Across South-East Europe, electricity pricing is still governed as much by physics as by markets. The region’s 400 kV transmission backbone does not simply move electrons; it determines where value is created, who captures it, and how long it persists. In an environment where price convergence remains incomplete, congestion has quietly evolved into one of the most reliable revenue streams in the system. It is measurable, tradable, and—crucially—persistent.
At the centre of this dynamic sits the north–south corridor linking Hungary, Serbia, Bulgaria and Greece, with additional east–west flows connecting Romania, Bosnia and Croatia. The structural reality is that while installed transfer capacity between these markets appears sufficient on paper—often exceeding 1,200–1,500 MW on key borders—the commercially available capacity, reflected in ATC allocations, is regularly constrained to 600–1,000 MW. The difference is not a technical footnote; it is the origin of congestion rent.
On the Serbia–Hungary border, one of the most liquid interconnections in the region, annual congestion revenues fluctuate between €50 million and €120 million, depending on volatility conditions. These revenues are not evenly distributed over time. They concentrate in periods of structural divergence, when Hungary tracks Central European price formation while Serbia reflects a mix of coal baseload, hydro variability and constrained export routes. During winter stress events or gas-driven price spikes in Greece, spreads can widen to €40–60/MWh, temporarily transforming this corridor into one of the most profitable trading routes in Europe.
Further south, the Bulgaria–Greece interconnection exhibits even stronger monetisation characteristics. With Greek prices frequently set by LNG-linked marginal generation, spreads versus Bulgaria can sustain €20–40/MWh over extended periods. In volatility phases, annual congestion rents on this border can exceed €150–200 million, reflecting both structural demand pressure in Greece and limited northbound transmission capacity. This dynamic is not cyclical in the traditional sense; it is embedded in the generation mix and infrastructure configuration of the region.
The Adriatic corridor offers a different but equally compelling case. The Montenegro–Italy HVDC link, with an operational capacity of 600 MW, functions as a direct export channel from a hydro-dominated Balkan system into a premium Italian market. Arbitrage spreads of €20–50/MWh are not unusual, particularly during periods of Italian peak demand. This single asset has effectively re-priced Montenegro’s electricity system, allowing surplus generation to access a higher-value market and generating annual congestion revenues in the range of €70–150 million. The discussion around a second cable, with an estimated CAPEX of €800 million to €1.2 billion, is therefore less about redundancy and more about scaling a proven arbitrage model.
What makes these congestion revenues structurally durable is the interaction between network topology and generation mix. In Western Europe, market coupling and dense interconnection have compressed spreads to marginal levels. In contrast, South-East Europe remains a system where loop flows, internal bottlenecks and uneven generation profiles prevent full price alignment. Even where market coupling is implemented—such as between Hungary and Romania—the benefits dissipate quickly when flows encounter constraints further south.
This creates a layered pricing environment. Northern nodes, particularly those connected to Hungary and Romania, tend to track Central European baseload prices within a narrow band of €2–8/MWh. Moving south, spreads widen progressively. In central Serbia, differences of €5–15/MWh are common, reflecting internal constraints and limited export capacity. In southern corridors and Greece, premiums of €10–40/MWh become structural, driven by gas pricing, solar intermittency and transmission limitations.
For traders, this geography defines strategy. Firms such as MET Group, Axpo, EFT and GEN-I do not operate on a uniform regional price curve; they build portfolios around specific corridors, time periods and capacity rights. The acquisition of long-term transmission rights through annual and monthly auctions becomes a form of optionality. When spreads widen, these rights translate directly into realised margin. When spreads compress, downside is limited to the cost of capacity, which is itself priced based on expected congestion.
The auction framework reinforces this monetisation structure. While parts of the region participate in implicit day-ahead market coupling, large sections—particularly Serbia, Bosnia and Montenegro—still rely on explicit auctions managed through platforms such as JAO. These auctions allocate capacity across yearly, monthly and daily timeframes, effectively creating a forward market for congestion. Prices paid for capacity rights embed market expectations of future spreads, making congestion not only a physical phenomenon but a traded financial variable.
From an investment perspective, the implications are direct. Transmission constraints behave like infrastructure tolls, generating predictable cash flows for system operators and creating arbitrage opportunities for market participants. Unlike generation assets, which are exposed to fuel costs, weather variability and policy shifts, congestion rents are driven by structural imbalances that take years to resolve. The planned €2.5–4.0 billion transmission investment pipeline across South-East Europe will reduce some bottlenecks, but it will not eliminate them. Grid expansion tends to shift constraints rather than remove them entirely, creating new pockets of congestion even as old ones are relieved.
For renewable developers, the same dynamics translate into risk and opportunity. A solar plant located in northern Serbia, with direct access to high-capacity interconnections, can capture prices close to the Hungarian benchmark—typically €70–85/MWh in current forward markets. The same plant in southern Serbia may face effective prices of €45–65/MWh, once curtailment and congestion discounts are factored in. This is not a marginal difference; it can determine whether a project achieves an equity IRR of 10–11% or struggles below 7%.
Curtailment risk amplifies the effect. In well-connected northern nodes, curtailment is typically below 5%, preserving revenue stability. In constrained southern zones, it can reach 20–30%, eroding both output and price capture. Developers are therefore forced to incorporate grid positioning into project design, treating transmission access as a core component of value rather than an external constraint.
This is where storage begins to reshape the equation. Battery energy storage systems (BESS), with current installed costs in the range of €400–600/kWh, provide a mechanism to convert congestion from a constraint into a revenue source. By shifting generation from low-price periods to high-price windows, storage captures intra-day spreads that often exceed €20–60/MWh in volatile markets such as Greece and Bulgaria. When co-located with solar, it also mitigates curtailment, effectively increasing the capture price of the underlying asset.
In practice, a 100 MW solar plant paired with a 200 MWh battery system can increase annual revenue by €15–30 million, combining arbitrage gains, avoided curtailment and ancillary service income. This can lift project IRRs from 8–9% to 12–16%, particularly in high-volatility nodes. The financial logic is clear: storage does not merely enhance returns; it stabilises them, improving debt service coverage ratios and enabling higher leverage.
Industrial demand adds a further layer of complexity. With the introduction of carbon border mechanisms, energy-intensive industries across the region are increasingly seeking long-term renewable supply to manage embedded emissions. These industrial PPAs often command premiums of €5–15/MWh above merchant-adjusted prices, reflecting the strategic importance of electricity sourcing for export competitiveness. In effect, electricity becomes an input into carbon compliance, not just a cost of production.
Taken together, these dynamics are reshaping how the SEE power system is perceived. It is no longer a collection of national markets loosely connected by transmission lines. It is a financial ecosystem in which infrastructure, generation and trading are tightly interlinked, and where value is created at the intersection of physical constraints and market design.
Platforms such as Electricity.Trade are increasingly reflecting this shift, tracking not just prices but the underlying drivers of spreads, capacity allocation and volatility. For investors, the critical insight is that the most attractive opportunities do not necessarily lie in building new generation at the lowest cost. They lie in positioning assets—generation, storage or capacity rights—at points in the grid where structural imbalances can be consistently monetised.
As transmission investments gradually reshape the network, some of today’s congestion corridors will weaken. Others will emerge. The fundamental logic, however, remains unchanged. In a system where full convergence is neither immediate nor complete, the grid itself becomes a source of yield. The ability to understand, model and access that yield will define the next phase of market participation in South-East Europe.