Hydrology drives a regional price reset
The first quarter of 2026 brought one of the most hydrologically favourable periods in Southeast Europe in recent years, with immediate effects on how electricity was priced and traded across the Western Balkans and neighbouring EU markets. Hydroelectric output rose sharply enough to change day-ahead price formation, compressing spreads against adjacent EU benchmarks. Although the Carbon Border Adjustment Mechanism was introduced during the same period, the hydrological shift acted as a separate and dominant operational driver that market participants had to account for in real time.
Regional hydro generation climbed from 16.7 TWh in Q1 2025 to 22.18 TWh in Q1 2026, an increase of 5.48 TWh or +33%. The expansion was broad-based across observed markets, led by Greece with an additional +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.
Low marginal cost supply meets carbon-cost friction
With abundant inflows, hydropower’s near-zero fuel cost pushed it into the dominant price-setting role, flooding markets with low marginal cost electricity. Day-ahead prices in the Western Balkans fell significantly during Q1 2026, with Serbia averaging €94.7/MWh, Montenegro €85.8/MWh and North Macedonia €96.7/MWh. These levels sat well below neighbouring EU benchmarks clustered around €120–130/MWh.
In a conventional setting, such a gap would typically support stronger export flows from the Western Balkans into higher-priced EU markets. Instead, the interaction between hydro-driven price suppression and CBAM-related export costs produced a more complex outcome: low prices did not translate into proportionally higher exports. Price spreads persisted despite surplus generation availability, reflecting how carbon-cost mechanisms can dampen commercial arbitrage even when physical supply is plentiful.
Merit order shifts displace coal generation
Hydro’s influence extended beyond price suppression by reshaping merit order within individual systems during the quarter. Coal-fired generation—often providing baseload supply across several Western Balkan markets—was displaced by hydro output throughout Q1 2026. Regional coal generation declined from 18.81 TWh to 15.79 TWh, a drop of 3.02 TWh or −16%.
Serbia reduced coal output from 6.08 TWh to 5.47 TWh, while Bosnia and Herzegovina fell from 2.09 TWh to 1.62 TWh. North Macedonia recorded the sharpest relative reduction at −37%, consistent with both weaker thermal dispatch needs and hydro’s stronger position in the dispatch order.
This displacement carried two implications for market design and carbon accounting signals. It temporarily reduced average carbon intensity of regional electricity production, but it also created a disconnect between actual generation emissions and the default emission factors applied under CBAM rules for exports from coal-heavy structural profiles.
Cross-border flows change as Albania becomes an exporter
Hydro dominance also altered cross-border flow patterns, with Albania illustrating the effect most clearly during Q1 2026. With a zero default emission factor and a significant rise in hydro output, Albania became a major exporter over the quarter rather than remaining primarily import-dependent or transit-oriented under typical assumptions.
Scheduled exports increased across all its borders, including flows to Greece, Kosovo and Montenegro. Compared with the same period in 2025, Albania’s trade position swung by approximately 1.2 TWh, and that surplus was redistributed across the region—often moving through Greece into EU markets such as Bulgaria and Italy.
Price convergence with Greece contrasts with Italy’s divergence
Greece itself saw a substantial increase in hydro production from 0.67 TWh to 2.53 TWh, a gain of +275%. That additional low-cost supply contributed to lower Greek market prices, which averaged €94.6/MWh—closely aligning with Western Balkan price levels during Q1 2026.
The convergence between Greece and WB6 markets contrasted with divergence observed elsewhere in the EU footprint. Italy remained elevated despite being the largest hydro producer in absolute terms at 6.03 TWh because output declined by −0.42 TWh versus Q1 2025; Italian prices were driven primarily by gas-fired generation instead of hydro-led dispatch.
Seasonality risk: January-February strength fades as inflows normalize
The timing of hydro output mattered for how quickly prices moved and how correlations behaved across the quarter. The strongest generation occurred in January and February, triggering an initial sharp drop in Western Balkan prices before partial recovery as hydrological conditions began to normalize later in Q1.
