European gas storage levels remained a central risk factor for SEE electricity markets in Week 26, even though spot and futures gas prices eased slightly on weekly average. EU gas storage was reported at 48.3% as of 27 June, well below 57.8% at the same time in 2025 and 76.5% in 2024. That storage gap is not a background statistic. It is a structural risk premium sitting beneath summer and winter power prices.
TTF futures averaged €41.31/MWh during the week, down 1.1% from the previous weekly average. The movement suggested some easing in immediate gas-market tension, helped by reduced geopolitical risk premiums and signs of recovering LNG shipping activity. But a weekly decline in TTF did not prevent SEE power prices from rising sharply, because the power system needed much more thermal generation during the heatwave.
Low storage matters because it limits the market’s confidence in future gas availability. Even when current flows look stable, traders must price the cost of refilling storage before winter. A hotter summer increases gas burn for power generation, especially when cooling demand rises and thermal plants are called more often. That can slow storage injections or force Europe to compete more aggressively for LNG cargoes.
The linkage to electricity is direct. Gas-fired power remains the marginal source in many high-price hours, especially in Italy, Greece, Hungary and parts of the broader European system. When gas storage is below seasonal norms, the marginal fuel price carries more risk. Power markets then reflect not only current gas costs but also the possibility of tighter gas balances later in the season.
Week 26 showed this mechanism clearly. Gas prices did not spike, but gas-fired generation rose 25.5% across the SEE region. Italy increased gas generation by 47.5%, Greece by 12.6%, and other markets also relied more heavily on thermal production. The power market was therefore exposed to gas through dispatch intensity, even without a strong fuel-price rally.
For industrial buyers, the storage gap adds another layer to procurement risk. Electricity contracts for Q3 and Q4 cannot be assessed only through current spot prices. The winter refill trajectory, LNG availability, Asian demand, Middle East shipping conditions and carbon pricing can all influence forward power costs. Buyers with flexible load or renewable-backed PPAs are better placed than those relying entirely on spot-indexed procurement.
For SEE generators, the storage situation supports the value of firm capacity. Gas plants may remain expensive to run, but their scarcity value rises when the system needs them during heatwaves. Renewables with storage, hydro flexibility and demand response can capture part of the same premium without direct gas exposure.
The market is not short of gas today in a crisis sense. It is short of storage comfort, and that is enough to keep power-price risk elevated.
Elevated by Virtu.Energy
