For most of the past half-century, Europe’s electricity system could be understood through a relatively simple lens. Power was generated close to where it was consumed, national systems were planned around predictable baseload plants, and cross-border flows played a supporting role rather than defining market outcomes. Electricity prices reflected domestic generation costs, demand patterns were stable, and system risk was largely internal to each country’s grid.
That world no longer exists.
Europe has crossed a structural threshold in which electricity is no longer a national commodity but a continental flow system. Power prices, system stability and investment signals are now shaped less by local generation mixes and more by how variable production in one part of the continent propagates through interconnected grids into neighbouring markets. Wind and solar have not merely added capacity; they have rewritten the physics, economics and geography of Europe’s power system. Nuclear, once the ultimate symbol of baseload stability, has become a rigid counterweight inside a system increasingly defined by flexibility. Coal, long the backbone of many eastern and southeastern systems, is being pushed out economically and politically, even where it still performs critical system functions.
Nowhere are these changes more visible than in southeast Europe. Countries from Slovenia and Croatia through Serbia, Bosnia and Herzegovina, Montenegro, Albania, North Macedonia, Greece, Bulgaria and Romania increasingly experience electricity prices, flows and system stress driven by decisions taken far beyond their borders. Southeast Europe has become both a transit corridor and a shock absorber for Europe’s variable power system, absorbing surplus electricity during oversupply hours and shouldering volatility during periods of stress.
Understanding how this transformation occurred requires abandoning the familiar language of national energy mixes and focusing instead on system behaviour: where variability is created, how it moves, and where its consequences ultimately land.
The rise of wind and solar did not destabilise Europe’s power system overnight. For years, variable renewables were treated as marginal additions layered on top of a system still anchored by coal, gas and nuclear. Early deployment was absorbed with relatively little disruption because the volumes were small, the grids were underutilised, and flexible capacity was plentiful. That phase is over. In many EU core markets, wind and solar now routinely set prices for significant portions of the day. Midday solar generation regularly exceeds local demand in parts of Germany, Italy and Spain. Wind output in the North Sea basin can swing by tens of gigawatts within hours.
What changed is not just scale, but correlation. As renewable capacity expanded, weather patterns began to align generation across entire regions. High-pressure systems deliver solar surges simultaneously across central and southern Europe. Atlantic wind systems create synchronized output across northern markets. The old assumption that variability in one country could be balanced by stability in another no longer holds. Variability has become continental in scope.
This shift has profound consequences for how electricity prices are formed. In a system dominated by dispatchable generation, prices are driven by the marginal cost of the last plant needed to meet demand. In a system dominated by variable generation with near-zero marginal cost, prices are increasingly driven by scarcity of flexibility rather than scarcity of energy. When the sun shines and the wind blows, electricity becomes abundant and cheap, sometimes even negatively priced. When both falter simultaneously, prices spike sharply as the system scrambles for flexible backup.
Nuclear power occupies an uneasy position in this new landscape. Designed to operate continuously at high load factors, nuclear plants are technically capable of some load-following but economically optimised for baseload operation. In markets like France and Slovenia, nuclear output continues to anchor system supply, but its rigidity increasingly collides with solar oversupply during daylight hours. Rather than stabilising prices, nuclear can exacerbate congestion and price suppression when combined with strong renewable output, pushing excess electricity into neighbouring markets.
Coal, by contrast, has been forced into decline not because it ceased to provide system value, but because it no longer fits the economic and political logic of the transition. In many southeastern European systems, coal plants still provide inertia, voltage support and predictable output that variable renewables cannot replace easily. Yet these assets face rising carbon costs, tightening environmental regulation and shrinking operating hours. As coal retreats, the system loses not just energy but stability, increasing reliance on cross-border flows and imported flexibility.
Gas has emerged as Europe’s de facto balancing fuel, but its role is deeply asymmetric. In the EU core, gas plants increasingly function as insurance policies rather than baseload producers, running fewer hours but setting prices during scarcity. In southeast Europe, gas is often more expensive, less flexible and constrained by infrastructure. The same gas-driven price signals that help stabilise western markets transmit eastward as cost pressure rather than balancing opportunity.
The transformation of generation would be manageable if electricity remained largely domestic. But Europe’s power system is now deeply interconnected, both physically and commercially. Market coupling, flow-based capacity allocation and harmonised trading platforms have integrated national markets into a single price-formation mechanism. Electricity moves not only according to physical laws, but according to price signals that propagate faster than grids can always respond.
This integration has created new power corridors across the continent. Electricity increasingly flows north to south during solar peaks, west to east during wind surges, and reverses direction during scarcity events. Germany’s renewable output influences prices in Austria and Italy; Italian solar oversupply spills into the Balkans; French nuclear availability affects markets from Spain to Slovenia. Southeast Europe sits at the intersection of several of these corridors, making it particularly exposed to system behaviour originating elsewhere.
