CBAM disrupts price convergence in Southeast Europe power markets as arbitrage weakens

The first quarter of 2026 is emerging as a structural turning point for Southeast Europe’s electricity markets. After more than a decade of uneven progress toward tighter alignment with the EU internal power market—most visibly through cross-border price convergence—the introduction of CBAM into its definitive phase on 1 January 2026 has coincided with a sharp deterioration in price correlations, wider and sustained spreads, and trading patterns that suggest early market fragmentation.

CBAM adds a non-market cost layer to cross-border imports

At the centre of the shift is a change in how cross-border electricity trade is priced. Electricity imports into the EU from non-member states are now subject to a carbon cost aligned with the EU Emissions Trading System (EU ETS). In theory, this creates a level playing field between EU and non-EU producers. In practice, it introduces a policy-driven cost component that disrupts the traditional arbitrage mechanics used to pull prices toward convergence.

The immediate impact shows up in day-ahead market outcomes. Average prices in major EU benchmark markets such as Hungary and Italy stayed anchored at €120–130/MWh in Q1 2026, broadly consistent with 2025 levels. By contrast, key WB6 markets fell: Serbia averaged €94.7/MWh, Montenegro €85.8/MWh, and North Macedonia €96.7/MWh. The resulting spread—above €30/MWh—is wider than historical norms and persisted across the quarter.

Correlation collapse points to impaired integration rather than one-off noise

To understand how abrupt the change is, it helps to look at 2025. Throughout that year, spreads between Hungary and the Western Balkans typically moved within a €5–15/MWh band, with correlation coefficients often exceeding 0.90—conditions consistent with an arbitrage mechanism that encouraged electricity flows from lower-priced zones to higher-priced ones until prices converged.

In Q1 2026, that mechanism weakened materially. Correlations collapsed sharply in January, with some relationships briefly approaching zero or turning negative. While partial recovery appeared later in the quarter, correlations remained below historical levels, indicating that underlying integration dynamics were impaired rather than temporarily distorted.

Hydrology helped push WB6 prices down—but CBAM explains why spreads endured

A key question for investors is whether decoupling is cyclical or structural. A straightforward explanation could point to unusually wet conditions during the quarter: hydro generation across the region rose by 33%, increasing from 16.7 TWh to 22.18 TWh and flooding WB6 markets with low-cost supply that pushed prices lower.

The effect was particularly pronounced in Albania, Serbia and Bosnia and Herzegovina; Greece also saw increased hydro output, which partially explains why its prices tracked closer to WB6 levels than core EU hubs did. Hydro-driven price suppression has occurred in previous wet years—what appears new is that wide spreads persisted despite available cross-border capacity and strong incentives to trade.

Under normal conditions, a €30–40/MWh spread between neighbouring markets would be expected to trigger substantial exports from lower-priced areas. Yet arbitrage flows were muted in Q1 2026 even though cross-border capacity allocation rates remained high—often above 95%—implying infrastructure availability was not the binding constraint.

Instead, economic factors dominated. CBAM-related costs—calculated using default emission factors and linked to EU ETS prices averaging €75.36/tCO₂—added an estimated €70–€86/MWh to electricity imports from coal-intensive WB6 systems. That additional charge effectively neutralised much of the price advantage created by cheaper generation in parts of the region.

Commercial segmentation emerges while physical interconnection remains

This produces a paradox for market participants: zones can remain physically connected through grid flows while becoming economically segmented through altered commercial incentives. Electricity continues to move according to grid constraints and physical realities, but trading decisions no longer align with regional price signals as they once did under integration assumptions.

The implications for price formation are significant. In an integrated setup, neighbouring zones typically reflect shared marginal costs adjusted for transmission constraints; in a fragmented environment, prices become increasingly localised around domestic supply conditions rather than regional equilibrium. In Q1 2026 specifically, WB6 pricing was driven primarily by hydro availability, while EU pricing remained tied more closely to gas-fired generation and carbon costs—an outcome reinforced by weakened arbitrage.

Forward markets and liquidity show participants adjusted expectations early

The bifurcation extends beyond spot pricing into forward contracting behavior. Forward markets depend on expectations of future convergence; when decoupling persists or becomes harder to hedge against arbitrage failure, contract pricing uncertainty rises for traders and utilities managing exposures or structuring power purchase agreements.

The article points to evidence that participants anticipated reduced arbitrage opportunities even before CBAM took full effect: forward capacity auction prices declined by 24–67% on key corridors. That adjustment supports the view that Q1’s divergence reflects more than short-term volatility—it also changed how market participants modelled future trading prospects.

Liquidity patterns across exchanges further illustrate the shift from transit- and arbitrage-driven activity toward generation-led dynamics. Total traded volumes in the Western Balkans increased by 11% year-on-year overall, but growth was uneven across venues: Albania’s ALPEX and Montenegro’s MEPX recorded substantial increases linked to hydro-driven supply conditions, while Serbia’s SEEPEX—which has historically played a role as a transit-based trading hub—fell by 11%.

Market coupling faces friction as policy design overrides price logic

The decoupling also raises questions about how far Southeast Europe can advance market coupling initiatives aimed at integrating neighbouring systems into a single electricity market for more efficient resource allocation and improved security of supply.

While CBAM is intended as a climate policy tool designed to prevent carbon leakage and support fair competition, its current design introduces frictions that run counter to integration goals by imposing uniform carbon costs on imports regardless of actual generation sources within exporting countries. The reliance on default emission factors creates blunt cost signals: hydro-dominated systems such as Albania face less relative penalty than coal-heavy systems do elsewhere in the region.

What comes next depends on hydrology, solar output and EU ETS dynamics

Looking ahead, whether decoupling persists will depend on several variables highlighted in the analysis. Hydrological conditions are expected to normalise during the second half of the year, which would reduce supply-driven advantages for parts of WB6 where hydro availability previously suppressed local prices. At the same time, increased solar generation during summer months may introduce new volatility patterns that could create surplus periods across both EU and non-EU markets.

The evolution of EU ETS prices will also matter directly because CBAM-linked import costs move with carbon market dynamics. Finally, regulatory clarity—particularly around how transit flows are treated and whether emission factor methodologies are refined—could influence how participants adapt their strategies under CBAM’s framework.

For investors, traders and system operators already operating through Q1’s evidence base, strategies may need recalibration: price signals cannot be assumed to converge automatically; arbitrage opportunities appear conditional on carbon-cost dynamics; and regulatory factors are increasingly shaping risk alongside traditional economic drivers like fuel costs and weather-dependent generation.