In 2025, the landscape of power risk management in Southeast Europe (SEE) revealed a significant shift in the cost structure associated with electricity trading. While outright price risk had traditionally been seen as the primary concern for market participants, it became evident that basis risk emerged as the more costly component, silently impacting financial results and undermining hedging strategies.
Basis risk manifests when there is a misalignment between the prices used for hedging and the actual prices of physical exposure. This issue became systemic within SEE markets, where industrial consumers and utilities typically hedged their local exposure against national exchanges while simultaneously executing forward hedges on regional or core European markets. While this strategy aimed to mitigate headline exposure, it inadvertently introduced a secondary layer of risk that proved to be financially burdensome.
The prevalent market configuration in 2025 saw physical exposure primarily linked to SEEPEX, OPCOM, or IBEX, with forward hedges executed on HUPX or German-linked EEX products. Although there was a high directional correlation between these markets, the amplitude of this correlation was notably weak.
When examining annual average spreads during 2025, they appeared relatively stable; however, intra-year volatility presented a starkly different picture. The spread between SEEPEX and HUPX annual baseload prices fluctuated by ±8–12 €/MWh during critical periods marked by hydro stress, thermal outages, and cross-border congestion. Similar volatility was observed between IBEX and HUPX, while OPCOM spreads experienced significant seasonal widening during drier quarters.
This volatility translates into tangible economic impacts for market participants. For instance, an industrial buyer managing a 50 MW flat load, equivalent to around 438 GWh annually, could face a deviation of approximately ±4.4 million € from expected energy costs due to a ±10 €/MWh basis movement, despite being nominally fully hedged.
Larger consumers or utilities operating at scales of 100 MW or more would see their exposure double proportionally. Such deviations were not isolated incidents; throughout 2025, they occurred frequently—especially during Q1 and Q3, driven by weather variability and infrastructure limitations.
The asymmetric nature of basis risk exacerbated its impact. Hedging strategies tended to be more effective at protecting against upward price shocks than capturing downward movements. In instances where local markets decoupled downwards—often due to surplus hydro availability or increased imports—hedged consumers found themselves unable to fully capitalize on favorable conditions. Conversely, when local prices surged, hedges frequently lagged or underperformed due to congestion-driven price divergences.
<pConsequently, many industrial buyers realized post-delivery that their “fully hedged” portfolios still held an effective exposure ranging from 15–30%. This exposure did not translate into catastrophic losses but rather resulted in persistent inconsistencies against budgeted energy costs. Over time, such variances contributed to diminished competitiveness and unpredictable EBITDA outcomes for these entities.
The situation was further complicated in Romania and Bulgaria where forward hedging often relied on bilateral contracts indexed to spot references. This reliance led to embedded risk premiums including credit risk, liquidity risk, and basis risk itself—adding an estimated 3–6 €/MWh onto effective hedging costs compared to core European consumers.
By the close of 2025, market participants had reached a consensus: while hedging strategies could reduce volatility within the market framework, they did not eradicate it entirely. The residual risks identified were not merely incidental; they were structural issues inherent within the market dynamics. Until local forward markets develop sufficiently to ensure alignment between hedging instruments and physical exposures, basis risk will persist as a significant hidden cost impacting electricity consumption across Southeast Europe.
