Analysis by Virtu.Energy
Serbian independent power producers (IPPs) could unlock additional long-term buyers, higher electricity revenues and improved project bankability by exporting electricity to Italy through Montenegro. However, the financial value of this route will depend on transmission costs, cross-border capacity availability and the treatment of imported electricity under the EU’s Carbon Border Adjustment Mechanism (CBAM).
The commercial opportunity is credible because existing interconnections link Serbia with Montenegro, while Montenegro’s submarine electricity connection provides access to the Italian market. Converting that infrastructure into predictable project revenues requires coordinated transmission capacity across both borders, clearly allocated delivery risks and verifiable emissions data supporting the electricity supplied to EU buyers.
The potential price advantage is significant. In the second quarter of 2026, average day-ahead electricity prices reached €120.9/MWh in Italy’s Centro Sud zone, compared with €96.3/MWh in Serbia and €93.6/MWh in Montenegro. The resulting Italy–Serbia price difference of €24.6/MWh provides an initial indication of the export opportunity, before accounting for transmission, balancing, network losses and carbon-related costs.
This historical price spread offers a useful starting point for evaluating cross-border sales, but it does not represent the additional profit available to a renewable generator. The amount retained by a wind, solar or hydropower producer depends on its actual generation profile, available transmission capacity and the commercial obligations defined in its power purchase agreement (PPA).
For lenders, the central question is whether an exporter can secure a dependable net selling price, reliable delivery arrangements and a counterparty capable of absorbing cross-border trading risks. Without these protections, the headline Italian price premium may offer limited value for project financing.
Two borders create separate transmission and delivery risks
Both the Serbia–Montenegro and Montenegro–Italy interconnections operate under yearly, monthly and daily explicit capacity allocation arrangements in 2026. Although the common allocation framework helps standardise procedures, the two borders remain separate commercial positions that must be secured and managed independently.
An exporter must coordinate electricity purchases, transmission capacity on both borders and the nominations required for physical delivery. Securing capacity between Serbia and Montenegro does not automatically guarantee corresponding capacity between Montenegro and Italy.
If a Serbian plant generates more electricity than can be transported across the most restrictive section of the corridor, the surplus must be sold through another route or managed under a separate trading arrangement. This can expose the producer to lower domestic prices, imbalance costs or the expense of arranging replacement delivery.
The resulting mismatch is particularly important for renewable projects seeking long-term financing. A PPA may run for ten years or longer, while the transmission products needed to fulfil it may be secured for substantially shorter periods. Long-term physical transmission rights can improve visibility, but they do not eliminate the risks of curtailment, renewal or changing network conditions.
For contracts requiring firm delivery, transmission compensation may also fail to cover the full commercial cost of replacing electricity in Italy. The exporter must therefore establish who bears the financial consequences of interrupted transmission, rather than assuming that capacity rights guarantee uninterrupted delivery.
A recent example illustrates the exposure. 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 high-voltage direct-current (HVDC) connection.
For an independent power producer, the consequences depend on the contract. An interruption may excuse delivery, require the purchase of replacement electricity or transfer the obligation to an offtaker or trading-service provider. The allocation of curtailment and replacement-power risk is therefore central to a bankable export agreement.
Grid expansion strengthens the corridor, but timing remains critical
The existing Montenegro–Italy electricity interconnector has a capacity of 600 MW and has been commercially operational since December 2019. It provides the physical foundation for electricity trading between the western Balkans and the Italian market.
However, the full 600 MW should not be treated as continuously available through public capacity auctions. Approximately 200 MW is assigned to private investors under a third-party-access exemption, with the private component associated with Monita Interconnector.
This private-capacity arrangement could be relevant to Italian industrial buyers seeking electricity under dedicated supply structures. Any Serbian IPP proposal relying on this route would need to establish the permitted use, remaining duration and actual contractual availability of the relevant transmission rights.
The wider regional network is also being reinforced. In Montenegro, the 400 kV Lastva–Pljevlja transmission line entered trial operation in July 2026, strengthening the connection between northern Montenegro and the coastal transmission system linked towards Italy.
On the Serbian side, the next stages of the Trans-Balkan Electricity Corridor are particularly important. The Obrenovac–Bajina Bašta reinforcement, with an estimated investment of approximately €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 improve Serbia’s connection towards Montenegro and strengthen the wider regional transmission corridor.
Nevertheless, additional physical network capacity does not automatically translate into an equivalent increase in commercially available export capacity. Network constraints, operational security requirements and allocation arrangements will continue to determine how much electricity can be transported at any given time.
An IPP entering operation before these reinforcements are completed should therefore base its financing assumptions on transmission capacity available under current conditions, rather than relying on future infrastructure that has not yet entered service.
