December 2025 opens the winter season in Central and South-East Europe with a familiar but very different energy landscape. The fears that once shaped the region’s winter outlook — tight gas balances, extreme price volatility, supply threats and fragile thermal fleets — have been replaced by a calmer, more technically governed market. The price signals coming from HUPX in Hungary, OPCOM in Romania, SEEPEX in Serbia and IBEX in Bulgaria tell a coherent regional story: winter premiums have returned, but without the panic that defined 2022 and the cautious recovery of 2023. At the same time, early-December volatility reminds policymakers and traders that regional integration has not eliminated local stress points. Instead, it has simply compressed them into narrow bands where fundamentals, weather and cross-border flows decide everything.
The month starts with markets coming off a soft November, supported by an unexpectedly benign gas outlook. By Week 48, TTF futures for early 2026 fell below 30 euros per megawatt-hour, reaching an eighteen-month low and signalling that Europe’s gas supply has more than enough resilience to handle a normal winter. This easing on the fuel side immediately filtered into day-ahead electricity pricing across the region. November baseload averages were tightly clustered around 120 euros across the four markets, with Serbia’s SEEPEX clearing at 119.15 euros per megawatt-hour and Romania’s OPCOM reporting a weighted average equivalent to roughly 120–125 euros. Hungary’s HUPX had already settled into the same band in October, and while Bulgaria’s IBEX carried its traditional mild premium, the year-to-date average of about 137 euros still reflected a region that has decisively shifted back to pre-crisis stability.
What followed in the first days of December, however, served as a reminder that stability does not mean flatness. On SEEPEX, the early days of the month produced some of the sharpest intraday swings of the year. The month began with prices clearing above 150 euros, then brushing 168 euros on a tight day, before falling below 100 euros by the sixth of December. The same pattern — brief, sharp spikes followed by rapid corrections — appeared across the region, although with different amplitudes. Bulgaria’s IBEX cleared at 125 euros for the fifth of December, drifting closely around the SEEPEX and OPCOM levels. HUPX did not publish its December average yet, but given tight historical coupling and identical fundamentals, its early-December prices tracked the same 110–130 euro corridor as the rest of the region.
These movements reveal a deeper structural truth about the Central and South-East European electricity market: price formation has become almost fully synchronised, but volatility is not gone. Instead, it has been reshaped. In the old world — the world of coal-heavy fleets, limited interconnection and state-directed price caps — each market carried its own signature. Hungary aligned loosely with Central Europe, Romania was anchored by nuclear and hydro, Serbia moved with its hydro-lignite balance and Bulgaria’s IBEX swung wildly depending on export flows. That fragmentation has collapsed. The Single Day-Ahead Coupling (SDAC) and the EUPHEMIA algorithm now bind the four exchanges into a single basin where prices move in parallel unless local conditions break the flow. The result is a region that trades with tight spreads most days, but where congestion, hydro variability, temperature swings or thermal outages can still create temporary price gaps of 20 to 40 euros per megawatt-hour.
December 2025 is shaping up exactly along that logic. The fundamental setting is soft: cheap gas, stable CO₂ prices and broadly available generation. The winter premium is visible but subdued. Most importantly, no structural shocks have emerged. Serbia’s lignite plants are performing within expected availability, Romanian nuclear output remains steady, and Bulgarian exports are active but not distorting the market. As long as gas remains cheap and weather remains seasonal rather than extreme, the region is operating close to its most efficient configuration: converged day-ahead markets shaped by pan-European conditions rather than national idiosyncrasies.
Forecasting Q1 2026 within this framework becomes an exercise in scenario weighting rather than crisis modelling. The base case is clear. If TTF holds in the 25–35 euro range, if hydro conditions remain average and if winter temperatures follow standard variability rather than delivering prolonged cold spells, then HUPX, OPCOM and SEEPEX will trade almost indistinguishably in the 115–135 euro band throughout January, February and March. Bulgaria’s IBEX, with its chronically higher marginal costs and limited flexibility, will likely settle slightly above, in the 125–145 euro range. In this baseline scenario, volatility remains contained. Daily price movements continue to swing between roughly 90 euros on mild or windy days and 170 euros on tight days, but these spikes flatten out when averaged across the month.
The second scenario is the one that operators and industrial buyers remain sensitive to: a cold-winter tightening. The region is structurally better prepared for cold shocks than it was three years ago, but it is not immune. A severe cold spell in January or February would lift demand sharply and reduce hydro flows, forcing CCGTs, lignite plants and imported electricity to define the price for most hours of the day. If such weather coincides with even a modest rise in gas prices toward 40 euros, day-ahead baseload averages could quickly rise into the 150–170 euro band, especially in Bulgaria and Hungary. Serbia, which often struggles with hydro seasonality and lignite plant outages, would be the first to show price stress. The risk then spreads outward through the coupling mechanism. In these moments, the regional market behaves less like a calm lake and more like a resonant instrument: one local constraint is enough to push prices upward across all four zones. Under such stress, hourly prices above 200 euros would not be unusual, even if monthly averages remain well below the extremes seen in the crisis years.
A third scenario — the mild-winter case — would bring the opposite outcome. If January and February temperatures run above seasonal averages, if LNG continues to flow into European terminals at the current pace and if reservoir levels remain comfortable, then the pressure on thermal generation will be limited and day-ahead prices could slide back below 110 euros for prolonged periods. In such a soft-fundamentals quarter, the baseload averages across HUPX, OPCOM and SEEPEX could drift into the 95–115 euro range, with IBEX clearing only marginally higher. This would mark one of the mildest winter quarters since full regional coupling, and it would further entrench the idea that the energy market has successfully transitioned back to a low-volatility equilibrium.
What emerges from these three outlooks is not uncertainty but a narrowing of the plausible range. The days when the region could swing from 70 euros to 350 euros on policy or fuel news alone are gone. The new reality of the Central and South-East European power market is defined by structural fundamentals — fuel, weather, interconnections and generation availability — and by the integration that magnifies or dampens those fundamentals across borders. The December 2025 price curve, with its fast swings but modest amplitude, is therefore not an anomaly. It is the early expression of the market regime that will shape the first quarter of 2026 and likely the years to come.
This has practical consequences. For utilities planning procurement strategies, for lenders financing renewable and thermal assets, and for industrial buyers exposed to day-ahead pricing, the winter of 2025–26 could be the first season in years where planning assumptions finally converge to predictable numbers. A baseload environment hovering around 120–130 euros is not without risk, but it is manageable. It allows industries to hedge with more confidence, and it allows investors to evaluate projects without the extreme uncertainty premiums that dominated recent years.
December 2025 offers something unusual for the region: a window into a future in which electricity prices are neither artificially suppressed nor chaotically inflated. The early winter volatility remains a reminder that weather and infrastructure still shape prices, but the overall structure signals stabilisation rather than stress. As the region moves into Q1 2026, the market appears ready to trade winter fundamentals rather than winter fears — and that, for the first time in a long while, is a story of normalisation.
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