February 2026 delivered a clear signal for Southeast Europe’s grid operators: even with renewables gaining momentum, thermal generation—especially lignite and coal—continued to provide the operational backbone. The month combined sharp price compression with pronounced swings in solar and wind output, reinforcing how dispatchable capacity remains central to system adequacy. For developers and grid investors, the takeaway is less about coal disappearing and more about how market roles are being redefined as variable generation expands.
Serbia’s lignite share holds the system baseline
In Serbia, lignite remained the dominant generation source at 53.01%, outpacing every other fuel in the mix. Renewable output rose by 23.10%, yet coal still set the baseline for how the system was run during the month. This pattern points to a structural constraint: where flexible capacity is limited and renewable penetration remains modest, coal functions as the primary balancing mechanism rather than a purely legacy asset.
Price signals also underscored this shift in market dynamics. Serbia recorded the steepest regional drop in spot prices, falling by 41.92% to €68.61/MWh. The decline was linked to marginal displacement of coal during periods of higher renewable output and lower demand, indicating that coal increasingly acts as a price floor rather than the driver of peak pricing.
Regional thermal dependence persists despite volatility
Bulgaria and Türkiye both maintained substantial coal/lignite exposure in February, highlighting that thermal generation continues to play a meaningful role across multiple market designs. Bulgaria’s electricity mix included 22.91% coal/lignite, while Türkiye’s system remained heavily coal-reliant at 34.89%. These shares reflect ongoing reliance on dispatchable generation in contexts where nuclear or large-scale gas capacity is not sufficient to fully absorb variability from wind and solar.
At the same time, the economic position of coal is changing as renewables penetrate further into dispatch schedules. As renewable output increases, coal plants are pushed out of the merit order more often, resulting in fewer operating hours and lower load factors. For utilities and operators planning grid modernization, this translates into a need to manage not only peak adequacy but also ramping requirements and reliability during shifting dispatch conditions.
Different system mixes shape coal’s operating role
The transition away from dominant baseload operation is not uniform across countries with different generation portfolios. In Bulgaria, nuclear power provides a stable baseload, leaving coal to operate more as a mid-merit or balancing source when conditions require it. That division of labor matters for planning studies because it affects how often thermal plants are called on to respond to forecast errors and intraday variability.
Türkiye’s structure differs: coal sits within a diversified system alongside hydro at 31.70% and renewables at 23.12%. In practice, this means coal’s role can range from baseload anchor to flexible backup depending on hydrology and renewable availability. For engineering teams preparing grid reinforcement or flexibility roadmaps, these contrasting mixes imply that one-size-fits-all assumptions about reserve margins and balancing strategies will not hold.
Lower prices pressure economics while services remain essential
Across the region, February reinforced how wholesale price compression can squeeze thermal economics even when plants remain operationally important. Lower prices reduce margins, while variability in renewable output adds operational uncertainty for assets designed for steadier production profiles. Coal units are therefore being forced into more flexible operating modes more frequently, which can raise maintenance demands and reduce efficiency.
Despite these pressures, coal continued to support system adequacy when renewables weakened or became more volatile. When solar output declined in southern markets and wind variability increased elsewhere, coal plants helped maintain reliability during periods when variable generation could not fully cover demand needs. This tension—economic displacement alongside continued operational indispensability—has direct implications for how future procurement frameworks should value flexibility and grid services.
Cross-border flows intensify competition for dispatchable generation
Interconnector dynamics further complicate thermal exposure by increasing competition from neighboring markets with stronger renewable performance. As renewable surpluses move across borders, coal generation becomes more exposed to external displacement during periods of strong wind generation in Romania and Hungary. The resulting regional merit order means coal competes not only with domestic renewables but also with imported renewable electricity.
For investors and contractors supporting transmission infrastructure upgrades, this matters because cross-border congestion management and scheduling coordination can determine whether domestic thermal plants are required more often or curtailed earlier in real time. Technical studies that focus on transfer capacity limits and operational constraints therefore become central inputs into investment planning for both interconnection expansions and balancing resources such as battery energy storage systems.
Implications for project readiness across grids and flexibility buildouts
Looking ahead, Southeast Europe’s near-term outlook suggests coal will not disappear quickly due to its continuing importance for stability and energy security. However, February data captures an evolving function: coal is shifting from dominant baseload toward residual balancing capacity as renewables reshape trading patterns. For utilities planning engineering studies, EPC preparation, and procurement sequencing, the priority is aligning grid modernization with the reality that dispatchable assets may be called on differently—not less reliably.
Broader industry implications follow from this operational picture: developers assessing wind and solar expansion will need coordinated planning for transmission reinforcement, flexibility assessments, and resource adequacy under variable output conditions. At the same time, investors evaluating battery energy storage systems should treat market price compression as a design constraint while recognizing that system services during renewable swings remain a key driver of value in many SEE markets.