South East Europe’s electricity-price divergence from Central Europe is often discussed in terms of generation, including coal, renewables, gas exposure and storage. These factors are described as partly relevant, but not complete. The grid is identified as an additional driver of market outcomes.
In electricity markets, regional price differences can reflect constraints that are not directly visible to traders. If lower-cost power cannot reach a higher-price area, prices separate. Congested interconnectors or limited cross-zonal capacity can prevent stress from being relieved efficiently across regions.
ACER findings on 2024 spikes and the persistence into 2026
The Agency for the Cooperation of Energy Regulators (ACER) concluded that more efficient use of available network capacity between South East Europe and the rest of the EU could have helped ease regional system stress during the 2024 price spikes. ACER also found that the price gap between Southeast and Central Europe persisted through 2025 and into early 2026. The findings point to structural challenges beyond generation adequacy.
Price spikes are described as not always linked to a lack of total generation. They can also occur when electricity cannot be moved across borders at the right time. A region may be surrounded by lower-cost power yet still face scarcity pricing if grid capacity is unavailable.
Cross-zonal capacity allocation and the 70% requirement
Cross-border capacity allocation is presented as a central market issue for resolving these divergences. ACER recommended finalising implementation of the EU’s minimum 70% cross-zonal capacity requirement across Central and Southeast Europe. The agency also called for extending market coupling to non-EU neighbours and expanding flow-based capacity calculation and allocation in the region.
The 70% rule is intended to ensure transmission capacity is available for cross-border electricity trade rather than being reserved for internal grid constraints. In South East Europe, where demand, renewable output and hydro conditions can change quickly, cross-border access is described as important for price convergence.
Market coupling progress and liquidity fragmentation
Market coupling is described as part of the same problem. EU member states participate in increasingly integrated day-ahead and intraday markets, while Western Balkan markets are still moving toward full integration. The Energy Community’s Electricity Integration Package is designed to enable Contracting Parties to integrate into the single European electricity market.
Until integration is complete, liquidity remains fragmented. Traders face more friction, and cross-border flows may not respond efficiently to price spreads. Renewable exporters face additional complexity, while consumers ultimately pay for inefficiency.
15-minute day-ahead trading from 30 September 2025
The EU’s move to 15-minute day-ahead trading from 30 September 2025 is described as adding granularity to pricing. More detailed intervals are said to help reflect actual system conditions more accurately, particularly with variable renewables. For South East Europe, the value of granular pricing depends on whether electricity can be moved across both time and space.
Fifteen-minute prices are described as revealing grid-related problems rather than resolving congestion by themselves. Where cross-border capacity is constrained, improved temporal resolution does not eliminate physical limits on transfers.
Transmission delays, curtailment risk and renewable project outcomes
The grid bottleneck is also linked to renewable development timelines. Solar and wind projects may be quick to build, while transmission upgrades are slower. When generation connects faster than grid expansion, the system can experience curtailment, congestion and lower capture prices.
This can affect project economics even when technical performance is strong. Developers face the risk that a commercially weaker outcome follows if a plant cannot deliver power when and where it is valuable .
Grid investment scope: lines, substations and operational tools
The need for grid investment is framed as part of energy-transition investment priorities. Transmission lines, substations and digital control systems are cited alongside dynamic line rating and phase-shifting transformers. Better outage coordination is also listed as relevant infrastructure for enabling renewable electricity delivery .
The implications for planning are stated as practical: investors are advised to study grid constraints alongside resource characteristics such as solar irradiation or wind speed. The availability of connection points affects whether projects can deliver value under curtailment risk and whether cross-border trading strategies can operate effectively when capacity is unavailable.
Policy focus for Southeast Europe reforms
The policy message described for South East Europe emphasises volatility management beyond generation investment alone. It highlights transmission reinforcement, market coupling progress, improved capacity calculation approaches, storage deployment and demand flexibility . The direction combines physical measures with institutional changes.
The grid constraint-to-price mechanism is reiterated: when the grid is constrained, prices diverge; when prices diverge, consumers pay, investors hesitate and system stress rises . South East Europe’s next electricity-market reform is described as requiring both building more grid infrastructure and making better use of existing network capacity.
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