Slovenia and Croatia function as key transit systems linking central Europe with the Adriatic and the Balkans. Bulgaria and Romania bridge the EU core with Greece and Turkey. Serbia, Bosnia and Herzegovina, Montenegro and Albania lie just beyond the EU’s internal market but are increasingly synchronised through physical flows and price coupling. These countries do not simply import electricity; they import volatility.
The consequences are visible in price dynamics. In many southeastern markets, prices increasingly move in lockstep with central European benchmarks, even when domestic generation conditions differ. Local abundance does not guarantee low prices if neighbouring markets are tight. Conversely, local scarcity may be masked by imports during oversupply periods, only to reappear abruptly when congestion binds. The traditional link between national generation costs and national prices has weakened, replaced by a system in which geography and timing dominate.
Hydropower plays a unique role in this environment. Southeast Europe’s hydro assets, particularly in Albania, Montenegro, Bosnia and Herzegovina and parts of Croatia and Serbia, provide some of the most valuable flexibility in the continental system. Hydropower can ramp quickly, respond to price signals and store energy seasonally. During periods of renewable oversupply in the EU core, hydro reservoirs can conserve water. During scarcity events, they can release power rapidly.
Yet this flexibility comes at a cost. As Europe relies more heavily on Balkan hydro to smooth variability, these systems face increasing stress, especially under changing climate conditions. Drought years expose the fragility of over-reliance on hydro as a balancing tool. When water levels fall, the region loses both energy and flexibility, precisely when the wider system needs it most. What appears as resilience in wet years can become vulnerability in dry ones.
The interaction between variable renewables, rigid baseload and flexible assets reshapes not only flows but incentives. In theory, flexibility should be rewarded in a system dominated by variability. In practice, market structures still prioritise energy volumes over response capability. Day-ahead markets dominate price formation, while intraday and balancing markets remain less liquid, especially in southeast Europe. Flexibility is used physically but often under-compensated financially.
This misalignment has strategic consequences. Investors hesitate to commit capital to flexible assets when revenue streams are uncertain. Utilities defer maintenance and upgrades on hydro and thermal plants that are dispatched intensively but earn thin margins. Governments intervene to cap prices, mandate production or subsidise losses, introducing political risk into what was once a technical system.
Nuclear’s role further complicates the picture. In systems where nuclear output remains high, excess generation during low-demand periods pushes power across borders regardless of local conditions. Southeast European markets absorb these flows, sometimes at suppressed prices that undermine domestic generators. Nuclear stability in one country translates into volatility management challenges in another.
The shift toward a variable power system also alters the meaning of security of supply. In the past, security was measured by domestic capacity adequacy. Today, it depends on regional coordination, cross-border capacity and the availability of flexible resources across the continent. A calm, sunny day in Germany can create system stress hundreds of kilometres away by displacing local generation and eroding economic signals. A cold, windless week can trigger continent-wide price spikes that test political tolerance and industrial competitiveness.
Southeast Europe’s position in this system is paradoxical. Physically, the region is essential to Europe’s energy transition, providing transit routes, flexibility and balancing capacity. Economically, it often captures limited value from this role. Prices reflect external conditions more than local realities, while investment signals remain weak. The region bears system risk without commensurate reward.
These dynamics are not the result of policy failure alone. They are the natural consequence of integrating a variable generation system across a continent with uneven infrastructure, divergent generation mixes and incomplete market harmonisation. But they raise fundamental questions about sustainability. Can a system that exports volatility faster than it builds flexibility remain stable? Can regions that act as buffers continue to do so without adequate compensation? And can political support for market integration survive repeated episodes of perceived unfairness?
The answers will shape Europe’s energy future. More grid investment, deeper balancing markets and better recognition of flexibility value are often cited as solutions. They are necessary, but not sufficient. What is also required is a shift in how system roles are understood. Southeast Europe cannot be treated merely as a passive extension of the EU core. Its assets, constraints and risks must be integrated explicitly into continental planning.
Europe’s variable power system has delivered remarkable progress toward explainable climate goals. Wind and solar have reduced emissions and reshaped energy economics. But they have also revealed the limits of treating electricity as a homogeneous commodity. In a system defined by variability, location, timing and flexibility matter as much as capacity.
For southeast Europe, the transition is not just about decarbonisation. It is about positioning within a continental system that increasingly relies on the region’s geography and assets while testing its resilience. Whether the region emerges as a valued partner or a stressed buffer will depend on how the next phase of integration is designed.
The transformation of Europe’s power system is far from complete. If anything, variability will intensify as renewable penetration rises further. Nuclear will remain rigid, gas will remain volatile, and climate impacts will add new layers of uncertainty. The question is no longer whether these forces will interact, but how their interaction will be managed and who will bear the consequences.
Southeast Europe is already living with the answer. The rest of Europe is only beginning to notice.
Elevated by clarion.energy
