For decades, electricity systems in South-Eastern Europe were organised around the concept of baseload. Large lignite units, supplemented by hydropower and limited gas capacity, ran continuously to meet predictable demand profiles. Dispatch followed a relatively stable hierarchy: coal first, hydro as seasonal modulation, imports as marginal adjustment. This architecture shaped not only technical planning, but also political narratives around energy security and sovereignty.
That model has now decisively broken down.
Across South-Eastern Europe, the defining feature of electricity dispatch is no longer continuity but optionality. Generation assets are increasingly valued not for how many hours they run, but for when they can run, how fast they can respond, and whether they can stabilise the system during stress periods. Baseload, as a conceptual category, has lost its operational meaning.
The data from the past two years make this shift unmistakable. Lignite and coal units across the region have seen sharp declines in load factors, not because capacity has disappeared, but because price formation and system needs no longer reward continuous operation. In several SEE systems, coal plants that historically operated at 70–80 percent annual utilisation are now frequently dispatched at 40–55 percent, with extended periods of ramp-down during high renewable output and imports. These units have effectively transitioned from baseload producers to residual suppliers, filling gaps when other sources are unavailable.
This transition is not primarily ideological. It is market-driven. Wind and solar generation increasingly set the marginal price during large portions of the year. When wind conditions are strong or solar output is high, thermal units are pushed out of the merit order, regardless of their historical role. When renewables fade, the system calls on whatever assets can respond quickly enough. In that environment, flexibility outweighs continuity.
Gas-fired generation illustrates this change most clearly. In classical system design, gas plants were expected to provide mid-merit or peak supply. In today’s SEE markets, gas plants increasingly operate as system insurance assets. They may run only a few hundred hours per year, yet their presence is critical during scarcity events. When wind collapses across the region or cross-border imports are constrained, gas units often become the marginal price setters, driving prices into the €150–250/MWh range during tight weeks, and much higher during extreme events.
Hydropower, long considered the region’s natural stabiliser, has also shifted roles. Rather than acting as a steady baseload supplement, hydro increasingly behaves as a strategic flexibility reserve. Reservoir operators optimise output around price signals, preserving water during low-price renewable surges and releasing it during evening peaks or import constraints. In drought-affected years, this flexibility is sharply reduced, exposing the system to higher volatility and reinforcing the insurance role of gas and imports.
The result is a dispatch landscape defined by optionality. Assets are valuable not because they run all the time, but because they can run when others cannot. This has profound economic implications. Low utilisation rates undermine traditional cost recovery models. Plants designed for baseload economics struggle to recover fixed costs when operating hours fall below 4,000 hours per year, let alone 2,500–3,000 hours, which is now common for several thermal units in SEE.
This is where market design tension emerges. Electricity markets remunerate energy, not availability. In a system where assets are increasingly valued for availability rather than output, pure energy-only pricing produces revenue instability. This instability is already visible. Several SEE utilities have reported that thermal assets essential for security of supply are commercially loss-making at current utilisation patterns, even though they remain system-critical.
The policy response has been uneven. Some countries have introduced or are considering capacity mechanisms, while others rely on state-owned utilities to absorb losses implicitly. Yet the underlying issue is structural. The end of baseload dispatch means that the region must explicitly decide how to pay for optionality.
From a system perspective, optionality has measurable value. During summer 2024 stress events, when solar output collapsed in the evening and imports were constrained, prices in parts of South-Eastern Europe spiked above €1,000/MWh for individual hours. These prices were not signals of fuel scarcity; they were signals of insufficient optionality. Assets capable of responding during those hours effectively prevented load shedding, industrial disruption, or emergency imports at even higher cost.
The economic logic therefore shifts from “least-cost energy” to “least-cost resilience.” This does not imply abandoning renewables or decarbonisation. It implies recognising that in a high-renewable system, dispatchable assets must be compensated for standing ready, not only for producing energy.
For South-Eastern Europe, this shift is particularly acute because the region lacks several buffers available elsewhere. Unlike France, it has limited nuclear baseload. Unlike the Nordics, it cannot rely indefinitely on hydrological abundance. Unlike Germany, it does not yet have deep storage or fully developed demand response. Optionality therefore rests disproportionately on a narrow set of assets: legacy coal, flexible gas, hydro reservoirs, and cross-border capacity.
As renewable penetration rises toward 30–40 percent of annual generation in several SEE markets, the system’s reliance on optionality will intensify. Each additional percentage point of variable renewables reduces average load factors for thermal units, while increasing the frequency of ramping events and scarcity pricing. Without explicit mechanisms to value availability and flexibility, investment signals will weaken precisely where system needs grow strongest.
The end of baseload is therefore not a temporary phase. It is a permanent structural transition. South-Eastern Europe’s electricity markets are moving toward a model where security of supply is delivered through portfolios of optional assets rather than continuous generation. The critical question is whether market and regulatory frameworks will adapt fast enough to recognise this reality.
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