South-Eastern Europe’s electricity system is entering a phase where short-term price formation, cross-border grid conditions and medium-term decarbonisation trajectories increasingly overlap. The region’s power market is becoming more interdependent across borders, with renewable variability, fossil fuel price signals, network congestion and regulatory alignment affecting trading and security of supply. The shift is reflected in how electricity is produced, traded, priced and secured across the area.
The SEE market spans EU and Energy Community participants and is anchored by systems including Serbia, Romania, Bulgaria, Greece and the Western Balkans. It is increasingly influenced by the same drivers seen in the wider European power market, including variable renewables that set marginal prices for extended periods. Gas-fired capacity is used as a balancing resource rather than operating as a baseload provider, while cross-border capacity influences whether volatility is absorbed or amplified.
Wholesale price shifts in early 2026
In early 2026, average wholesale electricity prices across SEE markets declined after the year-end period. Prices softened from roughly €95/MWh in late December to around €90/MWh in the first trading weeks of January. Some bidding zones recorded week-on-week declines of more than 10%. The move was linked to seasonal demand reduction and higher wind output across the region.
The price pattern also showed a stronger link to weather than in previous years. SEE prices began reacting to meteorological conditions in a way described as comparable to Northern Europe. Historically, lignite and coal marginal costs, hydrological conditions and import availability were cited as dominant influences on pricing. That balance has shifted as wind and solar output affects dispatch outcomes.
Renewables displace thermal generation but flexibility limits remain
Wind and solar generation increasingly displace thermal units during favourable conditions, compressing prices and contributing to intra-day volatility. When renewable output rises, prices fall quickly; when output drops, prices rebound as gas and coal units return to the merit order. The source describes this as a fundamental change from earlier pricing drivers dominated by thermal marginal costs and hydrology.
Despite the growing role of renewables, SEE systems are described as lacking sufficient flexibility to absorb swings fully. The result is that price movements respond rapidly to changes in renewable availability. This dynamic increases the importance of balancing resources that can react quickly when wind or solar output varies.
Interconnection constraints drive scarcity pricing
Grid constraints are identified as a key factor behind volatility in the region’s power markets. Cross-border interconnection capacity—both physical capability and operationally available capacity—has become one of the most important price drivers in SEE. During system stress events such as heatwaves, droughts or low renewable output, limited cross-zonal capacity can fragment markets and create extreme price divergence.
In previous summer periods, hourly prices above €1,000/MWh were recorded in parts of South-Eastern Europe while neighbouring markets saw much lower levels. Subsequent analysis indicated that a substantial share of these spikes could have been mitigated if 70% of interconnector capacity required by law had been made available to the market. The issue is framed as insufficiently optimised network usage combined with incomplete market coupling.
Market coupling progress under Energy Community framework
Institutional measures aimed at addressing these constraints are described as taking shape through market coupling initiatives under the Energy Community framework. Alignment with EU market design rules is linked to deeper day-ahead and intraday integration over time. In winter 2025–26, improved cross-border coordination among transmission system operators helped manage several stress events more effectively than in prior years.
The improvements cited include flow-based allocation, enhanced balancing cooperation and better forecasting, which reduced both the severity and duration of price dislocations. However, integration remains uneven across borders, with some interconnections operating close to best practice while others remain administratively constrained. This asymmetry can affect trading behaviour by shifting competition toward control over flows rather than solely generation assets.
Price levels remain higher than parts of Western and Northern Europe
Even after 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. During normal conditions, prices are described as often clustering in the €85–100/MWh range across SEE markets. Markets with high nuclear or hydro availability and stronger interconnection—such as France or parts of the Nordics—are described as clearing at substantially lower levels during comparable periods.
The difference is presented as relevant for energy-intensive industries operating in SEE due to persistent cost disadvantages tied to electricity pricing. The source links these outcomes to how cross-border access and congestion interact with changing generation mixes.
Decarbonisation reshapes dispatch across coal, gas and hydropower
Southeast European decarbonisation dynamics are described as combining renewable expansion with continued operation of legacy coal and lignite fleets for security of supply. Environmental constraints are also tightening alongside these changes. In systems such as Serbia’s, lignite remains dominant in annual generation while being exposed to operational and regulatory risk.
Gas-fired capacity, while described as cleaner and more flexible, faces constraints tied to fuel price volatility and import dependence. Hydropower is identified as stabilising but increasingly vulnerable to climate-driven precipitation variability. These factors shape how balancing needs evolve alongside renewable growth.
A balancing-first constraint emerges as flexibility becomes decisive
The region is described as moving into a “balancing-first” phase where coordinating existing and new assets in real time becomes central. Flexibility rather than installed capacity is identified as the binding constraint for system operation. The flexibility requirement includes not only flexible generation but also demand response, storage and cross-border balancing services.
The source quantifies a flexibility gap by linking it to lower system inertia and less dense interconnections in some SEE markets. It cites studies suggesting that without additional flexibility measures, renewable penetration beyond 30–35% of annual generation could materially increase price volatility and balancing costs. Policy responses are said to reflect this shift by reconsidering capacity mechanisms previously focused on preserving thermal generation.
Policy measures: capacity reform, grid investment and harmonised balancing products
Cited policy changes include reframing capacity mechanisms toward rewarding flexibility and availability rather than only installed megawatts. Grid reinforcement and digitalisation investments are increasingly framed as market integration measures rather than purely technical upgrades. Regional initiatives aimed at harmonising balancing markets and reserve products are described as moving from concept toward implementation.
The regional challenge is described as accelerating reforms while aligning them across borders because power flows do not follow political boundaries. The economic logic cited favours regional optimisation through shared reserves, coordinated outage planning and joint investment in interconnection and storage. The political challenge involves aligning regulatory frameworks, cost allocation approaches and national security narratives.
Outlook for demand growth and changing generation mix through 2030s
Looking ahead into the second half of the decade, electricity demand in SEE is expected to grow moderately driven by electrification of transport, heating and parts of industry. Efficiency gains are expected to offset some consumption growth. Renewable capacity is expected to continue expanding particularly for wind and solar supported by falling technology costs and EU-aligned policy frameworks.
The role of coal and lignite is expected to decline gradually through declining load factors and increasing operational stress rather than abrupt shutdowns. In this context, price volatility is described as reflecting system transition where legacy assets, new technologies and evolving market rules coexist.