BUDAPEST/BUCHAREST, Oct. 22, 2026 – Electricity-market participants across Central and Southeast Europe are assessing the implications of proposed changes to the EU carbon market while continuing to price power according to hourly generation costs, fuel availability and cross-border transmission constraints. The EU’s provisional agreement on its Market Stability Reserve could influence longer-term expectations for carbon prices, but it does not immediately change allowance supply or the operating economics of power plants.
On October 20, EU negotiators reached a provisional agreement to raise the threshold for permanent invalidation of allowances under the Market Stability Reserve (MSR) from 400 million to 700 million allowances. Announced on October 21, the agreement remains subject to formal adoption. It would not immediately release additional allowances or establish a fixed emissions price.
The direct effect on wholesale electricity prices therefore remains a scenario to be assessed rather than an observed market outcome. Carbon allowances are one component of generation costs, alongside natural gas, coal, hydropower availability and weather-dependent renewable output.
Fuel costs and plant efficiency determine carbon-price 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 Emissions Trading System (EU ETS) allowances required to cover its emissions.
Coal-fired generators have different fuel-cost and carbon-intensity profiles. When natural gas is competitively priced, a high allowance price can make coal generation less attractive relative to gas. The switching threshold depends on the heat rates and emissions intensities of the plants being compared, meaning there is no universal carbon surcharge per megawatt-hour that applies to every thermal generator.
Power traders across the region monitor exchanges including HUPX in Hungary, OPCOM in Romania, IBEX in Bulgaria, SEEPEX in Serbia and CROPEX in Croatia. Prices vary with generation availability, local demand and the capacity available to import or export electricity.
A higher Hungarian wholesale price relative to Romanian or Bulgarian prices may indicate a potential cross-border trading opportunity. However, transmission-capacity costs, network losses, nomination requirements and imbalance exposure can reduce or eliminate the apparent margin.
Renewable output and transmission constraints reshape hourly prices
During periods of strong solar or wind generation, additional renewable output can depress exchange prices independently of movements in carbon allowances. Thermal generators may regain a greater influence on market prices during evening peaks or periods of low renewable production.
Batteries and demand-response measures can moderate extreme price movements, although they do not eliminate the underlying differences in marginal generation costs between individual hours. In hydrologically variable markets such as Montenegro and Albania, water inflows add another source of uncertainty to price forecasts.
Carbon-price sensitivity can be estimated by multiplying a change in the EU allowance price by the relevant thermal plant’s verified emissions per megawatt-hour. In an illustrative calculation, 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 increased by €10/tCO₂, assuming all other factors remained unchanged.
That calculation does not mean the wholesale electricity price would necessarily rise by €4/MWh. The outcome depends on whether the plant sets the marginal price, as well as competition from imports and other available generation sources.
Electricity imports face a separate CBAM cost calculation
Electricity imported into the EU from certain non-exempt third countries is itself covered by the Carbon Border Adjustment Mechanism (CBAM). Its certificate cost is 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 of an imported megawatt-hour depends on the applicable electricity emissions factor and whether the importer can use eligible actual-emissions data under the relevant rules.
For illustration, chargeable emissions of 0.5 tCO₂e/MWh, multiplied by the certificate price of €82.32/tCO₂e, would represent a carbon cost of €41.16/MWh before any legally applicable deductions or exceptions.
This is a sensitivity calculation, not a universal charge for imported electricity. Actual transactions must use the applicable methodology and the relevant default or verified emissions value. A forward wholesale-price spread of €20/MWh, for example, may not be sufficient to cover the border-carbon exposure if the applicable emissions cost is materially higher.
Proposed electricity rules remain subject to negotiation
The European Commission’s COM(2025)989 proposal includes changes concerning electricity emissions defaults and the conditions for using actual emissions. Proposed adjustments, including possible changes to contractual treatment, remain under negotiation and should not be treated as rules already in force.
The existing framework’s cumulative conditions include a qualifying power purchase agreement (PPA), evidence concerning the electricity network, generation emissions limits, hourly capacity nomination and verifier assurance. Traders and investors need to distinguish these current requirements from changes that may emerge from the legislative process.
The interaction between hourly power prices and transmission constraints makes the impact of carbon-market reform particularly nonlinear. If a gas-fired generator sets the marginal price in one hour, a change in carbon costs can influence the clearing price. If solar, hydropower or imported electricity sets the marginal price in the following hour, the effect may be limited or absent.
A transmission-line outage can also reverse regional price spreads without any movement in fuel or carbon prices. Market analysis therefore needs hourly dispatch scenarios rather than a fixed carbon premium added to annual average electricity prices. This distinction is relevant to wind-farm valuations and battery-storage arbitrage.
Carbon costs redistribute revenues across electricity markets
Changes in marginal generation costs can also affect the distribution of revenues between generators and consumers. When carbon costs raise the wholesale market-clearing price, generators with low variable costs may receive higher market revenues because of their position in the market merit order.
Those gains depend on contractual hedging, regulatory arrangements, renewable generation cannibalisation and curtailment. Energy-intensive consumers may face higher electricity bills even when their own direct emissions are low.
The provisional Market Stability Reserve agreement does not resolve these distributional effects. Measures intended to support industrial competitiveness may also require consideration of grid investment, electricity procurement arrangements and industrial demand, alongside the supply of emissions allowances.
Investors need separate wholesale and border-carbon scenarios
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 the applicable emissions methodology and supporting evidence.
The proposed increase in the allowance invalidation threshold may affect longer-term expectations for the carbon market. It does not, by itself, determine hourly dispatch, guarantee a particular wholesale price or establish the cost of importing electricity across an EU border.
Each megawatt-hour must still be assessed in terms of its commercially available transmission route, the generation setting the marginal market price and the emissions calculation applicable to the relevant transaction.
