The first quarter of 2026 witnessed a significant increase in hydroelectric generation across Southeast Europe, fundamentally altering the dynamics of power markets in the region. This surge, characterized by a rise from 16.7 TWh in Q1 2025 to 22.18 TWh in Q1 2026—a notable increase of 5.48 TWh or 33%—was driven by favorable hydrological conditions that coincided with the implementation of the Carbon Border Adjustment Mechanism (CBAM). The interplay between these factors created a unique environment affecting price formation, trade flows, and overall market behavior.
Greece led the increase with an additional 1.86 TWh, followed closely by Romania (+1.04 TWh), Bulgaria (+0.87 TWh), and Croatia (+0.36 TWh). Within the Western Balkans, Bosnia and Herzegovina contributed +0.64 TWh, Serbia +0.53 TWh, Montenegro +0.36 TWh, and North Macedonia +0.23 TWh. Notably, Albania’s hydro-dominated system saw a remarkable rise of approximately 70%, adding +1.34 TWh, particularly strong during January and February.
This influx of low-cost hydroelectric power led to a dramatic reduction in day-ahead electricity prices across the Western Balkans. Serbia’s average price fell to €94.7/MWh, while Montenegro and North Macedonia recorded averages of €85.8/MWh and €96.7/MWh respectively—significantly lower than EU benchmarks that remained around €120–130/MWh.
Typically, such price differentials would encourage robust export activity from the Western Balkans to higher-priced EU markets. However, the combined effects of hydro-induced price suppression and CBAM-related costs complicated this scenario. While lower production costs from hydro generation reduced prices, CBAM imposed additional financial burdens on exports from carbon-intensive systems, limiting their ability to capitalize on these favorable pricing conditions.
The dominance of hydro generation also disrupted traditional merit order dispatching within regional markets. Coal-fired generation saw a decline from 18.81 TWh to 15.79 TWh—down by 3.02 TWh or 16%. Serbia’s output decreased from 6.08 TWh to 5.47 TWh, while Bosnia and Herzegovina’s production fell from 2.09 TWh to 1.62 TWh. North Macedonia experienced the most significant relative decrease at -37%, indicating both reduced demand for thermal generation and the prevailing influence of hydro resources.
This shift away from coal generation has two notable implications: it temporarily lowers the average carbon intensity of electricity production in the region and creates discrepancies between actual emissions from generation sources and default emission factors applied under CBAM regulations. Consequently, while hydropower may dominate during certain periods, exporters reliant on coal are still subject to carbon costs that do not accurately reflect real-time generation profiles.
Albania exemplifies how hydro dominance can reshape cross-border trading patterns; with its zero default emission factor and increased hydro output, it emerged as a significant exporter during Q1 2026. Scheduled exports surged across borders to Greece, Kosovo, and Montenegro, resulting in an approximate net trade position swing of 1.2 TWh compared to the same period in 2025.
Greece itself saw its hydro production increase dramatically from 0.67 TWh to 2.53 TWh (+275%), contributing to lower market prices averaging €94.6/MWh—aligning closely with Western Balkan levels but diverging from other EU markets where prices remained elevated due to reliance on gas-fired generation.
The temporal distribution of hydro output also influenced market dynamics; peak generation occurred early in the quarter leading to initial price drops that later stabilized as hydrological conditions normalized towards March. Nevertheless, persistent price spreads indicated that hydro was not the sole factor driving structural decoupling within the market.
From an operational standpoint, the surge in hydro generation presented both opportunities for enhanced supply security and challenges related to congestion risks on critical transmission corridors stretching northward from Greece through Albania to Bosnia and Herzegovina as surplus power was transmitted toward EU markets.
The interaction between physical flows driven by hydro generation and commercial flows impacted by CBAM further complicated system operations; instances arose where scheduled exports did not align with actual physical flows due to electricity following paths of least resistance rather than designated commercial routes—creating unpredictability for transmission operators.
Market liquidity trends reflected these shifts; exchanges in hydro-rich areas like Albania’s ALPEX experienced heightened trading volumes alongside Montenegro’s MEPX, while Serbia’s SEEPEX saw reduced activity as CBAM dampened cross-border arbitrage opportunities.
Looking ahead, the temporary nature of these hydrological advantages must be acknowledged; seasonal variations suggest that by mid-2026, the Western Balkans may transition from net exporters to net importers as water inflows decline, potentially reshaping trade balances once more.
Moreover, increasing solar penetration across the region adds another layer of complexity; anticipated rises in solar output during spring and summer could help mitigate declines in hydro generation and create new surplus periods—making interactions between solar energy, hydro resources, and CBAM-adjusted trade flows pivotal for future market behavior.
The developments observed in Q1 2026 highlight both opportunities and challenges inherent in reliance on hydropower within Southeast Europe’s evolving electricity landscape—emphasizing that while short-term benefits exist under favorable conditions, long-term stability will require adaptation as market dynamics shift over time.
