The gas markets in South-East Europe exhibited distinct characteristics in January, diverging significantly from the electricity sector. While electricity prices experienced sharp spikes due to scarcity, gas pricing was influenced by supply continuity, storage levels, and security of transport corridors. This resulted in a month marked by elevated yet stable gas prices, with volatility considerably lower than that of power markets. The differentiation between secure transit markets and those reliant on imports was particularly pronounced.
Throughout January, the Dutch TTF front-month gas prices fluctuated within the €28–34/MWh range, with temporary increases primarily driven by weather forecasts rather than any physical supply disruptions. This shift in the pricing mechanism is noteworthy for South-East Europe as it indicates a transition from emergency-driven pricing seen in previous years to a model more influenced by contract structures and transportation constraints. Consequently, local price variations relative to TTF have become more indicative of market conditions than the benchmark price itself.
Serbia’s gas market entered January with a robust position due to long-term contracts with Gazprom and deliveries via the Balkan Stream pipeline. This framework allowed Serbia to meet its winter demand at prices significantly below spot TTF levels, mitigating the impact of gas prices on its electricity market. Consequently, while SEEPEX peak electricity prices surged towards €300/MWh, gas did not emerge as the primary factor influencing these spikes; instead, issues related to flexibility and import constraints were more critical.
Bulgaria’s situation was somewhat more precarious yet still manageable. The country benefited from a diversified supply that included Azerbaijani gas through the IGB interconnector and LNG imports linked to European hubs. This allowed Bulgarian gas prices to closely follow TTF trends without experiencing acute pressure. The orderly withdrawal from storage facilities enabled Bulgaria to export over 400 GWh of electricity to Romania during January while maintaining competitive marginal costs.
In contrast, Romania’s gas profile is shaped by its significant domestic production capacity, which provided adequate coverage for winter demand. Despite this favorable balance, Romanian power prices remained elevated, averaging €150.51/MWh for baseload and €176.60/MWh for peak demand. This highlights a crucial observation: high power prices were not directly tied to gas costs but were instead influenced by factors such as system flexibility and cross-border congestion.
Croatia’s gas market dynamics positioned it between Bulgaria and the Adriatic LNG complex. Access to LNG imports via the Krk terminal offered Croatia a strategic advantage; however, its pricing remained susceptible to hub volatility. As a result, Croatian buyers faced higher delivered costs compared to Serbia due to regasification and transport spreads. This exposure was reflected in power pricing as well, with CROPEX clearing at peak averages of €165.66/MWh compared to Serbia’s €136.27/MWh when gas-fired units were marginally dispatched.
Montenegro’s energy landscape remains largely outside the gas system, which became evident in January as the country’s power generation relied heavily on hydro resources and imports. This led to significant price fluctuations on MEPX, where extreme lows of €18.79/MWh occurred during energy-abundant days while peaks exceeded €180/MWh during constrained periods. The influence of gas trends was minimal, impacting only through import pricing from neighboring systems.
The overall storage behavior across South-East Europe was crucial during January, as adequate inventories allowed operators to manage cold weather demands through withdrawals rather than relying on spot market purchases. This helped mitigate volatility and prevented gas from triggering systemic stress within the markets. Unlike electricity demand patterns characterized by sharp evening ramp-ups leading to scarcity pricing, gas demand remained more stable and predictable.
The interplay between gas and power markets in January illustrated a significant shift; while gas served as a stabilizing factor for pricing, it did not dictate marginal costs during peak power hours. The surges in electricity prices were primarily attributed to constraints in flexibility and import limitations rather than any sudden unavailability or unaffordability of gas supplies. This decoupling marks a structural evolution from previous winters marked by crisis-driven volatility.
From the perspective of market participants, January’s trends favored industrial consumers with indexed contracts and utilities with diversified supply chains capable of optimizing storage withdrawals. Spot market participants faced higher costs compared to their contract-bound counterparts but avoided the existential risks seen in earlier winters. The most affected groups included short-term buyers lacking storage access during cold snaps and gas-to-power generators competing against hydro or constrained imports instead of other gas units.
In summary, January has confirmed that South-East Europe is transitioning into a phase where natural gas no longer serves as the primary driver of market volatility but rather acts as a background factor influencing competitiveness among energy systems. Power markets are now predominantly influenced by flexibility, hydrological conditions, and grid constraints, with gas serving as a secondary consideration. As long as storage levels remain sufficient and supply routes are secure, natural gas is expected to stabilize rather than disrupt energy markets in South-East Europe.
