The South-Eastern European power system is moving into a structural operating pattern where coal no longer acts as the marginal stabiliser. A trading session on 26 February 2026 illustrated the change: coal units remained in the generation mix, but their influence on clearing prices was limited. Instead, price formation increasingly alternated between renewable-led suppression during daylight and gas-driven scarcity pricing during evening ramps.
From buffering marginality to residual coal dispatch
Coal’s earlier function in the region was to provide a buffering layer within the merit order. When demand rose or hydropower underperformed, coal typically entered and set prices at levels that helped smooth volatility between base and peak. That stabilising role has eroded as carbon costs rise, coal fleets age, and low-marginal-cost renewables displace coal under normal conditions.
On 26 February, coal represented roughly 18 percent of regional generation, yet that output did not translate into marginal price-setting power. Even when demand increased, coal units were often priced out by a combination of renewables, imports, and gas. The key driver cited was cost structure: with EUA prices elevated and expected to remain structurally firm, coal’s variable cost frequently exceeded gas on a clean spark basis.
A binary price regime reshapes operational planning
The market dynamic is described as simplifying the marginality “tree” while increasing volatility. Rather than transitioning smoothly across multiple layers, prices flip between two dominant regimes. During periods of high renewable output—particularly solar—prices fall toward operational floors, while low renewable availability can quickly make gas the marginal technology and push prices toward clean spark levels.
This has immediate implications for system operation and forecasting discipline. In southern SEE markets including Serbia, North Macedonia, and Montenegro, extended midday periods saw coal fully displaced and prices near zero or deeply depressed. As solar output declined in the evening, coal did not return to stabilise prices; gas set the marginal price almost immediately, producing rapid escalation within a narrow time window.
Cross-border effects and forecasting risk rise with fewer damping layers
The removal of coal as an intermediate buffer means small changes can trigger large price moves. The analysis highlights that relatively modest swings in renewable output can flip the system from surplus to scarcity almost instantaneously—such as a few hundred megawatts of solar disappearing at sunset. In practice, this increases the operational value of high-resolution weather and generation data and makes forecasting errors more consequential when the system balances near the margin.
Cross-border flows also become more important under binary conditions. In a coal-buffered setting, local generation could absorb shocks without immediately affecting neighbouring markets; with the current regime, shocks propagate faster across borders. A drop in renewable output in one market can raise imports from neighbours and transmit scarcity signals regionally, while surges in solar output can flood adjacent systems if interconnection capacity allows.
Investment relevance: what developers and grid planners should take from the shift
For asset valuation and commercial strategy, shrinking revenue windows are highlighted for thermal assets that once benefited from steady marginal pricing. Coal operating hours are squeezed between renewable-dominated periods and gas-driven peaks, leaving limited opportunities to capture margin even when coal runs below marginal price levels. Trading approaches also shift away from fuel spread structures involving coal toward renewable forecasting capability and exposure management for gas during peak hours.
For infrastructure planning teams, the direction points to a system where flexibility requirements concentrate around the transition periods between solar surplus and evening scarcity. Carbon pricing is identified as an accelerant because EUA costs embedded into coal generation disproportionately affect competitiveness even with modest carbon increases. With renewable expansion continuing—especially solar in southern SEE—and gas remaining the primary flexible thermal option, the analysis concludes that volatility will likely intensify unless substantial investment in storage or demand-side flexibility changes how quickly the system oscillates between surplus and scarcity.
Broader project implications follow from this operational reality: developers preparing wind and solar pipelines will need tighter integration with grid modernization plans and forecasting workflows; utilities planning transmission upgrades must account for faster regional propagation of imbalance signals; and battery energy storage projects will be evaluated increasingly on their ability to damp evening ramps rather than only on energy shifting. EPC preparation and procurement frameworks for flexibility assets therefore become closely linked to delivery readiness for high-variability operating conditions across Serbia, North Macedonia, Montenegro, Hungary, and wider SEE interconnections.