Default carbon costs now exceed conventional cross-border price spreads across much of the Western Balkans, placing new value on renewable PPAs, hourly traceability, accredited verification and the legal distinction between electricity imported into the EU and power merely transiting through it, explains experts from CBAM.Clarion.Engineer
Electricity has become the sharpest and least forgiving part of the European Union’s Carbon Border Adjustment Mechanism for Serbia and the neighbouring Western Balkan markets. Since 1 January 2026, electricity released for free circulation in the EU has been covered by the definitive CBAM regime. Unlike steel, aluminium, cement and fertilisers, electricity receives no 50-tonne exemption, meaning that even relatively small import volumes must be handled by an authorised CBAM declarant. It also receives none of the gradual protection created by the continuing allocation of free EU ETS allowances to European industrial producers. For power imports, the carbon-cost exposure begins immediately. (Taxation and Customs Union)
The financial settlement has been delayed, but the liability has not. Electricity imported during 2026 will be included in the first annual CBAM declaration, due by 30 September 2027, when the corresponding certificates must also be surrendered. Certificates will become available through the EU’s common purchasing platform from February 2027. The gap between import and payment gives utilities and traders more time to manage cash flow, but it does not create a grace period. Each qualifying megawatt-hour entering the EU during 2026 is already creating a future reporting and certificate obligation. (Taxation and Customs Union)
The official certificate price was €75.36 per tonne of CO₂ for the first quarter of 2026 and €75.28 per tonne for the second. When the second-quarter price is applied to the electricity default emission factors currently used for the Western Balkans, the resulting gross carbon costs are commercially substantial: €86.42/MWh for Bosnia and Herzegovina, €78.37/MWh for Serbia, €73.70/MWh for Montenegro and €66.77/MWh for North Macedonia. Albania’s default value is zero because of the overwhelmingly hydro-based character of its generation system. These are gross default-value calculations rather than final invoices, but they show the cost facing an importer that cannot establish eligible actual emissions or claim a recognised carbon price paid in the country of origin. (Taxation and Customs Union)
The comparison with regional wholesale prices explains why the electricity rules are so disruptive. Serbia’s average day-ahead price during the second quarter was approximately €96.3/MWh, compared with €109.2/MWh in Hungary. The conventional commercial spread was therefore about €13/MWh, while the Serbian default-value CBAM component was more than €78/MWh. A carbon charge more than six times the wholesale-price spread cannot be absorbed through ordinary cross-border arbitrage. It either makes the transaction uneconomic, forces the supplier to accept a lower net price or requires the electricity to qualify for actual emissions significantly below the Serbian national default.
The same pattern is visible on other regional borders. Montenegro’s second-quarter day-ahead price averaged €93.6/MWh, against €120.9/MWh in Italy, creating a spread of about €27.3/MWh. Yet the Montenegrin default-value carbon component was almost €73.7/MWh. North Macedonia averaged €91.6/MWh, slightly above Greece’s €90.2/MWh, leaving no positive wholesale spread at all before considering a default CBAM cost of almost €66.8/MWh. Albania, at €88.6/MWh, had only a modest discount to Greece, but its zero default value gave hydro-based exports a structural advantage that neighbouring fossil-intensive systems could not match.
For Serbia, the government’s preliminary fiscal modelling places the electricity component of the 2026 CBAM exposure at approximately €21.8mn under a baseline scenario using default values and assuming unchanged 2025 trade volumes. Full recognition of Serbia’s domestic carbon charge could reduce the electricity-related burden to around €20.7mn. A proposed change in the EU methodology, under which the default factor would reflect Serbia’s total national electricity mix rather than predominantly fossil generation, could lower the estimate further to approximately €14.5mn, representing a reduction of about 30 per cent. These are scenario calculations rather than forecasts of the final amount, and Serbia’s own fiscal analysis cautions that electricity trade may already have weakened because of regulatory uncertainty.
