As the Carbon Border Adjustment Mechanism takes effect at the start of 2026, developers and grid planners across Southeast Europe are confronting a new driver of cross-border electricity economics: carbon cost pass-through embedded into import transactions. Early signals from Q1 2026 show that electricity price formation is no longer governed only by fuel costs, hydrology, and demand cycles. Instead, carbon-linked charges are increasingly influencing the marginal logic that determines which resources set prices in interconnected markets.
EU ETS-linked benchmark sets the carbon layer for imports
The CBAM framework is tied to the EU Emissions Trading System through a quarterly carbon benchmark for electricity imports. In Q1 2026, that benchmark was set at a weighted average of €75.36 per tonne of CO₂, anchoring the carbon component of imported power to EU ETS levels. The mechanism then converts this benchmark into per-megawatt-hour costs applied to imports from non-EU systems.
For coal-heavy exporters in the Western Balkans, default emission factors translated into CBAM costs between €70 and €86/MWh. By contrast, low-carbon systems such as Albania faced no additional charge because a zero emission factor was applied. For market participants preparing trading strategies or underwriting revenue assumptions, this creates an immediate distinction between systems based on regulatory proxies rather than real-time generation mix.
Marginal pricing shifts from generation mix to border-adjusted costs
In conventional marginal pricing models, the electricity price reflects the marginal generator required to meet demand at a given time. In much of the EU, that marginal unit is often gas-fired during periods of moderate demand. In parts of the Western Balkans, marginal pricing has historically been shaped by coal and hydro depending on seasonal conditions.
CBAM adds a border-based cost dimension that changes what “marginal” effectively means for cross-border transactions. The marginal cost of imported electricity becomes linked not only to the exporting system’s generation mix but also to the carbon-adjusted cost imposed at the border. As a result, CBAM operates as a price floor for imports relative to EU domestic generation when carbon differentials are considered.
Price spreads narrow as carbon charges can erase trade incentives
Q1 2026 illustrates how carbon pass-through can overwhelm otherwise favorable market spreads between neighboring systems. EU markets including Hungary and Italy held prices in the €120–130/MWh range, reflecting gas prices combined with embedded EU ETS costs. Meanwhile, Western Balkan markets benefited from strong hydro output, with Serbia averaging €94.7/MWh and Montenegro averaging €85.8/MWh.
Under pre-CBAM conditions, lower-cost hydro-heavy systems would typically export toward higher-priced EU areas and support convergence. However, when CBAM costs of €70–80/MWh are added to exports from these regions, the effective cost of imported electricity often rises above EU domestic price levels. That removes the economic incentive to trade even when underlying generation costs appear competitive.
Default emission factors introduce distortions and operational uncertainty
The carbon pass-through is not uniform because it depends on default emission factors assigned at country level. These factors act as proxies for the carbon intensity of exported electricity and may not match actual generation at the time of export. A mixed portfolio that includes both hydro and coal can still attract a high default factor, pushing CBAM costs above what emissions would suggest for specific dispatch conditions.
This mismatch affects how price signals function in practice by decoupling border charges from real-time production costs. It also introduces uncertainty because changes in EU ETS prices flow directly into import costs under CBAM rules. In Q1 2026, carbon prices showed notable volatility, falling sharply between mid-January and end-March amid discussions on potential reforms—an input that can quickly propagate into electricity pricing outcomes.
Implications for day-ahead bidding and forward contracting risk
Carbon-linked charges are also affecting bidding behavior in day-ahead markets where generators and traders must anticipate more than supply-demand balance and fuel costs. They now need to account for how CBAM will influence cross-border trades into EU pricing zones. 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 decisions and certificate surrender—adds a risk premium reflected in bids. For forward markets and long-term contracting, power purchase agreements and hedging strategies must incorporate expectations for future price dynamics that include projected EU ETS levels and potential changes in emission factor methodologies. This increases complexity in contract structuring and risk management for utilities and trading counterparties.
Technology competitiveness diverges; Albania vs Montenegro highlights access effects
Beyond market-level pricing impacts, CBAM reshapes relative competitiveness across generation technologies by extending EU-style carbon incentives to imports. Within the EU merit order, carbon pricing has already favored lower-emission sources such as renewables and nuclear while penalizing coal and, to a lesser extent, gas. Through CBAM, that logic is carried into neighboring markets via import charges.
The use of default emission factors amplifies these effects by rewarding low-carbon systems disproportionately while penalizing high-factor systems regardless of their current dispatch mix. Albania’s hydro-dominated system is assigned a zero emission factor, enabling exports without incurring CBAM costs. Montenegro faces CBAM costs of approximately €73–74/MWh due to its coal share; in Q1 2026 this contributed to divergent outcomes where Albania increased exports while Montenegro saw exports decline despite favorable price spreads.
Broader project planning impacts: grid flows, dispatch choices, and investment signals
At system level, embedding carbon costs into cross-border price formation supports decarbonisation objectives but can also produce transitional inefficiencies. By changing relative electricity prices across borders, CBAM influences how generation is allocated and how transmission capacity is utilized between interconnected areas. In some cases it may lead to dispatch outcomes where higher-cost domestic generation is used instead of lower-cost imports once carbon adjustments are applied.
For investors planning renewable buildouts such as wind and solar projects alongside battery energy storage systems (BESS), these dynamics affect revenue certainty for assets whose value depends on export opportunities or participation in cross-border markets. Coal-heavy export-dependent projects face increased revenue uncertainty tied to carbon pricing dynamics, while low-carbon hydro or renewable projects gain structural advantages when exports avoid additional charges.
Looking ahead, developments will hinge on the trajectory of EU ETS prices because higher carbon levels increase import costs and reinforce Q1 2026 effects. Regulatory refinements to CBAM—particularly around treatment of emission factors and recognition of actual generation characteristics—could reduce current distortions driven by proxy assumptions. If carbon pricing mechanisms emerge within the Western Balkans, they could reduce asymmetry between EU and non-EU markets by aligning price signals more closely.
Overall, Q1 2026 demonstrates that carbon cost pass-through has become a central determinant of electricity price formation across Southeast Europe rather than a peripheral compliance variable. For developers coordinating wind and solar pipelines with grid modernization plans—along with BESS deployment strategies—these findings underline how cross-border transmission utilization and market access can shift when regulatory cost layers change marginal pricing behavior.