Hydro surge in Q1 2026 distorted Southeast Europe power prices—and complicated CBAM-driven exports

Hydropower’s seasonal swing has long been a stabilising force in Southeast Europe’s electricity markets. In Q1 2026, however, an unusually favourable hydrological period did more than lower prices—it also interacted with the Carbon Border Adjustment Mechanism (CBAM) in ways that blurred the usual link between cheaper power and export earnings.

Hydro output jumped across the Western Balkans

Regional hydro generation rose from 16.7 TWh in Q1 2025 to 22.18 TWh in Q1 2026, an increase of 5.48 TWh (+33%). The expansion was broad-based, affecting nearly all observed markets. Greece recorded the largest absolute gain at +1.86 TWh, followed by Romania (+1.04 TWh), Bulgaria (+0.87 TWh) and Croatia (+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—already described as hydro-dominated—increased production by +1.34 TWh, roughly +70%, with particularly strong output concentrated in January and February.

Low marginal cost supply pulled day-ahead prices below EU levels

The surge effectively flooded regional markets with low marginal cost electricity. Because hydropower has near-zero fuel cost once installed, abundant water inflows make it the dominant price-setting resource during such periods.

As a result, day-ahead electricity prices fell significantly across the Western Balkans during Q1 2026: Serbia averaged €94.7/MWh, Montenegro €85.8/MWh and North Macedonia €96.7/MWh—well below neighbouring EU benchmarks clustered around €120–130/MWh.

CBAM costs prevented a straightforward export response

Under typical conditions, such a price differential would be expected to support stronger export flows from the Western Balkans into higher-priced EU markets. In Q1 2026, though, CBAM-related costs on exports from carbon-intensive systems complicated the outcome.

The report describes a market where hydro reduced production costs and lowered prices domestically, but CBAM imposed additional costs on exports tied to carbon-intensive profiles—limiting exporters’ ability to monetise surplus generation at EU price levels. The result was persistent price spreads despite available surplus supply.

Coal was displaced—temporarily lowering carbon intensity while raising CBAM mismatches

Hydro dominance also reshaped merit order within individual markets by displacing coal-fired generation that typically provides baseload supply in several systems across the region.

Regional coal generation declined from 18.81 TWh to 15.79 TWh (down 3.02 TWh or −16%). Serbia reduced output from 6.08 TWh to 5.47 TWh; Bosnia and Herzegovina fell 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 hydro’s dispatch advantage.

The displacement had two implications highlighted by the report: it reduced average carbon intensity temporarily, but it also created a disconnect between real-time generation emissions and CBAM default emission factors used for exports. Even when hydro dominates production during a given period, exporters from coal-heavy systems remain subject to carbon costs based on structural emission profiles—amplifying distortions in price signals because applied costs do not reflect actual quarter-by-quarter generation composition.

Trade patterns shifted as Albania became a major exporter

The report points to Albania as an example of how hydro can alter cross-border flow patterns beyond simple domestic price effects. With a zero default emission factor and a significant increase in hydro output, Albania became a major exporter during Q1 2026.

Scheduled exports rose across all its borders—including flows to Greece, Kosovo and Montenegro—and translated into an estimated swing of about 1.2 TWh in Albania’s trade position versus the same period in 2025. That surplus was then redistributed across the region, often moving through Greece into EU markets such as Bulgaria and Italy.

Greece converged with Western Balkan pricing; Italy diverged on gas

Greece’s own hydro production increased from 0.67 TWh to 2.53 TWh (+275%), contributing to lower Greek market prices that averaged €94.6/MWh—closely aligning with Western Balkan levels.

Elsewhere, hydro influence was not uniform enough to erase regional differences. Italy produced less hydro than a year earlier: despite being the largest hydro producer at 6.03 TWh, output fell by −0.42 TWh compared with Q1 2025. Italian prices stayed elevated, driven primarily by gas-fired generation—helping widen price spreads between hydro-rich and gas-dependent systems.

A seasonal surge created volatility—and raised operational risks

The timing of inflows mattered as well: strongest hydro generation occurred in January and February, producing an initial sharp drop in Western Balkan prices before partial recovery later in the quarter as conditions normalised somewhat.

From a system standpoint, increased low-cost supply improved security of supply and reduced reliance on fossil fuels—but also introduced congestion risks on key transmission corridors along a south-north axis from Greece through Albania and Montenegro toward Bosnia and Herzegovina as surplus power moved toward EU markets.

The interaction between physical flows shaped by grid constraints and commercial flows affected by CBAM further complicated operations: scheduled exports did not always match proportional physical flows because electricity followed electrical pathways rather than designated commercial routes. The report notes that this divergence can reduce predictability for transmission system operators and increase risks related to unscheduled loop flows that may strain network stability.

Liquidity rose where surplus was available; transit trading cooled

Hydro dominance also influenced liquidity patterns across power exchanges. Trading activity increased in hydro-rich systems where surplus needed allocation: Albania’s ALPEX saw higher traded volumes while Montenegro’s MEPX recorded strong growth.

By contrast, markets more dependent on transit trading—such as Serbia’s SEEPEX—saw reduced activity because CBAM dampened incentives for cross-border arbitrage under those conditions.

A temporary outlier with longer-term lessons for investors

The report stresses that these dynamics are inherently temporary because hydrological conditions vary year to year; exceptional levels seen in Q1 2026 are unlikely to persist throughout the year.

In the second half of the year, when water inflows typically decline, Western Balkans systems often shift from net exporters to net importers of electricity—a seasonal reversal that will interact with CBAM differently and potentially change both trade balances and where price convergence occurs.

Additionally, rising solar penetration is expected to introduce another layer of variability: spring and summer months should bring higher solar output that could partially offset falling hydro generation and create new periods of surplus supply alongside CBAM-adjusted trade flows.

Why it matters now

For investors and market participants, Q1 2026 illustrates both opportunity and risk under changing policy settings: low marginal cost generation can support profitability when output is high—especially for systems with favourable emission profiles—but revenue streams remain highly sensitive to weather-driven hydrology volatility. CBAM further complicates monetisation by affecting export economics even when quarterly generation is dominated by low-carbon sources.

The broader takeaway is that while hydropower can stabilise Southeast European power markets over time, its ability to depress prices, reshape trade flows and alter system dynamics becomes more volatile when paired with new regulatory frameworks like CBAM—and when supply-side shocks coincide with exceptional weather patterns like those seen early this year.