Serbian independent power producers (IPPs) could reach additional long-term buyers and increase revenues by exporting electricity to Italy through Montenegro. Whether the route can support project financing depends on the cost and reliability of transmission access, delivery-risk allocation and how each shipment is treated under Europe’s carbon border rules. Analysis by Virtu.Energy finds that the commercial case rests on coordinating access across two borders and documenting the electricity’s emissions.
Average day-ahead electricity prices in the second quarter of 2026 were €120.9/MWh in Italy’s Centro Sud zone, €96.3/MWh in Serbia and €93.6/MWh in Montenegro. The calculated Italy–Serbia price difference was €24.6/MWh before transmission, balancing, losses and carbon-related costs. This historical spread provides a starting point for an export assessment, not a measure of the revenue a producer would necessarily retain.
The net value for a wind, solar or hydropower generator depends on its production profile, the hours when transmission is available and the obligations in its power purchase agreement (PPA). For lenders, the key questions are whether the producer has a dependable net price and whether its counterparty can manage delivery risks. The route is commercially credible, but making its revenue predictable requires coordinated capacity purchases across both borders, clear allocation of delivery risks and evidence supporting the emissions attributed to exported electricity.
Transmission access and delivery risks across two borders
In 2026, both the Serbia–Montenegro and Montenegro–Italy borders use yearly, monthly and daily explicit capacity allocation arrangements. A common allocation framework simplifies administration, but the borders remain separate commercial positions. Exporters must coordinate the electricity purchase, capacity on both borders and the nominations required for delivery.
Capacity secured on the Serbia–Montenegro border does not guarantee matching capacity from Montenegro to Italy. If the Serbian plant generates more than can be transported across the narrower of the two border positions, the surplus needs another buyer or trading arrangement. This creates a timing mismatch: a renewable project’s PPA may run for a decade or longer, while the transmission products needed to fulfil it are secured for considerably shorter periods.
Long-term physical transmission rights can improve visibility, but do not eliminate curtailment or renewal risk. For a firm-delivery contract, compensation for transmission does not necessarily cover the commercial cost of replacing electricity in Italy. On 3 October 2026, for example, 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 contractual consequences of such an interruption depend on whether it excuses delivery, requires replacement electricity or transfers the obligation to an offtaker or trading-service provider. The operating Montenegro–Italy electricity connection has a capacity of 600 MW and has been commercially operational since December 2019. However, around 200 MW is assigned to private investors under a third-party-access exemption.
Grid reinforcement and the available export portfolio
The private-capacity component is associated with Monita Interconnector, so the full 600 MW cannot be treated as continuously available through public capacity auctions. The private capacity could be relevant to Italian industrial buyers with access to the corresponding transmission rights. A Serbian IPP supply proposal using this structure would need to establish the rights’ permitted use, remaining duration and actual contractual availability.
Grid reinforcement is also under way. In Montenegro, the 400 kV Lastva–Pljevlja line entered trial operation in July 2026, strengthening the connection between northern Montenegro and the coastal transmission system linked towards Italy. In Serbia, the next stages of the Trans-Balkan Electricity Corridor are particularly important for the route.
The Obrenovac–Bajina Bašta reinforcement, with an estimated investment of about €113.5 million, is expected to be completed during 2028. The subsequent section linking the Bajina Bašta area towards Višegrad and Pljevlja is planned for 2029. These investments are intended to strengthen Serbia’s connection towards Montenegro and improve the regional transmission corridor, although greater network capacity does not automatically translate into the same volume of commercially available export capacity.
An IPP starting operations before those reinforcements are completed would need to finance its project against transmission capacity available at the time, rather than capacity expected later. A planned second Montenegro–Italy HVDC pole could eventually raise the connection’s total capacity to 1,200 MW, but its delivery timetable remains uncertain. Near-term investment models should therefore treat the additional capacity as an upside scenario, not guaranteed infrastructure.
Merchant projects, uncontracted production and renewable projects nearing the expiry of existing PPAs are the clearest candidates for Italian export arrangements. Installed generation capacity alone does not establish how much electricity an IPP can offer: existing contracts can define the buyer, delivery point, contracted quantity and ownership of renewable attributes for years. Each project needs a contractual review before export capacity is marketed.
This is particularly relevant to Serbia’s auction-supported renewable portfolio. Projects awarded support under Serbia’s renewable auction framework may have long-term arrangements linked to domestic supply and EPS. Output already committed under those arrangements cannot simply be treated as freely available for a second long-term Italian PPA.
Other Serbian projects show that international trading companies are already entering long-term contracts with Serbian renewable generators. The 105 MW Krivača wind farm, for example, signed a 10-year PPA with Axpo, demonstrating that a Serbian IPP can establish a long-term relationship with an international electricity trader. A producer considering exports through Montenegro should first determine exactly what output remains available for a new contract.
CBAM evidence for electricity exported to Italy
The EU’s Carbon Border Adjustment Mechanism (CBAM) adds another layer to the transaction. Electricity generated in Serbia and transported through Montenegro remains electricity of Serbian origin for CBAM purposes; transit through Montenegro does not change where it was produced. The emissions treatment of Serbian electricity may therefore materially affect the economics of an Italian sale.
For wind, solar and other low-carbon generators, the commercial opportunity depends on demonstrating the actual emissions associated with electricity from a named installation rather than relying on a broader country-level default. Renewable generation alone is not sufficient. Under the current CBAM framework, a qualifying physical PPA and supporting evidence must demonstrate the relationship between the named generator and the electricity imported into the EU.
