Serbian independent electricity producers could gain long-term buyers and higher revenue by exporting through Montenegro to Italy. The route uses existing interconnections, but its value for project financing depends on dependable transmission access, delivery-risk allocation and the Carbon Border Adjustment Mechanism (CBAM) treatment of each shipment. An analysis by Virtu.Energy examines whether producers can turn access to Italy into predictable net revenue.
In the second quarter of 2026, average day-ahead electricity prices were €120.9/MWh in Italy’s Centro Sud zone, against €96.3/MWh in Serbia and €93.6/MWh in Montenegro. The resulting Italy–Serbia difference was €24.6/MWh before transmission charges, balancing, losses and carbon-related costs. That historical spread is a starting point for assessing exports, not the amount a producer would retain.
For a wind, solar or hydropower project, the value available from Italy depends on its generating hours, when transmission can be secured and the terms of its power purchase agreement (PPA). Lenders need to establish whether the project has a dependable net price and a counterparty able to bear delivery risks. Access to a higher-priced market alone does not resolve either question.
Existing links and planned grid reinforcement
The operating Montenegro–Italy submarine electricity connection has 600 MW of capacity and has been commercially operational since December 2019. About 200 MW is assigned to private investors under a third-party-access exemption associated with Monita Interconnector. The full 600 MW therefore cannot be treated as continuously available in public capacity auctions.
The private-capacity component may be relevant to Italian industrial buyers that have access to the associated transmission rights. A Serbian independent power producer (IPP) seeking to supply such a buyer would need to confirm the rights’ permitted use, remaining term and actual availability under contract. Those checks are separate from assessing the capacity offered through public auctions.
Montenegro’s 400 kV Lastva–Pljevlja line entered trial operation in July 2026, reinforcing the connection between the country’s north and the coastal transmission system leading towards Italy. In Serbia, the next stages of the Trans-Balkan Electricity Corridor include the Obrenovac–Bajina Bašta reinforcement, an investment estimated at about €113.5 million and expected to be completed during 2028. A subsequent section from the Bajina Bašta area towards Višegrad and Pljevlja is planned for 2029.
These works should strengthen Serbia’s connection towards Montenegro and the wider regional corridor, although more network capacity does not automatically produce an equivalent increase in commercially available export capacity. A project starting operations before the reinforcements are complete must be financed against the capacity available now. A planned second Montenegro–Italy high-voltage direct current (HVDC) pole could eventually raise total connection capacity to 1,200 MW, but its delivery timetable remains uncertain, making that additional capacity an upside scenario rather than guaranteed infrastructure for near-term investment models.
Separate border rights create delivery exposure
In 2026, both the Serbia–Montenegro and Montenegro–Italy borders use yearly, monthly and daily explicit capacity allocation. A common allocation framework eases administration, but each border remains a separate commercial position. An exporter must align the electricity purchase with two capacity positions and the nominations needed to complete delivery.
Securing Serbia–Montenegro capacity does not ensure matching capacity from Montenegro to Italy. If a Serbian plant generates more than the narrower border position can carry, the surplus needs another buyer or trading arrangement. This also creates a mismatch between financing for a renewable project and the shorter-term transmission products underpinning exports under a PPA that may last a decade or longer.
Long-term physical transmission rights offer greater visibility without eliminating curtailment or renewal risk. Even when transmission compensation is available, it may not cover the commercial cost of buying replacement electricity in Italy for a firm-delivery contract. On 3 October 2026, 400 MW of Montenegro-to-Italy long-term transmission rights were curtailed to zero for six hours because of operational security limitations associated with the HVDC connection.
For an IPP, the effect of such an interruption depends on the contract. Its terms determine whether delivery is excused, replacement electricity must be obtained or the obligation falls to an offtaker or trading-service provider. The two-border route therefore requires a clear allocation of risks before revenues can be treated as predictable.
Existing contracts determine exportable output
Merchant projects, uncontracted generation and renewable plants nearing the end of existing PPAs are the clearest candidates for Italian sales. Installed capacity does not, by itself, establish how much electricity an IPP can offer. Existing agreements may specify the buyer, delivery point, contracted volume and ownership of renewable attributes for years ahead.
This is especially relevant to projects supported by Serbia’s renewable auction framework. Their long-term arrangements may be tied to domestic supply and EPS, so committed output cannot simply be assigned to a second long-term Italian PPA. Each project needs a review of its contracts before any export capacity is marketed.
International traders have already entered long-term agreements with Serbian renewable generators. The 105 MW Krivača wind farm signed a 10-year PPA with Axpo, demonstrating a bankable contractual relationship between a Serbian IPP and an international electricity trader. A producer considering the route through Montenegro must first identify precisely which output remains available for a new agreement.
