IN Brief:
- Gas-fired generation fell 13.60% to 3,444.30GWh in the week to 20 September.
- Coal and lignite output increased 1.30%, while total thermal generation fell 6.81%.
- The figures show a change in dispatch rather than a direct substitution of coal for gas across individual markets.
Gas-fired electricity generation across Southeast Europe fell 13.60% in the week to 20 September, more than twice the region’s 6.37% reduction in electricity demand and enough to pull total thermal generation lower despite a small increase in coal and lignite output.
Gas-fired production declined from 3,986.41GWh to 3,444.30GWh. Coal and lignite generation increased 1.30% to 3,380.18GWh, while combined thermal generation fell 6.81% to 6,824.48GWh.
The changes were far from uniform. Italy reduced gas-fired generation by 10.86%, Greece by 12.46%, and Türkiye by 26.16%. Bulgaria moved differently, with higher gas output partly offsetting lower coal and lignite generation and leaving its overall thermal production broadly stable.
The regional figures therefore describe a shift in dispatch rather than a straightforward replacement of one fuel by another. Lower demand, renewable output, hydropower conditions, plant availability, fuel prices, carbon costs, network constraints, and cross-border electricity trading all influence which generators run in each market and at each hour.
European Network of Transmission System Operators for Electricity (ENTSO-E) coordinates the European transmission-system framework and operates transparency arrangements covering generation, load, outages, transmission, and balancing data. Those datasets are central to understanding why weekly fuel totals cannot be separated from the wider operating conditions of the interconnected system.
The scale of the gas reduction is notable because gas-fired generation can provide both energy and flexibility. Combined-cycle and open-cycle plants can increase production when wind or solar output falls, when demand rises, or when other generators are unavailable. Their actual running hours, however, depend on whether they are competitive and required within the system at a particular time.
A week of weaker demand can reduce that requirement considerably. If lower consumption coincides with adequate renewable production, hydro, nuclear generation, imports, or cheaper thermal output, gas plants may spend fewer hours in merit. The 13.60% reduction therefore does not imply that the underlying generating capacity disappeared; it records how much less electricity the gas fleet produced during the period.
Fuel and carbon costs also influence that dispatch. Gas-fired generators have to recover gas procurement, carbon allowances, operations, maintenance, and plant cycling through market revenues. Coal and lignite plants face their own fuel and carbon costs, meaning relative competitiveness can shift as commodity prices and carbon prices move.
The small 1.30% increase in coal and lignite output should consequently be treated with care. It was nowhere near large enough to offset the fall in gas-fired generation across the region, and national changes differed materially. The aggregate movement does not establish that solid-fuel generation directly replaced gas-fired production on an hour-by-hour basis.
Modern gas generation is also increasingly valued for operational flexibility rather than continuous high-load operation. ENGIE’s 875MW Flémalle combined-cycle plant in Belgium, for example, was developed with rapid output adjustment among its operating requirements. The project is outside Southeast Europe, but the technical role is relevant as systems add more variable renewable generation.
That flexibility competes with a growing range of alternatives. Batteries can respond rapidly but are limited by stored energy duration; hydropower can provide substantial flexibility where water and reservoir conditions permit; demand response can reduce consumption during tighter periods; and interconnectors can bring electricity from neighbouring systems when capacity is available.
ACER’s 2026 assessment of Southeast Europe identified a shortage of flexible resources as one cause of previous evening price stress, particularly as solar generation fell while demand remained high. The regulator also found that limited cross-border capacity constrained the region’s ability to import lower-priced electricity, and recommended greater participation from storage, demand response, and other flexible assets.
Gas remains part of that portfolio because it can provide sustained dispatchable output for longer periods than many current battery installations. Its use can nevertheless vary substantially from week to week as demand and competing generation change, which is precisely what the latest data demonstrate.
The seasonal direction will become more important as the region approaches winter. Electricity consumption will rise in some markets, solar output will become less productive, wind conditions will remain variable, and gas demand for heating can influence fuel markets at the same time that generators compete for supply.
The week to 20 September left Southeast Europe using materially less gas-fired generation, slightly more coal and lignite, and less thermal generation overall. Whether that pattern continues will depend less on the weekly percentages themselves than on the availability and cost of flexible capacity when autumn and winter demand begin to tighten the system again.
