The integration of South-East Europe into the European electricity market has reached a stage where institutional alignment is largely in place, yet economic convergence remains incomplete. Market coupling through the Single Day-Ahead Coupling (SDAC) and Single Intraday Coupling (SIDC) frameworks has connected core EU markets with Romania, Hungary, Bulgaria and Greece, while Serbia, North Macedonia and Albania remain structurally linked through physical flows rather than full algorithmic integration. The expectation embedded in European policy design has been that coupling would compress price spreads, increase efficiency and deliver a unified electricity market. The reality emerging across the region is more complex: convergence improves, but persistent spreads remain structurally embedded.
The architecture of market coupling is built around implicit allocation. Instead of auctioning transmission capacity separately, energy and capacity are cleared simultaneously through centralised algorithms such as Euphemia. This removes inefficiencies associated with explicit auctions and ensures that available transmission capacity is used to maximise economic welfare. In Central Europe, where grid density is high and generation mixes are relatively balanced, this mechanism has delivered strong convergence. In South-East Europe, however, the physical structure of the grid and the composition of generation portfolios introduce constraints that coupling cannot eliminate.
The Romania–Hungary corridor, centred on interconnections such as Arad–Sandorfalva and Nadlac–Bekescsaba, provides a reference case for effective coupling. With combined transfer capacity of 1,500–2,000 MW and annual flows exceeding 12–15 TWh, this interface exhibits relatively stable price alignment. Day-ahead spreads between OPCOM (Romania) and HUPX (Hungary) have narrowed to €2–8/MWh in normal conditions, reflecting both sufficient capacity and similar marginal generation costs. During periods of high wind output in Romania or peak demand in Hungary, spreads can widen to €15–25/MWh, but these events are increasingly episodic rather than structural.
Moving south, the dynamics shift. The Bulgaria–Greece interconnection, anchored around Maritsa East and Thessaloniki, illustrates the limits of coupling in the presence of divergent generation structures. With physical capacity of 1,200–1,500 MW and flows exceeding 10–12 TWh annually, the corridor is fully integrated within European coupling frameworks. Yet price spreads between IBEX (Bulgaria) and HEnEx (Greece) persist at €20–40/MWh on average, expanding to €50–80/MWh during peak volatility. The driver is not market inefficiency but structural asymmetry: Greece’s gas-dominated marginal pricing versus Bulgaria’s mix of nuclear, coal and renewables.
The coupling algorithm efficiently allocates capacity, but once that capacity is saturated, prices diverge. This is a critical distinction. Coupling ensures optimal use of existing infrastructure; it does not create additional capacity. In a system where transmission expansion lags behind generation growth, particularly in solar-heavy southern markets, congestion becomes the defining feature of price formation.
The Serbia–Hungary interface (Subotica–Sandorfalva, 1,200–1,500 MW) sits at the boundary between coupled and non-coupled systems. Serbia is not yet fully integrated into SDAC, but its price formation is heavily influenced by Hungarian markets. Annual flows of 8–10 TWh and spreads averaging €5–15/MWh reflect partial convergence, with explicit auctions still playing a role. As Serbia progresses toward coupling, these spreads are expected to narrow modestly, potentially to €3–10/MWh, but not disappear entirely due to internal grid constraints and differing generation mixes.
The persistence of spreads under coupling has direct financial implications. For traders, it confirms that arbitrage remains viable even in a fully integrated market. The nature of arbitrage shifts from exploiting institutional inefficiencies to navigating physical and temporal constraints. For renewable developers, it reinforces the importance of location. A project connected near a highly integrated node can achieve realised prices close to reference hubs, while one in a constrained zone may face significant discounts despite operating within the same coupled market.
Transmission investment is often presented as the solution to this divergence. Projects such as the Trans-Balkan Corridor (€300–400 million), Bulgaria–Greece reinforcements exceeding €500 million, and IPTO’s northern expansion are expected to increase transfer capacity by 20–40% on key routes by 2030. These upgrades will reduce congestion and improve convergence, but their impact will be moderated by simultaneous growth in renewable capacity. With regional solar and wind installations projected to exceed 25 GW, new bottlenecks are likely to emerge even as existing ones are alleviated.
The interaction between coupling and renewable generation introduces a temporal dimension to price formation. During midday periods of high solar output in Greece, prices can collapse to €30–50/MWh, while northern markets remain at €70–90/MWh. Even with full coupling, the limited capacity of interconnections prevents complete equalisation. Conversely, during evening peaks, Greek prices can rise to €150–200/MWh, pulling neighbouring markets upward as flows reverse. This creates a system where convergence exists within limits, bounded by both capacity and time.
Intraday markets further complicate this picture. As coupling extends into continuous trading, price signals become more granular, reflecting real-time system conditions. Differences between day-ahead and intraday prices can exceed €30–70/MWh, particularly in volatile markets. For flexible assets such as storage, these differences represent a primary revenue source, reinforcing the importance of temporal arbitrage alongside spatial arbitrage.
The financial modelling of projects increasingly incorporates these dynamics. Capture price assumptions are no longer based solely on day-ahead averages but adjusted for both spatial and temporal factors. In northern nodes, capture discounts may remain limited to €2–5/MWh, supporting stable revenue profiles. In southern or constrained zones, combined effects of congestion and timing can reduce realised prices by €15–30/MWh, significantly affecting project economics.
Lenders are adapting their frameworks accordingly. Debt sizing now incorporates location-specific scenarios, with P90 production adjusted for curtailment and capture discounts. Projects in highly integrated nodes can support leverage of 65–75%, while those in constrained areas may be limited to 50–60%, unless mitigated by storage or contractual structures. Debt service coverage ratios are calibrated to reflect these risks, typically requiring 1.30x–1.50x depending on location and revenue stability.
Platforms such as Electricity.Trade are increasingly central to this process, providing data on cross-border flows, ATC utilisation and price spreads. This data enables developers, traders and lenders to model coupling effects with greater precision, moving beyond simplified assumptions toward more granular and realistic projections.
The broader implication of market coupling in South-East Europe is that integration does not eliminate complexity; it redistributes it. Institutional barriers are reduced, but physical and structural constraints become more visible. Price formation becomes a function of both market design and infrastructure, with coupling acting as a bridge rather than a solution.
As the region continues to integrate into the European market, the distinction between coupled and non-coupled systems will diminish. However, the underlying drivers of divergence—generation mix, grid topology and demand distribution—will remain. For investors and operators, understanding these drivers is essential. The value of electricity in South-East Europe is no longer determined solely by supply and demand within a market but by the interaction of multiple markets connected through a constrained and evolving grid.