CBAM treatment depends on a documented physical chain
Electricity produced in Serbia retains Serbian origin for CBAM purposes when it passes through Montenegro on its way to Italy. Transit does not change where the power was generated, and the emissions treatment of Serbian electricity may materially affect the sale’s economics. For wind, solar and other low-carbon plants, the opportunity is to demonstrate emissions from a named installation rather than rely on a broader country-level default.
Renewable generation on its own does not satisfy that requirement. The current CBAM framework calls for a qualifying physical PPA and evidence connecting the named generator with electricity imported into the European Union (EU). That evidence must cover the generating installation, contractual relationship, transmission and nominated delivery route, and hourly production.
It must also address metering and SCADA evidence, accepted physical schedules, the relevant importer or authorised CBAM declarant, and independent verification. For a Serbian generator supplying Italy through Montenegro, the chain may involve EMS, CGES and Terna alongside the producer, trader, importer and verifier. A capacity-auction award establishes transmission rights but does not, on its own, show that the delivered electricity came from the named renewable plant.
The current electricity methodology also gives substantial weight to the contractual links among the producer, any intermediary and the EU-side buyer or declarant. A structure with one bilateral IPP–trader contract and a separate trader–EU buyer resale contract may require legal and verification scrutiny if the importer plans to claim the producer’s actual emissions. Transaction design therefore matters before the PPA is signed.
The EU importer, authorised CBAM declarant, electricity buyer and trading-service provider must each be clearly identified. Reporting must connect the claimed quantity to a particular importing party and delivery period. Guarantees of origin can support the electricity’s renewable attribute, but they do not replace the physical PPA, nomination, network and verification evidence required for CBAM electricity actuals.
The resulting risk extends beyond whether the power reaches Italy. An importer could receive the electricity but lack sufficient evidence to apply the expected actual-emissions treatment. The PPA needs to allocate that risk explicitly.
Net value depends on generation hours and delivery costs
The €24.6/MWh historical Italy–Serbia day-ahead price difference is not an IPP’s additional profit. An export model must begin with the Italian price obtained in the producer’s actual generating hours. It must then account for the alternative value of a Serbian sale, charges on both the Serbia–Montenegro and Montenegro–Italy borders, balancing costs and network losses.
Further deductions include forecasting and scheduling services, trading fees, collateral and credit-support costs, and any CBAM-related carbon exposure assigned to the seller. Wind generation may be concentrated in hours when the Italy–Serbia spread differs substantially from an annual or quarterly average. Solar output is concentrated during daylight hours, when growing regional solar production can put pressure on wholesale prices.
Flexible hydropower may be better able to target higher-value delivery periods, subject to hydrological conditions and operating constraints. Storage could reshape renewable output, reduce imbalance exposure and shift delivery towards higher-value hours. Where charging and discharge occur in different periods, however, incorporating storage into a CBAM actual-emissions evidence chain requires careful treatment.
A modest retained spread can still have a material effect on project finances. At 200 GWh of exports a year, an additional net value of €5/MWh after transmission and trading costs would produce about €1 million in extra annual revenue. That amount can matter for debt-service coverage and equity returns, but it is bankable only when the relevant volume and pricing mechanism are predictable under contract.
Contract structures assign trading risks differently
One approach is for the IPP to sell at a Serbian delivery point to an international trader. The trader would manage cross-border capacity, nominations, balancing and subsequent sales into Italy. The producer could negotiate a minimum price and potentially share in additional value from the Italian market.
For many standalone renewable projects, that structure can be the most bankable because it places complex trading risks with a counterparty that has an established portfolio and balance sheet. A second option is a direct physical PPA with an Italian or EU industrial buyer, with a trader or balancing responsible party handling transmission and scheduling. This gives the producer more control over the final-customer relationship and potentially more value, while demanding closer coordination of delivery and CBAM evidence.
A third option is for the IPP or an affiliated trading company to manage exports directly. That gives it greater control of the value chain but also direct exposure to auction collateral, transmission prices, nomination risk, imbalances, replacement power and regulatory duties. The appropriate arrangement depends partly on whether the IPP intends to remain primarily a generator or take on the functions of an electricity trader.
Lenders assess distinct failure cases
A financing model needs to distinguish at least four adverse cases: insufficient transmission capacity, curtailment of rights already secured, a generation shortfall at the Serbian plant and failure to obtain the expected CBAM actual-emissions treatment. Each can cause a different financial loss. The contracts should allocate them separately rather than treat them as one delivery risk.
Lenders will also expect an alternative market for the plant’s output. If the Italian route is temporarily unavailable or uneconomic, production should be redirectable to Serbia or the wider regional electricity market without jeopardising debt service. A financing structure need not depend entirely on the Montenegro–Italy route for the project to use it as an additional higher-value outlet.