From gas-set marginality to a more renewable-led merit order
Across much of the past two decades, Southern European electricity markets followed a relatively stable pricing logic in which natural gas generation frequently set the marginal price. That structure kept wholesale electricity prices closely tied to gas market dynamics. Combined-cycle gas turbines reinforced the pattern by combining efficiency with operational flexibility, including the ability to ramp output quickly as demand changed. As coal generation declined and environmental rules tightened, gas plants increasingly took on balancing responsibilities.
In systems such as Spain, Italy and Greece, the result was a clear linkage between gas prices and electricity prices. When gas costs rose, electricity prices generally followed; when gas costs fell, wholesale prices usually declined as well. Market participants are now facing a different operating reality that is putting that long-standing relationship under pressure. The shift is not simply about fuel costs moving differently—it is about how often gas assets are needed to clear the market.
Renewables reduce gas operating hours and erode fuel-cost coupling
The pressure comes from the rapid expansion of renewable energy across Europe, which is changing how many hours gas plants run. Wind and solar are increasingly able to cover a large share of demand during favourable weather conditions. When renewable output rises, gas units are pushed further down the dispatch order, and in extreme cases they may not operate for extended periods. This directly reduces the frequency with which gas plants remain responsible for setting electricity prices.
Recent market data highlights how quickly dispatch patterns can move. At the beginning of 2026, Spain saw a significant increase in renewable electricity production driven by strong wind conditions alongside higher hydro availability. The resulting surge in renewables reduced reliance on gas-fired generation, with gas generation falling by approximately 2.4% compared with the same period in the previous year. While that change may look modest in percentage terms, it signals an important structural change in marginality.
Price signals swing with wind variability rather than steady fuel correlations
As renewables displace gas more often, electricity pricing becomes less dependent on gas prices and more influenced by renewable availability. In practical terms, markets begin to decouple from fuel costs when dispatchable capacity is no longer required to set marginal prices. The decoupling is particularly visible during periods of strong wind generation when renewable output can meet a large portion of demand. Under those conditions, gas plants can be pushed out of the dispatch stack and electricity prices tend to move toward the marginal cost of renewable generation.
Because wind and solar have very low operating costs, price levels during high-renewables periods can decline dramatically. However, volatility increases rather than disappearing: when renewable output falls, gas plants still become necessary to maintain grid balance. Electricity prices may then rise quickly because dispatchable generation must re-enter the system’s balancing role. Instead of gradual price movement tied to fuel costs, markets increasingly experience sharp fluctuations driven by renewable variability.
Implications for project planning: flexibility value rises as utilisation falls
The changing dispatch economics carry direct consequences for developers and operators of combined-cycle gas assets that historically could run for thousands of hours each year. Lower utilisation rates mean revenue from energy-only sales becomes less predictable even if plants remain operationally important. Gas units may operate fewer hours but must still stay available to provide flexibility when renewable generation drops. That operational shift changes how investors evaluate risk across both construction readiness and long-term performance assumptions.
To address this new revenue structure, market compensation mechanisms become more central to project viability. Capacity markets and ancillary service payments are increasingly used to ensure that dispatchable generation remains financially viable despite reduced energy margins. For power traders and portfolio managers, forecast methods also need adjustment because traditional models based primarily on fuel price correlations are becoming less reliable. Forecasting now requires integrating renewable production forecasts, weather models and grid constraints into trading analysis.
What this means for grid modernization and long-term power contracting
Forward electricity markets are also adapting as long-term expectations increasingly depend on renewable capacity growth rather than fuel market projections alone. For utilities and system operators planning grid modernization, this implies that transmission planning and operational studies must account for more frequent periods where renewables dominate dispatch outcomes. It also reinforces the importance of engineering readiness for balancing resources—whether through dispatchable plants or other flexibility solutions—so reliability is maintained when wind or solar output declines.
Overall, the structural transformation underway in European electricity markets points to a broader shift in how infrastructure value is allocated: energy-only marginality linked to gas is weakening while flexibility needs intensify around renewable variability. For developers, contractors and investors evaluating future build strategies—alongside technical studies and EPC preparation—revenue assumptions increasingly hinge on availability-based services rather than steady running hours alone.