Congestion rents in SEE: how grid bottlenecks are turning into tradable cash flows

South-East Europe’s electricity market is still shaped by physics, but traders and investors are increasingly treating that reality as a financial feature rather than an operational inconvenience. Where available transmission capacity falls short of what network infrastructure suggests, congestion becomes measurable, monetisable—and likely to endure while price convergence remains incomplete.

The region’s value creation is concentrated along a north–south backbone and associated east–west connections. A 400 kV transmission system does not simply move electrons; it determines how long spreads persist, which nodes capture them, and who can turn those gaps into revenue through trading or asset positioning.

A corridor map where “enough on paper” doesn’t translate into flows

At the centre of this dynamic sits the north–south corridor linking Hungary, Serbia, Bulgaria and Greece, complemented by east–west links connecting Romania, Bosnia and Croatia. While installed transfer capability between these markets often appears sufficient—frequently exceeding 1,200–1,500 MW on key borders—the commercially available capacity shown in ATC allocations is regularly constrained to 600–1,000 MW. That gap is the starting point for congestion rent.

Even when physical transfer capability exists on paper, what matters for settlement is what can actually be allocated. In practice, that means congestion rents emerge when demand patterns and generation dispatch collide with binding constraints.

Serbia–Hungary and Bulgaria–Greece: liquid routes with repeatable monetisation

On the Serbia–Hungary border, described as one of the most liquid interconnections in the region, annual congestion revenues fluctuate between €50 million and €120 million, depending on volatility conditions. The source text notes that revenues are not evenly distributed across time: they concentrate during periods of structural divergence—such as when Hungary tracks Central European price formation while Serbia reflects coal baseload dynamics alongside hydro variability and constrained export routes.

The same mechanism shows up during stress episodes. During winter pressure events or gas-driven price spikes in Greece (which feed into regional pricing), spreads can widen to €40–60/MWh, temporarily elevating this corridor into one of Europe’s more profitable trading pathways.

The Bulgaria–Greece interconnection, meanwhile, is characterised as having even stronger monetisation characteristics. With Greek prices frequently set by LNG-linked marginal generation in the scenarios described, 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 demand pressure in Greece and limited northbound transmission capacity.

This pattern is presented as less cyclical than seasonal: it is embedded in regional generation mix and infrastructure configuration.

The Adriatic case: an export channel that reshapes another system’s pricing

The discussion extends beyond continental corridors to the Adriatic corridor. The Montenegro–Italy HVDC link, operating with an operational capacity of 600 MW, functions as a direct export route from a hydro-dominated Balkan system into Italy’s higher-value market segment. Arbitrage spreads of €20–50/MWh are described as not unusual—particularly when Italian peak demand tightens prices.

This single connection has effectively re-priced Montenegro’s electricity system according to the source text, enabling surplus generation to access higher-value pricing while generating annual congestion revenues estimated at €70–150 million. The report also frames debate around a second cable—estimated CAPEX of €800 million to €1.2 billion—as less about redundancy than scaling an already proven arbitrage model.

Why durability remains: topology meets uneven dispatch across SEE

The persistence of these cash flows is linked to how network topology interacts with generation mix. In Western Europe, dense interconnection and market coupling compress spreads toward marginal levels. By contrast, South-East Europe still features loop flows, internal bottlenecks and uneven generation profiles that prevent full price alignment—even where market coupling exists locally (such as between Hungary and Romania), benefits fade once constrained paths appear further south.

This produces a layered pricing environment across nodes:

• Northern nodes connected to Hungary and Romania tend to track Central European baseload prices within roughly €2–8/MWh.
• Centrally located areas such as Serbia see differences commonly around €5–15/MWh, tied to internal constraints and limited export capacity.
• Southern corridors including Greece can carry premiums of about €10–40/MWh, driven by factors including gas pricing signals, solar intermittency effects and transmission limitations.

A forward market for congestion rights—and why auctions matter for finance teams too

This geography shapes trading strategies because firms do not manage risk against a single regional price curve—they build portfolios around specific corridors, time windows and capacity rights. According to the source text, companies including MET Group, Axpo, EFT and GEN-I use long-term transmission rights acquired via annual and monthly auctions as a form of optionality: when spreads widen these rights translate directly into realised margin; when spreads compress downside becomes more closely tied to capacity costs priced based on expected congestion levels.

The auction framework reinforces this monetisation structure. Parts of the region participate in implicit day-ahead market coupling, but large sections—especially Serbia, Bosnia and Montenegro—still rely on explicit auctions managed through platforms such as JAO. Those auctions allocate capacity across yearly, monthly and daily timeframes effectively creating a forward-like market for congestion conditions. Capacity prices embed expectations about future spread levels—turning congestion from purely physical friction into a traded variable with financial meaning.

Investors’ takeaway: grid expansion shifts constraints rather than erases them immediately

From an investment perspective highlighted in the source text, transmission constraints behave like infrastructure tolls: they generate predictable cash flows for system operators while offering arbitrage opportunities for market participants. Unlike generation assets exposed to fuel costs (and weather or policy changes), congestion rents are driven by structural imbalances that typically take years to resolve.

A planned grid investment pipeline across South-East Europe totals approximately <€2.5–4.0 billion. The report cautions that while new projects will reduce some bottlenecks they will not eliminate all constraints because grid expansion tends to shift where limits bind rather than remove them entirely—creating new pockets of congestion even as older ones ease.

The renewable development angle: curtailment risk depends on location—and changes IRR math fast

The same constraint logic affects renewables developers through both effective pricing differences and curtailment exposure. For example cited in the source material:

• A solar plant located in northern Serbia with access to high-capacity interconnections may capture prices close to the Hungarian benchmark—typically around <€70–85/MWh in current forward markets.
• The same plant placed in southern Serbia could face effective prices closer to €45–65/MWh, once curtailment impacts along with congestion discounts are considered.

• The difference can be decisive for project returns noted here as moving from an equity IRR target range around 10–11% to struggling below 7%.