The first quarter of 2026 marked a significant shift in the electricity landscape of Southeast Europe, driven by an exceptional surge in hydroelectric generation. This period was characterized by one of the most hydrologically favorable conditions in recent years, leading to a substantial increase in power output across the region. The rise in hydro generation significantly impacted price dynamics, trade flows, and overall system operations within the Western Balkans and neighboring EU member states.
Hydro generation escalated from 16.7 TWh in Q1 2025 to 22.18 TWh in Q1 2026, reflecting an impressive increase of 5.48 TWh, or +33%. Greece emerged as the largest contributor with an additional +1.86 TWh, followed closely by Romania at +1.04 TWh, Bulgaria at +0.87 TWh, and Croatia with +0.36 TWh. In the Western Balkans, Bosnia and Herzegovina added +0.64 TWh, Serbia contributed +0.53 TWh, while Montenegro and North Macedonia saw increases of +0.36 TWh and +0.23 TWh, respectively. Notably, Albania, heavily reliant on hydropower, increased its production by +1.34 TWh, marking a rise of approximately 70%.
This influx of low-cost hydroelectricity flooded regional markets, resulting in significantly lower day-ahead electricity prices across the Western Balkans. Serbia’s average price dropped to €94.7/MWh, while Montenegro averaged €85.8/MWh, and North Macedonia recorded prices around €96.7/MWh. These figures contrasted sharply with EU benchmarks clustered between €120–130/MWh.
The expected outcome of such price differentials would typically be increased export flows from the Western Balkans to higher-priced EU markets; however, this scenario was complicated by the introduction of the Carbon Border Adjustment Mechanism (CBAM). While hydro output lowered production costs and prices, CBAM imposed additional expenses on exports from carbon-intensive systems, hindering their ability to benefit from favorable market conditions.
The dominance of hydroelectric power also altered traditional merit order dispatching within local markets, displacing coal-fired generation which usually constitutes baseload supply. Regional coal output fell from 18.81 TWh to 15.79 TWh, a reduction of 3.02 TWh, or −16%. Serbia’s coal production decreased from 6.08 TWh to 5.47 TWh, while Bosnia and Herzegovina’s output declined from 2.09 TWh to 1.62 TWh. North Macedonia experienced a dramatic relative reduction of −37%.
This transition away from coal has implications for carbon intensity levels across the region; however, it also creates discrepancies between actual emissions and those calculated under CBAM regulations based on structural profiles rather than real-time generation composition.
The surge in hydro also reshaped cross-border electricity flows significantly, with Albania becoming a notable exporter during this quarter due to its zero default emission factor coupled with increased hydro output. Scheduled exports surged across all borders including Greece, Kosovo, and Montenegro, resulting in an approximate net swing of 1.2 TWh compared to Q1 2025.
The increase in Greek hydro production—from 0.67 TWh to 2.53 TWh, representing a gain of +275%—contributed to lower prices averaging €94.6/MWh. This convergence between Greece and Western Balkan market prices contrasts with divergence seen against other EU markets.
Divergence was particularly pronounced in Italy where despite being the largest hydro producer at 6.03 TWh, output fell by -0.42 TWh, resulting in elevated prices primarily driven by gas-fired generation.
The distribution pattern of hydro output throughout the quarter influenced market dynamics as well; January and February saw peak generation leading to initial price drops that later stabilized as hydrological conditions normalized but did not fully restore price correlations across markets.
This sudden increase in hydro generation created both opportunities for enhanced supply security while simultaneously posing challenges such as congestion risks on key transmission corridors—particularly along routes from Greece through Albania and Montenegro towards Bosnia and Herzegovina—as surplus electricity was transmitted towards EU markets.
The interaction between physical electricity flows driven by hydropower and commercial flows affected by CBAM further complicated system operations, leading to discrepancies between scheduled exports and actual physical flows which can challenge transmission system stability.
The temporary nature of these hydrological benefits must be acknowledged; typically variable conditions mean that such high levels are unlikely to persist throughout the year as seasonal shifts often turn net exporters into net importers during lower inflow periods later in the year.
The increasing integration of solar power into regional energy portfolios adds another layer of complexity as rising solar output during spring and summer months could counterbalance declines in hydroelectric production while creating new surplus scenarios that influence market behavior moving forward.
The developments observed during Q1 2026 underscore both opportunities for low-cost generation amid favorable weather conditions alongside risks tied to reliance on variable hydrology and regulatory frameworks like CBAM that complicate export strategies based on market dynamics.
This period serves as both an outlier indicative of extreme hydrological conditions while also previewing how regulatory frameworks interact with supply-side shocks leading to complex market outcomes requiring careful navigation by stakeholders across Southeast Europe’s evolving electricity landscape.