Serbia’s domestic response is built around a greenhouse-gas emissions tax of €4 per tonne of CO₂ equivalent above the defined technological minimum, applicable from 1 January 2026, with collection beginning in 2027. Electricity producers may claim a tax credit equal to as much as 20 per cent of qualifying decarbonisation investment, capped at 80 per cent of the relevant carbon-tax liability. The framework gives Serbia a mechanism to retain some carbon-related revenue domestically and direct part of it towards generation investment. Its rate, however, remains small compared with a CBAM certificate price above €75 per tonne, and any EU deduction will depend on proof that the Serbian charge was effectively paid and can be linked to the electricity or installation concerned.
The regional generation mix explains much of the difference in default exposure. Serbia remained the Western Balkans’ largest coal-based producer in the second quarter, despite coal generation falling by approximately 12 per cent to 6.54 TWh. Bosnia and Herzegovina generated around 2.35 TWh from coal, while North Macedonia produced approximately 0.67 TWh. Montenegro’s output of about 0.52 TWh was driven heavily by the Pljevlja lignite power plant, alongside hydro and wind production. Albania produced approximately 0.90 TWh, almost entirely from hydropower. The CBAM hierarchy therefore broadly follows the region’s underlying generation structure, but national averages can conceal major differences between individual plants.
A megawatt-hour generated by a Serbian wind farm has a fundamentally different emissions profile from electricity produced at a lignite plant, yet both can initially be exposed to the same national default factor when the renewable origin and delivery chain cannot be demonstrated under the EU rules. The same problem affects Montenegrin hydro and wind generation, Bosnian hydro plants and North Macedonian solar and wind projects. CBAM therefore creates two electricity products within the same national market: electricity supported by admissible installation-level evidence and electricity valued using the country’s default emission factor.
The first six months of the definitive regime suggest that regional trading patterns are already changing, although CBAM cannot be isolated from hydrology, plant availability, fuel prices, cross-border capacity and demand from Ukraine. Scheduled Western Balkan imports from EU markets fell by around 14 per cent year on year during the second quarter to approximately 4,271 GWh, while exports to the EU declined by 16 per cent to about 3,223 GWh. The region was consequently a net importer of roughly 1,048 GWh. Gross scheduled exchange with EU markets fell by approximately 15 per cent during the quarter and by about 19 per cent during the first half of 2026.
At the same time, trading on the region’s organised day-ahead exchanges increased by approximately 19 per cent to 2.70 TWh. Volumes rose by 52 per cent on ALPEX, 49 per cent on Montenegro’s MEPX, 31 per cent on North Macedonia’s MEMO and 7 per cent on Serbia’s SEEPEX. The combination of weaker gross exchange with the EU and stronger local exchange activity suggests that more electricity is being cleared and repriced within the Western Balkans, even as the economics of exporting carbon-intensive power into the EU become more difficult.
Serbia’s northern border nevertheless produced an apparently contradictory signal. Scheduled Serbia-to-Hungary flows increased by approximately 111 per cent year on year during the second quarter. That rise does not mean that Serbian electricity has escaped CBAM or that the carbon cost is commercially irrelevant. Hungary has also become an increasingly important transit and balancing hub for electricity moving towards Ukraine, with available Hungary-to-Ukraine auction capacity rising sharply during the period. Part of the increased Serbian flow may therefore reflect wider regional routing rather than final consumption in the EU.
The distinction is legally important. CBAM applies when electricity is released for free circulation in the EU. Electricity entering the Union under a transit procedure and subsequently leaving for consumption in another third country is not treated in the same way. A physical flow across the Serbia–Hungary border is therefore not automatically equivalent to a CBAM-liable import consumed in Hungary or elsewhere in the EU. Traders, customs representatives and transmission operators must distinguish between physical border flows, commercial nominations, customs treatment and the ultimate destination of the electricity. (Taxation and Customs Union)
Bosnia and Herzegovina demonstrates how commercial and physical flows can diverge. During the second quarter, approximately 824 GWh physically crossed from Bosnia and Herzegovina into Croatia, while only about 282 GWh was commercially scheduled in that direction. Scheduled exports fell while physical flows increased sharply. CBAM can influence where and how transactions are commercially nominated, but it cannot redirect electricity instantaneously through a meshed transmission network. Persistent differences between schedules and physical flows may require greater redispatch, countertrading and security margins, creating system costs that eventually feed into network tariffs.
