January gas markets in South-East Europe behaved very differently from power, even though the two were tightly linked at the margin. While electricity prices were dominated by short, violent scarcity intervals, gas pricing across the region was shaped by continuity of supply, storage positioning, and corridor security rather than outright shortage. The result was a month of elevated but controlled gas prices, with volatility far lower than in power and with clear differentiation between transit-secure markets and structurally exposed importers.
At the European benchmark level, the Dutch TTF front-month traded through January largely in the €28–34/MWh band, with short-lived spikes driven by weather forecasts rather than physical disruption. This matters for SEE because, unlike in 2022–2023, gas pricing in the region is no longer set by emergency scarcity but by contract structure and transport constraints, meaning that local premiums or discounts versus TTF tell you far more than the headline hub price.
Serbia entered January with a structurally insulated gas position. The supply framework anchored by long-term contracts with Gazprom, delivered via the Balkan Stream pipeline, meant that marginal winter demand was largely covered at oil-indexed or hybrid formula prices well below spot TTF peaks. This insulation explains why gas did not become the dominant marginal driver of Serbian power prices, even when SEEPEX peak hours exploded toward €300/MWh. In other words, Serbia’s January power scarcity was primarily a flexibility and import constraint problem, not a gas price shock. Industrial gas buyers benefited from relative price stability, while gas-fired generation did not face the kind of fuel-cost repricing that would normally transmit directly into power markets.
Bulgaria sat in a more exposed but still controlled position. With diversified supply including Azerbaijani volumes via the IGB interconnector and LNG-linked imports priced off European hubs, Bulgarian gas pricing tracked TTF more closely than Serbia but without acute stress. Storage withdrawals were orderly, and the system retained optionality to respond to cold spells without panic buying. This relative stability at the gas level partially explains Bulgaria’s ability to export power into Romania during January, feeding over 400 GWh of day-ahead electricity northbound while keeping its own marginal costs competitive.
Romania presents a different gas profile altogether. As a significant domestic producer, Romania entered winter with storage and production covering a large share of demand, muting direct exposure to international gas volatility. However, the Romanian power market still priced at a premium, with OPCOM baseload averaging €150.51/MWh and peak €176.60/MWh. This divergence underscores a key January lesson: high power prices in SEE were not gas-driven in a linear way. Romania’s gas balance was relatively comfortable, yet power prices remained elevated because the marginal constraint was not fuel cost but system flexibility, hydro availability, and cross-border congestion. Gas was available, but it was not always the cheapest or fastest marginal solution during peak ramps.
Croatia’s gas market dynamics sat between Bulgaria and the Adriatic LNG complex. Access to LNG imports via the Krk terminal gave Croatia a clear security advantage, but pricing was inherently more exposed to hub volatility. January gas prices for Croatian buyers therefore reflected TTF plus regasification and transport spreads, keeping delivered costs above Serbia’s contract-linked levels. This exposure translated indirectly into power pricing: when gas-fired units were on the margin during tight hours, Croatia’s CROPEX cleared higher than Serbia, with peak averages of €165.66/MWh versus €136.27/MWh. The gas market did not spike dramatically, but it consistently sat high enough to reinforce power price premia during stress periods.
Montenegro remains structurally outside the gas system, and January reinforced the implications of that absence. Without gas-fired generation, Montenegro’s power market was shaped almost entirely by hydro availability and imports. This is why MEPX could print extreme lows such as €18.79/MWh on energy-long days and still spike above €180/MWh on constrained peak days. Gas trends mattered only indirectly, through the prices Montenegro faced when importing from gas-influenced neighboring systems.
Across the region, storage behavior was critical. SEE gas systems entered January with adequate inventories, allowing operators to respond to cold spells through withdrawals rather than spot market exposure. This dampened volatility and prevented gas from becoming the trigger for systemic stress. Unlike power, where evening ramps repeatedly forced markets into scarcity pricing, gas demand curves were smoother and more predictable, allowing infrastructure and contracts to absorb shocks.
The interaction between gas and power in January therefore ran in one direction only. Gas provided a price ceiling and stability anchor, but it did not set the marginal price in most of the extreme power hours. When SEE power prices exploded, they did so because flexibility was scarce and imports were constrained, not because gas suddenly became unavailable or unaffordable. This decoupling is a structural change from earlier crisis winters and reflects both improved gas security and the growing importance of non-fuel constraints in SEE electricity systems.
From a market-participant perspective, January gas trends favored industrial buyers with indexed or long-term contracts, storage holders able to optimize withdrawal timing, and utilities with diversified supply portfolios. Spot-exposed buyers paid a premium versus contract-linked peers, but they did not face the existential risk seen in previous winters. The losers were fewer and more specific: short-term buyers without storage access during cold spells and gas-to-power generators competing in peak hours against hydro or import-scarcity pricing rather than against other gas units.
In structural terms, January confirms that South-East Europe has entered a new phase in which gas is no longer the dominant volatility transmitter, but rather a background variable that shapes competitiveness between systems. Power markets now reprice on flexibility, hydrology, and grid constraints first, with gas acting as a secondary input. As long as storage remains adequate and supply corridors remain open, gas will continue to stabilize rather than destabilize SEE energy markets—even while power prices remain capable of extreme, short-lived dislocations.
By virtu.energy
