Gas-fired generation in South-East Europe is used to manage rare but severe system stress, including frequency stabilisation and prevention of cascading failures. Seasonal adequacy assessments by ENTSO-E have pointed to the need for dispatchable depth. Market outcomes, however, show how the cost of missing that capability can surface during tight periods.
Low utilisation versus high-value operating hours
Across South-East Europe, effective gas-fired capacity typically operates at 10–25% load factors annually. In Serbia, Bulgaria and parts of Romania, gas plants may run for fewer than 200–400 hours per year. Those limited operating periods align with winter peaks, cold-start mornings, low-wind evenings and times when imports are constrained.
During these hours, gas units are not only producing electricity but also preventing system failure. The value is concentrated in moments when other resources are insufficient to cover demand and operational constraints. This mismatch between utilisation and system importance is central to how market outcomes develop.
Price spikes during winter stress and the role of fast ramping
Recent winter stress events saw peak electricity prices in SEE exceed €250–300/MWh. Intraday and balancing prices reached €400–600/MWh when response was scarce. Modelling indicates that adding 300–500 MW of fast-ramping gas capacity can reduce the probability of such outcomes.
The same modelling estimates that peak prices could be compressed by €40–80/MWh, alongside a 20–30% reduction in balancing activation volumes. The avoided cost across a single severe week can reach tens of millions of euros across the region. These figures link dispatchable depth to measurable market impacts during stress.
Energy-only remuneration versus insurance-like system function
Gas plants are remunerated primarily through energy margins that fall when the system is stable. When gas units are available and online, prices tend to be lower; when they are unavailable, prices rise. This creates a feedback loop where stronger performance in system insurance coincides with weaker earnings.
The investment logic therefore becomes tied to volatility rather than to steady availability. Capital economics highlight why: new or modernised gas-fired capacity requires CAPEX of roughly €700–1,100 million per GW, depending on configuration and grid connection. Fixed OPEX typically runs €25–40 million per GW per year, before fuel and variable costs.
Availability constraints and maintenance decisions under marginal profitability
The economics of recovering fixed costs through only a few hundred hours of energy margin are described as implausible without extreme price spikes. As a result, operators may defer maintenance, mothball units or limit availability during periods of marginal profitability. In stress conditions, the gap between installed capacity and available capacity becomes visible.
The effect is described as compounding: each missing megawatt increases the value of additional capacity that could have been online. Markets respond with sharp repricing, but structural under-incentivisation can leave insufficient time to bring capacity forward when it is needed most.
Synchronous support, inertia constraints and balancing costs
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 takes on this role in the system. During low-inertia periods, balancing prices in SEE have exceeded €600/MWh, reflecting scarcity of fast synchronous response.
The same framework notes that gas plants reduce both the frequency and severity of low-inertia events while receiving limited explicit compensation for those services. This affects how costs associated with stability provision are reflected in remuneration structures.
Cross-border stabilisation with national payments
A regional dimension applies through cross-border flows and frequency coupling between markets. A flexible unit in Romania can dampen volatility in Bulgaria, while availability in Hungary can cap prices in northern Serbia. Despite these cross-border effects, remuneration remains national.
The benefits are therefore regional while payments are local, which affects how investors evaluate the provision of capacity that supports neighbouring systems. The same dynamic is reflected in how market participants respond to incentives for availability rather than energy output.
Capacity mechanisms, ancillary services and short-duration undervaluation
Corrective mechanisms exist, including capacity payments, reliability options and ancillary service reform, but implementation is described as fragmented across the region. Where capacity mechanisms operate, they often undervalue fast ramping and short-duration availability by paying for installed MW rather than usable response during stress hours.
Ancillary markets pay for services, but volumes and prices rarely reflect the full insurance value attributed to dispatchable depth during rare events. This contributes to continued underpayment relative to the operational role gas plays during system stress.
Financing costs as coal exits accelerate
The transition away from coal is described as accelerating, with gas becoming the default insurance layer for stability needs. At the same time, policy signals often frame gas as transitional and risky, which increases financing costs for new investment. This widens the gap between system reliance on gas for stability and market willingness to pay for it.
The result is continued volatility under frameworks that do not explicitly remunerate availability-related attributes such as response speed and inertia support. Under this setup, prices spike not only due to scarcity conditions but because insurance is not fully paid for through existing remuneration channels.