EU gas storage remained a key risk factor for Southeast European electricity markets in Week 26, even as natural gas prices eased. On 27 June, EU storage was at 48.3%, compared with 57.8% at the same point in 2025 and 76.5% in 2024. The gap contributed to a structural risk premium affecting both summer and winter electricity pricing across the region.
During the week, TTF natural gas futures averaged €41.31/MWh, down 1.1% versus the prior weekly average. The decline coincided with lower geopolitical risk premiums and improving LNG shipping activity. Despite that easing, electricity prices across Southeast Europe rose sharply as extreme temperatures increased demand for thermal power generation.
Storage levels weigh on winter inventory expectations
Low storage levels reduce confidence in Europe’s ability to replenish inventories ahead of winter. Even with stable gas supplies, market participants continued to factor in the cost of refilling storage facilities over the coming months. Heatwaves added pressure by increasing gas consumption for electricity generation, slowing storage injections and affecting the timing of LNG procurement.
The market linkage between gas and power remains strong across Southeast Europe during periods of high demand. Gas-fired plants frequently set the marginal electricity price in interconnected systems, including those in Italy, Greece and Hungary. When storage is far below seasonal averages, wholesale electricity prices incorporate not only current fuel costs but also the risk of tighter gas balances later in the year.
Week 26 shows higher dispatch from gas despite lower TTF
Week 26 illustrated how dispatch volumes can drive exposure to natural gas even when fuel prices do not rise. Gas-fired electricity generation across Southeast Europe increased by 25.5%. Italy raised gas-fired generation by 47.5%, while Greece recorded a 12.6% increase, alongside higher reliance on thermal output in other countries.
This shift meant electricity markets became more exposed to natural gas through greater dispatch rather than through higher fuel prices alone. Extreme temperatures supported higher thermal generation needs across the region during the week.
Implications for industrial supply and power generation
For industrial electricity consumers, the storage deficit adds uncertainty to procurement planning for the third and fourth quarters. Purchasing decisions cannot rely only on prevailing spot prices, given multiple drivers behind forward electricity pricing. These include the pace of storage refilling, global LNG availability, Asian gas demand, shipping conditions in the Middle East and carbon allowance prices.
Companies with flexible electricity consumption or renewable-backed power purchase agreements are positioned differently from those relying entirely on spot-indexed contracts. For generators, low storage levels reinforce the importance of reliable and flexible capacity during periods of extreme demand when dispatchable resources are required.
While gas-fired plants remain relatively expensive to operate, their strategic role increases when demand peaks require controllable generation. Renewable projects paired with battery storage, flexible hydropower and demand response resources can capture similar market value while reducing direct exposure to natural gas price volatility.
Europe is not facing an immediate gas supply crisis, but it continues to run with a significant storage deficit. That lack of storage comfort is sufficient to keep elevated electricity price risks in place as summer progresses and attention shifts toward winter supply security.
Elevated by Virtu.Energy
