Gas-fired generation in monitored Southeast European markets fell 30.3% to 2.72 TWh in Week 34 compared with Week 30, while coal and lignite output rose 6.76%. Overall thermal generation declined 13.1% to 6.34 TWh, indicating the change was limited to the composition of thermal supply rather than a broad shift back to fossil fuels.
European TTF gas averaged about €63.99/MWh between Aug. 17 and 21, rising to €65.87/MWh at the end of that period. Since then, gas markets have tightened further, with European benchmark prices moving above €75/MWh by early September amid concerns over winter supplies. That pricing development feeds through directly into power-market outcomes.
Fuel costs and dispatch economics across the region
Combined-cycle gas plants can be among the most efficient thermal generators in the region, but their marginal cost increases rapidly when fuel prices rise. Coal and lignite stations with secure domestic fuel supplies can therefore regain dispatch hours even when carbon costs are higher.
The pattern is particularly relevant in Serbia, Bosnia and Herzegovina, Bulgaria, North Macedonia, and Romania, along with parts of the wider central and eastern European market where coal or lignite capacity remains available. It does not indicate a reversal of the longer-term transition away from coal.
European carbon pricing, ageing generating units, environmental requirements, and national decarbonisation commitments continue to make new coal investment difficult. The short-term merit order for dispatch is therefore not aligned with the long-term investment order for new capacity.
Renewables growth, scarcity periods, and wholesale price formation
A lignite plant that is unlikely to attract capital for another 30 years of operation can still be economically valuable during weeks when gas prices surge, wind generation falls, and evening electricity prices rise above €200/MWh. The value of that flexibility increases as renewable penetration grows.
Solar can cover a larger share of daytime consumption, but dispatchable generation is still required after sunset. If batteries, hydroelectric plants, demand response, and imports cannot cover the remaining demand, thermal plants become the residual provider.
The cost of that residual megawatt-hour determines wholesale prices. Gas prices continue to influence Southeast European electricity even when gas plants generate fewer megawatt-hours.
A relatively small amount of expensive gas-fired generation can set the marginal price during tight hours. Alternatively, high gas costs can shift dispatch so that coal moves ahead of gas, increasing coal utilisation.
Tightening supply outlook and an uneven transition period
The region is entering an “awkward transition period” as renewable output grows quickly enough to reduce average fossil-fuel utilisation but not quickly enough, or with enough storage, to remove thermal capacity from scarcity periods. Higher gas prices make this transition more expensive and increase the near-term economic value of existing coal plants.
In Southeast European electricity markets, coal’s role is increasingly tied to retaining dispatchable capacity when other sources are unavailable or too expensive rather than supplying uninterrupted baseload. For now, the cleaner system developing over the longer term remains dependent on an older fuel whenever gas becomes sufficiently costly.
