South-East Europe’s power markets face a widening gap between system value and where market remuneration is captured. Assets that stabilise the grid, suppress volatility, and prevent cascading failures can deliver outsized regional benefits. However, remuneration mechanisms remain largely national, energy-centric, and backward-looking. Seasonal system assessments by ENTSO-E show adequacy envelopes without clarifying who pays to keep the system within them.
From energy output to avoided failure
In legacy SEE markets, value was linked to producing energy at low marginal cost. Coal, lignite, and hydro plants monetised high utilisation while grids functioned as passive enablers. The basis for value has shifted toward preventing failure during rare but extreme stress events. Assets that keep frequency within bounds, absorb shocks, or unblock constrained corridors provide benefits that can propagate across borders.
Despite this shift, market payments still focus primarily on megawatt-hours delivered rather than crises avoided. The mismatch affects how investors evaluate projects that reduce the likelihood or severity of extreme conditions. It also shapes expectations about whether revenues align with the system services required during stress periods. As a result, the link between performance during rare events and captured income remains weak.
Winter stress costs and price spikes
During winter stress events, regional price spikes routinely exceed €300–500/MWh. In isolated zones, prices can surpass €600/MWh. A single severe cold week can impose system-wide costs in the hundreds of millions of euros through emergency imports, curtailments, and balancing activation. Assets that reduce the probability or severity of such events can therefore deliver expected value beyond observable market revenues in normal conditions.
The scale of avoided crises is reflected in how frequently extreme outcomes translate into large balancing and operational expenditures. Even marginal reductions in stress exposure can change the expected cost profile for the system. This creates a gap between the economic value of stability and the income streams available to assets providing it. The effect is visible across multiple parts of market design and settlement.
Transmission investment and congestion rents
Transmission infrastructure illustrates how benefits can be dispersed while compensation remains limited. A new 400 kV line with a cost range of €300–500 million may reduce congestion frequency by a few percentage points. From a national regulator’s perspective, the direct benefit can appear modest and often insufficient to justify CAPEX. From a regional trading perspective, the same line can compress peak spreads by €20–40/MWh.
The trading impact can also include lower winter risk premiums and reduced congestion rents of €30–70 million per year on affected corridors. Beneficiaries are spread across markets and consumers rather than concentrated with the investor funding the asset. This separation between where value is created and where revenue is captured is central to the mismatch described for SEE power markets. It also affects investment incentives for grid reinforcement projects.
Flexibility remuneration limits
Flexibility assets face similar distortions in how they are paid for system support. Grid-scale batteries and pumped hydro upgrades can prevent extreme balancing prices and emergency interventions. Yet their remuneration is typically capped by domestic market rules. A 100 MW / 400 MWh battery might generate 50–70% of annual EBITDA during fewer than 200 hours, while remaining idle most of the year.
Market revenues for such assets can fluctuate widely from year to year even when they provide consistent insurance value. This revenue volatility can discourage investment precisely where additional capability is needed for rare stress periods. The mismatch therefore extends beyond generation economics into ancillary roles linked to balancing outcomes. It also influences how quickly flexibility capacity can be built relative to system requirements.
Inertia provision and balancing incentives
Synchronous generation and inertia provision further deepen the remuneration gap described for SEE systems. Remaining thermal units still supply a disproportionate share of inertia and voltage support in the region. Their presence reduces balancing activation volumes and suppresses intraday volatility. By reducing volatility, these units also erode their own scarcity rents because prices tend to be lower when stability is higher.
This creates a perverse incentive in which assets that stabilise the system earn less than they would under more fragile conditions. The effect links operational performance during normal periods to lower scarcity outcomes that would otherwise raise revenues. It also ties revenue formation to system conditions that are influenced by the very assets being remunerated. In this way, stability provision can reduce the market signals used to fund it.
Balancing costs borne by consumers
The gap appears in balancing cost trends across several SEE systems. Annual balancing costs have risen into the €200–400 million range, with winter quarters accounting for more than 50% of total expenditure. Much of this cost is borne by consumers through tariffs rather than being matched by direct compensation for assets that reduce balancing needs. The described outcome is that the system pays for instability while underpaying for stability.
This pattern connects settlement outcomes to who bears costs during periods of stress. It also reflects how remuneration rules interact with operational needs during winter conditions when balancing requirements increase most sharply. The mismatch therefore shows up both in aggregate expenditure levels and in how those costs are allocated across market participants.
Cross-border benefits without compensation transfer
Cross-border effects compound the issue as SEE systems become more interconnected. When one system invests in stabilising assets such as grid reinforcement, flexibility, or disciplined operation, it reduces volatility for neighbours. Traders and consumers in adjacent markets benefit through lower prices and reduced risk. However, no mechanism transfers these benefits back to the investor funding stabilisation measures.
Over time, rational actors may underinvest in regional public goods because returns are not aligned with broader system impacts. This underinvestment increases the probability of abrupt failures that markets then price violently. The described dynamic links investment incentives to cross-border externalities affecting reliability outcomes across multiple systems.
Forward curves and longer-dated uncertainty
The trading consequences are reflected in forward curves embedding persistent winter risk premiums even when near-term adequacy appears comfortable. Peak-to-baseload spreads of €40–60/MWh in winter quarters reflect not only expected scarcity but also uncertainty about whether stabilising assets will be available when needed. Longer-dated products show widening bid-ask spreads beyond Y+2, signalling disagreement over how quickly remuneration gaps will be addressed.
This pricing pattern indicates that market participants factor in uncertainty about future stability provision into longer-horizon contracts and liquidity conditions. It also suggests that perceived gaps between system needs and revenue capture persist beyond immediate delivery periods. The result is a continued risk premium structure tied to expectations about stabilisation investment availability.
Policy design remains nationally scoped
The policy response described remains behind market reality in several areas affecting remuneration alignment. Capacity mechanisms, where they exist, often remain nationally scoped and energy-focused rather than reflecting stability contributions across borders. Ancillary service markets undervalue fast response and inertia substitutes compared with their role during stress events. Congestion income allocation does not reflect regional benefit distribution tied to stabilisation investments.
As interconnection increases across SEE markets, these misalignments are described as becoming more costly relative to system-wide impacts. The policy framework therefore does not fully match how value from stability provision propagates across neighbouring systems through price effects and reduced risk exposure.
Investor returns and trading risk under volatility
The mismatch elevates required returns for investors evaluating new projects using merchant revenue alone rather than system-value considerations. Projects that could be justified on a system-value basis may struggle to clear hurdle rates when assessed solely on expected market earnings from average output conditions. The result can be delayed or downsized investment that reinforces volatility levels associated with winter stress pricing dynamics.
For traders, volatility translates into opportunity and risk as stabilising investment remains insufficient relative to stress needs described for SEE systems. Those positioned to monetise stress events benefit while those exposed to extreme prices suffer from adverse outcomes during high-price periods. Over time, excessive volatility can erode confidence, increase hedging costs, and discourage long-term contracting—factors linked to market depth conditions.
A structural gap between tail-risk value and average-output payments
The structural conclusion presented is that South-East Europe’s power system generates value primarily by reducing tail risk while remunerating primarily for average output delivered through existing mechanisms. Until remuneration frameworks address this gap through regional coordination, revised market design, or explicit stability payments, underinvestment is described as likely to persist alongside continued pricing of risk rather than resolution.
The region faces an outcome set tied to whether remuneration frameworks evolve or remain unchanged: higher volatility, sharper price spikes, and episodic crisis interventions are described as potential consequences if stability value continues without corresponding compensation pathways for providers of grid support services.