The Energy Community Secretariat’s first quarterly assessment of the EU Carbon Border Adjustment Mechanism (CBAM) for electricity imports delivers one of the clearest early warnings yet that the mechanism is already reshaping electricity trading dynamics across Southeast Europe. The report argues that CBAM has begun creating measurable structural divergence between EU and non-EU electricity markets, altering arbitrage economics, weakening market coupling, and potentially undermining renewable investment signals in parts of the Western Balkans.
The report covers the six Western Balkan Energy Community Contracting Parties — Albania, Bosnia and Herzegovina, Kosovo, Montenegro, North Macedonia and Serbia — alongside neighbouring EU markets including Hungary, Croatia, Bulgaria, Romania, Greece and Italy.
What makes the document strategically important is that it moves beyond regulatory theory and provides the first operational evidence of how CBAM is beginning to affect actual power flows, market spreads, interconnector usage, system operation and regional price formation after the definitive CBAM phase for electricity started on 1 January 2026.
The most significant finding is the sudden breakdown of the long-standing price convergence mechanism between the Western Balkans and neighbouring EU electricity markets. Historically, Southeast European electricity markets moved in relatively synchronized patterns, particularly around the Hungarian benchmark. During Q1 2026, however, that convergence weakened sharply. The report notes that day-ahead price spreads between WB6 markets and neighbouring EU zones widened to more than €30/MWh, approximately two to three times higher than in the same period of 2025.
This divergence emerged despite exceptionally strong hydro generation across the region, which should ordinarily have intensified exports from lower-cost Western Balkan systems into higher-priced EU markets. Instead, CBAM-related costs appear to have neutralized much of that arbitrage opportunity. The report repeatedly highlights that electricity imports from non-EU systems became economically less attractive once CBAM certificate costs were included, even when physical electricity remained significantly cheaper than inside the EU.
The market implications are profound for Serbia and Montenegro in particular.
Serbia’s average default CBAM emission factor was calculated at 1.041 tCO2eq/MWh, producing an estimated CBAM cost of €78.45/MWh for electricity imported into the EU during Q1 2026. Montenegro’s default factor reached 0.979 tCO2eq/MWh, equivalent to approximately €73.78/MWh. Bosnia and Herzegovina faced the highest burden at €86.51/MWh. Albania, by contrast, retained a zero default emission factor, effectively exempting Albanian hydro exports from CBAM charges.
This differential immediately began reshaping regional competitiveness.
The report identifies Albania as structurally advantaged under CBAM because its hydro-dominated generation mix allows exports into EU markets without additional carbon charges. Montenegro, despite also benefiting from strong hydro output during Q1, remained commercially disadvantaged because the country-level default emission factor still reflected the presence of coal-fired generation within the national system.
The Montenegro–Italy submarine cable became the clearest illustration of this distortion.
The Italy South bidding zone recorded average Q1 2026 prices above €130/MWh, while Montenegro averaged only €85.8/MWh, creating the largest regional spread at approximately €43/MWh. Under normal market conditions, such a spread would have triggered strong export growth from Montenegro into Italy. Instead, scheduled flows from Montenegro to Italy declined by more than 2,100 MWh/day, while physical flows also dropped materially.
The Energy Community Secretariat explicitly concludes that the most plausible explanation is that CBAM charges absorbed most or all of the available arbitrage margin. The report notes that auction-clearing prices for cross-border capacity on the Montenegro–Italy interconnector remained almost unchanged compared with 2025 despite the huge increase in market spread, indicating traders did not view the price differential as commercially usable after CBAM costs were included.
This is arguably the first real-world evidence that CBAM is directly altering the commercial value of major Southeast European transmission infrastructure.
Serbia experienced similar dynamics.
SEEPEX, the region’s largest power exchange, recorded an 11% decline in traded volumes during Q1 2026 even as several neighbouring exchanges expanded. The report links this decline partly to Serbia’s previous importance as a transit trading corridor between EU markets. Before CBAM implementation, routes such as Hungary–Serbia–Bulgaria were commercially attractive for regional electricity trading. Following CBAM introduction, those transit strategies became less economically viable due to regulatory uncertainty and the financial implications of electricity crossing non-EU territory.
