In Southeast Europe, gas-fired power generation is increasingly recognized for its critical role in maintaining grid stability, particularly during periods of high demand and low renewable output. These plants serve as a form of regional system insurance, providing essential support when other energy sources are insufficient. However, the current remuneration frameworks fail to adequately compensate these facilities for their reliability and availability, leading to significant structural underpayment.
Gas plants across the region typically operate at low capacity factors, ranging from 10–25% annually. In countries such as Serbia, Bulgaria, and parts of Romania, these facilities may only be active for 200–400 hours per year. Despite this limited operational time, their contribution is crucial during peak demand periods, such as cold winter mornings or evenings with low wind generation. During these critical hours, gas units not only provide energy but also prevent potential system failures.
The economic implications of this underpayment are substantial yet often overlooked. Recent winter stress events have seen peak electricity prices in Southeast Europe soar to between €250–300/MWh, with intraday prices reaching €400–600/MWh. Analysis indicates that an additional 300–500 MW of fast-ramping gas capacity could significantly mitigate these price spikes, potentially lowering peak costs by €40–80/MWh and reducing balancing activation needs by 20–30%. The cumulative savings during severe demand weeks could amount to tens of millions of euros across the region.
This situation is exacerbated by the existing pricing mechanisms that primarily reward energy production rather than availability. When gas plants are online, they help stabilize prices; conversely, when they are offline, prices tend to spike. This creates a paradox where the more effectively gas plants fulfill their role as insurance providers, the less financial return they receive. The market inadvertently incentivizes instability over stability.
The capital costs associated with establishing or upgrading gas-fired capacity are considerable, estimated at around €700–1,100 million per GW. Fixed operating expenses can reach €25–40 million per GW annually, excluding fuel costs. Such financial demands make it impractical for operators to recover costs through limited operational hours without experiencing extreme price volatility. Consequently, investors seek higher volatility to justify their investments, even though this contradicts the system’s need for stability.
The consequences of this underpayment are evident in operational practices. Many operators may defer maintenance or limit the availability of their units during times of marginal profitability. As a result, when demand surges, the system often finds that its “installed” capacity does not equate to “available” capacity. This discrepancy can lead to dramatic price adjustments in response to shortages that have been systematically under-incentivized.
The dynamics of grid management further highlight the importance of gas-fired units. These synchronous generators provide essential frequency support and voltage control that renewable resources currently cannot replicate at scale. As coal and lignite plants retire from the market, gas-fired units will increasingly take on this responsibility. During periods of low inertia, balancing prices have exceeded €600/MWh, underscoring the pressing need for reliable gas capacity.
For traders in the market, understanding the implications of underpaid gas capacity is critical to navigating ongoing volatility. The market does not merely react to immediate supply and demand; it also factors in the likelihood that necessary insurance may be absent when required. This uncertainty results in winter peak products consistently trading at premiums of €40–70/MWh over baseload prices, reflecting concerns about availability rather than average scarcity.
This issue extends beyond traders to industrial electricity consumers who indirectly bear the costs associated with underpaid gas plants. While stable prices benefit buyers when gas units are operational, they face increased costs during outages or market exits—often manifesting as peak surcharges or imbalance penalties during stress events. In practical terms, up to 30% of annual electricity expenditures can stem from just a few days when system insurance fails.
The regional interdependencies complicate matters further as gas plants in one country can stabilize neighboring markets through cross-border energy flows and frequency coupling. However, remuneration remains confined within national borders despite the regional benefits provided by these units. This misalignment discourages rational investment in what should be a regional public good.
The transition away from coal raises additional challenges for gas as it becomes an essential component of energy security amidst evolving policy landscapes that often frame it as a transitional fuel. This perception increases financing costs and widens the gap between reliance on gas for stability and market willingness to pay for it—ensuring continued volatility if left unaddressed.
Potential solutions such as capacity payments and ancillary service reforms exist but remain inconsistently applied across the region. Where these mechanisms do exist, they often undervalue rapid response capabilities and short-duration availability by compensating based on installed capacity rather than usable response during critical periods.
The overarching conclusion is clear: while gas-fired capacity is fundamentally priced as an energy source, its operational behavior aligns more closely with that of an insurance provider. Undercompensating for this role does not yield savings; instead, it shifts costs into crisis situations that impact all market participants. Until compensation structures explicitly recognize availability and responsive capabilities—rather than relying solely on energy margins—the issues of underprovisioning will persist alongside structural volatility in pricing.
