Montenegro’s electricity link with Italy provides access to the European Union’s power market, but renewable energy investors must account for cross-border trading costs, congestion and carbon pricing when forecasting export revenues.
The 600-MW high-voltage direct-current (HVDC) interconnector, which has operated since 2019, connects Montenegro’s transmission system directly to Italy through a 445-km cable. The infrastructure supports regional electricity trading, provides access to an EU market and forms part of the wider Trans-Balkan corridor.
For renewable energy developers, however, physical access to Italy does not automatically translate into higher electricity prices or guaranteed additional revenue. The commercial value of the connection depends on cross-border capacity costs, congestion, market price differences and the treatment of carbon emissions.
This was illustrated in the first quarter of 2026, when Energy Community analysis recorded an average day-ahead electricity price spread of approximately EUR 43/MWh between Montenegro and southern Italy. Montenegro’s default emissions factor for electricity under the EU Carbon Border Adjustment Mechanism (CBAM), meanwhile, implied a theoretical carbon cost of around EUR 73.78/MWh at the prevailing EU Emissions Trading System (EU ETS) price.
The implied carbon surcharge exceeded the market price difference, weakening the economics of an export arbitrage strategy that might otherwise have appeared attractive.
Renewable project developers therefore need to assess the interconnector’s contribution to revenues using detailed cross-border market assumptions rather than simply applying Italian electricity prices to their financial models. Relevant considerations include cross-border capacity allocation, congestion charges, transmission losses, scheduling arrangements, market coupling, CBAM treatment and the documentation required to apply actual emissions data instead of a national default factor.
Emissions verification and export revenues
For projects seeking to demonstrate that their electricity has a low carbon intensity, metering and contractual arrangements are becoming important components of revenue assessments.
Generation records, supervisory control and data acquisition (SCADA) systems, settlement metering, accepted electricity schedules and the contractual chain connecting a generator to an EU importer may determine whether a renewable megawatt-hour qualifies for the intended emissions treatment. These requirements involve technical verification and electricity market arrangements, rather than relying solely on a project’s designation as renewable or low-carbon.
Regional trading and financial scenarios
Montenegro’s electricity market position also extends beyond the Italian connection. The country is linked to Serbia, Bosnia and Herzegovina and Albania, meaning electricity flows are influenced by regional hydrological conditions, thermal generation availability, renewable output and price differences between markets. Depending on market conditions, a project may derive greater revenue from balancing services or regional electricity trading than from a strategy focused exclusively on exports to Italy.
Lenders assessing renewable projects should therefore use scenario-based financial models. The base case should reflect existing cross-border arrangements and conservative assumptions for capacity costs.
An upside scenario can incorporate stronger market coupling, improved carbon treatment and future infrastructure developments. Downside cases should account for narrower Italian price spreads, higher congestion costs, electricity curtailment and less favourable CBAM assumptions. Montenegro’s 600-MW interconnector with Italy remains a major energy asset, but its contribution to renewable project revenues depends on market conditions, transmission costs and the regulatory treatment of exported electricity.
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