European gas storage levels were a key underlying factor for Southeast European electricity markets during Week 26, even as both spot and futures natural gas prices eased. EU gas storage was 48.3% on 27 June, compared with 57.8% at the same point in 2025 and 76.5% in 2024. The deficit continued to support a structural risk premium affecting both summer and winter electricity pricing across the region.
Over the week, TTF natural gas futures averaged €41.31/MWh, down 1.1% versus the prior weekly average. The decline reflected lower geopolitical risk premiums and improving LNG shipping activity. Despite the softer gas market, electricity prices in Southeast Europe increased sharply as extreme temperatures raised demand for thermal power generation.
Storage gap and winter refill 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 price the cost of refilling storage facilities over the coming months. Heatwaves added pressure by increasing gas consumption for electricity generation, slowing storage injections.
The same conditions also raised potential competition for global LNG cargoes as consumption increased. With storage below seasonal norms, the forward outlook remained linked to tighter balances later in the year. This kept the risk premium embedded in electricity pricing across interconnected markets.
Gas-to-power linkage during peak demand
The link between gas and electricity markets remained strong across Southeast Europe, particularly during high-demand periods. Gas-fired plants frequently set the marginal electricity price, with notable exposure in Italy, Greece, and Hungary, alongside other interconnected systems. When storage levels are well below seasonal averages, wholesale electricity prices reflect both current fuel costs and heightened balance risk.
Week 26 showed this pattern as gas-fired output rose even though gas prices stayed relatively steady. 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, with other countries also increasing reliance on thermal generation.
Implications for procurement and generation planning
The storage deficit added uncertainty for industrial electricity consumers managing procurement strategies. Decisions for the third and fourth quarters could not rely solely on prevailing spot prices. Forward pricing drivers included 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 were positioned differently from those relying entirely on spot-indexed contracts. For generators, low storage levels reinforced the value of reliable and flexible capacity during periods of extreme demand when dispatchable resources are needed.
While gas-fired plants remained relatively expensive to operate, their strategic role increased under high-demand conditions. Renewable projects paired with battery storage, flexible hydropower, and demand response resources were also described as positioned to capture similar market value while reducing direct exposure to natural gas price volatility.
No immediate supply crisis but elevated summer risks
Europe was not facing an immediate gas supply crisis, but the region continued operating with a significant storage deficit. That level of “storage comfort” remained sufficient to sustain elevated electricity price risks as summer progressed. Market attention was shifting gradually toward winter supply security while storage levels stayed below prior-year benchmarks.
Elevated by Virtu.Energy