By 2025, the most expensive component of power risk management in South-East Europe was no longer outright price risk. It was basis risk. This risk did not appear on invoices, but it accumulated silently in financial results, eroding the effectiveness of hedging strategies that were theoretically sound yet practically incomplete.
Basis risk arises when the price used to hedge does not perfectly match the price of physical exposure. In SEE, this mismatch became systemic. Industrial consumers and utilities typically hedged local exposure indexed to national exchanges while executing forward hedges on regional or core European markets. The hedge reduced headline exposure but introduced a secondary risk layer that proved costly.
The most common configuration in 2025 involved physical exposure linked to SEEPEX, OPCOM, or IBEX, with forward hedges executed on HUPX or German-linked EEX products. Correlation between these markets was high in direction, but weak in amplitude.
During 2025 delivery, annual average spreads appeared benign. However, intra-year volatility told a different story. The spread between SEEPEX and HUPX annual baseload prices experienced swings of ±8–12 €/MWh during periods of hydro stress, thermal outages, and cross-border congestion. Similar magnitudes were observed between IBEX and HUPX, while OPCOM spreads exhibited strong seasonal widening during dry quarters.
To translate this into economic terms, consider an industrial buyer with a 50 MW flat load, equivalent to approximately 438 GWh annually. A ±10 €/MWh basis movement produces a ±4.4 million € deviation from expected energy costs. This occurs despite the portfolio being fully hedged in nominal terms.
For larger consumers or utilities managing 100 MW or more, the exposure doubles proportionally. Importantly, this is not a tail scenario. In 2025, such deviations occurred repeatedly, particularly in Q1 and Q3, driven by weather variability and infrastructure constraints.
What made basis risk especially damaging was its asymmetric nature. Hedges tended to protect against upward price shocks more effectively than they captured downward movements. When local markets decoupled downward due to surplus hydro or imports, hedged consumers failed to fully benefit. When prices spiked locally, hedges often lagged or underperformed due to congestion-driven divergence.
As a result, many industrial buyers discovered post-delivery that their “fully hedged” portfolios still exhibited 15–30 % effective exposure. This exposure manifested not as catastrophic losses, but as persistent variance against budgeted energy costs. Over time, this variance translated into reduced competitiveness and unpredictable EBITDA outcomes.
In Romania and Bulgaria, where forward hedging often relied on bilateral contracts indexed to spot references, the problem was compounded by embedded risk premia. Credit risk, liquidity risk, and basis risk were priced into contracts, adding an estimated 3–6 €/MWh to effective hedging costs relative to core European consumers.
By the end of 2025, sophisticated market participants had reached a clear conclusion. In SEE, hedging reduced volatility, but it did not eliminate it. The residual risk was not accidental; it was structural. Until local forward markets deepen sufficiently to align hedging instruments with physical exposure, basis risk will remain the hidden tax on electricity consumption in South-East Europe.
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