CBAM’s carbon cost pass-through is reshaping electricity price formation across Southeast Europe

The Carbon Border Adjustment Mechanism (CBAM), introduced at the start of 2026, is moving beyond trade policy and into the mechanics of how power prices form. Early evidence from Southeast Europe shows carbon cost pass-through is becoming a direct input to cross-border electricity economics—altering marginal pricing logic and raising new risks for market participants.

EU ETS linkage sets a carbon anchor for imports

At the centre of the shift is the connection between CBAM and the EU Emissions Trading System (EU ETS). In Q1 2026, the carbon benchmark applied to electricity imports was set as a quarterly weighted average of €75.36 per tonne of CO₂. That figure effectively anchors the cost of imported electricity to EU carbon market pricing and is translated into per-megawatt-hour charges for imports from non-EU systems.

For coal-heavy exporters in the Western Balkans, default emission factors produced CBAM costs in a range of €70 to €86/MWh. By contrast, low-carbon systems such as Albania faced no additional CBAM cost because they were assigned a zero emission factor.

A new variable enters marginal pricing

Electricity markets typically rely on marginal pricing: the price in a given market reflects the cost of the last unit needed to meet demand. Across much of the EU, that marginal unit is often gas-fired generation during periods of moderate demand. In parts of the Western Balkans, historical marginal pricing has been shaped by coal and hydro depending on seasonal conditions.

CBAM adds a fourth driver to this framework—carbon-adjusted import costs embedded at the border. As a result, marginal pricing in interconnected markets is no longer determined solely by neighbouring generation mixes; it increasingly reflects regulatory carbon charges attached to imports.

Price spreads can flip when CBAM charges are added

The impact is visible in Q1 2026 price differentials between markets. EU hubs such as Hungary and Italy held prices around €120–130/MWh, reflecting fuel costs alongside carbon costs embedded within EU ETS-linked pricing. Meanwhile, Western Balkan markets with strong hydro output recorded lower averages—Serbia at €94.7/MWh and Montenegro at €85.8/MWh.

Under traditional conditions, lower-cost systems would be expected to export electricity toward higher-priced EU markets, supporting convergence. But when CBAM charges of roughly €70–80/MWh are applied to those exports, the effective cost of imported electricity can rise above EU domestic levels—removing or reversing economic incentives to trade.

In practical terms, CBAM functions like a price floor for imported electricity: it limits how far imports can undercut EU domestic generation once carbon differentials are accounted for.

Default emission factors introduce approximation—and uncertainty

The pass-through mechanism does not operate uniformly because it depends on default emission factors assigned at country level. These factors act as proxies for carbon intensity but may not match actual generation patterns at the time electricity is exported. The mismatch can distort price signals by applying border costs that do not perfectly align with real-time emissions.

Market participants also face uncertainty because import costs move with EU ETS prices. In Q1 2026, carbon prices showed notable volatility—dropping sharply between mid-January and late March amid discussions about potential reforms—which feeds directly into electricity import economics.

Day-ahead bidding becomes more cautious

Because CBAM affects cross-border trades and certificate surrender timing lags behind trading decisions, it changes how bids are formed in day-ahead markets. Generators and traders must anticipate not only supply-demand balance and fuel costs but also how CBAM will affect export economics into the EU.

The result has been more cautious bidding strategies for exports into the EU. The uncertainty around final CBAM certificate costs—combined with timing differences between trading and surrender—adds an additional risk premium that shows up in bids.

Technology competitiveness shifts—and so does access

Within the EU, existing carbon pricing has already shifted merit order toward lower-emission sources such as renewables and nuclear while penalising coal and, to a lesser extent, gas. CBAM extends this logic across borders by exporting parts of that carbon price signal into neighbouring markets.

However, default emission factors can amplify advantages or penalties beyond what actual emissions would suggest. Systems assigned high default factors face significant cost penalties regardless of their current generation mix; low-carbon systems gain disproportionate benefits.

This contrast is illustrated by Albania versus Montenegro. Albania’s hydro-dominated system carries a zero emission factor, enabling exports without incurring CBAM charges. Montenegro’s substantial coal generation leads to CBAM costs estimated at about €73–74/MWh; despite favourable price spreads in Q1 2026, Montenegro’s exports declined while Albania increased exports—reflecting how carbon cost pass-through can become a determinant of market access rather than just an adjustment mechanism.

Implications for investors and contracting

For investors, integrating carbon cost pass-through into electricity pricing increases revenue uncertainty for projects reliant on cross-border exports from coal-heavy systems: competitiveness becomes more contingent on evolving carbon pricing dynamics. Conversely, low-carbon projects—particularly hydro and renewable generation—benefit from structural advantages when they can export without additional border charges.

The same complexity carries over into forward markets and long-term contracting. Power purchase agreements and hedging strategies must incorporate expectations about future relationships between different markets alongside projections for EU ETS prices and potential regulatory changes affecting emission factor methodologies.

What comes next: policy refinement could reduce distortions

At system level, embedding carbon costs into cross-border price formation supports decarbonisation goals but may create transitional inefficiencies by altering relative electricity prices across borders and influencing dispatch decisions through transmission capacity allocation. In some cases this could lead to suboptimal dispatch outcomes where higher-cost domestic generation is used instead of lower-cost imports due to carbon adjustments—even if such outcomes align with climate policy objectives.

Looking ahead, developments will depend heavily on EU ETS price trajectories: higher carbon prices would reinforce observed effects by increasing import costs further. Regulatory refinements to CBAM—especially around how emission factors are treated and whether actual generation characteristics are recognised—could mitigate distortions currently driven by country-level proxies.

The first quarter of 2026 shows that carbon cost pass-through has become central to electricity price formation rather than a peripheral consideration. By embedding EU ETS-linked costs directly into cross-border transactions, CBAM extends parts of EU climate policy beyond its borders and reshapes both trade economics and marginal pricing across Southeast Europe—a shift that market participants will need to navigate as the region moves deeper into the CBAM era.