January 2026 has marked a pivotal moment for the power markets in Southeast Europe, with gas re-establishing itself as the primary marginal driver of electricity pricing. Despite a notable increase in renewable energy generation across various markets and improved hydro conditions in parts of the Balkans, these developments have not diminished gas’s critical role in price formation during periods of system stress.
The resurgence of gas marginality is primarily attributed to shifting expectations around risk rather than a genuine scarcity of supply. In January, TTF prices escalated from €28–29/MWh at the start of the month to nearly €41/MWh by its conclusion. This price movement prompted power markets in Hungary, Romania, Italy, and Bulgaria to reprice based on anticipatory measures rather than immediate spot fundamentals. Observations indicate that electricity bids increasingly incorporated forward gas risk, reflecting a proactive stance among market participants.
Hungary and Romania serve as prime examples of this trend. Both countries experienced average electricity prices exceeding €150/MWh, despite only modest growth in demand. In Hungary, a net import share of 34.03% linked local prices to broader Central European dynamics driven by gas. Meanwhile, Romania faced declining hydro output that diminished its ability to buffer against rising prices, compelling reliance on gas and imports to set the margin. Thus, price formation took on a forward-looking nature, embedding gas volatility even before physical constraints were evident.
Italy further underscores the dominance of gas within this regional hierarchy. With approximately 61.91% of its generation sourced from gas and net imports totaling 2.78 TWh, Italian electricity prices remained elevated at €132.67/MWh. Even during periods characterized by robust renewable output, gas maintained its position as the primary driver for peak pricing, influencing Adriatic spreads and transmitting volatility into adjacent markets.
In contrast, hydro-rich countries such as Greece and Serbia momentarily resisted this repricing phenomenon. Supported by significant increases in hydro generation—155.37% for Greece and 186.06% for Serbia—these nations temporarily decoupled from the overarching gas-driven surge in prices. However, this insulation is deemed conditional and short-lived; once hydro availability returns to normal levels, pricing dynamics are expected to revert quickly back to being dictated by gas and imports.
The overarching structural implications are significant: while renewable energy growth has altered average price levels within these markets, it has not fundamentally changed who controls marginal pricing. The absence of adequate dispatchable capacity or storage means that intermittent renewable sources cannot effectively suppress gas prices during peak demand or stress scenarios. Consequently, gas continues to set price ceilings and shape volatility profiles across Southeast European electricity markets.
In conclusion, it is evident that gas marginality has transitioned from being a cyclical phenomenon to one that is systemic within these markets. As such, energy market participants must prioritize gas as an essential variable in their pricing strategies, hedging approaches, and risk management decisions moving forward.