A planned second Montenegro–Italy HVDC pole could eventually increase the interconnector’s total capacity to 1,200 MW, potentially expanding opportunities for regional electricity exports. However, its delivery timetable remains uncertain, meaning that the additional capacity should be modelled as an upside scenario rather than guaranteed infrastructure.
Existing offtake contracts limit Serbia’s exportable electricity
The most promising candidates for Italian supply agreements are likely to be merchant renewable projects, uncontracted generation and projects approaching the expiry of existing PPAs. Installed capacity alone does not establish how much electricity a producer can offer to a new buyer.
Existing contracts may determine the purchaser, delivery point, contracted volume and ownership of renewable attributes for many years. These commitments can significantly restrict the volume available for a second long-term agreement.
This is particularly relevant to Serbia’s auction-supported renewable energy portfolio. Projects awarded support under the domestic renewable auction framework may have long-term arrangements associated with domestic supply and Elektroprivreda Srbije (EPS). Electricity already committed under those arrangements cannot automatically be treated as available for a separate Italian PPA.
Each project therefore requires a detailed contractual review before export volumes are marketed. Producers must establish which output is uncommitted, whether existing agreements permit cross-border sales and who controls the relevant renewable attributes.
Other Serbian projects demonstrate that international trading companies are already prepared to enter long-term contracts with domestic renewable generators. The 105 MW Krivača wind farm, for example, entered into a 10-year PPA with Axpo, illustrating how a Serbian independent producer can establish a bankable relationship with an international electricity trader.
For IPPs considering the Montenegro–Italy corridor, the first step should therefore be to identify the electricity genuinely available for a new contract. Only then can the potential Italian price premium be assessed against the costs and risks of cross-border delivery.
CBAM makes emissions verification a commercial priority
The EU’s Carbon Border Adjustment Mechanism (CBAM) introduces an additional layer of regulatory and financial complexity. Electricity generated in Serbia and transported through Montenegro remains electricity of Serbian origin for CBAM purposes. Transit through Montenegro does not change the country where the electricity was produced.
This distinction matters because the emissions treatment applied to Serbian electricity can materially affect the economics of sales into Italy. For wind, solar and other low-carbon generators, the commercial opportunity may depend on demonstrating the actual emissions associated with electricity supplied by a specific generating installation, rather than relying on a broader country-level default.
However, renewable generation alone is not sufficient to establish eligibility for actual-emissions treatment. The applicable CBAM framework requires a qualifying physical power purchase agreement and supporting evidence demonstrating the relationship between the named generator and the electricity imported into the EU.
The evidence chain must address several elements, including:
- The generating installation and its identity.
- The contractual relationship between the producer, intermediaries and relevant EU-side buyer.
- The transmission route and nominated delivery arrangements.
- Hourly generation and metering records.
- SCADA data and accepted physical schedules.
- The relevant importer or authorised CBAM declarant.
- Independent verification and supporting documentation.
For a Serbian producer selling electricity through Montenegro into Italy, the documentation chain could involve EMS, CGES and Terna, alongside the generator, trader, importer and verifier. Each participant may provide a different part of the evidence required to substantiate the transaction.
A transmission capacity award is only one component of this process. It confirms access to a particular allocation of cross-border capacity, but does not independently prove that the imported electricity originated from the named renewable installation.
The contractual structure also requires careful attention. The relationship between the generator, any intermediary and the EU-side buyer or declarant can be important when demonstrating eligibility for actual-emissions treatment.
A conventional arrangement involving one bilateral contract between an IPP and a trader, followed by a separate resale agreement between that trader and an EU buyer, may therefore require specific legal and verification review if the importer intends to claim the producer’s actual emissions. These requirements should be assessed before the PPA is signed, rather than after electricity deliveries begin.
The transaction must clearly identify the EU importer, authorised CBAM declarant, electricity buyer and trading-service provider. The supporting reporting package must also connect the claimed electricity volume to the relevant importing party and delivery period.
Guarantees of origin can support claims about renewable attributes, but they do not independently replace the physical PPA, transmission, nomination and verification evidence required for CBAM actual-emissions treatment.
The resulting commercial risk extends beyond whether the electricity physically reaches Italy. A shipment may be delivered successfully while the supporting evidence remains insufficient for the importer to obtain the expected emissions treatment. The PPA should explicitly allocate responsibility for documentation, verification failures and any resulting carbon-related costs.
The retained margin matters more than the Italian price premium
The €24.6/MWh Italy–Serbia price difference recorded in the second quarter of 2026 explains why the route is attracting interest, but it should not be confused with an IPP’s additional profit. The relevant starting point is the Italian market price achieved during the producer’s actual generating and delivery hours.
The exporter must then deduct the alternative value of selling electricity in Serbia, Serbia–Montenegro and Montenegro–Italy transmission costs, balancing charges, network losses, forecasting and scheduling services, trading fees, collateral requirements and any CBAM-related exposure allocated to the seller.
