Serbian independent electricity producers could reach Italian buyers through Montenegro’s 600 MW submarine connection, but the route’s financing value depends on transmission costs and reliability, as well as carbon-accounting requirements. An analysis by Virtu.Energy finds that the commercial opportunity rests on coordinating access across two borders, allocating delivery risks and documenting the emissions assigned to exported electricity.
Existing interconnections link Serbia to Montenegro, whose submarine cable connects to the Italian market. In the second quarter of 2026, average day-ahead prices were €120.9/MWh in Italy’s Centro Sud zone, against €96.3/MWh in Serbia and €93.6/MWh in Montenegro. The calculated Italy–Serbia spread was €24.6/MWh, before transmission, balancing, losses and carbon-related costs.
That historical difference provides a starting point, not a measure of a producer’s additional profit. The amount a wind, solar or hydropower plant retains depends on its generation profile, the hours when transmission is available and the obligations in its PPA. Lenders will focus on whether the producer has a dependable net price and a counterparty able to manage delivery risks.
Two borders create separate commercial exposures
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 two borders remain separate commercial positions. Exporters must coordinate the electricity sale, capacity on both borders and delivery nominations.
Securing capacity between Serbia and Montenegro does not guarantee corresponding capacity from Montenegro to Italy. If a Serbian plant generates more than can cross the narrower of the two border positions, the surplus needs another buyer or trading arrangement. This creates a mismatch between the duration of renewable project financing and the shorter-term transmission products supporting exports.
A PPA may run for a decade or longer, while the transmission capacity needed to deliver under it may be secured for considerably shorter periods. Long-term physical transmission rights can improve visibility, but do not remove curtailment or renewal risk. For firm-delivery contracts, compensation for transmission interruptions may not cover the commercial cost of replacing electricity in Italy.
On 3 October 2026, 400 MW of long-term transmission rights from Montenegro to Italy were curtailed to zero for six hours because of operational security limitations associated with the HVDC connection. For an IPP, the contractual consequences depend on whether an interruption excuses delivery, requires replacement electricity or shifts the obligation to an offtaker or trading-service provider.
Grid expansion improves the route, but timing matters
The Montenegro–Italy connection, with a capacity of 600 MW, has been commercially operational since December 2019. Around 200 MW is assigned to private investors under a third-party-access exemption, a component associated with Monita Interconnector. As a result, the full 600 MW cannot be treated as continuously available through public capacity auctions.
The private-capacity component could matter to Italian industrial buyers able to access the corresponding transmission rights. Any Serbian IPP proposal relying on this structure would need to establish the permitted use, remaining duration and actual contractual availability of those rights. Meanwhile, transmission networks in both Serbia and Montenegro are being reinforced.
In Montenegro, the 400 kV Lastva–Pljevlja line entered trial operation in July 2026, strengthening the link between northern Montenegro and the coastal transmission system connected towards Italy. On the Serbian side, the next stages of the Trans-Balkan Electricity Corridor are particularly important. The Obrenovac–Bajina Bašta reinforcement, estimated to cost about €113.5 million, is expected to be completed during 2028.
The subsequent section, connecting the Bajina Bašta area towards Višegrad and Pljevlja, is planned for 2029. These investments should strengthen Serbia’s connection towards Montenegro and improve the regional transmission corridor, but additional network capacity does not automatically mean the same volume of commercially available export capacity. An IPP starting operations before the reinforcements are complete needs to base financing on capacity available today, not on later expected capacity.
A planned second Montenegro–Italy HVDC pole could eventually raise the total connection capacity to 1,200 MW, but the delivery timetable remains uncertain. For near-term investment modelling, the extra capacity should therefore be treated as an upside scenario rather than guaranteed infrastructure.
Existing contracts constrain available Serbian supply
The clearest candidates for Italian export deals are merchant projects, uncontracted generation and renewable projects nearing the end of existing PPAs. Installed capacity alone does not determine how much an IPP can offer to an Italian buyer. Existing contracts may set the buyer, delivery point, contracted volume and ownership of renewable attributes for many years.
This is especially relevant to Serbia’s auction-supported renewable portfolio. Projects awarded support under the country’s renewable auction framework may have long-term arrangements tied to domestic supply and EPS. Output already committed under those structures cannot be assumed to be available for a separate long-term Italian PPA, so each project needs a contractual review before export capacity is marketed.
Other projects show that international trading companies already enter 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 bankable relationship with an international electricity trader. A producer considering exports through Montenegro should first determine exactly how much generation remains available for a new contract.
