Montenegro’s electricity connection with Italy provides renewable developers access to a major EU market, while CBAM costs can affect whether cross-border sales generate margins. Developers are expected to review contractual structures and supporting evidence before treating Italian offtake agreements as dependable export revenue. The undersea interconnector enables physical access, but the commercial value increasingly depends on how imported electricity is treated under CBAM.
In a first-quarter 2026 illustration, the Energy Community Secretariat reported an average electricity price spread of about €43/MWh between Montenegro and southern Italy. In the same comparison, an indicative CBAM carbon cost was calculated at €73.78/MWh using the relevant reference price and Montenegro’s applicable default emissions factor at the time. The indicative carbon cost exceeded the reported wholesale price spread in that example.
The figures relate to the reporting period and assumptions used in the comparison. They are not presented as a forecast for every future trading hour. The comparison also does not establish actual emissions for any individual generating installation.
Carbon costs versus day-ahead price spreads
The reported example shows that relying only on day-ahead market arbitrage may not be sufficient to produce export margins when CBAM-related costs are higher than the wholesale spread. The comparison is limited to the stated period and does not quantify outcomes for each future trading interval. It also does not determine whether specific installations meet any emissions eligibility conditions.
For EPCG and independent Montenegrin hydropower, wind and solar developers, eligibility can depend on whether electricity is treated using default emissions or supported by actual emissions data. A low-carbon installation could have an advantage over the national default emissions factor if it satisfies applicable requirements. Securing that treatment requires documentation linking the generating plant, contractual arrangements, electricity deliveries and the importing entity.
Evidence chain for default versus actual-emissions treatment
The evidence described includes a qualifying power purchase agreement (PPA) that involves the correct EU declarant. It also requires plant-specific emissions and metering records, applicable physical-network evidence, firm hourly nominations and independent verification. A direct physical PPA with the Italian importing entity is described as a straightforward contractual starting point.
A regional trader could provide dispatch and balancing services separately, according to the described contracting options. Where an intermediary must participate in the commodity agreement, parties may consider a qualifying single tripartite contract. Developers are advised to obtain legal advice before assuming that sequential resales through a Balkan trading company and an Italian counterparty will preserve eligibility for actual-emissions treatment.
CGES–Terna interface and delivery documentation
The operational chain runs through the CGES–Terna transmission interface. Export schedules need reconciliation with the generating installation’s dispatch records and with documentation from the Italian importer’s side. Developers also need to verify whether physical-network conditions along the transmission route are satisfied.
The existence of the undersea cable alone is not presented as proof that all applicable criteria are met. Metering at a substation is also described as insufficient by itself to establish final imported quantity and attribution to a particular PPA. The evidence must connect plant output with nominated and delivered volumes claimed under the relevant contractual arrangement.
Portfolio qualification challenges from Montenegro’s generation mix
Montenegro’s electricity mix adds complexity for exporters marketing power from a broader portfolio. Hydropower output varies with rainfall and reservoir conditions, while thermal generation and electricity purchases also affect the national balance. As a result, a month with high hydropower generation does not automatically qualify an unspecified EPCG portfolio sale as electricity from a particular low-carbon installation.
Supporting records must identify individual plants and allocate eligible volumes without double counting. This distinction becomes relevant when suppliers combine generation from multiple sources or use market purchases to meet contractual delivery obligations. Volumes eligible for actual-emissions treatment must be supported by required plant-specific evidence.
Financing scenarios for wind and solar exports
For wind and solar developers, potential carbon benefits from an Italian export PPA can influence investment decisions and financing assumptions. The anticipated benefit may be reduced if intermediary contracts, hourly nominations or documentation procedures cannot substantiate projected eligible electricity volumes.
Lenders are described as assessing three cases: a domestic merchant-sales scenario, an ordinary Italian electricity-import scenario incorporating applicable carbon costs, and a verified actual-emissions scenario. Each case can lead to different revenue margins as well as different collateral requirements and operating costs.
Status of proposed EU changes as of October 2026
Proposed EU reforms could eventually facilitate qualifying electricity trade by changing elements of electricity methodology and intermediary treatment. However, as of October 2026, those proposals have not become law. Until rule changes occur, documented volumes linked to specific generating plants are described as the most defensible basis for Montenegrin renewable exports.
The commercial value of the Montenegro–Italy interconnector depends not only on market prices and physical transmission access. It also depends on whether individual transactions meet contractual, operational and verification requirements tied to claimed CBAM treatment.