South-Eastern Europe’s electricity debate still carries a legacy obsession with capacity. How many megawatts a country “has” is treated as the primary measure of security. Yet the behaviour of SEE markets over the last eighteen months shows that the binding constraint has shifted. The core system limitation is increasingly flexibility: the ability to respond to fast changes in net load, to compensate for variable renewables, to manage cross-border constraints, and to stabilise the system during ramp hours when solar falls and demand remains high. Capacity matters, but it no longer determines outcomes on its own. A system can have enough installed megawatts and still experience price spikes, congestion, or emergency imports because it lacks the operational tools to balance volatility in real time.
The clearest indicator that flexibility is now central is the region’s increasingly sharp price response to meteorology and cross-border conditions. In early January 2026, SEE spot prices softened materially as wind output surged and demand dipped after the holidays. A regional market review quantified this shift: the average price fell from €94.82/MWh in Week 52 (late December) to €89.73/MWh in Week 01 (early January), a decline of 8.40%, with Serbia at -12.80% and Romania at -11.53%. The same review attributed the move to a powerful wind rebound, reporting a roughly 125% week-on-week increase in wind generation in the observed markets.
The more revealing point is not that prices fell. It is how rapidly they reversed. One week later, prices jumped across the region: the average rose from €89.73/MWh to €111.36/MWh, a 24.1% increase in Week 02. By Week 03, prices climbed again; one regional note described a roughly 29% week-on-week increase with Serbia experiencing the largest jump at 65.5%, and neighbouring markets clustering around €170–175/MWh. This is what a system looks like when flexibility is scarce: weather shifts and cross-border constraints quickly translate into sharp market repricing.
In a more mature electricity system, such swings are dampened by layered flexibility: large balancing platforms, deep intraday liquidity, extensive demand response, storage, strong interconnectors with high available trading capacity, and stable hydrological buffers. In SEE, some of these tools exist in partial form, but the region is still developing their depth and coordination. That is why system volatility manifests as abrupt week-to-week price changes and, in stress periods, extreme spikes.
The flexibility gap is most visible during evening peaks in summer and winter, when solar output collapses while demand remains elevated. In summer 2024, South-East Europe experienced a wave of extreme price spikes in evening hours, with reported peak prices reaching as high as €1,000/MWh. An ACER-referenced summary of the episode indicated 147 major price spikes in the region. The detail that matters is not the headline number; it is the diagnosis. The spikes were not an unavoidable consequence of demand. They reflected the system’s limited ability to import flexibility at scale when needed, which is directly linked to cross-border capacity availability and congestion management. In other words, the price spikes were a symptom of flexibility scarcity, not only generation scarcity.
ACER’s analysis 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 also suggested that 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 the counterfactual scenario. This is a direct quantitative expression of flexibility value: the ability to move power across borders at the right time is worth dozens of euros per megawatt-hour in avoided scarcity pricing.
But flexibility is not only cross-border. It is also inside the system. SEE grids still rely on legacy thermal plants to provide inertia and balancing, with hydropower often acting as the critical modulator. Yet climate variability and hydrological constraints reduce the reliability of hydro as an always-available flexibility source, forcing the system to lean more heavily on fossil balancing or imports. This dynamic increases the value of storage, demand-side response, and balancing market integration — precisely the areas where SEE is still structurally incomplete.
Here the European balancing platforms become crucial. Europe’s Electricity Balancing Guideline has driven the creation of common platforms for balancing energy exchange across TSOs, including PICASSO for automated frequency restoration reserves and MARI for manual frequency restoration reserves. These platforms matter because they transform flexibility from a national asset into a regional one. When functioning fully, they allow balancing energy to flow to where it is needed, reducing system costs and lowering price volatility. For SEE, deep participation in such mechanisms is not a regulatory exercise; it is a structural hedge against scarcity events.
Yet balancing integration is not automatic. It depends on grid code alignment, operational readiness, interconnector availability, and national market arrangements. This is why SEE’s integration trajectory — including formal market coupling initiatives — becomes central. The Energy Community’s implementation reporting underscores steady but uneven progress toward deeper integration, highlighting market coupling completion and infrastructure bottleneck removal as continuing priorities. The market coupling agenda matters because coupling is not merely about day-ahead efficiency; it is about allowing flexibility to be shared and scarcity to be mitigated.
The region’s emerging trading behaviour confirms that flexibility is now monetised. Market participants increasingly focus on flow control, border positions, and volatility capture rather than simply generation ownership. One January 2026 market note described the return of tradable liquidity, intensified cross-border flows, and the monetisation of volatility by professional traders. This is not a sign of market manipulation by itself; it is a sign of structural change. When flexibility is scarce and prices are volatile, traders become de facto allocators of system optionality. That fact increases the importance of transparent capacity allocation rules, robust intraday markets, and market coupling discipline.
What, then, is the strategic implication for SEE systems? It is that the transition will be won or lost through flexibility build-out rather than simple capacity announcements. The region needs a coherent flexibility stack: stronger interconnector availability, deeper market coupling, participation in European balancing platforms, scalable storage deployment, and credible demand response programmes for industry and large consumers. Without this stack, each additional gigawatt of wind or solar will increase operational stress and price volatility. With it, renewables can scale while price stability improves.
The economic case is no longer theoretical. The market has already priced flexibility scarcity in extreme events. When a rule change — such as making more cross-zonal capacity available — can reduce evening peak prices by up to €78/MWh, the system is telling policymakers the value of integration and flexibility in quantified form. When the region can swing from €89.73/MWh to €111.36/MWh in one week and then to price clusters near €170–175/MWh, it is demonstrating how quickly a flexibility deficit becomes a cost problem for industry and households.
The SEE flexibility gap is therefore not an abstract engineering issue. It is the region’s defining macroeconomic electricity risk — and the region’s defining opportunity. If SEE builds flexibility fast enough, it can converge toward European market stability and lower long-run volatility costs. If it does not, it will remain an exposed volatility belt where system stress is priced into every industrial electricity contract.
Quantitative annex context for this article: SEE average spot prices fell from €94.82/MWh to €89.73/MWh in early January 2026 and then rose to €111.36/MWh the following week. Summer 2024 saw price spikes up to €1,000/MWh, with 147 major spikes recorded in the region; ACER’s counterfactual suggests ~half could have been avoided with full 70% cross-zonal capacity availability, and peak prices reduced by up to €78/MWh.
By virtu.energy
