Electricity prices across Southeast Europe and Hungary moved decisively lower on 24 March, breaking the elevated levels seen earlier in the week as a combination of higher thermal generation, rising imports and stabilizing demand reshaped the regional balance. The correction was broad-based, with most markets recording day-on-day declines of €10–40/MWh, signalling a temporary easing of tightness rather than a structural shift in fundamentals.
Day-ahead prices converged across the region, clustering in a relatively narrow band between €109/MWh and €124/MWh, with Hungary (HUPX) at €124.33/MWh, Serbia (SEEPEX) at €113.12/MWh, and Romania (OPCOM) at €114.77/MWh. Southern and peripheral markets followed the same direction, with Greece at €109.02/MWh and Bulgaria at €110.64/MWh, while Albania stood out at €84.52/MWh, reflecting localized oversupply conditions.
The scale of the daily move was notable. Hungary dropped €35/MWh, Romania €40/MWh, and Greece €38/MWh, underlining how quickly regional markets are adjusting to short-term shifts in generation mix and cross-border flows.
At the core of the price correction lies a sharp rebalancing of the generation stack. Total regional output increased to around 34.4 GW, up more than 2.1 GW day-on-day, driven primarily by a strong ramp in gas-fired generation and hydro recovery. Gas output surged by +1.7 GW, while hydro added +1.1 GW, compensating for a steep drop in wind generation of -1.4 GW.
This shift highlights a recurring structural feature of SEE markets: price formation remains highly sensitive to renewable volatility, particularly wind. The sharp decline in wind output—down to roughly 2.5 GW—removed a key source of low-cost supply, but this was more than offset by dispatchable thermal capacity stepping in. Gas-fired plants, in particular, continue to act as the marginal price setters across much of the region.
Solar generation, meanwhile, increased modestly to 3.4 GW, providing intraday price compression during daylight hours but insufficient to fully counterbalance the wind shortfall. Nuclear output remained stable at ~5.8 GW, anchoring baseload conditions.
Demand dynamics also played a stabilizing role. Total consumption rose slightly to 34.2 GW, reflecting a modest uptick linked to cooler conditions earlier in the week, but temperatures across the region are now trending upward toward 10–11°C, reducing heating-related demand pressure.
Cross-border flows were equally decisive. Net imports into the SEE+Hungary region narrowed to -91 MW, effectively balancing the system compared to stronger import reliance in previous days. At the same time, core imports from Central Europe increased to 2,132 MW, indicating continued reliance on cheaper upstream markets, particularly Austria and Slovakia.
The widening HU-DE spread to €47.5/MWh, up sharply day-on-day, reflects this dynamic. German prices remained structurally lower due to stronger renewable penetration, allowing power to flow eastward and cap price spikes in Hungary and adjacent markets.
Intraday price profiles confirm the persistence of volatility beneath the daily averages. Peak-hour prices across the region still reached €150–260/MWh, particularly in evening hours when solar output fades and gas-fired generation dominates. At the same time, midday prices softened significantly, with several markets recording minimum prices near €0–20/MWh, and occasional negative pricing in Slovenia earlier in the week.
This widening intraday spread continues to reinforce arbitrage opportunities, particularly for flexible assets such as battery storage and fast-ramping gas units. Romania’s emerging battery storage market, where revenues can reportedly reach up to $500,000 per MW annually, reflects precisely these volatility-driven value pools.
On the forward curve, signals are mixed but broadly supportive of near-term stability. Hungarian power forwards for April are trading around €109/MWh, while Q2 contracts are near €103/MWh, indicating expectations of slightly softer pricing into spring.
Gas markets remain elevated but stable, with CEGH forward prices around €59/MWh, while carbon (EUA) prices continue to hover near €60–65/t, maintaining cost pressure on thermal generation.
Coal prices, by contrast, are trending lower, offering limited relief for lignite-heavy systems in the Balkans but insufficient to materially shift the merit order against gas under current carbon pricing conditions.
Structurally, the market continues to exhibit three dominant features shaping trading behavior. First, the increasing penetration of renewables—now approaching 47.3% of EU electricity generation—is amplifying volatility rather than suppressing it, particularly in regions like SEE where grid flexibility remains limited.
Second, cross-border integration is becoming more influential in price formation. The ability of Central European markets to export surplus power into SEE is increasingly capping extreme price spikes, but also transmitting volatility across borders.
Third, dispatchable generation—especially gas—retains a critical role as the balancing mechanism, effectively setting marginal prices during peak demand and low renewable output periods.
Looking ahead, the near-term trajectory will depend heavily on weather-driven renewable output. Forecasts indicate gradually rising temperatures and relatively stable solar conditions, which could continue to suppress midday prices. However, the absence of strong wind generation suggests that evening peak pricing will remain elevated, preserving intraday volatility.
Hydrological conditions will also be closely watched. Recent increases in hydro output, supported by improving river flows, have provided some relief, but sustained recovery will be necessary to materially reduce reliance on thermal generation.
In practical trading terms, the current environment continues to favor flexible strategies. Intraday spreads remain wide, cross-border arbitrage opportunities are active—particularly along the Germany–Austria–Hungary corridor—and balancing markets are becoming increasingly valuable as renewable penetration rises.
The broader structural shift is clear: SEE electricity markets are no longer defined primarily by scarcity, but by volatility. Price direction is increasingly dictated not by absolute supply deficits, but by the interplay between intermittent renewables, flexible generation, and cross-border flows—a dynamic that is likely to intensify as new renewable and storage capacity enters the system through 2026 and beyond.