The generating profile can materially change the result. Wind output may be concentrated in hours when the Italian price premium differs considerably from the quarterly average. Solar producers face a separate challenge because generation is concentrated during daylight hours, when rising regional solar output can put downward pressure on wholesale prices.
Hydropower with operational flexibility may be better positioned to target higher-value delivery periods, subject to water availability, reservoir constraints and plant operating requirements. The ability to schedule production can make a meaningful difference to the net price achieved under an export agreement.
Storage could further improve the commercial model by reshaping renewable output, reducing imbalance exposure and shifting deliveries towards higher-value hours. However, where storage charges and discharges electricity at different times, its integration into a CBAM actual-emissions evidence chain requires careful treatment of the relevant generation, consumption and delivery records.
Even relatively modest retained price differences can have a material effect on project economics. If a Serbian renewable producer exported 200 GWh annually and achieved just €5/MWh in additional net value after transmission and trading costs, it would generate approximately €1 million in additional annual revenue.
That additional revenue could support debt-service coverage, cash-flow stability and equity returns. Its financing value, however, depends on whether the export volume and pricing mechanism are sufficiently predictable to be incorporated into a lender’s base-case assumptions.
Three commercial structures could unlock the Italian market
One option is to sell electricity at a Serbian delivery point to an international electricity trader. The trader would then manage cross-border capacity, nominations, balancing and onward sales into Italy. The producer could negotiate a minimum price and, depending on the agreement, participate in some of the additional value generated by the Italian market.
For many standalone renewable projects, this may be the most bankable structure, because complex cross-border trading risks are transferred to a counterparty with an established trading portfolio, operational expertise and balance sheet.
A second option is a direct physical PPA with an Italian or other EU industrial buyer, supported by a trader or balancing responsible party that manages transmission and scheduling services. This arrangement could provide the producer with greater control over its relationship with the final consumer and potentially allow it to retain a larger share of the Italian market premium.
However, direct supply requires substantially more coordination of physical delivery, transmission capacity, nominations and CBAM evidence. The parties would need to establish clear responsibilities for interruptions, replacement electricity, reporting and verification.
A third option is for the IPP, or an affiliated trading company, to manage the export position directly. This would provide greater control over the value chain but expose the producer to transmission auction collateral, capacity prices, nomination risk, imbalances, replacement-power costs and additional regulatory obligations.
The optimal structure depends on the producer’s financial capacity, risk appetite and commercial strategy. An IPP seeking predictable revenues may prefer to remain primarily a generator, while a larger company with trading expertise may seek to capture more of the value created by cross-border sales.
Banks will test transmission, generation and compliance risks
For lenders, the export opportunity becomes credible only when the transaction remains viable under adverse conditions. Financial models should distinguish between insufficient transmission capacity, curtailment of secured rights, lower-than-expected generation and failure to obtain the expected CBAM emissions treatment.
Each scenario can create a different financial loss and should be addressed separately in the contractual structure. The agreements must establish who bears replacement-power costs, balancing exposure, lost revenue and any additional carbon-related liabilities.
Lenders are also likely to expect the producer to maintain an alternative route to market. If the Italian corridor becomes temporarily unavailable or uneconomic, the plant should be able to redirect electricity into Serbia or another regional market without jeopardising its ability to service debt.
This makes a diversified sales strategy more attractive than a financing structure dependent entirely on a single cross-border route. The Montenegro–Italy corridor can instead function as an additional high-value market outlet, complementing the domestic and regional sales arrangements supporting the underlying renewable project.
Montenegro could become a strategic export corridor for Serbian IPPs
The Montenegro–Italy interconnector gives Serbian independent power producers access to a major European electricity market with historically higher wholesale prices. The physical infrastructure is already in operation, while planned reinforcement of the Serbian and Montenegrin grids could improve the corridor’s commercial potential during the second half of the decade.
A future expansion of the submarine connection could also increase the volume of electricity traded between Italy and the western Balkans. Nevertheless, access to the Italian market is not equivalent to guaranteed Italian revenue. Available transmission capacity, market-price differences and operating conditions will determine the volume and value of actual deliveries.
The commercially valuable product is therefore not simply renewable electricity generated in Serbia. It is renewable electricity backed by secured transmission capacity, reliable hourly delivery, a bankable PPA, robust balancing arrangements and an auditable CBAM evidence chain.
Serbian IPPs capable of combining these elements could turn Montenegro from a neighbouring electricity market into a strategic transit platform connecting Balkan renewable generation with Italian industrial demand.
For investors and lenders, the decisive metric will not be the Italian wholesale price premium alone. It will be the share of that premium retained by the Serbian producer after transmission, trading, balancing, financing and compliance costs have been deducted.
Analysis by Virtu.Energy
