The electricity markets in South-Eastern Europe (SEE) are undergoing significant changes as they adapt to evolving dynamics that are reshaping the region’s energy landscape. The convergence of short-term price mechanisms, cross-border grid interactions, and medium-term decarbonization strategies is creating a more interconnected and interdependent system. This transformation is characterized not by instability but by a fundamental restructuring of electricity production, trading, pricing, and security across the region.
Countries such as Serbia, Romania, Bulgaria, and Greece are increasingly influenced by continental electricity market trends. The integration of variable renewable energy sources is becoming a dominant factor in price formation, with gas-fired generation shifting from being a baseload provider to a balancing resource. Cross-border transmission capacity is now critical in determining how price fluctuations are managed within the region.
Recent trends in wholesale electricity prices highlight this shift. In early 2026, average prices across SEE markets decreased from approximately €95/MWh at year-end to around €90/MWh in January, with some areas experiencing declines exceeding 10% week-on-week. This reduction was attributed to seasonal demand drops and increased wind generation rather than oversupply or diminished demand, indicating a growing responsiveness to meteorological conditions akin to that seen in Northern Europe.
This newfound sensitivity to renewable generation marks a pivotal change. Historically, SEE electricity prices were largely dictated by lignite and coal costs, hydrological factors, and import levels. Currently, favorable conditions for wind and solar are leading to their increased displacement of thermal generation, resulting in compressed prices and heightened intra-day volatility. However, the region still grapples with insufficient flexibility to manage these fluctuations effectively; rapid price declines occur during renewable surges, while sharp rebounds follow when output diminishes.
Grid constraints further complicate the situation. Limited cross-border interconnection capacity has emerged as a key factor influencing price behavior. During periods of high demand or low renewable output—such as heatwaves or droughts—restricted cross-zonal capacity can lead to fragmented markets and significant price discrepancies. Historical data shows instances where hourly prices exceeded €1,000/MWh in certain areas of SEE while neighboring markets maintained lower rates. Analysis indicates that many of these spikes could have been alleviated if market access had met the legally mandated 70% utilization of interconnector capacity.
The core challenge facing the SEE electricity sector lies not in generation capacity but rather in optimizing network usage and enhancing market coupling. When transmission flows are limited, local scarcity pricing can emerge despite available surplus power just across borders. As renewable energy penetration increases, this issue becomes more pronounced, underscoring the necessity for flexible imports and exports that transform interconnectors into vital system assets.
On a positive note, institutional frameworks aimed at addressing these challenges are being established. Initiatives under the Energy Community framework are fostering deeper integration within day-ahead and intraday markets. Improved coordination among transmission system operators during winter 2025–26 allowed for better management of stress events compared to previous years, with advancements in flow-based allocation and balancing cooperation contributing to reduced price volatility.
Despite progress, integration remains inconsistent across borders. While some areas operate near best practices, others encounter administrative hurdles that hinder efficiency. This disparity fosters strategic trading behavior as market participants vie for control over transmission flows rather than merely focusing on generation assets. Consequently, electricity trading has evolved into a competition for congestion rents and advantageous border positions.
The implications of these developments extend to system costs and industrial competitiveness. Average wholesale prices in SEE have consistently remained higher than those in many parts of Western and Northern Europe over the past two years, often fluctuating between €85–100/MWh during typical conditions. In contrast, regions with abundant nuclear or hydro resources enjoy significantly lower prices during similar periods, placing energy-intensive industries in SEE at a competitive disadvantage.
The ongoing decarbonization efforts add another layer of complexity to the region’s energy landscape. Countries are expanding renewable capacity while simultaneously relying on traditional coal and lignite plants for security of supply amidst tightening environmental regulations. In Serbia’s case, lignite continues to dominate annual generation but faces increasing operational risks due to regulatory pressures. Gas-fired plants offer cleaner alternatives but are constrained by fuel price volatility and dependency on imports.
This scenario suggests that SEE is entering a “balancing-first” phase of its energy transition. The primary challenge is no longer simply adding generation capacity but ensuring real-time coordination among existing and new assets. Flexibility has become the crucial constraint encompassing not just generation but also demand response mechanisms, storage solutions, and cross-border balancing services.
The flexibility gap remains substantial; while wind and solar contributions in some SEE markets lag behind EU averages, their incremental growth imposes disproportionate balancing demands due to lower system inertia and less dense interconnections. Studies indicate that without enhanced flexibility measures, renewable shares exceeding 30–35% could lead to increased price volatility and balancing costs—highlighting the urgent need for coordinated reforms in grid operations and market structures.
Policy responses are beginning to align with these realities as capacity mechanisms evolve from tools focused on preserving thermal generation to instruments rewarding flexibility and availability instead of merely installed megawatts. Investments aimed at reinforcing grids and enhancing digital infrastructure are increasingly viewed as integral to market integration rather than isolated technical upgrades.
The strategic imperative for SEE lies in accelerating reforms that align across national borders. Fragmented solutions will prove inadequate in an interconnected system where power flows disregard political boundaries. The economic rationale increasingly supports regional optimization through shared reserves, coordinated outage planning, and collaborative investments in interconnections and storage solutions.
Looking toward the latter half of the decade reveals several emerging trends: moderate growth in electricity demand driven by electrification efforts across transport, heating, and industry; ongoing expansion of renewable capacity—particularly wind and solar—supported by declining technology costs; and a gradual decline in coal’s role through diminishing load factors rather than abrupt closures.
In this context, price volatility should be understood not as a failure but as an indicator of transition—a reflection of a system where legacy assets coexist with new technologies under evolving market rules. The challenge for policymakers will be managing this volatility effectively while ensuring it signals investment opportunities rather than provoking public discontent.
The stakes for South-Eastern Europe remain high as it occupies a strategic position within continental power flows linking Central Europe with the Mediterranean and Western Balkans. The region’s electricity system must navigate its dual role as both a stabilizing bridge and potential bottleneck—a task requiring ongoing commitment to market coupling alongside disciplined grid investments that recognize the continued importance of flexible thermal and hydro resources throughout this transition.
