However, recent developments indicate a breakdown of this conventional model. The past two years have shown that the region’s electricity dispatch is increasingly defined by the ability of generation assets to respond flexibly rather than their operational continuity. The concept of baseload has lost its relevance as market dynamics evolve.
Data reveals that lignite and coal units have experienced notable declines in their load factors. These declines are not due to a reduction in capacity but stem from changes in price formation and system requirements that no longer incentivize continuous operation. In many SEE countries, coal plants that once operated at 70–80 percent utilization are now frequently running at 40–55 percent, often idled during periods of high renewable energy output or imports. This shift has effectively redefined these units from baseload producers to residual suppliers, tasked with filling gaps when other sources are unavailable.
This transition is largely market-driven rather than ideological. Wind and solar generation increasingly dictate marginal pricing throughout much of the year. During times of strong wind or high solar output, thermal units are often sidelined, regardless of their historical importance in the energy mix. Conversely, when renewable generation declines, the grid relies on assets that can respond quickly, emphasizing flexibility over continuity.
Gas-fired power generation exemplifies this change in operational strategy. Traditionally viewed as mid-merit or peak supply sources, gas plants are now functioning more as insurance against supply shortages. They may operate only a few hundred hours annually but play a crucial role during scarcity events, often becoming marginal price setters when demand exceeds supply capabilities.
Hydropower’s role has also evolved; rather than serving as a consistent baseload support, it now acts as a strategic reserve for flexibility. Reservoir managers optimize water usage based on price signals, conserving resources during low-price periods while releasing them during peak demand times or when imports are constrained. Drought conditions further complicate this dynamic by limiting hydropower’s availability and increasing reliance on gas and imports.
The implications of this shift toward optionality are profound for the economic landscape of SEE’s electricity markets. Low utilization rates challenge traditional cost recovery models for thermal plants, which struggle to cover fixed costs when annual operating hours fall below 4,000—an increasingly common scenario for many thermal units in the region.
This evolving market design creates tension; current electricity markets reward energy production rather than availability. As assets become more valuable for their capacity to respond rather than their output levels, revenue instability emerges. Several utilities in SEE report that critical thermal assets are currently operating at a loss under prevailing utilization patterns despite their importance for ensuring supply security.
Responses from policymakers have varied across the region. Some nations are exploring capacity mechanisms to address these challenges, while others depend on state-owned utilities to absorb financial losses implicitly. However, the underlying structural issue remains: as baseload dispatch wanes, there is an urgent need to establish frameworks that adequately compensate for optionality.
From a systemic perspective, the value of optionality has become evident during stress events in summer 2024 when solar output diminished significantly during peak demand hours and imports were limited. Prices surged above €1,000/MWh in certain areas—not due to fuel scarcity but because of inadequate optionality within the system.
The economic rationale is shifting from prioritizing “least-cost energy” to focusing on “least-cost resilience.” This does not entail abandoning renewable energy initiatives but highlights the necessity of compensating dispatchable resources for their readiness to provide power rather than solely for energy production.
For SEE, this transition is particularly critical given its limited buffers compared to other regions. Unlike France with its nuclear capacity or Germany with advanced storage solutions and demand response capabilities, SEE’s reliance on legacy coal, flexible gas, hydro reservoirs, and cross-border connections makes it vulnerable as renewable penetration approaches 30-40 percent of annual generation.
As variable renewables increase in share, the dependence on optionality will intensify further. Each incremental rise in renewables diminishes average load factors for thermal units while amplifying ramping events and scarcity pricing occurrences. Without mechanisms explicitly valuing availability and flexibility, investment signals may weaken precisely where they are most needed.
Ultimately, the end of baseload generation marks not merely a transitional phase but a fundamental structural change within SEE’s electricity markets. The future will hinge on whether regulatory frameworks can adapt swiftly enough to embrace this new reality where security of supply is ensured through diverse portfolios of responsive assets rather than through continuous generation alone.
