Thermal generation reaffirmed its role as the primary price-setting force across Southeast Europe’s electricity markets during Week 26 (22–28 June 2026), as rising temperatures and stronger electricity demand increased reliance on conventional power plants. Regional thermal generation climbed 24.7% week on week to 6.52 TWh, with gas-fired output rising 25.5% (+803 GWh) and coal and lignite generation increasing 23.6% (+490 GWh). The figures highlight the continued importance of dispatchable generation in maintaining system reliability during periods of peak summer demand.
The latest market data provide an important reminder that, despite the rapid expansion of renewable energy across the region, thermal power plants continue to determine wholesale electricity prices during periods of market stress. Wind generation strengthened in several countries, solar maintained strong daytime production and hydropower continued to support balancing where available. However, as hydroelectric output declined and cooling demand accelerated, gas, coal and lignite plants became the dominant sources of flexible generation, setting marginal prices across much of Southeast Europe.
Italy provided the clearest example of this trend. Gas-fired generation surged 47.5% compared with the previous week, while coal-fired production more than tripled, pushing total thermal generation up by 50.8%. The increase was accompanied by one of the region’s highest wholesale electricity prices, with the Italian market averaging €144.67/MWh during the week. Given Italy’s strategic role in linking European gas and electricity markets, developments in its thermal generation fleet continue to influence price formation across the Adriatic and Southern European trading region.
Other Southeast European markets followed a similar pattern. Greece increased gas-fired generation by 12.6%, while lignite-fired power returned to the generation mix after recording no output during Week 25. Serbia expanded lignite generation by 17.9%, reinforcing the role of coal in meeting higher cooling demand. Hungary, Croatia and Bulgaria also increased thermal electricity production as regional demand strengthened. Romania was the notable exception, with a slight decline in overall thermal generation as lower gas-fired output offset higher coal generation. Meanwhile, Türkiye recorded a modest increase in thermal production, driven by stronger coal generation despite lower gas-fired output.
The stronger contribution from thermal power plants does not signal a slowdown in the region’s energy transition. Instead, it highlights the current shortage of flexible low-carbon capacity capable of replacing conventional generation during periods of peak electricity demand. Until investments in battery energy storage systems (BESS), demand response, transmission interconnections and dispatchable renewable technologies become more widespread, thermal generation will continue to play the decisive role in setting wholesale electricity prices during scarcity periods.
These market dynamics carry significant implications for both electricity consumers and renewable energy developers. Renewable projects that generate primarily during periods of abundant solar production may face increasing price cannibalisation, while assets capable of delivering electricity during high-value evening peak hours stand to capture stronger revenues. Similarly, corporate power purchase agreements (PPAs) that focus only on annual energy volumes without addressing hourly balancing requirements and peak-period costs may prove less cost-effective during periods of elevated summer demand.
Week 26 demonstrated that Southeast Europe’s electricity transition is no longer defined solely by the pace of renewable capacity additions. Increasingly, the key challenge is replacing the price-setting role of thermal generation with flexible, low-carbon resources capable of maintaining system reliability during the hours when electricity demand—and market value—are at their highest.
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