SEE power markets daily: Core prices ease while the southern Balkans tighten on April 15

Electricity trading on 15 April 2026 underscored how quickly South East Europe can diverge from broader European price trends. While most coupled “core” markets saw softer day-ahead levels, several less tightly connected areas in the southern Balkans recorded sharp increases, reflecting a mix of localized supply constraints, shifting renewable output and heightened cross-border flows that periodically decouple peripheral pricing.

Day-ahead prices: easing in core hubs, spikes in the southern Balkans

Across most coupled markets, prices softened. Hungary’s HUPX settled at 140.67 €/MWh (down 3.5 €/MWh), while Romania’s OPCOM fell to 134.98 €/MWh (down 4.8 €/MWh). Bulgaria’s IBEX dropped to 125.42 €/MWh, Greece’s HENEX to 125.87 €/MWh, Slovenia’s BSP to 128.85 €/MWh and Croatia’s CROPEX to 130.03 €/MWh.

Germany’s benchmark price was lower at 117.53 €/MWh, whereas Italy stayed comparatively elevated at 140.19 €/MWh—evidence of persistent price gradients across the continent.

By contrast, the southern and less tightly coupled markets posted notable gains. Serbia’s SEEPEX rose to 132.99 €/MWh, North Macedonia’s MEMO increased to 127.22 €/MWh, Montenegro’s BELEN reached 122.16 €/MWh and Albania’s ALPEX climbed to 146.50 €/MWh, the highest level in the region on the day.

Demand and generation: higher consumption met by thermal flexibility

Fundamental conditions pointed to a tightening regional balance. Electricity consumption increased to 30,837 MW—up 758 MW versus the previous day—while total generation reached 29,662 MW. The system relied on higher thermal output and increased imports to manage variability from renewables.

Net imports rose sharply to 1,534 MW (up 1,116 MW day on day), with core imports reaching 2,782 MW, reinforcing dependence on cross-border electricity flows during periods of constrained local balance.

Thermal generation played a decisive role in balancing supply and demand: gas-fired output climbed to 4,103 MW (up 992 MW) and coal-fired generation rose to 4,590 MW (up 398 MW). Nuclear production remained stable at 5,839 MW and hydro provided significant flexibility at 7,193 MW.

The overall generation mix reflected a thermally supported system: hydro accounted for about 26% of output, nuclear for 21%, coal for 16%, gas for 15%, solar for 14% and wind for 7%.

Renewables and weather: weaker solar support helped lift prices locally

Renewable output was mixed but tilted against price softness in parts of the region. Solar generation declined to 3,956 MW (down 162 MW), while wind production stood at 2,061 MW with only marginal growth.

Forecasts also indicated weaker solar and wind generation across parts of SEE and Hungary. Temperatures ranged between about 13°C and 16°C—slightly above seasonal norms—supporting moderate demand levels; however, warming conditions combined with variable renewable output contributed to intraday volatility.

Cross-border flows: congestion risk sustained market segmentation

Interconnection dynamics continued to shape price formation. The SEE region maintained strong import activity from Central Europe into Hungary and neighboring markets supplied by Austria and Slovakia. Elevated spreads alongside congestion risks contributed to market segmentation—particularly in the southern Balkans where liquidity is comparatively limited.

Commercial flow data over the past week showed persistent cross-border exchanges among Bulgaria, Romania, Hungary, Serbia and Greece. The pattern highlighted how interconnectivity remains central both for system stability and for efforts toward price convergence across borders.

Forward markets: fuel costs eased slightly while carbon stayed firm

Despite day-ahead volatility, forward indicators pointed to relative stability. At the Central European Gas Hub (Austrian gas), prices were quoted at 46.12 €/MWh (down by 3.2 €/MWh). EU Emissions Allowances traded at 74.87 €/t (up by 2.3 €/t).

Hungarian power forwards showed moderate movement: Week 17 was priced at 104.50 €/MWh; Week 18 at 92.50 €/MWh; May 2026 at 93.00 €/MWh; and Calendar Year 2026 at 108.50 €/MWh—levels that suggested expectations of gradual normalization supported by improving renewable generation alongside stable fuel costs.

The coal and gas forward curves trended slightly lower as well, reinforcing a bearish medium-term cost outlook for thermal generation costs even as carbon prices remained resilient—continuing to influence marginal fossil-based electricity production across Europe.

Intraday picture: synchronized evening peaks reinforced the value of flexibility

Hourly curves showed pronounced evening peaks across major exchanges as solar output declined while demand stayed elevated through peak hours. On Hungary’s HUPX market, prices reached a daily maximum of 275.1 €/MWh—signaling evening tightness—and pointing again to the importance of flexibility assets such as gas-fired plants and energy storage.

A similar pattern appeared across Romania, Slovenia and Greece, indicating synchronized peak-demand dynamics within interconnected European markets.

What it means for investors watching SEE power

The session highlighted three recurring themes for South East Europe power pricing: first, structural price divergence driven by varying levels of market coupling and infrastructure capacity; second, continued reliance on thermal generation as a balancing mechanism amid fluctuating renewables; and third, the role of cross-border interconnections in supporting both system stability and price convergence when capacity allows.

Looking ahead from this trading day profile, improved weather conditions alongside higher renewable output could place downward pressure on prices; however geopolitical uncertainty and fuel-market risks could keep volatility elevated. As Europe accelerates its energy transition, SEE markets are likely to remain especially sensitive to interconnection constraints, shifts in generation mix and changes in regional demand patterns.