South-Eastern Europe’s electricity system has entered a decisive phase in which short-term price formation, cross-border grid physics, and medium-term decarbonisation trajectories are converging into a single operational reality. What used to be a loosely connected periphery of Europe’s power market is becoming a tightly interdependent regional system, exposed simultaneously to renewable variability, fossil fuel price signals, network congestion, and regulatory convergence pressures. The result is not instability in the classical sense, but a structural re-ordering of how electricity is produced, traded, priced, and secured across the region.
The SEE electricity space, stretching across EU and Energy Community members and anchored by systems such as Serbia, Romania, Bulgaria, Greece, and the Western Balkans, is no longer insulated from continental dynamics. Instead, it is increasingly shaped by the same forces that now define the wider European power market: variable renewables setting marginal prices for long stretches of the year, gas-fired capacity acting as a system balancer rather than a baseload provider, and cross-border capacity determining whether price volatility is absorbed or amplified.
Price behaviour in early 2026 illustrated this new reality clearly. Following the year-end period, average wholesale electricity prices across SEE markets softened from roughly €95/MWh in late December to around €90/MWh in the first trading weeks of January, with some bidding zones registering declines of more than 10 percent week-on-week. This was not driven by structural oversupply or demand destruction, but by a combination of seasonal demand reduction and a sharp increase in wind output across the region. In practical terms, SEE prices are now reacting to meteorology almost as directly as those in Northern Europe, something that would have been unthinkable a decade ago.
This sensitivity to renewable output marks a fundamental shift. Historically, SEE electricity prices were dominated by lignite and coal marginal costs, hydrological conditions, and import availability. Today, wind and solar generation increasingly displace thermal units during favourable conditions, compressing prices and creating frequent intra-day volatility. Yet unlike more mature markets, SEE systems still lack sufficient flexibility to fully absorb these swings. When renewables surge, prices fall quickly; when output drops, prices rebound sharply as gas and coal units re-enter the merit order.
This volatility is exacerbated by grid constraints. Cross-border interconnection capacity, both physical and operationally available, has become one of the most important price drivers in the region. During periods of system stress, whether driven by heatwaves, droughts, or low renewable output, limited cross-zonal capacity can fragment markets and produce extreme price divergence. In previous summer periods, hourly prices above €1,000/MWh were recorded in parts of South-Eastern Europe, even as neighbouring markets experienced significantly lower levels. Subsequent system analysis showed that a substantial share of these spikes could have been mitigated if the legally required 70 percent of interconnector capacity had been made available to the market.
This observation goes to the heart of the SEE electricity challenge. The region does not primarily suffer from a lack of generation capacity in aggregate terms. It suffers from insufficiently optimised network usage and incomplete market coupling. When flows are constrained, local scarcity pricing emerges even if surplus power exists just across the border. As renewable penetration increases, this problem becomes more acute, not less. Variable generation amplifies the importance of flexible imports and exports, turning interconnectors into critical system assets rather than optional trade channels.
Encouragingly, the institutional architecture for addressing this issue is now in place. Progressive market coupling initiatives under the Energy Community framework and alignment with EU market design rules are slowly translating into deeper day-ahead and intraday integration. In winter 2025–26, improved cross-border coordination among transmission system operators allowed the region to manage several stress events more effectively than in previous years. Flow-based allocation, enhanced balancing cooperation, and better forecasting reduced the severity and duration of price dislocations.
However, integration remains uneven. Some borders operate close to best practice, while others remain administratively constrained. This asymmetry creates opportunities for strategic trading behaviour, as market participants increasingly compete for control over flows rather than simply generation assets. In SEE, electricity trading has evolved into a contest over congestion rents, border positions, and time-of-delivery advantages. The market is no longer defined only by who owns power plants, but by who can reliably access interconnector capacity at critical hours.
This evolution has important implications for system costs and industrial competitiveness. Despite recent softening, average wholesale prices in SEE have remained structurally higher than in parts of Western and Northern Europe for much of the past two years, often clustering in the €85–100/MWh range during normal conditions. By contrast, markets with high nuclear or hydro availability and stronger interconnection, such as France or parts of the Nordics, have frequently cleared at substantially lower levels during the same periods. For energy-intensive industries in SEE, this price gap represents a persistent competitive disadvantage.
Decarbonisation dynamics further complicate the picture. SEE countries are simultaneously expanding renewable capacity, maintaining legacy coal and lignite fleets for security of supply, and facing tightening environmental constraints. In systems such as Serbia’s, lignite still plays a dominant role in annual generation, providing inertia and capacity adequacy but increasingly exposed to operational and regulatory risk. Gas-fired capacity, while cleaner and more flexible, is constrained by fuel price volatility and import dependence. Hydropower remains a stabilising force but is increasingly vulnerable to climate-driven variability in precipitation patterns.
As a result, the region is entering what could be described as a “balancing-first” phase of the energy transition. The core system challenge is no longer how to add megawatts of generation, but how to ensure that existing and new assets can be coordinated in real time. Flexibility, rather than capacity, has become the binding constraint. This includes not only flexible generation, but also demand response, storage, and cross-border balancing services.
Quantitatively, the flexibility gap is significant. While wind and solar shares in some SEE markets are still below the EU average, incremental additions already impose disproportionate balancing requirements because system inertia is lower and interconnections are less dense. Studies of regional dispatch patterns suggest that without additional flexibility measures, renewable penetration beyond 30–35 percent of annual generation could materially increase price volatility and balancing costs. This does not imply a ceiling on renewables, but it does underline the need for coordinated grid and market reforms.
Policy responses are beginning to reflect this reality. Capacity mechanisms, once viewed primarily as tools to preserve thermal generation, are being reconsidered as instruments to reward flexibility and availability rather than sheer installed megawatts. Investments in grid reinforcement and digitalisation are increasingly framed as market integration measures rather than purely technical upgrades. Regional initiatives to harmonise balancing markets and reserve products are moving from concept to implementation.
For SEE, the strategic question is whether these reforms can be accelerated and aligned across borders. Fragmented national solutions will not be sufficient in a system where power flows ignore political boundaries. The economic logic increasingly favours regional optimisation: shared reserves, coordinated outage planning, and joint investment in interconnection and storage. The political challenge lies in aligning regulatory frameworks, cost allocation, and national security narratives.
Looking ahead to the second half of the decade, several structural trajectories are becoming clear. Electricity demand in SEE is likely to grow moderately, driven by electrification of transport, heating, and parts of industry, even as efficiency gains offset some consumption. Renewable capacity will continue to expand, particularly wind and solar, supported by falling technology costs and EU-aligned policy frameworks. At the same time, the role of coal and lignite will gradually diminish, not through abrupt shutdowns but through declining load factors and increasing operational stress.
In this context, price volatility should not be interpreted as market failure. It is a signal. It reflects a system in transition, where legacy assets, new technologies, and evolving market rules coexist. The challenge for policymakers and system operators is to ensure that this volatility remains manageable and that it delivers investment signals rather than social backlash.
For South-Eastern Europe, the stakes are particularly high. The region sits at the crossroads of continental power flows, linking Central Europe, the Mediterranean, and the Western Balkans. Its electricity system can either become a stabilising bridge or a persistent bottleneck. Achieving the former requires continued commitment to market coupling, disciplined grid investment, and a pragmatic approach to system balancing that recognises the continued role of flexible thermal and hydro assets during the transition.
What is clear is that SEE electricity markets have moved beyond their transitional adolescence. They are now fully exposed to the same structural forces shaping Europe’s power system as a whole. The question is no longer whether integration and decarbonisation will reshape the region, but how effectively the region can shape that process in return.
