The first quarter of 2026 delivered one of the most hydrologically favourable periods in Southeast Europe in recent years, and its impact on electricity markets was both immediate and profound. Across the Western Balkans and neighbouring European Union member states, hydroelectric output surged to levels that materially altered price formation, trade flows, and system dynamics. While this surge coincided with the introduction of the Carbon Border Adjustment Mechanism, the hydrological factor represents a distinct and powerful driver that must be isolated to properly understand the market behaviour observed in early 2026.
Regional hydro generation increased from 16.7 TWh in Q1 2025 to 22.18 TWh in Q1 2026, representing a rise of 5.48 TWh, or +33%. This expansion was broad-based, affecting nearly all observed markets. Greece contributed the largest absolute increase, adding +1.86 TWh, followed by Romania with +1.04 TWh, Bulgaria with +0.87 TWh, and Croatia with +0.36 TWh. Among the Western Balkans, Bosnia and Herzegovina added +0.64 TWh, Serbia +0.53 TWh, Montenegro +0.36 TWh, and North Macedonia +0.23 TWh. Albania, a hydro-dominated system, increased production by +1.34 TWh, a rise of approximately 70%, with particularly strong output concentrated in January and February.
This surge in hydro output effectively flooded regional markets with low marginal cost electricity. Hydropower, once installed, operates with near-zero fuel cost, meaning that in periods of abundant water inflow it becomes the dominant price-setting resource. As a result, day-ahead electricity prices in the Western Balkans fell significantly during Q1 2026. Serbia averaged €94.7/MWh, Montenegro €85.8/MWh, and North Macedonia €96.7/MWh, all well below neighbouring EU benchmarks, which remained clustered around €120–130/MWh.
Under typical market conditions, such a differential would lead to strong export flows from the Western Balkans to higher-priced EU markets. However, the interaction between hydro-driven price suppression and CBAM-related costs created a more complex outcome. While hydro reduced production costs and lowered prices, CBAM imposed additional costs on exports from carbon-intensive systems, limiting their ability to capitalise on these favourable conditions. The result was a market where low prices did not translate into proportionally higher exports, and where price spreads persisted despite the availability of surplus generation.
The role of hydro in shaping these dynamics extends beyond simple price suppression. It also alters the merit order within individual markets. Coal-fired generation, which typically provides baseload supply in several Western Balkan systems, was displaced by hydro during the quarter. Regional coal generation declined from 18.81 TWh to 15.79 TWh, a reduction of 3.02 TWh, or −16%. Serbia, the largest coal producer in the region, reduced output from 6.08 TWh to 5.47 TWh, while Bosnia and Herzegovina declined from 2.09 TWh to 1.62 TWh. North Macedonia recorded the sharpest relative reduction at −37%, reflecting both lower demand for thermal generation and the dominance of hydro in the dispatch order.
This displacement of coal has two important implications. First, it reduces the average carbon intensity of electricity production in the region, albeit temporarily. Second, it creates a disconnect between actual generation emissions and the default emission factors used under CBAM. While hydro generation may dominate in a given period, exporters from coal-heavy systems are still subject to carbon costs based on their structural emission profiles. This mismatch amplifies the distortion in price signals, as the cost applied to exports does not reflect the real-time composition of generation.
Hydro dominance also reshapes cross-border flow patterns. Albania provides a clear example of this effect. With a zero default emission factor and a significant increase in hydro output, Albania became a major exporter during Q1 2026. Scheduled exports increased across all its borders, including flows to Greece, Kosovo, and Montenegro. The net effect was a swing of approximately 1.2 TWh in Albania’s trade position compared to the same period in 2025. This surplus was then redistributed across the region, often moving through Greece into EU markets such as Bulgaria and Italy.
Greece itself experienced a substantial increase in hydro production, rising from 0.67 TWh to 2.53 TWh, a gain of +275%. This contributed to lower prices in the Greek market, which averaged €94.6/MWh, closely aligning with Western Balkan price levels. The convergence between Greece and WB6 markets stands in contrast to the divergence observed with other EU markets, highlighting the role of hydro in shaping regional price clusters.