Bosnia and Herzegovina also has the region’s highest current electricity default factor, at approximately 1.148 tonnes of CO₂ per MWh. That produces a gross CBAM value of more than €86/MWh at the second-quarter certificate price. For a system combining coal-heavy generation with substantial hydroelectric capacity, the national default value can penalise individual low-carbon plants unless their output is separated through an admissible contractual and verification chain. The lack of full integration with the EU’s coupled electricity market adds another layer of difficulty for exporters trying to demonstrate delivery to a particular EU importer.
Montenegro faces a similar contrast between the national mix and individual assets. Its default factor of approximately 0.979 tonnes of CO₂ per MWh reflects the continuing role of Pljevlja, even though the country also has significant hydro and wind output. Under default treatment, the carbon cost is almost three times the second-quarter wholesale spread between Montenegro and Italy. The commercial value of power from the Piva and Perućica hydropower plants, as well as wind production from Krnovo and Možura, will increasingly depend on whether it can be contractually and operationally separated from the national average and supported by evidence acceptable to an EU importer and verifier.
North Macedonia’s trade relationship with Greece also moved sharply during the quarter. Scheduled exports from North Macedonia to Greece fell by approximately 78 per cent, while flows in the opposite direction increased by around 70 per cent. The change cannot be attributed solely to CBAM, but the combination of closely aligned day-ahead prices and a default carbon component above €66/MWh leaves little economic basis for exporting unidentified Macedonian system power southward. Renewable production with verified actual values could still compete, but ordinary national-mix electricity faces a much harder commercial test.
Albania occupies the strongest default-value position because its electricity system is almost entirely hydro-based. Its zero default factor allowed exports to Greece to increase modestly even though the underlying price spread was small. This advantage is real but not unlimited. Albania’s export capacity remains highly dependent on hydrology, and dry periods can quickly turn the country into a significant importer. The value of its low-carbon status therefore depends on water availability, reservoir management, grid capacity and the ability to convert favourable generation conditions into firm export positions.
The alternative to national default values is to use actual installation-level emissions. For electricity, however, this is not simply a matter of presenting a guarantee of origin or identifying a renewable generator. Under the current rules, several conditions must be satisfied cumulatively. The authorised CBAM declarant must have an appropriate power-purchase agreement with the third-country generator; the physical and contractual delivery route must meet the applicable requirements; electricity must be firmly nominated against allocated interconnection capacity; and generation and import must be matched over periods no longer than one hour. The current framework also includes network and emissions-related conditions that can be difficult to demonstrate across several borders. (Taxation and Customs Union)
A guarantee of origin may support the renewable provenance of the electricity, but it does not replace the PPA, scheduling, interconnection, hourly matching and verification evidence required by CBAM. This is particularly important for traders buying renewable attributes separately from physical electricity. A corporate buyer may be entitled to claim renewable consumption for sustainability reporting while still being unable to use zero actual emissions for CBAM purposes. The carbon-border regime is concerned with the qualifying relationship between the generator, importer, nominated electricity and physical delivery period, not only with ownership of an environmental certificate.
Actual values must also be verified by an accredited CBAM verifier. Accreditation programmes only began to become operational during 2026, with the first accredited electricity verifiers expected around the end of 2026 or in early 2027. This creates a timing problem because 2026 generation, nominations, meter readings, contractual allocations and cross-border evidence must be preserved before the first verification engagements are completed. The EU importer remains legally responsible for the declaration even where a producer, trader or external verifier supplies the underlying information. (Taxation and Customs Union)
The structure of the PPA is therefore becoming a determinant of carbon value. A baseload or shaped PPA can create a compliance gap when the renewable generator underproduces and the supplier replaces the missing volume through the intraday or balancing market. Unless the replacement electricity can be traced to another qualifying low-carbon source, that portion may fall back to the national default factor. A pay-as-produced PPA can preserve a clearer relationship between metered output and imported volume, although it transfers profile and balancing risk to the buyer. Portfolio and intermediary structures are commercially useful, but they currently make the evidentiary chain more complicated.