Even after that recovery phase, overall spreads remained wide, indicating that while hydro influenced the magnitude of divergence it was not the only factor behind structural decoupling under CBAM conditions. For developers and operators planning dispatch strategies or commercial hedges tied to seasonal patterns, this highlights how quickly market regimes can shift when inflows move off peak levels.
Grid modernization relevance: congestion risk rises on south-north corridors
From a system perspective, higher hydro output improved security of supply and reduced reliance on fossil fuels during Q1 2026, but it also introduced new operational constraints linked to network loading. The sudden influx of generation created congestion risks on key transmission corridors—particularly along a south-north axis running from Greece through Albania and Montenegro to Bosnia and Herzegovina.
These corridors were already critical for regional power movements; during Q1 they experienced increased loading as surplus hydro was transmitted toward EU markets. For transmission system operators preparing grid reinforcement studies or operational constraints updates, this combination of surplus injection patterns and cross-border transfer needs can materially affect curtailment risk assumptions used in planning models.
Scheduled vs physical flows diverge under commercial distortions
The operational challenge was compounded where physical flows driven by network physics did not match commercially designated schedules shaped by CBAM-related incentives and costs. In multiple instances during Q1 2026, increased scheduled exports did not correspond to proportional increases in physical flows because electricity followed paths of least electrical resistance rather than contract routes.
This divergence reduces predictability for transmission system operators and increases exposure to unscheduled loop flows that can strain network stability margins. For engineering teams supporting grid studies—such as power flow analysis updates or remedial action scheme reviews—these outcomes underscore why schedule-based expectations may need validation against actual flow behaviour during periods of extreme hydrological conditions.
Market liquidity signals point to where trading activity concentrates
Hydro dominance also influenced liquidity patterns across power exchanges by changing where surplus supply needed allocation through trading platforms. Exchanges in hydro-rich systems saw increased activity as participants sought efficient mechanisms for distributing available generation within constrained regional dynamics.
Albania’s ALPEX experienced a significant increase in traded volumes while Montenegro’s MEPX also recorded strong growth during Q1 2026. By contrast, transit-trading oriented activity such as Serbia’s SEEPEX saw reduced activity as CBAM dampened cross-border arbitrage attractiveness even when price differentials appeared favourable on paper.
BESS planning takeaway: volatility management becomes more important than ever
The temporary nature of hydro-driven dynamics is central for investment planning because hydrological conditions are inherently variable and exceptional levels observed in Q1 are unlikely to persist throughout the year. In the second half of 2026—when water inflows typically decline—the Western Balkans often shift from net exporters to net importers of electricity, changing both trade balances and price convergence directions under CBAM effects.
At the same time, rising solar penetration across the region adds another layer that can partially offset declining hydro output during spring and summer months by creating new surplus windows or altering timing of system imbalances. For battery energy storage developers preparing feasibility studies or EPC preparation workstreams tied to flexibility services, these interacting seasonal drivers strengthen the case for robust revenue stacking assumptions that do not rely solely on stable hydro availability.
Industry implications: project readiness must reflect policy-linked market distortions
For investors evaluating renewable integration strategies alongside grid modernization roadmaps, Q1 2026 demonstrates both opportunity and risk under carbon-cost frameworks that affect export monetisation even when low-cost generation is abundant locally. Low marginal cost supply can support profitability where emission profiles align favourably with market rules; however hydrology-driven variability makes output—and therefore revenue—highly weather sensitive.
The broader takeaway is that hydro dominance delivered short-term benefits but did not create a stable foundation for long-term market integration because CBAM interacted with supply-side shocks to produce counterintuitive outcomes: persistent spreads despite surplus availability and schedule-versus-physical-flow mismatches that raise operational uncertainty on constrained corridors.