European gas risk moved back to the centre of the Southeast European power-market story in early June, as TTF prices approached €50/MWh and geopolitical risk around LNG supply routes sharpened. The effect on SEE electricity markets was not uniform, but the direction of risk was clear: gas-linked marginal pricing remains a major upside threat for power prices, especially during evening peaks and low-renewable hours.
During Week 23, TTF gas futures averaged €48.56/MWh, up 4.3% from the previous week. The one-month forward contract was trading near €49.335/MWh, equivalent to around $16.72/MMBtu, at the time of publication. Daily TTF values were relatively stable inside the week, but the broader level remained elevated for early summer and reflected a risk premium linked to Middle East tensions, LNG availability and storage replenishment.
The report highlighted the stalemate in US-Iran talks and renewed regional fighting as key drivers of market concern. The issue is not only direct European gas supply. It is the global LNG system. Around 20% of global LNG trade passes through the Strait of Hormuz, and more than 85% of those volumes are normally destined for Asian markets. Any disruption to Qatari LNG exports would force Asian buyers to compete more aggressively for alternative cargoes, including Atlantic Basin LNG that Europe also needs.
This is why Europe remains exposed even though its direct dependence on Qatari LNG has declined to around 8% of total imports. LNG is globally priced. If Asian buyers lose access to part of their usual Qatari supply, they can bid cargoes away from Europe. In such a scenario, European prices would need to rise to attract sufficient LNG and preserve winter security.
The report cites analysis suggesting that European benchmark gas prices may need to rise 40–50% from current levels to secure adequate LNG if disruptions to Qatari exports persist. That would imply a materially higher gas-price environment, with direct consequences for gas-fired power generation in Italy, Greece, Türkiye, Hungary, Romania and other markets where gas units often influence marginal pricing.
Storage is another weakness. European storage was around 38% full, after exiting February near 35%, below the five-year average. Early-summer storage levels matter because Europe needs to rebuild inventories before winter. If LNG competition intensifies while storage remains relatively low, the market can reprice quickly.
US LNG flexibility appears limited. Export facilities were operating at approximately 94% utilisation, leaving little spare capacity to respond to a sudden increase in European or Asian demand. This means price, rather than additional immediate supply, would be the main balancing mechanism. Higher TTF prices would be needed to divert cargoes.
For SEE, the implications are direct. Gas-fired generation rose sharply in Türkiye during Week 23, with gas output increasing 278.1%. Romania also recorded higher thermal production supported by stronger gas-fired output. Greece’s total thermal generation increased, although its gas output declined modestly while lignite rose. Italy reduced gas-fired generation during the week, but it remains structurally exposed to gas-linked price formation.
Pipeline risk was also visible. Russian gas deliveries through TurkStream were temporarily suspended because of scheduled maintenance from 2 June to 10 June. TurkStream is now the only remaining route for Russian pipeline gas deliveries to Europe after the Russia–Ukraine transit agreement expired on 1 January 2025. It supplies Türkiye, Serbia, Hungary and Slovakia, making any interruption closely watched by regional markets even when planned.
Gas-flow data showed mixed LNG movements. LNG inflows to Greece recovered sharply to 860.32 GWh, up 112.9% week on week. Italy remained the largest LNG recipient among the countries covered, with 2,836.03 GWh, although that was down 31.06% from the previous week. Croatia recorded 645.30 GWh of LNG inflows, up 1.9%. The pattern confirms that LNG terminals remain central to regional supply balancing, but flows are uneven and price-sensitive.
The power-market implication is that gas has re-entered the risk stack before the peak summer load period. If heat-driven demand increases while wind generation weakens and hydro support becomes uneven, gas-fired plants can become more important in setting evening prices. TTF near €50/MWh already makes gas-fired power expensive. A further LNG-driven price shock would raise the ceiling for SEE electricity prices, especially in Italy and Greece.
The Week 23 report therefore points to a market where electricity prices cannot be analysed separately from gas security. SEE power markets are fragmented, but they share exposure to the same gas-price risk. LNG disruption, low storage, limited US spare capacity and TurkStream sensitivity all create a wider risk premium. Even where weekly power prices softened, gas remains a latent upside driver for the next phase of summer trading.