The value at risk is large enough to affect renewable-project financing. The Energy Community modelled a 130 MW onshore wind farm that could incur an opportunity cost of approximately €8.9mn over six months when it was unable to claim actual emissions and therefore had to sell into a lower-priced non-EU market rather than against the Hungarian day-ahead benchmark. The loss was not caused by emissions from the wind farm itself. It resulted from the inability to turn low physical emissions into an admissible CBAM position.
This creates a new bankability issue for Serbian, Montenegrin, Bosnian and North Macedonian renewable projects. Revenue models based on exports to Hungary, Croatia, Italy or Greece can no longer rely solely on historical wholesale spreads and available interconnection capacity. Lenders will need to examine whether the project has an eligible EU buyer, a compliant PPA, hourly metering, scheduling and nomination arrangements, an accredited verifier and a contractually complete audit trail. A project may be technically connected to the European market yet commercially restricted to regional prices because its electricity cannot qualify for actual emissions.
Brussels has acknowledged that parts of the current electricity framework are too rigid. Proposed amendments would calculate national default factors using the weighted average emissions intensity of the entire geographic electricity mix rather than primarily the fossil-fuel component. They would allow intermediaries within the PPA chain where the connection between generator and importer remains verifiable, clarify the requirement for physical PPAs and remove the condition requiring proof that no physical network congestion existed between the generator and the EU system. The Commission has proposed applying the revised default and actual-value rules to electricity imported from 1 January 2026, but the amendments remain under negotiation and are not yet binding law.
For Serbia, the whole-mix methodology is the most immediately valuable proposed change because it would recognise hydro, wind, solar and other lower-carbon generation within the national factor rather than treating exported electricity through a predominantly fossil-based lens. It would not eliminate the impact of lignite, nor would it provide the same value as plant-specific verification for a renewable generator. It could, however, reduce the default penalty sufficiently to restore some cross-border transactions that are uneconomic under the existing €78.37/MWh gross Serbian value.
The longer-term route is a possible exemption linked to full electricity-market integration with the EU. The CBAM Regulation allows limited treatment for third-country electricity systems integrated with the Union through market coupling, subject to demanding conditions including regulatory alignment and progress towards carbon pricing equivalent to the EU ETS. The Energy Community process increasingly connects market coupling, CBAM treatment and an expectation of EU ETS-equivalent carbon pricing by 2030. For Serbia and its neighbours, this is a strategic pathway rather than an immediate defence against 2026 liabilities. (EUR-Lex)
CBAM is consequently dividing Western Balkan electricity into several commercial categories. Unverified national-mix power carries the default factor. Verified renewable electricity can potentially enter the EU with close to zero direct emissions, but only where the contractual, physical and metering chain meets the applicable rules. Electricity passing through the EU to another third country may fall outside the charge, while domestic carbon payments can reduce the liability only when they are recognised and adequately documented.
Serbia’s position is particularly complex. Its lignite-heavy generation mix creates a high default value, but its transmission system also gives it an important transit role between the southern Balkans, Hungary and the wider central European market. Its organised exchange is gaining liquidity, while its wind, solar and hydro pipeline could provide increasing volumes of low-carbon power. The commercial value of those assets will depend on more than installed megawatts. It will be determined by hourly metering, physical delivery structures, cross-border nominations, PPA design, verifier availability and an audit trail capable of surviving scrutiny by an EU customs authority.
The regional power market is not simply being divided between renewable and fossil generation. It is being divided between electricity whose carbon characteristics can be proven and electricity whose characteristics must be assumed. For Serbia and neighbouring countries, that distinction is now worth between €66 and €86 per megawatt-hour under current default values—large enough to change dispatch, trading routes, PPA structures and the financing case for the next generation of Western Balkan power projects.
Elevated by CBAM.Clarion.Engineer