The gas markets in South-East Europe (SEE) exhibited distinct characteristics in January, diverging significantly from power market dynamics. While electricity prices experienced extreme volatility due to short scarcity intervals, gas pricing remained relatively stable. This stability was driven by consistent supply, effective storage management, and secure transport corridors rather than acute shortages. Consequently, the region saw elevated but manageable gas prices, with a marked reduction in volatility compared to power markets.
Throughout January, the Dutch TTF front-month contract traded within the €28–34/MWh range, with brief spikes primarily influenced by weather forecasts rather than major physical disruptions. This shift in gas pricing is noteworthy for SEE as it reflects a departure from the emergency-driven pricing of previous years. Instead, local market conditions now rely on contract structures and transport limitations, making regional premiums or discounts more indicative of market health than the headline hub price.
Serbia began January with a robust gas supply framework supported by long-term contracts with Gazprom via the Balkan Stream pipeline. This arrangement allowed Serbia to meet marginal winter demand at prices significantly lower than spot TTF peaks. As a result, gas did not emerge as the primary factor influencing Serbian power prices, even amid peak electricity prices reaching €300/MWh on SEEPEX. The challenges faced by Serbia’s power sector were more related to flexibility and import constraints rather than gas price fluctuations.
Bulgaria’s position was somewhat more vulnerable yet still stable compared to Serbia. With a diversified supply portfolio that included Azerbaijani imports through the IGB interconnector and LNG supplies linked to European hubs, Bulgaria’s gas pricing closely tracked TTF without experiencing acute stress. The orderly withdrawal from storage facilities allowed Bulgaria to export over 400 GWh of electricity to Romania during January while maintaining competitive marginal costs.
Romania’s gas landscape presented a different scenario altogether. As a significant domestic producer, Romania had sufficient storage and production capacity to meet most of its winter demand, reducing its exposure to international gas price volatility. However, despite this favorable position, Romanian power prices remained elevated—OPCOM reported an average baseload price of €150.51/MWh and peak prices at €176.60/MWh—indicating that factors beyond fuel costs were at play, such as system flexibility and hydro availability.
In Croatia, access to LNG imports via the Krk terminal provided a security advantage; however, this also made Croatian pricing more susceptible to hub volatility. The January gas prices for Croatian consumers reflected TTF levels plus regasification and transportation costs, resulting in higher delivered prices compared to Serbia’s contract-based rates. This situation translated into higher power pricing when gas-fired generation was on the margin during peak hours; CROPEX reported peak averages of €165.66/MWh against Serbia’s €136.27/MWh.
Conversely, Montenegro continued to operate outside the gas system entirely in January. Lacking gas-fired generation capacity meant that Montenegro’s electricity market was predominantly influenced by hydro availability and imports from neighboring countries. This resulted in significant price fluctuations on MEPX, where low demand days saw prices drop as low as €18.79/MWh while constrained peak days could spike above €180/MWh.
Storage behavior across SEE played a pivotal role throughout January. Adequate inventories allowed operators to manage cold weather demands through withdrawals instead of relying on volatile spot markets, effectively mitigating potential systemic stress within the region’s energy framework. Unlike power markets that frequently faced scarcity pricing during evening hours due to fluctuating demand curves, gas markets maintained smoother demand profiles that facilitated stability.
The interaction between gas and power markets revealed a one-way influence during this period: while gas served as a stabilizing force for pricing structures, it did not dictate marginal costs during peak electricity demand periods. The surges in power prices were attributed more to constraints in flexibility and import limitations rather than any significant shifts in gas supply or affordability—a notable departure from previous winters characterized by crisis-driven dynamics.
From an operational standpoint for market participants in January, trends favored industrial buyers with long-term contracts or indexed pricing arrangements alongside those managing storage effectively for optimal withdrawal timing. Utilities with diverse supply chains also benefited from these conditions while spot-exposed buyers faced higher premiums without facing existential risks seen in prior winters. On the downside were short-term purchasers lacking storage access during cold spells and gas-to-power generators competing against hydro or limited import scenarios instead of other gas units.
This period marks a structural evolution within South-East Europe’s energy landscape where natural gas is no longer primarily viewed as a major source of volatility but rather as an influencing factor shaping competitiveness across energy systems. Power market repricing now hinges on factors such as flexibility and grid constraints first and foremost while natural gas serves as a secondary consideration—setting the stage for continued stability provided storage capacities remain adequate and supply lines open.
