South-East Europe’s electricity debate has long treated installed capacity as the main indicator of system security. Over the last eighteen months, market behaviour in the region has pointed to a shift in what constrains outcomes. The key limitation is increasingly flexibility, defined as the ability to respond to fast net-load changes, offset variable renewables, manage cross-border constraints, and stabilise the system during ramp hours when solar output falls while demand remains high. Capacity can still be sufficient in installed terms while price spikes, congestion, or emergency imports occur due to limited operational tools to balance volatility in real time.
Spot price swings linked to wind and cross-border conditions
Early January 2026 showed a clear meteorological impact on regional pricing. SEE spot prices softened materially as wind generation rose and demand dipped after the holidays. A regional market review quantified the move, with the average price falling from €94.82/MWh in Week 52 (late December) to €89.73/MWh in Week 01 (early January), down 8.40%. Serbia recorded a -12.80% change and Romania -11.53%, while the same review attributed the shift to a roughly 125% week-on-week increase in wind output across observed markets.
The reversal came quickly. One week later, prices increased across the region, with the average rising from €89.73/MWh to €111.36/MWh, a 24.1% increase in Week 02. By Week 03, prices climbed again, with one regional note describing about a 29% week-on-week rise and Serbia seeing the largest jump at 65.5%. Neighbouring markets clustered around €170–175/MWh.
Evening peak stress during summer and winter
The flexibility gap is described as most visible during evening peaks in summer and winter, when solar output collapses but demand stays elevated. In summer 2024, South-East Europe experienced a wave of extreme evening-hour price spikes, with reported peak prices reaching as high as €1,000/MWh. An ACER-referenced summary of that episode recorded 147 major price spikes across the region.
The analysis cited those spikes as reflecting limited ability to import flexibility at scale when needed. It links this constraint to cross-border capacity availability and congestion management rather than demand alone. ACER’s analysis also concluded that meeting the EU’s cross-zonal capacity availability requirement—the so-called 70% rule—could have prevented roughly half of the most severe spikes. It further suggested fuller cross-border capacity availability could have reduced average evening peak prices by up to €78/MWh in central and south-east bidding zones in a counterfactual scenario.
Balancing tools beyond interconnectors
Flexibility is also framed as an internal system requirement rather than only a cross-border issue. SEE grids are described as relying on legacy thermal plants for inertia and balancing, with hydropower often acting as a critical modulator. Climate variability and hydrological constraints are said to reduce hydro’s reliability as an always-available flexibility source.
This is described as pushing systems toward greater reliance on fossil balancing or imports when hydrological conditions limit flexibility from hydro. The dynamic increases the value of storage, demand-side response, and balancing market integration—areas identified as structurally incomplete in SEE.
European balancing platforms and market coupling progress
The European balancing framework is presented as a key mechanism for turning flexibility into something usable across borders. The Electricity Balancing Guideline has driven common platforms for balancing energy exchange across transmission system operators, including PICASSO for automated frequency restoration reserves and MARI for manual frequency restoration reserves.
The platforms are described as enabling balancing energy to flow to where it is needed when functioning fully, reducing system costs and lowering price volatility. For SEE, deep participation is described as important for mitigating scarcity events, but balancing integration is also noted as dependent on grid code alignment, operational readiness, interconnector availability, and national market arrangements.
The Energy Community’s implementation reporting is cited as showing steady but uneven progress toward deeper integration. It highlights priorities including market coupling completion and removal of infrastructure bottlenecks. The market coupling agenda is described as extending beyond day-ahead efficiency by enabling flexibility sharing and scarcity mitigation.
Trading behaviour shifts toward flow control and volatility capture
The region’s trading behaviour is described as confirming that flexibility is increasingly monetised by market participants. Focus is said to be shifting toward flow control, border positions, and volatility capture rather than only generation ownership.
A January 2026 market note cited the return of tradable liquidity alongside intensified cross-border flows and monetisation of volatility by professional traders. It also links this pattern to structural change under conditions where flexibility is scarce and prices are volatile. The same account ties this shift to the importance of transparent capacity allocation rules, robust intraday markets, and market coupling discipline.
Quantified context from recent pricing episodes
The quantitative annex context cited for early January 2026 shows SEE average spot prices falling from €94.82/MWh to €89.73/MWh, then rising to €111.36/MWh the following week. For summer 2024, reported price spikes reached up to €1,000/MWh, with 147 major spikes recorded across the region.
The cited counterfactual suggests around half of those most severe spikes could have been avoided with full 70% cross-zonal capacity availability, with peak prices reduced by up to €78/MWh.