By 2025, Romania and Bulgaria stood out in South-East Europe for one specific reason: they had achieved scale in spot electricity trading that many neighbouring markets could not match. Monthly volumes on both exchanges regularly reached terawatt-hour levels, anchoring price discovery across the eastern Balkans. Yet this success masked a fundamental weakness. Despite impressive turnover, neither market could absorb risk at scale. They priced electricity efficiently, but they did not hedge it.
In Romania, OPCOM operated one of the region’s most liquid day-ahead markets. Throughout 2025, monthly traded volumes consistently exceeded 1.4–1.6 TWh, supported by a diversified generation mix that included nuclear, hydro, wind, and gas. This diversity produced a price signal widely regarded as credible and regionally relevant. Bulgarian participants, Serbian traders, and even Greek counterparties monitored OPCOM prices as an indicator of eastern SEE fundamentals.
Bulgaria’s IBEX pushed spot liquidity even further. Monthly volumes frequently reached 2.2–2.4 TWh, with intraday trading surpassing 600 GWh per month. IBEX became a magnet for short-term optimisation, particularly for hydro balancing and cross-border arbitrage into Greece and Romania.
Yet in both markets, this spot dominance failed to translate into forward hedging depth. Exchange-traded futures, where available, remained thin and opaque. Open interest was limited, tenor coverage uneven, and execution capacity insufficient for large industrial or utility portfolios. As a result, forward risk management referencing OPCOM or IBEX prices migrated almost entirely into the bilateral OTC space.
These bilateral forwards served a purpose. They allowed counterparties to lock in prices indexed to familiar spot references. However, they embedded multiple layers of hidden cost. Credit risk premia reflected counterparty balance sheets rather than market liquidity. Liquidity premia compensated sellers for holding unhedgeable exposure. Basis risk premia accounted for the inability to offset positions dynamically.
In 2025, these embedded costs became measurable. Industrial buyers in Romania and Bulgaria often paid an effective hedge price 3–6 €/MWh higher than comparable consumers in Germany or Austria, even before accounting for network charges and taxes. This differential was not driven by generation costs alone, but by the structural inability of local markets to warehouse risk efficiently.
The paradox was stark. OPCOM and IBEX generated some of the clearest spot price signals in SEE, yet those signals could not be transformed into scalable hedging instruments. Risk was priced, but not absorbed. It was pushed outward, primarily toward HUPX and further into core European futures markets, where deeper liquidity pools existed.
By the end of 2025, market participants understood the distinction clearly. OPCOM and IBEX were price formation hubs, not hedging hubs. Their value lay in transparency and immediacy, not in long-term risk management. Until forward markets in Romania and Bulgaria achieve visible, multi-tenor depth with anonymous clearing, this division of labour will persist, and risk premia will remain embedded in electricity costs across the eastern Balkans.
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