Southeast Europe’s electricity market is exposed to further price shocks as renewable deployment advances faster than cross-border grids, operational coordination and flexible capacity, according to an ACER assessment supported by market developments during the summer of 2026.
The EU energy regulator said the region’s 2024 price spikes were not a one-off event but pointed to structural weaknesses. In May, ACER set out 10 measures focused on transmission investment, improved outage coordination, storage and demand response, alongside flow-based market coupling and compliance with the EU requirement to make at least 70% of transmission capacity available for cross-border trade.
Since the report’s publication in May, conditions have reinforced the regulator’s assessment. The summer disruption pattern also highlighted how availability of generation and cooling resources can coincide with falling solar output and rising demand.
Drought and cooling constraints cut generation across multiple markets
During July and August, severe drought and low river levels reduced nuclear, hydro and thermal availability across Romania, Hungary, Slovenia and neighbouring markets. At the same time, air-conditioning demand increased while solar output fell rapidly in the evening, prompting several countries to seek imports during overlapping hours.
Romania’s Cernavodă nuclear plant lost both of its approximately 706 MW units at the height of the drought. That outage removed capacity that normally supplies close to one fifth of national electricity.
Hungary’s 2,000 MW Paks nuclear plant faced heavy constraints as authorities intervened to maintain sufficient Danube water for cooling. Hydro production weakened across parts of the region while thermal plants encountered cooling and fuel-related constraints.
In Montenegro, the 307 MW Perućica hydropower plant shortened an overhaul to return 190 MW to service because the system was under pressure. The 225 MW Pljevlja thermal plant was unavailable during the same period.
Interconnectors depend on released capacity for cross-border trade
The events shifted interconnectors into the region’s main mechanism for balancing supply between countries. However, an interconnector can only support neighbouring markets when physical capacity exists and national operators release it for trade.
ACER’s requirement that at least 70% of transmission capacity be available for cross-border exchange is central to that process. Keeping excess transmission capacity for domestic congestion management limits trade flows and can widen price differences between neighbouring bidding zones.
The regulator said making more capacity available would enable cheaper generation to displace expensive plants across a broader area. It also noted that transmission operators cannot safely release capacity that the network cannot carry.
Compliance therefore needs to be paired with grid reinforcement, improved regional network models and more effective remedial actions.
Planned outages, market coupling delays and meshed-grid effects
ACER identified weak coordination of planned grid outages as a source of avoidable capacity reductions. The issue is particularly relevant in Southeast Europe because maintenance on one line can redirect flows through multiple neighbouring systems.
The regulator also pointed to vulnerabilities in institutional arrangements affecting regional power exchanges. Recent partial decoupling and delayed market-coupling outcomes were cited as evidence that even short disruptions can reduce liquidity, separate bidding zones and push traders toward more expensive intraday or balancing transactions.
The meshed nature of the grid further complicates congestion management. Electricity scheduled on one border may physically flow across several others rather than remaining confined to a single corridor.
Energy Community data for the first quarter showed large discrepancies between commercial schedules and physical flows on corridors running from Greece and Albania through Montenegro and Bosnia towards Croatia, Hungary and Romania.
Flow-based capacity calculation and coordinated remedial actions
The divergence between schedules and physical flows increases redispatch requirements and makes available capacity harder to calculate. It also raises the operational value of coordinated remedial actions compared with uncoordinated national restrictions.
ACER recommended wider use of flow-based capacity calculation. The method models how transactions affect the entire interconnected grid instead of treating each border separately.
The approach is already used in parts of the EU but remains incomplete across Southeast Europe. ACER said it does not yet fully include the Western Balkans.
Batteries expand while participation rules lag in energy markets
Storage additions can reduce solar-driven volatility by charging during low-price daylight hours and discharging during evening peaks. Bulgaria and Greece have moved quickly to support battery investment, while Romania and Serbia have substantial project pipelines.
Serbia has identified 724 MW of prospective battery capacity through transmission-related planning. It also cited an additional 200 MW/400 MWh within the EPS investment programme.
Planned storage cannot support system operation until projects are connected, prequalified and allowed to participate in energy and balancing markets. Regulatory barriers remain material for some projects, including double network charging, unclear connection treatment or limited access to reserve products.
Demand response and aggregation are also at an early stage across much of the region. As a result, Southeast Europe may add several gigawatts of renewable generation and storage while still relying on older hydro and thermal plants for most operational flexibility.
Tighter evenings expected as weather-driven spreads widen through autumn 2026
Regional wholesale markets are expected to remain volatile through autumn 2026. Cooler weather should reduce air-conditioning demand compared with summer conditions, but risks from July and August are expected to carry over.
Low hydro reserves may limit utilities’ ability to generate aggressively during high-price periods. Nuclear availability in Hungary and Romania will remain closely watched alongside planned thermal outages and grid maintenance that could remove additional capacity.
Gas prices are another upward risk for electricity costs in Greece, Italy and Romania. Higher European gas costs increase marginal generation costs across connected markets, with the strongest impact during evening hours when solar output declines and gas plants increasingly set clearing prices.
The likely autumn pattern described by ACER is repeated episodes of sharp hourly divergence rather than continuous scarcity: lower prices during renewable-rich periods followed by expensive evening ramps where border capacity constraints widen spreads.
Differing exposure across countries as flexibility tightens near peak hours
Bulgaria could retain a relative advantage when nuclear, coal and battery availability are strong. Romania and Hungary are described as more exposed to nuclear recovery performance, Danube water conditions and import availability.
Serbia and Montenegro are expected to depend on hydro availability alongside how their thermal fleets perform. Greece is described as continuing to transmit gas-price exposure northward during low-renewable hours.
The regulator said its recommendations will not remove these risks before winter because grid reinforcement and flow-based integration take years. For the coming months, ACER highlighted outage coordination, real-time border capacity availability and whether batteries and flexible plants can respond when multiple countries need them simultaneously.
The region does not lack interconnection; its vulnerability lies in how little usable flexibility may remain during the most difficult evening hours.
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