Southeast Europe’s electricity market significantly reduced its reliance on gas-fired generation in Week 34 compared with Week 30, even as European gas prices continued to rise. The combination highlights an increasingly important feature of regional power markets: lower gas consumption does not necessarily translate into lower gas-price influence on wholesale electricity prices.
Gas-fired generation across the monitored Southeast European markets fell from 3,901.11 GWh in Week 30 to 2,718.16 GWh in Week 34, representing a 30.32% decline. Total thermal generation also decreased, falling 13.07% from 7,294.50 GWh to 6,341.11 GWh. Coal and lignite generation moved in the opposite direction, increasing by 6.76% over the same period.
The decline in gas-fired generation came despite a significant increase in European gas prices. TTF futures averaged €63.99/MWh between 17 and 21 August, 4.4% above the Week 30 level. Prices climbed from €61.76/MWh on Monday to €65.87/MWh on Friday, with the weekly closing level reaching the highest point in the report’s series since January 2023.
The divergence is important because wholesale electricity markets are generally shaped by the marginal generation unit needed to balance supply and demand, rather than by the average cost of electricity production. As a result, a market can substantially reduce its overall gas consumption while remaining highly exposed to gas prices whenever gas-fired plants are required to meet demand during periods of tighter supply.
This dynamic becomes particularly relevant during evening hours, when solar generation falls rapidly after sunset while electricity demand can remain elevated during the summer. If available hydro, wind, imports and lower-cost thermal generation are insufficient to cover the residual load, gas-fired capacity may still be required to balance the system, even if its overall weekly generation remains relatively low.
Week 34 therefore illustrates how gas can retain a significant role in electricity price formation without dominating the generation mix. The reduction in gas-fired output was partly driven by elevated fuel costs, but those same costs increased the marginal value of the gas capacity that remained available during periods of system tightness.
Conditions in the European gas market added another layer of risk. The report pointed to disruptions affecting LNG shipping through the Strait of Hormuz, tighter global LNG availability and growing concerns over European winter supply. European gas storage stood at only 63.24% full on 23 August, leaving the market particularly sensitive to further supply disruptions or stronger-than-expected demand.
For Southeast European power markets, the implication is clear: lower gas burn does not eliminate gas-price exposure. As renewable generation becomes increasingly variable, flexible gas-fired plants can remain essential during periods of scarcity. Their reduced operating hours may even increase their importance for price formation when they are called upon to cover the system’s most expensive and constrained hours.
The Week 34 data therefore point to a broader shift in regional electricity-market dynamics. Gas is becoming less dominant in terms of generation volume, but its role as a marginal and flexible source of supply means that movements in European gas prices can continue to influence Southeast European power prices well beyond the periods when gas-fired generation is operating at high levels.
