Week 21 brought a decline in conventional generation economics across Southeast Europe as renewable output increased, electricity demand softened, and regional imports fell. Total thermal generation across the region decreased 5% week-on-week to 3.84 TWh. Gas-fired output fell 6.6%, while coal and lignite generation declined 2.4%.
Lower thermal output can coincide with decarbonisation trends, but the operational role of thermal plants remains linked to system needs. Thermal assets are seeing fewer operating hours and reduced pricing power. At the same time, power systems continue to rely on them for balancing, reserve capacity, and evening ramp stability.
Country-level changes in thermal generation during Week 21
Hungary recorded the steepest thermal decline in the region, with output down 35.8%. The fall was primarily attributed to reduced gas-fired generation. Romania and Serbia also reported double-digit declines in coal output.
Greece moved in the opposite direction, increasing thermal generation by 4.2%. Gas output rose by 7.5% as weaker wind and hydro production required additional thermal supply.
From baseload dispatch to balancing activation
The regional divergence reflects a change in how conventional plants are used within power systems. Instead of operating only as baseload units, thermal plants are increasingly activated when renewable output weakens. They are also called on when evening demand ramps after solar production fades.
This operational shift affects financial outcomes for coal and gas generators. Plants designed for high utilisation and relatively stable dispatch face lower annual operating hours, more start-stop cycling, and greater intraday volatility. They also become more dependent on balancing revenues rather than baseload energy sales.
Solar growth, demand softness, and price pressure
Coal-heavy systems such as Serbia and parts of the Western Balkans face particular pressure under the evolving dispatch pattern. During Week 21, solar generation across Southeast Europe increased 8.1%. Regional electricity demand fell by 1.7%.
During daylight hours, thermal units increasingly struggle against low-marginal-cost renewable generation. During evening peaks and low-renewable periods, those same plants remain important for grid stability. The result is a combination of weaker economics and continued operational necessity for thermal fleets.
Market mechanisms for reliability services
The shift in revenue sources is expected to increase the importance of market mechanisms tied to reliability. Capacity payments, strategic reserve frameworks, and ancillary-service remuneration are described as likely to grow in relevance as conventional plants lose energy-market revenues while continuing to provide reliability services.
Gas market conditions add further constraints on generator economics. The TTF benchmark remained close to €50/MWh, keeping fuel costs elevated for gas-fired generation across Europe. This sustains commercial pressure on flexible gas plants even where system operators require them for balancing intermittent renewables.
Wholesale price divergence across Italy and Serbia
Southeast Europe is described as facing a transition where renewables increasingly influence daytime pricing while large-scale storage is not yet deployed widely enough to replace thermal flexibility fully. This creates a period where conventional backup is needed but may not be supported economically through wholesale markets alone.
Italy illustrates the pricing outcome of that structure despite weaker regional prices. Italy remained the highest-priced market at €116.31/MWh, supported by dependence on flexible gas-fired generation and imports that raise clearing prices during evening balancing periods.
Serbia’s average price fell to €81.24/MWh, reflecting how solar-heavy conditions and lower demand can suppress prices even in coal-oriented systems. The divergence increases pressure on coal and gas operators in lower-priced markets including Serbia, Bulgaria, and Romania.
Implications for investment valuation and plant design
The changing revenue profile affects how thermal assets are valued by investors. Future value is expected to depend less on annual generation volume and more on flexibility capability, ramp speed, minimum stable load, start-up economics, fuel efficiency, access to ancillary services, and participation in balancing markets.
Older inflexible coal assets are described as becoming more exposed under this framework. More efficient gas turbines and hybrid configurations integrated with storage may retain strategic value longer because they can respond faster to renewable intermittency.
Cross-border flows and seasonal reliability roles
The regional cross-border market reinforces the transition dynamics described for Southeast Europe. Net regional imports fell by 34.6%, indicating reduced reliance on imported thermal generation as renewable availability improved.
This also means domestic solar and hydro compete more directly with thermal fleets rather than imports tightening supply conditions structurally across the region.
The role of thermal generation over time is expected to narrow toward three functions: system balancing, security-of-supply support, and seasonal reliability during weak renewable periods. Week 21 is presented as evidence that the electricity transition in Southeast Europe is increasingly a flexibility transition rather than only an expansion of renewables.