The final week of June highlighted one of the most important dynamics shaping Southeast Europe’s electricity markets this summer: wholesale power prices surged even as European natural gas prices edged lower. During Week 26 (22–28 June 2026), TTF natural gas futures averaged €41.31/MWh, down 1.1% from the previous week. Despite this modest decline, electricity prices climbed sharply across the region, with Hungary, Romania, Italy, Croatia, Serbia and Bulgaria all recording weekly average prices above €100/MWh. The divergence underscored that electricity demand—not fuel prices alone—was the dominant driver of market pricing.
The week’s developments illustrate a new summer market paradox for Southeast Europe. Although gas remains a key component of electricity price formation, rapid growth in electricity consumption outweighed the limited relief provided by lower gas prices. Regional power demand increased 12.7% week on week to 18.41 TWh, while hydropower generation declined and renewable output, despite stronger wind production, remained uneven across national markets. As a result, system operators relied more heavily on gas-fired, coal-fired and lignite-fired generation to satisfy growing cooling demand, pushing wholesale electricity prices significantly higher.
At the same time, the gas market itself remained far from inexpensive. TTF futures traded within a relatively narrow range, reaching €42.16/MWh on 23 June, easing to €40.50/MWh on 25 June, before recovering later in the week. By the close of the reporting period, the one-month forward TTF contract stood at €44.08/MWh, indicating that fuel costs for gas-fired power plants remained elevated despite the weekly decline. Consequently, gas-fired generators continued to operate as high-cost marginal units, particularly during periods of peak electricity demand.
The relationship between gas and electricity prices during Week 26 therefore reflected higher gas dispatch volumes rather than higher gas prices. Even though the benchmark fuel price softened slightly, regional gas-fired electricity generation increased by 25.5%, demonstrating that a greater number of gas plants were required to maintain system balance. Italy provided the clearest example, with gas-fired generation surging 47.5%, illustrating how strong cooling demand can outweigh modest improvements in fuel costs and continue to support elevated wholesale electricity prices.
For electricity traders, the week’s market performance reinforces the need for a more sophisticated approach to price risk. Monitoring whether TTF prices rise or fall on a weekly basis is no longer sufficient. Instead, market participants must assess how frequently gas-fired power plants become the marginal generators, how demand evolves during peak consumption hours and how much flexibility remains available from renewable energy, hydropower and cross-border interconnections. Even relatively stable gas prices can coincide with significantly higher electricity prices when demand accelerates and flexible generation becomes scarce.
The implications are equally significant for industrial electricity consumers. Gas price hedging and electricity price hedging are closely connected but cannot be treated as interchangeable strategies. A decline in gas prices does not automatically translate into lower electricity procurement costs if wholesale power markets remain constrained by high demand, increased thermal dispatch and limited import capacity. In these conditions, the generation mix, hourly demand profile and transmission constraints become the primary determinants of wholesale electricity prices.
Week 26 did not reflect a gas market under stress—it reflected an electricity market experiencing tightening supply conditions while operating on top of a still-elevated natural gas price floor. As Southeast Europe moves deeper into the summer season, demand patterns and system flexibility are likely to remain the key drivers of electricity price formation, even if fuel markets remain relatively stable.
Elevated by Virtu.Energy