Gas-fired generation in South-East Europe no longer earns its keep by running often. It earns it by being there when nothing else works. In market terms, these plants function as regional system insurance: they suppress tail risk, stabilise frequency, and prevent cascading failures during rare but severe stress events. Yet remuneration frameworks still pay them as if they were ordinary energy suppliers. The result is structural underpayment, persistent volatility, and a market that prices crises instead of preventing them. Seasonal adequacy assessments by ENTSO-E acknowledge the need for dispatchable depth; market outcomes reveal the cost of not paying for it.
The mismatch begins with utilisation. Across South-East Europe, effective gas-fired capacity typically runs at 10–25% load factors annually. In Serbia, Bulgaria, and parts of Romania, gas plants may operate heavily for fewer than 200–400 hours in a year. Yet those hours coincide with the most valuable moments in the system: winter peaks, cold-start mornings, low-wind evenings, and periods of constrained imports. In those hours, gas units do not just add energy; they prevent failure.
The economic value of that prevention is large and largely invisible. During recent winter stress events, peak electricity prices in SEE exceeded €250–300/MWh, with intraday and balancing prices reaching €400–600/MWh when response was scarce. Modelling shows that the presence of even 300–500 MW of additional fast-ramping gas capacity can reduce the probability of such outcomes materially, compressing peak prices by €40–80/MWh and cutting balancing activation volumes by 20–30%. The avoided cost across a single severe week can reach tens of millions of euros region-wide.
Despite this, gas plants are remunerated primarily through energy margins that collapse when the system is stable—the very condition they help create. When gas units are available and online, prices are lower; when they are unavailable, prices spike. This creates a perverse feedback loop: the better gas plants perform their insurance role, the less they earn. Markets reward instability more reliably than stability.
Capital economics underscore the problem. New or modernised gas-fired capacity in the region requires CAPEX of roughly €700–1,100 million per GW, depending on configuration and grid connection. Fixed OPEX—including staffing, maintenance, and capacity-related costs—typically runs €25–40 million per GW per year, before fuel and variable costs. Recovering these costs through a few hundred hours of energy margin is implausible without extreme price spikes. Investors therefore require volatility to justify entry, even though volatility is what the system seeks to avoid.
This underpayment has observable consequences. Operators defer maintenance, mothball units, or limit availability during periods of marginal profitability. In stress conditions, the system discovers that “installed” capacity is not “available” capacity. Each missing megawatt then raises the value of the next one exponentially. Markets respond with violent repricing, but by then it is too late to summon capacity that has been structurally under-incentivised.
Grid and inertia dynamics amplify the insurance value of gas. Synchronous gas units provide frequency support and voltage control that inverter-based resources cannot yet fully replicate at scale. As coal and lignite retire, gas increasingly shoulders this role. During low-inertia periods, balancing prices in SEE have exceeded €600/MWh, reflecting the scarcity of fast, synchronous response. Gas plants reduce both the frequency and severity of these events, but receive little explicit compensation for doing so.
For traders, underpaid gas capacity explains why volatility persists even when fundamentals appear comfortable. The market does not overreact; it prices the probability that insurance will be missing when needed. This is why winter peak products carry persistent premia of €40–70/MWh over baseload, even in years with ample nominal capacity. The premium is not about average scarcity; it is about uncertainty over availability. Traders who understand this treat gas capacity as an option written by the system—one that is often underwritten too cheaply.
For industrial electricity buyers, the underpayment problem translates into hidden risk. Buyers benefit from gas plants when prices are stable, but pay indirectly when those plants are unavailable or exit the market. The cost arrives through peak surcharges, imbalance exposure, or emergency pricing during stress events. In practical terms, 20–30% of annual electricity spend can be driven by a few days when system insurance fails. Average price savings achieved by squeezing suppliers often pale next to these episodic losses.
The regional dimension complicates matters further. Gas plants in one country stabilise neighbouring markets through cross-border flows and frequency coupling. A flexible unit in Romania can dampen volatility in Bulgaria; availability in Hungary can cap prices in northern Serbia. Yet remuneration remains national. The benefits are regional; the payments are local. Rational investors underprovide a regional public good.
Carbon convergence sharpens the dilemma. As coal exits accelerate, gas becomes the default insurance layer. At the same time, policy signals often frame gas as transitional and risky, increasing financing costs. The result is a widening gap between the system’s reliance on gas for stability and the market’s willingness to pay for it. Without correction, this gap ensures continued volatility.
Corrective mechanisms exist—capacity payments, reliability options, ancillary service reform—but their implementation remains fragmented. Where capacity mechanisms do exist, they often undervalue fast ramping and short-duration availability, paying for installed MW rather than usable response in stress hours. Ancillary markets pay for services, but volumes and prices rarely reflect the full insurance value.
The unified conclusion is unavoidable. Gas-fired capacity in South-East Europe is priced as energy but behaves as insurance. Underpaying insurance does not save money; it shifts cost into crises. Traders see this in persistent convexity and peak premia. Buyers feel it in budget volatility that no average-price hedge can eliminate.
Until markets explicitly pay for availability, response speed, and inertia—rather than hoping energy margins will suffice—gas capacity will continue to be underprovided. Volatility will remain structurally embedded, and prices will spike not because fuel is scarce, but because insurance was never fully paid for.