Electricity-market participants across Central and Southeast Europe are evaluating proposed changes affecting the EU carbon market while continuing to set power prices using hourly generation costs, fuel availability and cross-border transmission constraints. A provisional agreement on the EU Market Stability Reserve may affect longer-term expectations for carbon prices. It does not immediately alter allowance supply or the operating economics of power plants.
On October 20, EU negotiators reached a provisional deal 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. The deal would not immediately release additional allowances or set a fixed emissions price.
Wholesale electricity price impacts are therefore expected to be assessed as scenarios rather than treated as an observed outcome. Carbon allowances remain one element of generation costs alongside natural gas, coal, hydropower availability and weather-dependent renewable output.
Gas and coal costs linked to EU ETS allowance 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 EU ETS allowances required to cover emissions. Coal-fired generators face 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 the heat rates and emissions intensities of the specific plants being compared. As a result, there is no single carbon surcharge per megawatt-hour that applies uniformly across thermal generators.
Traders in the region monitor exchanges including HUPX in Hungary, OPCOM in Romania, IBEX in Bulgaria, SEEPEX in Serbia and CROPEX in Croatia. Prices vary based on generation availability, local demand and the capacity available for imports or exports.
A higher wholesale price in Hungary compared with Romania or Bulgaria can 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, storage and outages influence hourly clearing prices
During periods of strong solar or wind output, additional renewables can depress exchange prices independently of changes in carbon allowances. Thermal generation can regain influence during evening peaks or during periods of lower renewable production.
Batteries and demand-response measures can moderate extreme price movements, but they do not remove differences in marginal generation costs across individual hours. In hydrologically variable markets such as Montenegro and Albania, water inflows add another uncertainty factor for price forecasts.
The sensitivity of power costs to carbon-price changes can be estimated by multiplying an allowance-price move 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 add €4/MWh in carbon-related generation costs if the allowance price rose by €10/tCO₂, assuming other factors remain unchanged.
The €4/MWh illustration does not imply wholesale prices would increase by the same amount. The effect depends on whether the unit sets the marginal price in a given hour and on competition from imports and other available generation sources.
CBAM treatment for imported electricity uses electricity-specific embedded emissions
Electricity imported into the EU from certain non-exempt third countries is covered by CBAM. Certificate costs are calculated using electricity-specific embedded emissions expressed in tonnes of CO₂ equivalent per megawatt-hour rather than the emissions calculation used for steel products.
The published CBAM certificate price for Q3 2026 is €82.32/tCO₂e. The carbon component for an imported megawatt-hour depends on the applicable electricity emissions factor and whether eligible actual-emissions data can be used under relevant rules.
For illustration, chargeable emissions of 0.5 tCO₂e/MWh multiplied by €82.32/tCO₂e would equal €41.16/MWh in carbon cost before any legally applicable deductions or exceptions. This is presented as a sensitivity calculation rather than a universal charge for imported electricity.
Actual transactions must apply the applicable methodology and use default or verified emissions values as required. 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 proposal on electricity emissions defaults remains 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, remain under negotiation and are not treated as rules 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 expected to distinguish these current requirements from potential changes emerging through the legislative process.
The interaction between hourly power prices and transmission constraints can make carbon-market reform effects nonlinear across hours. If a gas-fired generator sets marginal price in one hour, changes in carbon costs can affect clearing prices; if solar, hydropower or imported electricity sets marginal price in a following hour, the effect 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 applying a fixed carbon premium to annual average electricity prices, which is relevant for wind-farm valuations and battery-storage arbitrage.
Carbon-cost shifts 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 within the market merit order.
These outcomes depend on contractual hedging, regulatory arrangements, renewable generation cannibalisation and curtailment patterns. Energy-intensive consumers may face higher electricity bills even when their own direct emissions are low.
The provisional MSR agreement does not resolve distributional effects tied to changes in marginal costs. Measures intended to support industrial competitiveness may require consideration beyond allowance supply, including grid investment, electricity procurement arrangements and industrial demand alongside emissions-allowance supply.
Banks assess separate wholesale ETS scenarios and import CBAM exposures
Banks financing wind farms, gas-fired power plants, battery storage and electricity interconnectors need to assess 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 influence longer-term expectations for the carbon market but does not determine hourly dispatch by itself. It also does not guarantee any particular wholesale price level or establish import costs across an EU border.
Each megawatt-hour still needs assessment based on its commercially available transmission route, which generator sets the marginal market price for that hour, and which emissions calculation applies to the relevant transaction.