The result has been a partial rerouting of Southeast European electricity trading away from Western Balkan transit corridors and toward “CBAM-free” pathways.
The report repeatedly references the emergence of new trading structures bypassing Serbia and other WB6 markets. Intra-WB6 trading increased, while some EU-EU corridors and Albania-linked routes gained strategic importance. Exports from Albania into Greece surged, while Greece itself increasingly acted as a redistribution hub toward Bulgaria and Italy.
This has potentially major implications for future grid investment and regional market integration.
One of the report’s strongest conclusions is that CBAM may unintentionally increase fragmentation between EU and non-EU electricity systems. If sustained, the mechanism could create two parallel regional realities: low-carbon exporters such as Albania benefiting from privileged access to EU markets, while coal-exposed systems such as Serbia, Montenegro and Bosnia face structurally weaker export economics regardless of actual hourly renewable production.
For renewable developers and investors, this changes the bankability equation.
The report explicitly warns that uniform default emission factors risk weakening incentives for renewable investment in carbon-intensive jurisdictions because exported renewable electricity may still inherit national-level emission penalties. This directly intersects with ongoing debates around guarantees of origin, hourly matching, PPA structuring and physical traceability of low-carbon electricity exports from the Western Balkans into the EU.
From an investment perspective, the implications extend well beyond short-term electricity trading.
If default national emission factors continue dominating electricity CBAM treatment, developers in Serbia, Montenegro and Bosnia may increasingly require additional contractual structures to preserve export competitiveness. This could accelerate demand for physically traceable renewable PPAs, hourly matched electricity sourcing frameworks, dedicated industrial offtake structures and pre-verification systems capable of demonstrating lower embedded carbon intensity than national averages.
The report also raises concerns around operational system stability.
Commercial schedules and physical electricity flows increasingly diverged during Q1 2026. While traders reduced commercial usage of certain WB6 transit corridors, physical electricity continued flowing according to network physics rather than commercial schedules.
This matters because transmission system operators depend on commercially scheduled flows for balancing and congestion management. The report warns that the widening mismatch between commercial and physical flows could create additional operational stress for regional TSOs and potentially increase system costs and network tariffs.
The Secretariat specifically highlights the South-North corridor running from Greece through Albania and Montenegro toward Bosnia and Croatia as strategically sensitive. The document references the June 2024 regional blackout triggered by simultaneous outages of 400 kV lines in Montenegro and Albania as an example of how heavily loaded and insufficiently coordinated systems can become vulnerable under stressed operational conditions.
Hydrology was undeniably a major factor during Q1 2026.
Regional hydro generation increased by 33% year-on-year, rising from 16.70 TWh to 22.18 TWh. Albania alone expanded hydro output by roughly 70%, while Greece recorded a dramatic 275% increase compared with the low 2025 base. Coal generation simultaneously fell by approximately 16% across the region.
The report carefully avoids attributing all observed changes solely to CBAM, repeatedly emphasizing that Q1 hydrological conditions were exceptional and that longer observation periods are required before drawing definitive structural conclusions.
Nevertheless, the market signals are increasingly difficult to ignore.
The Secretariat’s core message is that CBAM is already beginning to reshape Southeast European electricity economics, even before many longer-term compliance structures and carbon alignment mechanisms have fully developed. The mechanism is no longer merely a future regulatory concept for the region’s power sector. It is now actively influencing price spreads, transmission economics, market liquidity, route selection, renewable competitiveness and system operation across Southeast Europe.
For Serbia, Montenegro and the wider Western Balkans, the strategic question is no longer whether CBAM will affect regional electricity markets, but whether regional power systems, TSOs, exchanges, traders, industrial exporters and renewable developers can adapt quickly enough to prevent long-term fragmentation from becoming structurally embedded into Southeast Europe’s electricity architecture.