However, the influence of hydro is not uniform across all markets. Italy, despite being the largest hydro producer in absolute terms at 6.03 TWh, recorded a decline in output of −0.42 TWh compared to Q1 2025. As a result, Italian prices remained elevated, driven primarily by gas-fired generation. This divergence between hydro-rich and gas-dependent systems contributed to the widening of price spreads across the region.
The temporal distribution of hydro output also played a role in market dynamics. The strongest generation occurred in January and February, leading to an initial sharp drop in prices in the Western Balkans. As the quarter progressed and hydrological conditions began to normalise, prices recovered somewhat, contributing to a partial restoration of price correlations. However, the overall spread remained wide, suggesting that while hydro influenced the magnitude of price divergence, it was not the sole driver of the structural decoupling observed.
From a system perspective, the surge in hydro generation introduced both opportunities and challenges. On the one hand, increased low-cost supply enhanced security of supply and reduced reliance on fossil fuels. On the other hand, the sudden influx of generation created congestion risks on key transmission corridors, particularly along the south-north axis from Greece through Albania and Montenegro to Bosnia and Herzegovina. These corridors, already critical to regional flows, experienced increased loading as surplus hydro was transmitted towards EU markets.
The interaction between hydro-driven physical flows and CBAM-affected commercial flows further complicated system operation. In several instances, increased scheduled exports did not correspond to proportional increases in physical flows, as electricity followed the path of least electrical resistance rather than the commercially designated route. This divergence between scheduled and actual flows reduces predictability for transmission system operators and increases the risk of unscheduled loop flows, which can strain network stability.
From a market perspective, hydro dominance also influenced liquidity patterns across power exchanges. Exchanges in hydro-rich systems saw increased trading activity, reflecting the availability of surplus generation and the need to allocate it efficiently. Albania’s ALPEX, for example, experienced a significant increase in traded volumes, while Montenegro’s MEPX also recorded strong growth. By contrast, markets more dependent on transit trading, such as Serbia’s SEEPEX, saw reduced activity, as CBAM dampened the attractiveness of cross-border arbitrage.
The temporary nature of hydro-driven dynamics is a critical consideration. Hydrological conditions are inherently variable, and the exceptional levels observed in Q1 2026 are unlikely to persist throughout the year. In the second half of the year, when water inflows typically decline, the Western Balkans often shift from net exporters to net importers of electricity. This seasonal reversal will interact with CBAM in different ways, potentially altering the balance of trade and the direction of price convergence.
At the same time, the increasing penetration of solar generation across the region introduces a new layer of complexity. Spring and summer months are expected to see rising solar output, which could partially offset the decline in hydro generation and create new periods of surplus supply. The interaction between solar, hydro, and CBAM-adjusted trade flows will be a key determinant of market behaviour in the coming quarters.
For investors, the hydro-driven market conditions of Q1 2026 highlight both opportunities and risks. On the positive side, low marginal cost generation can enhance profitability during periods of high output, particularly for systems with favourable emission profiles. On the risk side, reliance on hydrology introduces variability in revenue streams, as output and prices are highly sensitive to weather conditions. The addition of CBAM further complicates this picture, as it affects the ability to export surplus generation and monetise it in higher-priced markets.
The broader implication is that hydro dominance, while beneficial in the short term, does not provide a stable foundation for long-term market integration. The distortion observed in Q1 2026 is the result of an exceptional alignment of factors: high water inflows, low marginal costs, and the introduction of a new carbon pricing mechanism. As these conditions evolve, the market will need to adjust to a new equilibrium where hydro remains important but is no longer the dominant force shaping prices and flows.
In this context, Q1 2026 can be seen as both an outlier and a preview. It is an outlier in terms of hydrological conditions, but a preview of how CBAM interacts with supply-side shocks to produce complex and sometimes counterintuitive market outcomes. The challenge for market participants is to disentangle these effects, identifying which dynamics are temporary and which represent lasting structural changes.
What is already evident is that hydro, long considered a stabilising force in Southeast European electricity markets, can also act as a source of volatility when combined with new regulatory frameworks. Its ability to depress prices, alter trade flows, and reshape system dynamics is amplified under CBAM conditions, creating a market environment that is both more dynamic and more uncertain. As the region moves into subsequent quarters, the interplay between hydrology, carbon pricing, and market integration will remain a defining feature of its evolving electricity landscape.
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