By early 2026, South-East Europe’s electricity market is no longer best understood through national supply–demand balances alone. The decisive variable has become where liquidity concentrates, how effectively it travels across borders, and how deeply intraday markets absorb volatility. Power exchanges in SEE are no longer merely trading venues; they are price transmission engines whose depth, coupling status and participant mix directly shape what industry ultimately pays per megawatt-hour.
The region now exhibits a clear liquidity hierarchy. At the top sit HUPX, OPCOM and IBEX, each operating at volumes large enough to dampen single-asset dominance and create statistically reliable reference prices. In the middle tier are SEEPEX and CROPEX, which increasingly function as regional anchors but remain sensitive to cross-border congestion. On the developing edge sit ALPEX and BELEN, whose importance lies more in transparency and institutional discipline than raw liquidity.
Hungary’s HUPX remains the integration bridge of the region. Daily traded day-ahead volumes consistently operate in the 70–80 GWh range, while intraday trading is measured in terawatt-hours per month, not as an exception but as a baseline. This scale matters because it creates a market where no single generator, utility or trader can structurally dominate price formation. For industry, this translates into lower embedded risk premiums in supply contracts. When suppliers hedge through HUPX, they face narrower bid–ask spreads and lower imbalance exposure, allowing margins to compress naturally.
Romania’s OPCOM plays a different but equally decisive role. With monthly day-ahead volumes frequently exceeding 1.4–1.6 TWh, OPCOM has become a volume engine rather than a corridor market. Romania’s diversified generation mix—nuclear baseload, hydro flexibility, wind intermittency and gas marginality—creates a price curve that reacts to fundamentals rather than administrative interventions. Average baseload prices around €115–125/MWh in late 2025 and early 2026 did not reflect scarcity alone; they reflected a functioning market clearing mechanism. For regional industry, OPCOM’s importance lies in its reliability as a statistical reference, increasingly used as an index component in bilateral supply contracts beyond Romania itself.
Bulgaria’s IBEX is structurally the export hub of SEE. Monthly day-ahead volumes around 2.2–2.4 TWh, combined with record intraday volumes exceeding 600 GWh per month, make IBEX one of the most operationally relevant exchanges in the region. The presence of over 150 licensed traders, alongside generators, consumers and network operators, ensures continuous arbitrage pressure. This pressure does not necessarily lower prices, but it eliminates unjustified price separation. Where Bulgarian prices diverge, they usually do so because of real constraints—fuel, carbon or transmission—not because of illiquidity.
The Western Balkans’ core reference markets, SEEPEX and CROPEX, occupy a more nuanced position. Serbia’s SEEPEX, with annual traded volumes above 5.4 TWh and daily averages approaching 16 GWh, has crossed the threshold from symbolic exchange to functional market. The presence of over 40 active participants from more than 15 countries has materially altered pricing behaviour. Volatility remains, but it is increasingly volatility with depth, not single-bid price jumps. For Serbian industry, this has reduced supplier risk premiums by an estimated €4–7/MWh compared to pre-2024 bilateral-only procurement structures.
CROPEX shows a similar but more hydro-driven profile. Monthly day-ahead volumes around 0.8–0.9 TWh, combined with meaningful intraday trading—including 15-minute products exceeding 50 GWh per month—make Croatia one of the most intraday-mature markets in SEE. This matters disproportionately for industry because intraday liquidity directly reduces imbalance costs. Where intraday volumes are thin, suppliers embed balancing risk into fixed margins. Where intraday markets are deep, that risk is traded rather than priced administratively.
Slovenia’s BSP SouthPool is small in absolute terms but strategically oversized. Daily traded volumes in the 30–40 GWh range would not normally define a regional hub. What changes the equation is BSP’s integration into ADEX together with HUPX and SEEPEX. ADEX is not a market itself; it is an access and infrastructure unifier. By lowering participation friction across multiple zones, it effectively multiplies liquidity. A trader active on ADEX can arbitrage Hungary, Slovenia and Serbia as a single optimisation space, which in turn tightens spreads and accelerates price convergence during normal conditions.
Greece’s power exchange ecosystem occupies a unique position. Greece is large enough that daily volumes exceed 1.2 TWh, but its price formation remains highly sensitive to gas pricing, interconnector availability and renewable intermittency. Directional congestion toward Bulgaria and Italy frequently generates spreads of €6–10/MWh, creating sustained arbitrage value. For industry, Greece demonstrates an important principle: large volume does not automatically mean low risk if cross-border constraints remain binding.
On the development frontier, ALPEX represents potential rather than scale. Monthly volumes around 120–130 GWh and prices near €105–110/MWh indicate a functioning but still shallow market. ALPEX’s real importance lies in its coupling trajectory. If Albania, Kosovo, North Macedonia and Greece achieve operational coupling, ALPEX could transition from a national transparency tool into a corridor market that trades scarcity and surplus across multiple systems. That transition would materially alter industrial price formation in the southern Western Balkans.
Montenegro’s BELEN illustrates the limits of scale. Annual traded volumes below 0.35 TWh and daily averages under 1 GWh mean that price prints can swing from €30/MWh to over €230/MWh without reflecting system-wide marginal cost. For Montenegrin industry, the exchange provides transparency but not hedging depth. Suppliers therefore continue to price contracts with high risk buffers, often €10–15/MWh above regional benchmarks, to compensate for thin liquidity.
The impact of these structures on industrial electricity prices is not theoretical. A modeled comparison of two identical industrial buyers—one sourcing power in a deep, coupled market, the other in a thin, congested one—shows how exchange liquidity translates into real cost. In markets where day-ahead liquidity exceeds 1 TWh per month and intraday liquidity exceeds 20% of day-ahead volume, supplier margins typically compress to €3–5/MWh. Where intraday liquidity falls below 10%, margins expand toward €8–12/MWh, regardless of the headline spot price.
Cross-border congestion adds another layer. A reduction of congestion hours by 10–15% per year through improved coupling and capacity allocation typically lowers delivered industrial prices by €5–9/MWh, even if average spot prices remain unchanged. This is why infrastructure and market design matter more than isolated price spikes.
Trading companies are the silent enforcers of this discipline. Firms such as Axpo, MET Group, Statkraft, RWE Supply & Trading and Engie Trading operate across multiple SEE exchanges simultaneously. Their presence is not about speculation; it is about forcing price alignment. Where they can trade, spreads narrow. Where they cannot, local monopolies persist.
By early 2026, the hierarchy is therefore clear. Romania and Bulgaria are volume engines. Hungary is the optimisation bridge. Greece is a large but constraint-sensitive price setter. Serbia and Croatia are the Western Balkans’ reference hubs, increasingly relevant as liquidity deepens. Slovenia is small but structurally amplified through integration. Albania and Montenegro are transparency markets whose future importance depends on coupling and scale.
For industry, the strategic implication is straightforward. Competitiveness in SEE will not be determined by whether electricity is “cheap” or “expensive” on any given day. It will be determined by how liquid the reference market is, how deep intraday trading runs, and how often borders are open when prices diverge. Where those conditions are met, risk is traded. Where they are not, risk is priced—and industry pays for it.
Elevated by virtu.energy