts indicate rising temperatures along with stable solar conditions could further suppress midday pricing trends while evening peak pricing may remain elevated due to limited wind generation availability.
Overall hydrological conditions will also be monitored closely as recent hydro output increases have provided some relief but sustained improvements are necessary for significant reductions in reliance on thermal resources.
