Serbian independent electricity generators could reach additional long-term buyers and earn stronger revenues by exporting power to Italy through Montenegro. The commercial case depends on the cost and reliability of transmission access, as well as how each shipment is treated under Europe’s carbon border rules. For lenders, the key questions include whether producers can secure a dependable net price and allocate delivery risks.
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 calculated Italy–Serbia price difference was €24.6/MWh before transmission, balancing, losses and carbon-related costs. This historical spread offers a starting point for export assessments, not a measure of the revenue a producer would retain.
The amount available to a wind, solar or hydropower producer depends on its generation profile, the hours when transmission is available and the obligations in its power purchase agreement (PPA). Existing interconnections link Serbia with Montenegro, whose submarine electricity connection provides access to the Italian market. Turning that access into predictable project revenue requires coordinated capacity purchases across both borders, a clear allocation of delivery risks and evidence for the emissions attributed to exported electricity.
Capacity and delivery risks span 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 can simplify administration, but each border remains a separate commercial position. Exporters must coordinate the electricity purchase, capacity on both borders and the nominations needed for delivery.
Securing capacity on the Serbia–Montenegro border does not ensure that corresponding capacity will be available from Montenegro to Italy. If a Serbian plant generates more electricity than can cross the narrower of the two border positions, the remaining output needs another buyer or trading arrangement. This creates a mismatch between a renewable project’s financing term and the shorter periods for which export transmission products are secured.
A PPA may run for a decade or longer, while the capacity needed to deliver electricity under it is purchased for considerably shorter periods. Long-term physical transmission rights can improve visibility, but they do not eliminate curtailment or renewal risk. For a firm-delivery contract, compensation for transmission curtailment 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 independent power producer (IPP), the contractual consequences depend on whether such an interruption excuses delivery, requires replacement electricity or shifts the obligation to an offtaker or trading-service provider.
Infrastructure capacity and project timelines
The 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. This 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 proposal based on this arrangement would need to establish the rights’ permitted use, remaining duration and actual contractual availability. Meanwhile, transmission networks in Montenegro and Serbia are being reinforced.
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. 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 expected to strengthen Serbia’s connection towards Montenegro and improve the regional transmission corridor, but additional network capacity does not automatically become the same volume of commercially available export capacity. An IPP starting operations before the reinforcements are completed therefore needs to base project financing on transmission capacity available at the time, not on capacity expected later.
A planned second Montenegro–Italy HVDC pole could eventually raise total connection capacity to 1,200 MW, but its delivery timetable remains uncertain. For near-term investment modelling, the additional capacity should be treated as an upside scenario rather than guaranteed infrastructure.
Existing contracts shape Serbia’s exportable supply
Potential candidates for Italian export agreements include merchant projects, uncontracted production and renewable projects nearing the end of existing PPAs. Installed generation capacity alone does not determine what an IPP can offer an Italian buyer. Existing contracts may set the buyer, delivery point, contracted volume and ownership of renewable attributes for many years.
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 structures cannot be assumed to be freely available for a separate long-term Italian PPA.
Each project therefore requires a contract review before export capacity is marketed. 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 bankable relationship with an international electricity trader.
For a producer considering the Montenegro–Italy corridor, the first step is to establish exactly how much production remains available for a new contract.
CBAM requires evidence for the electricity delivered
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 materially affect the economics of a sale in Italy.
For wind, solar and other low-carbon generators, the commercial opportunity depends on demonstrating the actual emissions associated with electricity supplied 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 also needs to include 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.
An award of capacity at auction establishes transmission rights but does not independently prove that the electricity came from the named renewable plant. The current electricity methodology also places considerable weight on the contractual relationship between the producer, any intermediary and the EU-side buyer or declarant. A conventional chain of one bilateral contract between an IPP and a trader, followed by 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 structure needs to be addressed before a PPA is signed. The roles of the EU importer, authorised CBAM declarant, electricity buyer and trading-service provider must be clearly defined. The reporting package must also link the claimed quantity to a specific importing party and delivery period.
Guarantees of origin can support the renewable attribute of the electricity, but they do not by themselves replace the physical PPA, nomination, network and verification requirements associated with CBAM electricity actuals. Electricity could reach Italy while the supporting evidence remains insufficient for the importer to use the expected actual-emissions treatment. The PPA should explicitly allocate that risk.
Net value depends on generation and trading costs
The €24.6/MWh historical Italy–Serbia price difference explains the route’s appeal but is not equivalent to additional IPP profit. An export model needs to begin with the Italian price achieved during the producer’s actual generating hours. It must then account for the alternative value of selling in Serbia; transmission costs on both the Serbia–Montenegro and Montenegro–Italy borders; balancing costs; and network losses.
The calculation also needs to include forecasting and scheduling services, trading fees, collateral and credit-support costs, and any CBAM-related carbon exposure allocated to the seller. Generation profiles matter because wind output may be concentrated in hours when the Italy–Serbia spread differs substantially from an annual or quarterly average. Solar output is concentrated in daytime hours, when growing 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 production, reducing imbalance exposure and moving delivery towards higher-value hours. Its place 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. If a Serbian renewable producer exported 200 GWh per year and captured only €5/MWh of additional net value after transmission and trading costs, the project would earn about €1 million in additional annual revenue. That amount can be material for debt service coverage and equity returns, but it becomes bankable only when the relevant volume and pricing mechanism are contractually predictable.
Three structures can allocate export responsibilities
One option is for the Serbian IPP to sell electricity at a Serbian delivery point to an international trader. The trader would then manage cross-border capacity, nominations, balancing and onward sales into Italy. The producer can negotiate a minimum price and may also participate in additional value created in the Italian market.
For many standalone renewable projects, this may be the most bankable structure because complex trading risks pass 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 more control over its relationship with the final consumer and potentially allow it to capture more value, but it requires more detailed 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 over the value chain while exposing the producer 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 the functions of an electricity trader.
Lenders will assess separate failure scenarios
For lenders, the opportunity is credible only if the transaction can withstand adverse cases. Financial models should distinguish a failure to obtain sufficient transmission capacity from curtailment of capacity already secured. They should also account separately for a generation shortfall at the Serbian plant and failure to obtain the expected CBAM actual-emissions treatment.
Each scenario can produce a different financial loss and should be allocated separately in the contractual structure. Lenders will also expect the producer to maintain 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 Montenegro–Italy corridor can therefore serve as an additional high-value outlet for a Serbian renewable project, rather than the sole basis for its financing. The route offers Serbian IPPs commercial exposure to one of Europe’s largest and historically higher-priced electricity markets. Infrastructure is already in place, and further reinforcement of the Serbian and Montenegrin grids could improve the route’s 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 is not the same as guaranteed Italian revenue. The product is renewable electricity combined with secured transmission, hourly delivery capability, a strong PPA, robust balancing arrangements and an auditable CBAM evidence chain. The amount of the Italian wholesale premium retained by the Serbian generator after the delivery and compliance chain has been paid for remains decisive for investors and lenders.
Analysis by Virtu.Energy.