CBAM makes delivery evidence commercially decisive
The EU’s Carbon Border Adjustment Mechanism adds another layer to the transaction. Electricity generated in Serbia and transported through Montenegro remains 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 opportunity lies in 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 enough. The current CBAM framework requires a qualifying physical PPA and supporting evidence linking the named generator to the electricity imported into the EU.
The evidence chain must cover the generating installation, contractual relationship, transmission and nominated delivery route, 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 establishes transmission rights, but does not independently prove that the electricity came from the named renewable plant.
The current electricity methodology also places significant weight on 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 the trader and an EU buyer may need careful legal and verification review if the importer intends to claim the producer’s actual emissions. Transaction structure therefore needs attention before the PPA is signed.
The roles of the EU importer, authorised CBAM declarant, electricity buyer and trading-service provider should be clearly defined. Reporting must also link the claimed quantity to a specific importing party and delivery period. Guarantees of origin can support the renewable attribute, but do not by themselves replace the physical PPA, nomination, network and verification requirements for CBAM electricity actuals.
The exposure extends beyond physical delivery: electricity could reach Italy while the supporting evidence is insufficient for the importer to use the expected actual-emissions treatment. The PPA should explicitly allocate that risk.
Retained margin matters more than the Italian price premium
The €24.6/MWh historical Italy–Serbia spread explains the route’s appeal, but does not represent an IPP’s additional profit. An export model needs to start with the Italian price achieved during the producer’s actual generation hours. It must then account for the alternative value of selling in Serbia, transmission on both borders, balancing, 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 can materially affect the outcome. Wind output may be concentrated in hours when the Italy–Serbia spread differs substantially from its annual or quarterly average. Solar production is concentrated in daytime hours, when rising regional solar generation can put pressure on wholesale prices.
Hydropower with operational flexibility may be better able to target higher-value delivery periods, subject to hydrological conditions and plant operating constraints. Storage could improve the model by reshaping renewable output, reducing imbalance exposure and shifting delivery towards higher-value hours. However, its place in a CBAM actual-emissions evidence chain needs careful treatment when charging and discharge occur in different periods.
Even a modest retained spread can affect project economics. If a Serbian renewable producer exported 200 GWh per year and gained only €5/MWh in additional net value after transmission and trading costs, it would generate about €1 million in additional annual revenue. That amount can be meaningful for debt service coverage and equity returns, but is bankable only when the relevant volume and pricing mechanism are contractually predictable.
Three commercial structures are available
One option is to sell electricity at a Serbian delivery point to an international trader. The trader would manage cross-border capacity, nominations, balancing and onward 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, this may be the most bankable structure 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 that provides transmission and scheduling services. This can give the producer more control over its relationship with the final consumer and potentially capture more value, but requires closer coordination of physical delivery and CBAM evidence.
A third possibility is for the IPP, or an affiliated trading company, to manage the export position itself. This offers greater control of the value chain, but exposes the producer directly to auction collateral, transmission prices, nomination risk, imbalances, replacement electricity and regulatory obligations. The choice depends partly on whether the IPP wants to remain primarily a generator or gradually take on the functions of an electricity trader.
Lenders will assess delivery and compliance risks
For lenders, the opportunity is credible only if the transaction can withstand adverse scenarios. Financial models should distinguish at least four failures: insufficient transmission capacity; curtailment of capacity rights already secured; a shortfall in generation at the Serbian plant; and failure to obtain the expected CBAM actual-emissions treatment. Each can produce a different financial loss and should be allocated separately in the contracts.
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 output into the Serbian or wider regional electricity market without jeopardising debt service. A financing structure is therefore unlikely to rely entirely on one cross-border route; the Montenegro–Italy corridor can instead provide an additional high-value outlet for an otherwise bankable Serbian renewable project.
Italy offers a strategic market for Serbian IPPs
The corridor gives Serbian independent power producers 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 Serbian and Montenegrin grids could improve its value during the second half of the decade. A future expansion of the submarine connection could also increase the volume of electricity flowing between the western Balkans and Italy.
Access to Italy, however, is not the same as guaranteed Italian revenue. The commercially valuable product combines renewable electricity with secured transmission, hourly delivery capability, a strong PPA, robust balancing arrangements and an auditable CBAM evidence chain. Serbian IPPs able to assemble those elements could use Montenegro as a transit platform connecting Balkan renewable generation with Italian industry.
For investors and lenders, the decisive figure will not be the Italian wholesale premium alone, but the share remaining with the Serbian generator after the full delivery and compliance chain has been paid for.
