In South-East Europe, the power grid is increasingly a driver of returns

In South-East Europe, electricity markets are starting to look like a map of grid bottlenecks rather than a single trading arena. As interconnectors and substations increasingly determine where power can flow, investors are finding that nodal positioning can matter as much as generation technology when it comes to price outcomes.

That shift is captured in the region’s evolving South-East Europe’s electricity system, where the transformation of SEE electricity is described as an infrastructure story: the region’s 400 kV transmission backbone is actively shaping price formation, investment returns and capital allocation. What once functioned mainly as background logistics for electrons has become an economic mechanism that influences where value is created—or trapped.

A strategically placed network at the centre of regional pricing

Serbia sits at the heart of this system. Its transmission operator EMS manages one of the most strategically located grids in continental Europe, with key nodes anchoring corridors that connect SEE markets to broader Central European price signals.

The Subotica 400 kV substation, linked northward to Hungary’s Sandorfalva node, supports what is described as the region’s most liquid corridor—bridging SEE trading activity with Central European price formation. To the east, Serbia’s Djerdap–Resita interconnection ties into Romania’s Transelectrica system, which draws support from Cernavoda nuclear baseload and growing Black Sea wind capacity. Southward connectivity runs through Serbia toward Greece via Niš 400 kV node, while flows westward are shaped through Bajina Bašta and Višegrad, linking into Bosnia and Herzegovina’s hydro-dominated system.

From apparent convergence to widening splits under stress

The picture changes when conditions move away from stability. Under relatively calm circumstances, prices across Hungary, Romania and northern Serbia tend to converge within a narrow band of €5–10/MWh, consistent with strong interconnection capacity and partial market coupling. But structural fragility shows up quickly: when constraints emerge—whether from outages, seasonal demand surges or renewable intermittency—spreads widen sharply.

The article notes that differences can reach €20–60/MWh between northern and southern SEE zones. Rather than being random market noise, these divergences are attributed directly to transmission bottlenecks.

Bottlenecks turn transfer limits into monetised scarcity

A key example is the Serbia–Hungary corridor. Even with nominal transfer capacity cited as up to 1,500 MW, available transfer capacity (ATC) often drops toward 600–1,000 MW, due to loop flows and system security constraints. Southbound capacity out of Serbia toward Bulgaria and North Macedonia is described as structurally tighter as well, which limits how effectively lower-cost northern generation can reach higher-priced southern markets.

This produces a system likened to interconnected pricing islands rather than a fully unified market. Greece trades at a premium—often €10–40/MWh above Central European levels—in connection with its LNG-driven marginal pricing approach. Albania and North Macedonia face even sharper volatility tied to hydro conditions and constrained interconnection capacity.

Montenegro adds another dimension because it acts both as transit and export node through the Lastva 400 kV substation. The link connects Montenegro to Italy via a 600 MW HVDC submarine cable to Pescara, enabling access to Italian price premiums. The piece estimates annual congestion rents from this pathway at €70–150 million, depending on market conditions.

What congestion rents signal for traders—and why lenders care

The article treats congestion rents as an indicator of structural imbalance across borders. On the Serbia–Hungary border, annual rents in the range of €50–120 million reflect persistent differentials alongside insufficient transmission capacity. On the Greece–Bulgaria interconnection—where LNG imports and solar variability drive rapid intraday swings—rents can exceed €200 million.

These revenues are framed not only as accounting figures but as monetised scarcity that transfers value from constrained areas toward operators or holders associated with cross-border capability.

The same mechanism underpins profitable strategies for traders such as MET Group, Axpo and EFT: by securing cross-border capacity through explicit auctions on the Joint Allocation Office platform and pairing it with short-term positions in spot markets, participants can extract value from differentials rooted in physical constraints.

A hybrid market design that amplifies divergence risks investment economics

The paper also points to auction design as part of why divergence persists during transitions between market models. While Hungary, Romania and Croatia participate in implicit day-ahead coupling under Single Day-Ahead Coupling rules, Serbia, Bosnia and Herzegovina—and Montenegro—rely heavily on explicit capacity auctions.

This hybrid setup can create inefficiencies that amplify price gaps: capacity may not always be allocated strictly according to real-time value signals, increasing volatility and contributing to suboptimal flows.

Lenders now underwrite projects based on location exposure—not just resource quality

The implications extend beyond trading desks into project finance underwriting standards. In this framework, electricity prices in SEE are no longer determined solely by fuel costs or generation merit order—they are shaped by where assets sit relative to constraints.

An example given is solar development near strong connections such as around the Subotica node : proximity enables capture prices close to regional baseload levels because export paths improve access to Central European markets. A similar project in southern Serbia near Vranje , however, faces curtailment risk alongside lower capture prices due to limited export ability and local oversupply during peak solar hours.

Differentiated economics across renewables pipelines in Serbia & Montenegro

The article then contrasts specific pipeline dynamics for renewables investments across Serbia and Montenegro. It highlights a planned wind project—the Gvozd wind farm d eveloped by EPCG in Montenegro—with approximately 55 MW . With integration described as relatively strong through access enabled by the Nikšić and Lastva nodes (and partial exposure via Italy through the interconnector), estimated CAPEX is placed at about €90–110 million . The project targets equity IRRs ranging from 9–12% , supported by merchant exposure alongside potential structured offtake agreements.

Solar developments under Serbia’s EPS renewable programme—including hybrid solar-plus-storage projects in central and southern regions—face more complex dynamics because battery sizing interacts directly with constraint-driven price patterns.

A representative case cited involves a 100 MW solar plant paired with a 50 MW / 200 MWh battery system. Total CAPEX is estimated at roughly €140–180 million , split between about €60–80 million </bfor solar construction costs plus about b €80–120 million for storage at current cost levels of b €400–600/kWh . Without storage in constrained nodes it notes unlevered IRR could land around b7–9% , reflecting capture discounts tied to curtailment potentially reaching b15–25% . With battery integration shifting output toward evening peaks—and thereby capturing wider spreads—it suggests IRRs can rise toward b10–13% , with upside potentially approaching b15% under high-volatility scenarios.

Bankability hinges on DSCR sensitivity amid grid-driven revenue swings

The financing structure described follows naturally from these operational realities. Lenders increasingly assess not only resource quality or sponsor strength but also how projects sit within congested parts of the network—captured in terms such as congestion exposure combined with nodal positioning.

Debt sizing depends on expected cash flow stability using debt service coverage ratios (DSCR). In lower-risk locations DSCR profiles around b1.30–1.40x support leverage levels roughly b65–75% . In more constrained areas where revenue volatility rises further tightening occurs: DSCR requirements move toward b1.40–1.60x , reducing leverage toward b50–60% unless mitigated by long-term PPAs or storage integration.

Industrial buyers introduce stability through longer contracts tied partly to premiums

A further change highlighted is how industrial off takers begin reshaping risk allocation through procurement strategy. Firms operating in CBAM-exposed sectors such as steel, aluminium and fertilisers are increasingly entering long-term power purchase agreements intended to secure low-carbon electricity supply over time. 

 This willingness includes paying premiums measured at €5–15/MWh above merchant-adjusted prices . In regions where grid constraints would otherwise depress revenues or increase volatility for merchant generators alone, This kind of contract structure acts like an additional layer of confidence for cash flows: 

 The article describes these agreements as credit anchors that improve bankability—and enable higher leverage compared with purely merchant-based revenue streams. 

The next investment cycle targets bottleneck relief—but full convergence remains distant