Electricity-market participants across Central and Southeast Europe are evaluating how proposed changes to the EU carbon market could affect longer-term expectations for carbon prices while power continues to be priced using hourly generation costs, fuel availability and cross-border transmission constraints. A provisional EU agreement on the Market Stability Reserve is expected to influence expectations, but it does not immediately alter allowance supply or the operating economics of power plants.
On October 20, EU negotiators reached a provisional agreement to increase the threshold for permanent invalidation of allowances under the MSR from 400 million to 700 million allowances. The agreement was announced on October 21 and remains subject to formal adoption. It would not immediately release additional allowances or set a fixed emissions price.
Because of that, any impact on wholesale electricity prices remains a scenario for assessment rather than an observed market outcome. Allowance costs are described as one element of generation costs alongside natural gas, coal, hydropower availability and weather-dependent renewable output.
How fuel costs and plant performance shape carbon exposure
The short-run generation cost of a gas-fired power plant depends on its gas procurement price, heat rate, variable operating expenses and the number of EU ETS allowances required to cover emissions. Coal-fired generators are described as having different fuel-cost and carbon-intensity profiles compared with gas units.
When natural gas is competitively priced, a higher allowance price can make coal generation less attractive relative to gas. The point at which switching occurs depends on heat rates and emissions intensities across the compared plants, so there is no single carbon surcharge per megawatt-hour that applies to every thermal generator.
Across the region, traders monitor exchanges including HUPX in Hungary, OPCOM in Romania, IBEX in Bulgaria, SEEPEX in Serbia and CROPEX in Croatia. Prices are said to vary with generation availability, local demand and the capacity available for electricity imports or exports.
A higher Hungarian wholesale price relative to Romanian or Bulgarian prices may signal a potential cross-border trading opportunity. Transmission-capacity costs, network losses, nomination requirements and imbalance exposure can reduce or eliminate any apparent margin.
Renewables output and grid limits affect hourly power prices
During periods of strong solar or wind generation, additional renewable output can depress exchange prices even if carbon allowance movements do not change. Thermal generators may regain greater influence on market prices during evening peaks or when renewable production is low.
Batteries and demand-response measures can moderate extreme price movements but do not remove differences in marginal generation costs between individual hours. In hydrologically variable markets such as Montenegro and Albania, water inflows add uncertainty for price forecasts.
Carbon-price sensitivity is estimated by multiplying a change in the EU allowance price by a thermal plant’s verified emissions per megawatt-hour. In an illustrative example, a generator emitting 0.4 tonnes of CO₂ per MWh would incur an additional €4/MWh in carbon-related generation costs if the allowance price rose by €10/tCO₂, assuming other factors remain unchanged.
The calculation is not treated as proof that wholesale electricity prices would rise by €4/MWh. The effect depends on whether the plant sets the marginal price and on competition from imports and other available generation sources.
CBAM treatment for imported electricity uses embedded emissions factors
Electricity imported into the EU from certain non-exempt third countries is covered by the Carbon Border Adjustment Mechanism (CBAM). For electricity, certificate costs are calculated using electricity-specific embedded emissions expressed in tonnes of CO₂ equivalent per megawatt-hour rather than the emissions approach used for steel products.
The published CBAM certificate price for Q3 2026 is €82.32/tCO₂e. The carbon component of an imported megawatt-hour depends on the applicable electricity emissions factor and whether eligible actual-emissions data can be used under relevant rules.
As an illustration, chargeable emissions of 0.5 tCO₂e/MWh multiplied by €82.32/tCO₂e would yield a carbon cost of €41.16/MWh before any legally applicable deductions or exceptions. The example is described as a sensitivity calculation rather than a universal charge for imported electricity.
Actual transactions must use the applicable methodology and either default or verified emissions values. A forward wholesale-price spread of €20/MWh may not be sufficient to cover border-carbon exposure if applicable emissions costs are materially higher.
Commission proposals on electricity emissions defaults remain under negotiation
The European Commission’s COM(2025)989 proposal includes changes related to electricity emissions defaults and conditions for using actual emissions data. Proposed adjustments, including possible changes to contractual treatment, are described as remaining under negotiation rather than already in force.
The existing framework includes cumulative conditions such as a qualifying power purchase agreement (PPA), evidence concerning the electricity network, generation emissions limits, hourly capacity nomination and verifier assurance. Traders and investors are described as needing to distinguish current requirements from potential changes emerging from the legislative process.
The interaction between hourly power prices and transmission constraints is described as making carbon-market reform impacts particularly nonlinear. If a gas-fired generator sets marginal prices in one hour, carbon-cost changes can influence clearing prices; if solar, hydropower or imported electricity sets marginal prices in another hour, effects may be limited or absent.
A transmission-line outage can also reverse regional price spreads without movement in fuel or carbon prices. Market analysis therefore requires hourly dispatch scenarios rather than adding a fixed carbon premium to annual average electricity prices.
Carbon costs can change revenue distribution between generators and consumers
Changes in marginal generation costs can affect how revenues are distributed between generators and consumers. When carbon costs raise wholesale market-clearing prices, generators with low variable costs may receive higher revenues due to their position in the market merit order.
The magnitude of those gains depends on contractual hedging, regulatory arrangements, renewable generation cannibalisation and curtailment. Energy-intensive consumers may face higher electricity bills even when their direct emissions are low.
The provisional MSR agreement does not resolve these distributional effects. Measures intended to support industrial competitiveness may require consideration of grid investment, electricity procurement arrangements and industrial demand alongside the supply of emissions allowances.
Separate assessments needed for wholesale ETS exposure and CBAM import costs
Banks financing wind farms, gas-fired power plants, battery storage and electricity interconnectors are described as needing two distinct exposures: wholesale-market prices under potential EU ETS reforms and electricity-import CBAM costs based on applicable emissions methodology and supporting evidence.
The proposed increase in the allowance invalidation threshold may affect longer-term expectations for the carbon market but does not by itself determine hourly dispatch. It also does not guarantee a particular wholesale price or establish import costs across an EU border.
Each megawatt-hour must still be assessed using its commercially available transmission route, whether it is from the unit setting marginal market pricing in that hour, and the emissions calculation applicable to the relevant transaction.