The implementation of the EU Carbon Border Adjustment Mechanism (CBAM) on electricity imports from South-East Europe presents significant financial and structural challenges for the region’s power sector. This comes at a critical time when substantial capital investment is necessary for decarbonization and the integration of energy grids. In Serbia, electricity serves not only as a utility but also as a traded commodity essential for regional balance, liquidity, and investment returns. Any mispricing of carbon content in exported electricity directly affects power pricing, investment costs, and system adequacy.
Serbia has an installed electricity capacity of approximately 9.0 gigawatts (GW) and generates around 34 to 35 terawatt-hours (TWh) annually under normal hydrological conditions. The energy mix is dominated by lignite-fired thermal power plants, which account for about 60 to 65 percent of output, while hydropower contributes roughly 24 to 26 percent. The remainder comes from wind, gas, and other sources. In years conducive to exports, Serbia typically sends between 2.0 to 4.0 TWh of net electricity to neighboring markets, primarily Hungary, Romania, and Croatia. These exports represent a significant economic factor, with gross revenues estimated between €170 million and €360 million annually at conservative wholesale prices ranging from €85 to €95 per megawatt-hour (MWh).
Under CBAM regulations, electricity imports into the European Union are subject to a carbon price equivalent to the current EU Emissions Trading System (ETS) allowance price. Assuming a forward-looking ETS price range of €80 to €100 per tonne of CO₂, the carbon cost associated with Serbian electricity is contingent upon the emissions factor applied. If default grid-average values are utilized, Serbia’s average intensity of about 0.55 tCO₂/MWh results in a CBAM charge of €44 to €55 per MWh. This translates to an annual CBAM exposure of approximately €130 million to €165 million for 3.0 TWh of exports, potentially consuming 40 to 55 percent of gross export value under average market conditions.
A critical risk arises from the fact that electricity dispatch is conducted on a marginal basis rather than based on an annual-average emissions profile. During much of the year in Serbia and the broader South-East European region, hydropower or wind energy constitutes the marginal export unit rather than lignite coal. In spring and early summer months, hydropower often accounts for 40 to 60 percent of export volumes. Applying an annual average emissions factor could lead to excessive taxation on low-carbon electricity sources, which contradicts EU policy objectives aimed at promoting such generation assets.
The implications for capital markets are immediate and significant. Current development costs for new wind projects in Serbia range from €1.1 million to €1.4 million per MW, while utility-scale solar projects range from €0.55 million to €0.75 million per MW, excluding grid reinforcement expenses. The addition of battery storage systems incurs further costs between €0.35 million and €0.55 million per MWh installed capacity. These projects depend on regional price convergence and export opportunities to achieve internal rates of return (IRRs) between 8 and 12 percent. A reduction in expected export prices due to CBAM uncertainty by even €10 to €15 per MWh could compress project IRRs by 150 to 250 basis points, jeopardizing many developments unless offset by increased support tariffs or state guarantees.
Operationally, CBAM introduces new ongoing expenses related to monitoring, reporting, and verification processes. For instance, a mid-sized private wind portfolio generating approximately 900 GWh annually would incur verification costs ranging from €0.25 million to €0.45 million each year—equating to about €0.30 to €0.50 per MWh. While this may seem modest compared to energy prices, it becomes significant when combined with balancing costs and grid fees.
To comply with CBAM regulations regarding green electricity verification, importers can declare actual emissions instead of relying on default values if verified by an accredited independent entity. This necessitates precise carbon attribution at the installation level for Serbian producers rather than using grid-average metrics.
Verification involves capturing generation data with high temporal resolution aligned with market dispatch intervals while ensuring compliance with records maintained by transmission system operators like Elektromreža Srbije in Serbia. Additionally, producers must document their installations’ emissions profiles accurately; for renewable sources like wind and solar, this typically indicates zero operational emissions.
Looking ahead, Serbia’s national energy plans suggest an increase in renewable generation aimed at achieving around 40 percent of total electricity production by 2030—up from about 30 percent currently—requiring investments estimated between €6 billion and €8 billion over the next five years in generation and grid assets.
If CBAM is fully implemented immediately using default emission factors, many renewable projects may become non-bankable due to reduced export revenues from low-carbon generation. Conversely, delaying CBAM until 2028 while developing hourly emissions attribution could mitigate carbon leakage risks while maintaining investment signals.
In summary, careful sequencing rather than outright exemptions appears necessary for effective policy implementation regarding CBAM in Serbia’s electricity sector as it navigates these complex challenges within the broader regional context.
