Rising European natural gas prices are improving the short-term competitive position of coal and lignite generation in Southeast Europe, even as the region continues adding renewable capacity and preparing for tighter carbon constraints.
Gas-fired generation across monitored Southeast European markets fell 30.3% to 2.72 TWh in Week 34 compared with Week 30, while coal and lignite output increased 6.76%.
Overall thermal generation still declined 13.1% to 6.34 TWh, meaning the movement was not a broad return to fossil generation but a change in the composition of the thermal fleet.
European TTF gas averaged about €63.99/MWh between Aug. 17 and 21 and reached €65.87/MWh at the end of that period.
Gas markets have tightened further since then, with European benchmark prices moving above €75/MWh by early September amid concerns over winter supplies.
That matters directly for power prices.
Combined-cycle gas plants can be among the most efficient thermal generators in the region, but their marginal cost rises rapidly when fuel prices increase. Coal and lignite stations with secure domestic fuel supplies can therefore regain dispatch hours even when they face higher carbon costs.
The trend is particularly relevant in Serbia, Bosnia and Herzegovina, Bulgaria, North Macedonia, Romania and parts of the wider central and eastern European market where coal or lignite capacity remains available.
It does not represent 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 shift is instead a reminder that the short-term merit order and long-term investment order are not the same thing.
A lignite plant that is unlikely to attract capital for another 30 years of operation can still be economically valuable during a week when gas prices surge, wind generation falls and evening electricity prices rise above €200/MWh.
The importance of that optionality increases as renewable penetration grows.
Solar can cover a larger portion of daytime consumption, but the system still requires dispatchable generation after sunset. If batteries, hydroelectric plants, demand response and imports cannot fill the gap, thermal plants become the residual provider.
The cost of that residual megawatt-hour determines wholesale prices.
Gas prices therefore 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 move coal ahead of gas in dispatch, increasing coal utilisation.
The region is consequently entering an awkward transition period.
Renewable generation is growing quickly enough to reduce average fossil-fuel utilisation but not yet quickly enough, or with enough storage, to eliminate thermal capacity from scarcity periods.
High gas prices make that transition more expensive and strengthen the near-term economic value of existing coal plants.
For Southeast European electricity markets, coal’s role is increasingly less about providing uninterrupted baseload and more about retaining dispatchable capacity when other sources are unavailable or too expensive.
The cleaner system emerging over the longer term is therefore, for now, still dependent on an old fuel whenever gas becomes sufficiently costly.
