European gas storage levels remained one of the key underlying risks for Southeast European electricity markets during Week 26, despite a modest decline in both spot and futures natural gas prices. EU gas storage stood at 48.3% on 27 June, significantly below the 57.8% recorded at the same point in 2025 and 76.5% in 2024. This sizeable storage deficit continues to underpin a structural risk premium that influences both summer and winter electricity prices across the region.
During the week, TTF natural gas futures averaged €41.31/MWh, down 1.1% compared to the previous weekly average. The slight easing reflected lower geopolitical risk premiums and improving LNG shipping activity. However, the decline in gas prices did little to prevent electricity prices across Southeast Europe from rising sharply, as extreme temperatures significantly increased demand for thermal power generation.
Low gas storage levels remain a major concern because they reduce confidence in Europe’s ability to replenish inventories ahead of winter. Even with stable gas supplies, market participants continue to price in the cost of refilling storage facilities during the coming months. Heatwaves further complicate this process by increasing gas consumption for electricity generation, slowing storage injections and potentially intensifying competition for global LNG cargoes.
The relationship between gas and electricity markets remains particularly strong across Southeast Europe. Gas-fired power plants frequently set the marginal electricity price during high-demand periods, especially in Italy, Greece, Hungary and other interconnected markets. When storage levels remain well below seasonal averages, wholesale electricity prices reflect not only current fuel costs but also the increased risk of tighter gas balances later in the year.
Week 26 clearly illustrated this dynamic. Although gas prices remained relatively stable, gas-fired electricity generation across Southeast Europe increased by 25.5%. Italy expanded gas-fired generation by 47.5%, while Greece recorded a 12.6% increase, with several other countries also relying more heavily on thermal power plants. As a result, electricity markets became increasingly exposed to natural gas through higher dispatch volumes rather than rising fuel prices alone.
For industrial electricity consumers, the current storage deficit adds another layer of uncertainty to procurement strategies. Power purchasing decisions for the third and fourth quarters cannot be based solely on prevailing spot prices. The pace of storage refilling, global LNG availability, Asian gas demand, shipping conditions in the Middle East and carbon allowance prices all remain important drivers of forward electricity prices. Companies with flexible electricity consumption or renewable-backed power purchase agreements are likely to be better positioned than those relying entirely on spot-indexed contracts.
For electricity generators, low gas storage levels reinforce the value of reliable and flexible generation capacity. While gas-fired plants remain relatively expensive to operate, their strategic importance increases during periods of extreme demand when dispatchable capacity becomes essential. At the same time, renewable energy projects paired with battery storage, flexible hydropower and demand response resources are well placed to capture similar market value while reducing direct exposure to natural gas price volatility.
Although Europe is not currently facing an immediate gas supply crisis, the region continues to operate with a significant storage deficit. That lack of storage comfort remains enough to sustain elevated electricity price risks as the summer progresses and attention gradually shifts toward winter supply security.
Elevated by Virtu.Energy