During Week 26 (22–28 June 2026), wholesale electricity prices rose across Southeast Europe despite a weekly easing in European natural gas benchmarks. TTF natural gas futures averaged €41.31/MWh, down 1.1% compared with the prior week. Weekly average electricity prices were above €100/MWh in Hungary, Romania, Italy, Croatia, Serbia and Bulgaria. The gap between gas and power movements pointed to demand conditions as a key pricing factor.
Power demand growth and reduced hydro output
Regional power demand increased 12.7% week on week to 18.41 TWh during the same period. Hydropower generation declined, while renewable output remained uneven across national markets even with stronger wind production. With cooling demand rising, system operators leaned more on thermal generation. Gas-fired, coal-fired and lignite-fired units were used more frequently to meet load requirements.
This shift in generation support contributed to higher wholesale electricity prices across the region. The combination of stronger demand and weaker hydro availability increased reliance on dispatchable plants. As a result, market pricing moved upward even though the gas benchmark showed only a modest weekly decline.
TTF trading range and forward contract levels
The gas market remained elevated during Week 26, with TTF futures moving within a relatively narrow band. Prices reached €42.16/MWh on 23 June before easing to €40.50/MWh on 25 June, then recovering later in the week. By the end of the reporting period, the one-month forward TTF contract stood at €44.08/MWh.
The weekly softening did not change the level at which fuel costs supported marginal pricing for gas-fired generation. Gas-fired plants continued to run as high-cost marginal units, particularly during periods of peak electricity demand. The pattern aligned with higher dispatch volumes rather than a sustained drop in the gas benchmark.
Gas dispatch increases alongside higher electricity prices
During Week 26, regional gas-fired electricity generation rose by 25.5%. This increase indicated that more gas capacity was needed to maintain system balance under tightening supply conditions in the power market. Italy saw the largest change, with gas-fired generation surging 47.5%.
The weekly relationship between gas and electricity therefore reflected changes in how often gas plants were called on to set prices. Even with TTF easing slightly on a weekly basis, electricity outcomes varied based on demand timing and available flexibility from renewables and hydropower. Cross-border interconnections also formed part of the flexibility picture referenced by market participants.
Implications for price risk management and procurement
The Week 26 developments highlighted limits of relying solely on weekly direction in TTF for power price risk assessment. Market participants were described as needing to evaluate how frequently gas-fired units become marginal generators during peak hours. They also needed to track how demand evolves through high-consumption periods and how much operational flexibility remains from renewables, hydropower and cross-border flows.
For industrial electricity consumers, the linkage between fuel costs and power procurement was presented as connected but not interchangeable for hedging purposes. A decline in gas prices did not automatically translate into lower electricity procurement costs when wholesale markets were constrained by high demand, increased thermal dispatch and limited import capacity. In those conditions, generation mix, hourly load patterns and transmission constraints were identified as primary determinants of wholesale electricity price levels.
Overall, Week 26 was characterized as an electricity market tightening while operating on top of a still-elevated natural gas price floor. As Southeast Europe moves further into summer, demand patterns and system flexibility were cited as likely to remain central drivers of electricity price formation even if fuel markets stay relatively stable.
Elevated by Virtu.Energy
