Southeastern Europe’s next bottleneck is transmission—and it is starting to reshape prices

Southeastern Europe’s next major energy constraint is unlikely to be a lack of power plants. The early warning sign is already showing up in market pricing: transmission capacity is increasingly determining whether electricity can reach the right place at the right hour—turning grid congestion into both a risk and a potential revenue source.

Congestion signals appeared even as demand fell

In the first half of May 2026, regional data pointed to congestion-led market behavior. Prices rose sharply even though demand declined. Solar generation increased, but it did not prevent higher system prices, while cross-border flows changed materially and several corridors showed signs of tightening, reversal, or structural imbalance.

The implication for investors and market participants is straightforward: electricity value in SEE is becoming more dependent on physical deliverability than on generation volumes alone.

Regional flows deteriorated and corridor positions worsened

Net exports across the broader HU+SEE system deteriorated from -767 MW to -1,170 MW, indicating that the region became more import-dependent during the observed period. Flows toward Italy reversed from +310 MW to -148 MW. Meanwhile, the Bulgaria–North Macedonia–Albania flow position toward Greece worsened to -1,129 MW.

These movements matter commercially because the Balkans have historically relied on cross-border flexibility to smooth national imbalances. Hydro-rich systems exported during favorable hydrology, coal-heavy systems provided baseload, and Greece, Italy, Hungary and Romania often acted as price anchors depending on seasonality, weather and fuel spreads. That balancing structure is becoming less predictable as multiple pressures converge.

Multiple pressures are colliding with limited cross-border capacity

The region faces several simultaneous challenges. Solar capacity is growing faster than grid reinforcement. Coal plants are becoming less reliable. Nuclear outages have a stronger price impact. Hydro output is less consistently monetizable. Gas is returning as a marginal balancing fuel. CBAM is also altering buyer behavior for Western Balkan electricity.

At the same time, cross-border capacity remains constrained by older network design, slow permitting and fragmented national investment planning—limits that can intensify congestion even when generation looks sufficient at a system level.

Price differences show constraints shaping value

The regional price map already reflects this shift. Romania’s OPCOM averaged €115.88/MWh in the first half of May and traded at a €7.65/MWh premium to Hungary’s HUPX. Bulgaria’s IBEX averaged €104.98/MWh; Croatia’s CROPEX €105.77/MWh; Slovenia’s BSP €103.85/MWh; Serbia’s SEEPEX €101.61/MWh; Montenegro’s BELEN €98.76/MWh; and Albania’s ALPEX €98.60/MWh.

The spreads are not large enough on their own to indicate a fully fractured market, but they are wide enough to suggest that national conditions and corridor constraints are increasingly shaping where value lands.

Country examples illustrate how grid access can outweigh resources

Romania illustrates how complex interactions can sustain a premium even with strong supply fundamentals: it combines major generation resources, renewable potential, nuclear exposure and hydro flexibility alongside cross-border links toward Hungary, Bulgaria, Serbia, Moldova and Ukraine. Yet it also faces network connection disputes and regulatory pressure around new grid access rules—factors reflected in May data showing Romania at the top of the SEE price stack above Hungary, Bulgaria and Serbia.

Bulgaria presents another version of the same problem as it develops into a solar and battery storage hub. Storage growth can respond to grid pressure by mitigating issues such as curtailment risk or negative-price exposure from uncontrolled solar—but it does not replace stronger transmission corridors.

Greece serves as a clearer warning sign where renewable deployment appears to be outpacing system flexibility. The May flow data—showing northern flows toward Greece deteriorating sharply—points to continued dependence on imported balancing under certain conditions even as domestic solar can depress prices during other hours.

A “timing” problem becomes more common across SEE

The emerging pattern suggests that SEE may increasingly experience renewable oversupply in one zone while scarcity persists in another at different times of day. A solar-heavy area can generate negative prices around noon while still requiring expensive imports later in the evening if spatial coordination and flexibility do not keep pace.

This dynamic places Serbia inside the congestion map due to its geographic position between multiple markets including Hungary, Romania, Bulgaria, Bosnia and Herzegovina, Montenegro, Kosovo and North Macedonia. Serbia could function as a regional balancing corridor if transmission investment, market coupling, grid-code enforcement and renewable connection planning move fast enough alongside project development; otherwise it risks becoming more of a congestion buffer than a value-capturing hub.

Regulatory change amplifies physical constraints

Montenegro faces similar economics through different resources: its hydropower and wind resources have regional value potential, but export monetization depends increasingly on access to premium corridors. The article cites EPCG’s reported €13 million Q1 export revenue impact from CBAM-related market effects as an example of how trade rules can reduce value for low-carbon generation when corridor economics change; adding physical congestion would widen that gap further.

Bosnia and Herzegovina confronts yet another constraint set: aging coal assets, delayed hydropower projects and fragmented institutional governance create uncertainty around future supply reliability. The piece points to projects including HPP Dabar, HPP Mrsovo, Poklecani wind farm and Vlasic wind farm as illustrations of how difficult it can be to translate resource potential into bankable grid-connected capacity.

Due diligence priorities shift toward grid location

For investors considering renewable projects in SEE, evaluation criteria are changing beyond resource quality and commercial terms such as PPA pricing or permitting status. Grid location is becoming a primary bankability variable—down to which substation or voltage level matters within which congestion zone relative to neighboring markets.

The article frames this as a material shift in capital allocation: developers with land secured cheaply in weak-grid areas may face declining financing appetite compared with projects near strong transmission nodes that offer lower curtailment probability and better industrial offtake options.

Banks may require deeper technical analysis

Lenders are likely to demand more detailed grid studies before committing long-term debt—covering TSO correspondence, curtailment scenarios, congestion sensitivity modeling, power-flow analysis and dispatch simulations supported by independent technical review.

This also increases the value of Owner’s Engineer roles and technical advisory work because transmission risk cannot be fully captured through legal documentation alone; it requires integrated engineering together with market understanding and financial analysis.

Storage economics evolve into “congestion-relief” investments

The congestion decade will also reshape battery storage economics in SEE beyond shifting solar output from noon into evening. Storage can reduce congestion at specific nodes, support grid stability and participate in balancing markets—meaning optimal locations will be defined by network stress rather than only co-location with generation.

The article describes this as creating an emerging locational investment class: congestion-relief batteries near constrained renewable clusters that can earn revenue from arbitrage while supporting reliability; in more advanced designs they may eventually receive regulated or semi-regulated compensation for grid services—even though SEE is “not yet fully there.”

Transmission constraints become an industrial policy issue

Beyond power markets themselves, congestion affects industrial competitiveness through CBAM-linked requirements for traceable low-carbon electricity delivery. A factory cannot rely on distant renewables if congestion prevents credible physical supply or hourly matching tied to compliance needs.

The piece argues this makes electricity-market congestion an economic development question rather than only a power-sector one: governments may need to treat transmission investment not merely as slow regulated utility work but as strategic industrial policy priority so renewable capacity translates into export competitiveness instead of stranded production.

The next decade rewards corridor coordination—not just megawatts

No single country can solve SEE congestion alone because electricity economics are corridor-based across borders—from Bulgaria–Greece links to Serbia–Hungary flows; Romania–Hungary connections; Montenegro–Italy-linked markets; and Bosnia interacting with Serbia and Croatia via shared constraints.

The May data therefore reads less like an isolated snapshot than an early shape of structural transition: transmission becomes the central scarce asset while generation remains essential but increasingly determines whether projects capture prices reliably enough for financing—and whether countries connect supply to high-value consumers and export corridors efficiently.