The evidence chain needs to cover the generating installation and contractual relationship, as well as the transmission and nominated delivery route. It must also address hourly production, metering and SCADA evidence, accepted physical schedules, the relevant importer or authorised CBAM declarant, and independent verification. For a Serbian generator selling through Montenegro into Italy, this could involve EMS, CGES and Terna, alongside the producer, trader, importer and verifier.
A capacity-auction award is only one element of that chain: it establishes transmission rights but does not independently prove that the electricity came from the named renewable plant. The current electricity methodology also gives considerable importance to the contractual relationship between the producer, any intermediary and the EU-side buyer or declarant. A conventional structure with one bilateral contract between an IPP and a trader and a separate resale contract between that trader and an EU buyer may therefore need careful legal and verification review if the importer intends to claim the producer’s actual emissions.
Transaction arrangements need to be established before the PPA is signed. The roles of the EU importer, authorised CBAM declarant, electricity buyer and trading-service provider must be clearly defined, and the reporting package must connect the claimed quantity with a specific importing party and delivery period. Guarantees of origin can support the renewable attribute of the electricity, but do not replace the physical PPA, nomination, network and verification requirements for CBAM electricity actuals.
The risk extends beyond physical delivery: electricity could reach Italy while the evidence remains insufficient for the importer to use the expected actual-emissions treatment. The PPA should explicitly allocate that risk. The evidence and contractual structure are therefore part of the delivery arrangement, not simply a record of the electricity’s route.
Net export value and possible contract structures
The historical €24.6/MWh Italy–Serbia price difference helps explain the route’s appeal, but it is not equivalent to additional IPP profit. An export model should begin with the Italian price achieved during the producer’s actual generating hours, then deduct the alternative value of sales in Serbia. It must also account for Serbia–Montenegro and Montenegro–Italy transmission costs, balancing costs, network losses, forecasting and scheduling services, trading fees, collateral and credit-support costs, and any CBAM-related carbon exposure allocated to the seller.
The generation profile matters. Wind output may be concentrated in hours when the Italy–Serbia spread differs substantially from the annual or quarterly average. Solar generation is concentrated in daytime hours, when increasing regional solar output can put pressure on wholesale prices. Hydropower with operational flexibility may be better placed to target higher-value delivery periods, subject to hydrological conditions and plant operating constraints.
Storage could improve the model by reshaping renewable production, reducing imbalance exposure and shifting delivery towards higher-value hours. However, its inclusion in a CBAM actual-emissions evidence chain requires careful treatment when charging and discharge occur in different periods. Even a modest retained spread can affect project economics: a Serbian renewable producer exporting 200 GWh per year and achieving just €5/MWh of additional net value after transmission and trading costs would generate about €1 million of additional annual revenue.
That revenue could be meaningful for debt service coverage and equity returns, but it becomes bankable only if the relevant volume and pricing mechanism are contractually predictable. One option is for the producer to sell electricity at a Serbian delivery point to an international trader. The trader then manages cross-border capacity, nominations, balancing and onward sales into Italy, while the producer can negotiate a minimum price and potentially share in additional value created by the Italian market.
For many standalone renewable projects, that structure may be the most bankable because it transfers complex trading risks to a party with an established portfolio and balance sheet. A second option is a direct physical PPA with an Italian or EU industrial buyer, supported by a trader or balancing responsible party providing transmission and scheduling services. This can give the producer greater control over its relationship with the final consumer and potentially capture more value, but requires more detailed coordination of physical delivery and CBAM evidence.
A third option is for the IPP or an affiliated trading company to manage the export position itself. This gives the producer greater control over the value chain but exposes it directly to auction collateral, transmission prices, nomination risk, imbalances, replacement electricity and regulatory obligations. The choice partly depends on whether the IPP intends to operate primarily as a generator or gradually take on electricity-trading functions.
Financing tests and the role of the corridor
Lenders will assess whether the transaction can withstand adverse cases. The financial model should distinguish a failure to obtain sufficient transmission capacity, curtailment of transmission 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 and should be allocated separately in the contractual structure.
Lenders will also expect an alternative route to market. If the Italian route is temporarily unavailable or uneconomic, the plant should be able to redirect production into the Serbian or wider regional electricity market without jeopardising debt service. The financing structure is therefore unlikely to rely entirely on one cross-border route; the Montenegro–Italy corridor can instead provide an additional high-value market outlet for an otherwise bankable Serbian renewable project.
The corridor offers Serbian IPPs direct commercial exposure to one of Europe’s largest and historically higher-priced electricity markets. The infrastructure is already in place, and further reinforcement of the Serbian and Montenegrin grids could improve its value during the second half of the decade. A future expansion of the submarine connection could potentially increase electricity flows between the western Balkans and Italy.
Access to Italy does not guarantee Italian revenues. The commercial product is renewable electricity combined with secured transmission, hourly delivery capability, a strong PPA, robust balancing arrangements and an auditable CBAM evidence chain. Serbian IPPs that assemble those elements could use Montenegro as a transit platform linking Balkan renewable generation with Italian industry.
For investors and lenders, the relevant figure is how much of the Italian wholesale premium remains with the Serbian generator after the full delivery and compliance chain has been paid for. Analysis by Virtu.Energy