For decades, electricity systems across South-Eastern Europe were built around baseload generation. Large lignite units ran continuously, supported by hydropower and limited gas capacity to match predictable demand. Dispatch generally followed a hierarchy with coal taking priority, hydro providing seasonal modulation, and imports used for marginal adjustments. The approach also influenced political narratives about energy security and sovereignty.
That operating model has changed. Across the region, dispatch is increasingly defined by optionality, with value placed on when assets can run and how quickly they can respond during stress periods. Baseload has lost its operational meaning as system needs shift toward balancing variable supply. Over the past two years, changes in plant utilisation have reflected this transition.
Coal and lignite utilisation declines as renewables set prices
Lignite and coal units across South-Eastern Europe have seen sharp declines in load factors. The change is linked to how price formation and system requirements reward generation rather than to the disappearance of capacity. In several systems, coal plants that historically operated at 70–80% annual utilisation are now dispatched at 40–55%. Extended ramp-down periods occur during periods of high renewable output and imports.
These plants increasingly function as residual suppliers rather than continuous baseload providers. Wind and solar generation are described as setting 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 relies on assets that can respond quickly enough.
Gas plants move toward scarcity response roles
Gas-fired generation illustrates the shift in operating expectations. Under classical system design, gas plants were expected to provide mid-merit or peak supply. In today’s South-Eastern Europe markets, gas plants increasingly operate as system insurance assets. They may run only a few hundred hours per year while remaining important during scarcity events.
During periods when wind collapses across the region or cross-border imports are constrained, gas units can become marginal price setters. The source data links these conditions to prices in the €150–250/MWh range during tight weeks. It also notes that prices can rise much higher during extreme events. Gas dispatch therefore aligns with scarcity timing rather than continuous generation.
Hydropower shifts from steady support to flexibility reserve
Hydropower has also changed its role in regional dispatch patterns. Instead of acting as a steady baseload supplement, hydro increasingly functions 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 reduced.
The reduction in available flexibility contributes to higher volatility in affected periods. The source describes this outcome as reinforcing the insurance role of gas and imports when hydrological conditions weaken. It also frames hydro’s operational behaviour as tied to market signals rather than a fixed contribution to baseline demand coverage. These changes affect how stress periods are managed across the region.
Market design tension over energy-only remuneration
The dispatch landscape is described as being defined by optionality rather than continuous output. Assets are valued for their ability to run when other sources cannot, including during system stress periods. The economic implications include challenges for traditional cost recovery models under lower utilisation rates. Plants designed for baseload economics struggle when operating hours fall below 4,000 hours per year, and even more so below 2,500–3,000 hours.
The source highlights a market design issue: electricity markets remunerate energy rather than availability. In systems where assets are valued for availability instead of output, energy-only pricing can lead to revenue instability. It notes that several utilities have reported that thermal assets needed for security of supply are commercially loss-making at current utilisation patterns despite remaining system-critical. Policy responses have varied across countries.
Capacity mechanisms considered alongside state support
The policy response described is uneven across South-Eastern Europe. Some countries have introduced or are considering capacity mechanisms. Others rely on state-owned utilities to absorb losses implicitly under current market outcomes. The underlying issue is characterised as structural because dispatch no longer follows a baseload model.
The end of traditional baseload dispatch means the region must decide how to pay for optionality explicitly. From a system perspective, optionality is described as having measurable value during stress periods when fast-response resources prevent more severe outcomes. The source points to summer 2024 events as an example involving evening solar collapse and constrained imports.
Summer 2024 price spikes reflect scarcity timing and constrained imports
During summer 2024 stress events, prices in parts of South-Eastern Europe spiked above €1,000/MWh for individual hours when solar output collapsed in the evening and imports were constrained. The source states that these prices were not signals of fuel scarcity but signals of insufficient optionality at those times. Assets capable of responding during those hours helped prevent load shedding and industrial disruption. It also notes that emergency imports would have been at even higher cost.
The source describes an economic logic shift from least-cost energy toward least-cost resilience without abandoning renewables or decarbonisation objectives. It links this shift to the need to compensate dispatchable assets for standing ready rather than only for producing energy during normal conditions. For South-Eastern Europe, it says this requirement is intensified by limited buffers compared with other regions.
Narrow regional buffers increase reliance on flexible portfolios
The source says South-Eastern Europe lacks several buffers available elsewhere in Europe. It contrasts limited nuclear baseload with France’s situation, notes that unlike the Nordics it cannot rely indefinitely on hydrological abundance, and states that unlike Germany it does not yet have deep storage or fully developed demand response. As a result, optionality depends disproportionately on legacy coal, flexible gas, hydro reservoirs, and cross-border capacity.
As renewable penetration rises toward 30–40% of annual generation in several markets, reliance on optionality is expected to intensify under the source’s description. Each additional percentage point of variable renewables reduces average load factors for thermal units while increasing ramping frequency and scarcity pricing occurrences. Without mechanisms to value availability and flexibility explicitly, investment signals would weaken where system needs grow strongest according to the source material.
The source concludes that the end of baseload dispatch is not described as temporary but as a permanent structural transition in the region’s power markets. It describes movement toward security of supply delivered through portfolios of optional assets rather than continuous generation patterns. It also raises whether market and regulatory frameworks will adapt quickly enough to reflect this change.
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