Starting in 2026, the introduction of the Carbon Border Adjustment Mechanism (CBAM) will fundamentally reshape electricity trading in Southeast Europe (SEE), transitioning it from a straightforward spread-and-capacity approach to a more complex carbon-adjusted market. This shift signifies that power exported from the Western Balkans to the European Union will be evaluated not solely based on price per megawatt-hour (€ / MWh), but will also consider factors such as embedded CO₂ emissions, national carbon pricing, generation mix, and proof of low-carbon energy sources.
Initial indicators of this transformation are already apparent. According to monitoring conducted by the Energy Community, commercial electricity flows between the EU and the Western Balkans (WB6) contracted by approximately 25% year-on-year in Q1 2026. This trend suggests that traders are increasingly favoring routes that minimize exposure to CBAM-related challenges, indicating that this regulatory framework is exerting real influence on route selection and interconnector utilization.
The implications of CBAM are expected to create five significant structural trends for traders in the region. First, coal-heavy baseload exports will experience diminished flexibility. While thermal outputs from countries such as Serbia, Bosnia, Montenegro, and North Macedonia can still engage in regional trade, exports destined for the EU will incur a carbon discount. The previous model of exporting surplus lignite generation during higher-priced EU hours is becoming less viable due to carbon adjustments affecting profit margins. Serbia’s export economics face additional pressure as CBAM coincides with SEEPEX’s introduction of negative pricing starting May 5, 2026, allowing day-ahead prices to plummet to -€500/MWh and intraday prices down to -€9,999/MWh.
Second, renewable energy sources—specifically hydroelectric, wind, and solar—are gaining value beyond mere energy pricing. Low-carbon megawatt-hours are increasingly associated with compliance premiums when linked to industrial off-takers or EU buyers seeking cleaner supply chains. As a result, hydro-linked electricity flows from Albania and Greece have gained prominence in early 2026 while alternative trading corridors that circumvent CBAM friction have become more appealing.
Third, Power Purchase Agreements (PPAs) are evolving into critical instruments under CBAM regulations. For industries involved in steel production, aluminum manufacturing, fertilizers, cement production, and processing sectors, PPAs now serve not only as hedges against wholesale price volatility but also as documentable safeguards against carbon risk—provided they include robust metering and reliable emissions accounting. This trend enhances the financial viability of projects focused on wind energy, solar power, battery energy storage systems (BESS), and hybrid solutions throughout Serbia, Montenegro, Bosnia, and North Macedonia.
Fourth, domestic carbon pricing is emerging as an important variable within trading dynamics. Montenegro serves as a pertinent example; EPCG has projected that potential CBAM costs could reach approximately €191 million annually. Reports indicate that CBAM-related pressures may have already resulted in impacts around €13 million during Q1 2026. Montenegro’s vulnerability is particularly pronounced due to its significant reliance on electricity exports and its dependence on TE Pljevlja for generation capacity.
Lastly, the interplay between negative pricing and CBAM is accelerating the economics of flexibility within power markets. Negative prices penalize inflexible generation during oversupply periods while CBAM imposes costs on high-carbon exports directed toward the EU market. Together these factors elevate the significance of battery storage solutions, hydro flexibility options, demand response strategies, intraday optimization practices, and balancing services. Market participants are likely to derive greater financial benefits from strategic hourly positioning and management of congestion rather than relying solely on traditional baseload exports.
The overarching outcome indicates a transition toward a dual-price market structure in SEE electricity trading: one price reflecting visible wholesale rates while another accounts for embedded carbon values or penalties associated with each megawatt-hour sold. From 2026 onward, stakeholders—including traders, utilities, and financial institutions—that overlook this duality risk misjudging market spreads and may overestimate the viability of coal-based exports while undervaluing clean electricity’s bankability premium.
