Thermal generation across Southeast Europe entered a more difficult market environment in Week 21, with conventional economics declining as renewable output increased, electricity demand softened, and regional imports fell sharply. Total thermal generation across SEE decreased 5% week-on-week to 3.84 TWh. Gas-fired output fell 6.6%, while coal and lignite generation declined 2.4%.
Week 21 declines and country-level divergence
The reduction in thermal output coincided with changing operating conditions across the region. Hungary recorded the steepest decline, with thermal generation down 35.8%, driven primarily by lower gas-fired generation. Romania and Serbia also posted double-digit coal declines.
Greece moved in the opposite direction, increasing thermal generation by 4.2%. The increase followed higher gas output, which rose by 7.5%, as wind and hydro production weakened.
Balancing role changes for conventional plants
Despite lower output, thermal assets still support system needs including balancing, reserve capacity and evening ramp stability. The shift changes how conventional plants are dispatched compared with earlier baseload patterns. Thermal units are increasingly activated when renewable output weakens or when demand ramps after solar production fades.
This operational change has financial implications for coal and gas fleets. Plants designed around high utilization rates and stable dispatch face lower annual operating hours, higher start-stop cycling, greater intraday volatility, and a growing reliance on balancing revenues rather than baseload energy sales.
Solar growth raises daytime competition; evening needs persist
Coal-heavy systems such as Serbia and parts of the Western Balkans face stronger pressure under the new dispatch profile. During Week 21, solar generation across SEE increased 8.1%, while electricity demand fell 1.7% regionally.
During daylight hours, thermal plants increasingly struggle to compete against low-marginal-cost renewables. During evening peaks and low-renewable periods, the same plants remain critical for grid stability, leaving fleets with weaker economics but continued operational requirements.
Market mechanisms and gas price pressures
The changing revenue balance is linked to potential shifts in market design. Capacity payments, strategic reserve frameworks and ancillary-service remuneration are expected to become more important as conventional plants lose energy-market revenues while continuing to provide reliability services.
Gas market conditions add another constraint to flexible generation economics. TTF remained close to €50/MWh, supporting elevated fuel costs for gas-fired generation across Europe and keeping flexible gas plants commercially expensive even as system operators rely on them for balancing intermittent renewables.
Wholesale price differences across Italy and Serbia
Southeast Europe also faces a transition where renewables increasingly set daytime pricing while large-scale storage is not yet deployed widely enough to fully replace thermal flexibility. This creates a period in which systems require conventional backup but cannot always sustain it economically through wholesale markets alone.
Italy illustrated this pricing divergence by remaining the highest-priced market at €116.31/MWh. 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.
Implications for thermal valuation and investment priorities
The price gap increases pressure on thermal operators in lower-priced markets across SEE, including Serbia, Bulgaria and Romania. Coal and gas plants may see worsening margins unless they secure additional balancing-market revenues or receive regulatory support mechanisms.
For investors, the basis for valuing thermal assets shifts away from annual generation volume toward flexibility capability, ramp speed, minimum stable load, start-up economics, fuel efficiency, access to ancillary services, and balancing-market participation.
Technology fit for flexibility; effects on renewables and consumers
Older inflexible coal assets become more exposed under the new dispatch pattern. More efficient gas turbines and hybrid systems integrated with storage may retain strategic value longer because they can respond faster to renewable intermittency.
The change also affects renewable project development decisions as captured pricing becomes more dependent on system marginality during solar-heavy periods. Industrial consumers may see temporary benefits from lower wholesale prices, while system costs shift toward balancing infrastructure, reserve mechanisms and grid investments needed for reliability in a renewable-heavy system.
Cross-border flows and future functions of thermal generation
The cross-border market reinforces the transition dynamics as net regional imports fell by 34.6%. Stronger renewable availability reduced reliance on imported thermal generation, while domestic solar and hydro availability increases direct competition for thermal fleets.
Over time, thermal generation’s role in Southeast Europe is expected to narrow toward three functions: system balancing, security-of-supply support, and seasonal reliability during weak renewable periods. In that structure, conventional plants remain necessary but no longer dominate pricing or investment logic based solely on energy-market volumes.
