As Montenegro approaches the first quarter of 2026, it finds itself in a precarious position within the evolving electricity market of Southeast Europe. The implementation of the Carbon Border Adjustment Mechanism (CBAM) presents a dual challenge for Montenegro, which benefits from strong hydroelectric generation but faces constraints due to carbon-adjusted trade economics that diminish export value. This situation highlights a disconnect between the country’s physical energy potential and its commercial viability, particularly regarding the strategic importance of the interconnector with Italy.
Entering Q1 2026, Montenegro’s electricity generation mix is somewhat diversified but still heavily influenced by thermal energy sources. The Pljevlja coal power plant remains a key component of baseload supply, even as hydroelectric production surged significantly. Hydropower generation rose from 0.45 TWh to 0.81 TWh, marking a 79% increase, one of the highest in the region. This influx of low-cost hydroelectric power contributed to lowering average day-ahead prices to €85.8/MWh, well below EU benchmarks, which hovered between €120–130/MWh.
Under normal circumstances, such favorable pricing conditions would create an attractive environment for electricity exports, particularly given that the price differential between Montenegro and Southern Italy reached approximately €43/MWh. Traditionally, this price spread would incentivize robust export activity through the submarine high-voltage direct current (HVDC) interconnector linking Montenegro to Italy, which was designed to capitalize on these arbitrage opportunities.
However, contrary to expectations, scheduled exports from Montenegro to Italy decreased by over 2,100 MWh per day, with actual physical flows dropping by around 1,400 MWh per day compared to Q1 2025. The primary reason for this decline is tied directly to CBAM regulations. Montenegro’s default emission factor of 0.979 tCO₂/MWh incurs a carbon adjustment cost of about €73.8/MWh, effectively neutralizing the economic rationale for cross-border trade by absorbing the entire price spread.
This shift in economic dynamics has significant implications for Montenegro’s position in the electricity market. Originally intended as a conduit for exporting electricity to premium EU markets, the Italy interconnector now faces a conditional valuation based on carbon-adjusted economics rather than simple price differentials. In Q1 2026, this resulted in a paradox where a corridor with strong price signals experienced reduced commercial flows.
The repricing of interconnector value is evident in capacity markets as well. Despite widening day-ahead price spreads, auction clearing prices for capacity on the Montenegro–Italy interconnection remained stable at around €7–8/MWh, consistent with 2025 figures. In an ideal arbitraged market, capacity prices would typically rise alongside spreads; however, their stagnation suggests market participants foresee limited realizable value under current CBAM costs.
Domestically, while the impact of CBAM is less direct, it remains significant. Regional hydrological conditions continue to influence Montenegro’s electricity pricing. The increased hydro output during Q1 2026 suppressed domestic prices and drove trading activity on the Montenegrin exchange (MEPX), where trading volumes increased by 49% year-on-year as surplus generation needed allocation amid diminished export opportunities to the EU.
This inward focus on trading does present challenges; intra-regional markets in the Western Balkans generally offer lower prices and less liquidity compared to EU markets. Although Montenegro can enhance trade with neighboring countries such as Serbia, Bosnia and Herzegovina, and Albania, the revenue potential remains limited. Consequently, this results in compressed overall market value despite periods of strong generation output.
The divergence between scheduled commercial exchanges and actual physical flows further complicates matters. Montenegro serves as a critical node in the transmission corridor connecting Greece and Albania to the broader European grid. Increased hydro generation in these countries during Q1 2026 led to higher physical flows through Montenegro, even as commercial schedules shifted away from routes exposed to CBAM regulations.
This operational complexity arises from transmission system operators needing to manage flows that do not align with commercial schedules, increasing congestion risks and necessitating balancing interventions. Given its relatively small grid size yet strategic importance, these challenges could result in heightened operational complexities and potential cost increases for Montenegro.
The interplay between hydro and thermal generation within Montenegro’s system also warrants attention. While hydroelectric output dominated in Q1 2026, reliance on coal ensures that exports are priced according to a higher default emission factor under CBAM. This creates a mismatch between actual generation conditions and carbon costs applied to exports, diminishing competitiveness even when hydro power constitutes most output.
This structural issue underscores a broader limitation within CBAM: its dependence on default emission factors rather than real-time data reflecting generation emissions. For Montenegro, short-term improvements in carbon intensity do not yield immediate economic benefits in cross-border trade under these rules. Although there is an incentive for increased low-carbon generation, recognition of such changes may be delayed within market mechanisms.
Investment signals emerging from Q1 2026 present mixed prospects. On one hand, robust hydro performance coupled with no CBAM costs for low-carbon output enhances the appeal of renewable investments. Montenegro’s existing hydro resources and potential for expansion position it favorably within a carbon-constrained framework. Conversely, limited access to high-value EU markets under CBAM diminishes revenue prospects for new projects.
The future economics surrounding investments will largely hinge on developments in carbon pricing and regulatory frameworks. Should CBAM continue relying on default emission factors without adjustments recognizing actual emissions from generation sources, coal-dependent systems will remain disadvantaged while interconnectors like that with Italy will see constrained value creation.
The necessity for system flexibility and storage solutions grows more pressing as regional hydro outputs fluctuate and solar capacity expands. To address increasing variability in generation patterns effectively, investments in battery storage and grid modernization will be essential for enhancing operational efficiency and market positioning—albeit requiring stable revenue frameworks complicated by ongoing uncertainties surrounding CBAM.
In summary, Montenegro’s electricity market appears set to evolve along two parallel paths: domestically and regionally integrated operations driven by hydrological factors versus adaptation strategies required for engagement with EU markets under new carbon exposure conditions. The Italy interconnector will continue playing a strategic role but will require justification based on carbon-adjusted economics rather than merely prevailing price differentials.
