South-East Europe is undergoing a structural transformation that is not yet fully reflected in headline adequacy statistics but is already deeply embedded in power prices, forward curves, and congestion behaviour. The region’s dispatchable core—the combination of coal, lignite, hydro flexibility, and synchronous thermal capacity that historically anchored reliability—is shrinking faster than market participants have recalibrated their risk models. The immediate consequence is not widespread shortages, but a fundamental repricing of risk across time horizons, products, and corridors.
For decades, SEE power markets were defined by surplus logic. Large lignite fleets in Romania, Bulgaria, Serbia, and Bosnia and Herzegovina created structural oversupply during most hours, while hydro assets smoothed seasonal variability. Price volatility existed, but it was largely fuel-driven and locally contained. That regime is ending. The retirement of coal assets, the ageing of remaining synchronous units, and the uneven deployment of renewables are hollowing out the dispatchable centre of the regional system. What replaces it is not a new equilibrium, but a fragile balance maintained by cross-border flows.
The market impact of this shift is already visible. Forward prices increasingly diverge from marginal fuel cost assumptions and instead embed probability-weighted stress outcomes. Traders no longer ask whether capacity exists somewhere in the region; they ask whether it will be available, deliverable, and unconstrained at the same hour across multiple bidding zones. This is a fundamentally different risk framework.
Romania’s accelerated lignite retirements exemplify the shift. The removal of approximately 1.7 GW of dispatchable capacity by early 2026 does not simply reduce Romanian supply; it reduces regional shock absorption. These units historically operated during winter stress, anchoring prices and supporting exports. Their exit compresses reserve margins and transfers volatility into neighbouring markets through shared corridors. Bulgaria follows a similar trajectory, albeit more slowly, while Bosnia and Herzegovina’s thermal fleet ages without clear replacement pathways.
The immediate effect is not constant scarcity but optionality inflation. Dispatchable megawatts that may only run a few hundred hours per year command rising value because they determine outcomes during extreme events. Forward curves increasingly resemble volatility instruments rather than energy price forecasts. Q1 products exhibit convexity, with limited downside—anchored by remaining lignite and hydro—but open-ended upside driven by correlated cold spells and congestion risk.
This repricing is structural, not cyclical. Weather correlation across the Danube basin and the Balkans means that winter stress rarely affects one system in isolation. Cold air masses raise demand simultaneously while suppressing wind output and constraining hydro inflows across wide geographies. When dispatchable depth declines, the system loses its ability to absorb these shocks internally. The burden shifts to interconnectors.
Cross-border trade thus becomes the dominant adequacy mechanism, but one with hard physical limits. Transmission capacity was not designed for persistent stress balancing across multiple countries simultaneously. As dispatchable capacity shrinks, corridors saturate more frequently, and congestion becomes the primary price-setting force. In this environment, generation adequacy statistics lose explanatory power; grid topology becomes the market.
The trading implications are profound. Historical correlations between neighbouring markets weaken. Price hierarchies invert. Lower-cost systems can clear above higher-cost ones if congestion isolates scarcity. Intraday volatility increases as system operators intervene more frequently to manage imbalances. Balancing prices spike not because energy is unavailable, but because response time and inertia are scarce.
This environment rewards traders who understand system physics rather than those who model fuel curves alone. Congestion forecasting, maintenance scheduling, and weather correlation analysis now matter more than nominal capacity balances. Market participants increasingly price tail risk, not average outcomes. This is visible in widening bid-ask spreads, higher risk premiums in longer-dated products, and increased demand for optionality.
The shrinkage of the dispatchable core also alters the investment landscape. Assets that preserve or mimic dispatchability—storage, pumped hydro, fast-ramping thermal units—gain systemic value disproportionate to their average utilisation. Their economics are driven by rare but decisive events. In effect, the market is paying for insurance, not energy.
Yet the cost of this insurance is not evenly distributed. Systems that still retain dispatchable capacity suppress volatility for the region, reducing price spikes and thus their own revenue potential. This creates a paradox where stability providers under-earn relative to the risk they mitigate. Over time, this misalignment threatens reinvestment incentives, increasing the likelihood of abrupt rather than orderly transitions.
South-East Europe now sits in an intermediate phase between surplus-driven markets and scarcity-managed systems. Dispatchable capacity has not vanished, but it is no longer abundant enough to anchor prices unconditionally. The market response is not linear adjustment but risk repricing. Power is increasingly valued not by how cheaply it can be produced, but by when and where it can be delivered under stress.
This shift is irreversible. Even if renewable capacity accelerates, it does not recreate dispatchable depth. Without massive and coordinated investment in flexibility and grids, the region will continue to trade in probabilities rather than certainties. For traders, utilities, and investors, understanding this structural change is now a prerequisite for participation. The era of fuel-driven SEE power pricing is over; the era of system-risk trading has begun.