Liquidity has become one of the most decisive structural variables shaping electricity market behavior in South-East Europe. Beyond prices and flows, the distribution of trading volumes across exchanges determines which markets act as price setters, which function as price takers, and how efficiently system stress is translated into economic signals. Week 08 of 2026 illustrates that SEE electricity markets operate within a clear hierarchy of liquidity, one that mirrors grid strength and cross-border relevance rather than national demand size alone .
At the top of this hierarchy sit exchanges tightly linked to Central Europe. Hungary’s HUPX and Italy’s IPEX continue to function as regional liquidity anchors, concentrating the majority of tradable volume and acting as reference points for price discovery. Even in a week of falling prices, these markets maintained depth and responsiveness, enabling prices to adjust smoothly to improving supply conditions. Hungary’s average price of €107.17/MWh, despite a -11.57% weekly decline, reflects not only system constraints but also the fact that HUPX absorbs and redistributes stress from the German–Austrian core .
Italy’s role is equally instructive. Although Italian prices declined by -9.80%, remaining near €104.82/MWh, IPEX continued to shape regional expectations through its scale and liquidity . Italy’s exceptional renewable output in Week 08, including a +449 GWh increase in variable RES generation, was rapidly internalized by the market, demonstrating how high liquidity allows supply shocks to be priced efficiently without destabilizing adjacent systems.
Slovenia’s BSP and Croatia’s CROPEX occupy an intermediate tier. These exchanges benefit from proximity to liquid hubs and relatively strong interconnections, allowing partial price alignment with Central Europe. In Week 08, Croatia’s price declined by -21.39%, while Slovenia followed a similar downward trajectory, reflecting how liquidity-enabled markets can transmit flexibility gains even when domestic demand rises . For TSOs, this tier illustrates how moderate liquidity can amplify grid integration benefits, reducing volatility and smoothing adjustments.
Below this level sit the Western Balkan exchanges: SEEPEX (Serbia), BELEN (Montenegro) and ALPEX (Albania). These markets exhibit significantly thinner liquidity, with prices more heavily influenced by bilateral flows and domestic generation rather than continuous trading depth. During Week 08, Serbia’s price fell by -27.80%, Montenegro’s by a comparable margin, and Albania’s remained among the lowest in the region . While these declines reflect genuine system improvement, the speed and magnitude of adjustment also reveal the fragility of price formation in thin markets.
In low-liquidity environments, prices respond less to incremental changes and more to discrete events. This explains why Albania, despite maintaining a weekly average price around €29–30/MWh, can still experience extreme hourly spikes under stress conditions. Liquidity scarcity does not eliminate volatility; it postpones and concentrates it. For TSOs, this creates a mismatch between apparent calm and latent risk.
The Bulgaria shock in Week 08 further illustrates liquidity asymmetry. Bulgaria’s extraordinary net imports of 6,165 GWh reshaped regional flows, yet Bulgarian price signals did not dominate regional benchmarks . Instead, stress was absorbed and priced through more liquid hubs upstream. This demonstrates that liquidity, not physical imbalance, determines where prices move most visibly.
Forward markets reinforce this hierarchy. Liquid exchanges support active week-ahead, month-ahead and calendar products, allowing participants to hedge and smooth expectations. In contrast, SEEPEX, BELEN and ALPEX lack meaningful forward liquidity, forcing market participants to hedge exposure through HUPX or BSP. This practice effectively imports price and carbon risk into markets that otherwise appear insulated on a spot basis.
From a TSO perspective, this behavior has operational implications. When hedging occurs upstream, system operators must anticipate that downstream markets will react to stress indirectly, often through flows rather than prices. Liquidity concentration therefore channels risk into the grid before it becomes visible in domestic price signals.
Week 08 also demonstrates that falling prices do not equate to declining liquidity importance. On the contrary, liquidity becomes more valuable during transitions from stress to balance. High-liquidity markets adjusted smoothly as renewables and hydro expanded. Low-liquidity markets followed with larger percentage moves but less granularity. This difference affects how TSOs interpret price changes as system signals.
Another structural consequence of liquidity hierarchy is the persistence of price tiers. Despite synchronized declines, prices remained stratified, with Hungary and Italy above €100/MWh, Central Balkan markets clustered around €50–60/MWh, and Türkiye near €29.54/MWh . Liquidity reinforces these tiers by anchoring expectations locally. High-liquidity markets price future scarcity earlier; low-liquidity markets adjust later and more abruptly.
For TSOs, this implies that price convergence is not solely a function of interconnection capacity. It also depends on whether markets have sufficient liquidity to translate physical integration into economic alignment. Reinforcing grid corridors without addressing liquidity gaps may increase flows without improving price signaling quality.
The interaction between liquidity and grid topology is therefore central to understanding SEE market behavior. Liquidity accumulates where grids are strong, interconnections are reliable and participants perceive optionality. These locations become economic control points for the region, even if they are not the largest consumers or producers.
Looking forward, the evolution of liquidity will shape how SEE absorbs future shocks. As renewable penetration rises and thermal generation retreats, markets with deep liquidity will continue to act as buffers, while thin markets will experience sharper episodic volatility. For TSOs, recognizing this hierarchy is essential for effective coordination and contingency planning.
Week 08 confirms that liquidity is not a passive market attribute. It is an active system variable that determines where stress is priced, how quickly balance is restored and which corridors bear the operational burden. In a highly interconnected SEE system, understanding liquidity distribution is therefore as important as understanding generation mix or demand trends.
For transmission system operators, the strategic implication is clear. Market surveillance must extend beyond prices and volumes to include where liquidity resides and how it migrates under stress. Only by integrating liquidity analysis into system monitoring can TSOs fully anticipate the operational consequences of market behavior in an increasingly flexible, but unevenly structured, regional power system.
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