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SEE power prices jump above €150/MWh on 1 April as imports shrink and gas takes over marginal cost
Southeast European day-ahead electricity markets saw a pronounced move higher in day-ahead power pricing on 1 April 2026, with markets converging around €150–158/MWh. The shift matters for investors because it underscores how quickly tighter physical conditions—especially reduced imports and weaker renewables—can translate into higher marginal costs across interconnected systems.
The rally was broadly synchronized across Central Eastern and Southeast Europe, reflecting a tightening balance where shared drivers increasingly determine price formation rather than isolated national factors.
Benchmarks converge while Serbia holds a premium
Most exchanges cleared within the same narrow range. Hungary (HUPX) settled at €154.3/MWh, Romania (OPCOM) at €156.3/MWh, Bulgaria (IBEX) at €155.4/MWh, and Greece (HENEX) reached €155.0/MWh. Serbia’s SEEPEX price finished at €158.5/MWh, keeping a premium versus neighboring markets.
Croatia and Slovenia followed closely at €151–150/MWh levels, reinforcing the sense of one regional pricing mechanism under stress.
The main outlier was Albania, where ALPEX dropped to €138.7/MWh. The lower print was linked to localized hydro oversupply alongside weaker coupling with broader regional price formation.
Import compression tightens liquidity and raises marginal prices
A central driver behind the upward move was a sharp contraction in cross-border electricity imports, particularly into Hungary and more widely into the SEE region from Central Europe.
Total net imports fell to 1,325 MW, down 687 MW day-on-day. Flows from key source markets such as Austria and Slovakia declined even more steeply, dropping to 2,765 MW—a reduction of 1,439 MW.
This reduction in external supply tightened liquidity across the region. With less imported power available to meet demand, domestic generation had to cover a larger share of load—pushing marginal prices up accordingly.
The change also showed up in cross-market spreads: the Hungary–Germany spread narrowed to around €10/MWh, down sharply from prior sessions. That smaller gap reduced arbitrage incentives that might otherwise have supported cheaper Western European flows into Southeast Europe.
Renewables fall back; gas becomes the balancing technology
On the supply side, weaker renewable output reshaped the generation stack. Wind output declined by 613 MW, while solar generation fell by 453 MW. Together, those moves removed more than 1.0 GW of low-cost supply.
The shortfall was largely offset by gas-fired generation increasing by 1,095 MW to 5,856 MW. In this session, gas became the dominant marginal source of electricity across the region.
Coal and hydro were broadly stable at 6,007 MW and 7,961 MW respectively**, while nuclear held steady at around 5,800 MW. The implication is that system flexibility is increasingly concentrated in gas assets when renewables weaken.
This pattern is consistent with recurring structural dynamics in SEE markets: when renewable output drops and imports decline simultaneously, gas rapidly becomes the price-setting technology, reinforcing upward pressure on prices.
Demand eases slightly but cannot offset supply tightness
Electricity consumption across SEE eased modestly to 35,377 MW (down 608 MW), helped by marginally warmer temperatures of around 9°C.
However, that demand softness was not enough to counterbalance the sharper contraction on the supply side. As a result, overall conditions remained tight—supporting higher day-ahead pricing.
The session highlights how sensitive these markets are to relatively small shifts in key inputs: <supply changes—particularly imports and renewables—can outweigh demand-side movements.
Northern-to-southern dependency remains visible in flow data
The direction of cross-border flows points to persistent imbalances between specific countries. Flow data shows that <Hungary and Serbia continue to rely on imports, recording average net import positions of -741 MW for Hungary and -724 MW for Serbia.
By contrast, Greece maintained a net export position of +772 MW, reflecting stronger thermal and renewable availability in the southern part of the region.
Taken together, these patterns reinforce ongoing dependence running from northwest toward southeast: constraints on inflows from Central Europe can tighten conditions across multiple SEE markets at once.
An elevated intraday curve signals limited surplus capacity—and upcoming policy-driven volatility risk for Serbia’s exchange
The hourly structure offered little relief during the day. Minimum prices stayed above €100/MWh, while peak levels exceeded €230/MWh .
A relatively flat but high intraday profile indicates a system that is structurally tight with limited surplus capacity. That reduces opportunities for arbitrage while supporting baseload-driven pricing behavior.
Market participants are also preparing for negative pricing on Serbia’s SEEPEX exchange from May, which is expected to increase intraday volatility and alter bidding strategies—particularly during periods when solar output is high.
Gas market easing meets firm carbon costs as fuel signals stay mixed
A look upstream shows mixed signals for thermal economics. At Austria’s CEGH hub, €55.3/MWh was reported after gas prices eased slightly. C oal benchmarks continued their gradual downward trend.
But EU carbon allowances remained firm: €70–80/t range. That level keeps pressure on thermal generation costs despite softer gas fundamentals.
The combination suggests clean spark spreads remain tight but supportive enough for continued gas dispatch—especially given weak renewable performance during this period.
The forward view points to possible easing if weather improves—but risks persist if wind or imports disappoint
The forward curve remains below current spot levels. April baseload trading hovered around €100–115/MWh, indicating expectations for some normalization ahead.
Weather forecasts point toward gradually rising temperatures toward 11–13°C. If realized, that could reduce demand while supporting higher solar generation — potentially easing prices into €135–150/MWh range.
