South-East Europe’s power markets are increasingly characterised by a widening gap between where system value is created and where revenue is actually captured. Assets and systems that stabilise the grid, suppress volatility, and prevent cascading failures generate outsized regional benefits, yet market remuneration mechanisms remain largely national, energy-centric, and backward-looking. This mismatch is no longer a theoretical inefficiency; it is a material risk to future investment, trading stability, and security of supply. Seasonal system assessments by ENTSO-E highlight adequacy envelopes, but they do not resolve who pays for keeping the system inside them.
At the heart of the mismatch lies the changing nature of value. In legacy SEE markets, value was created by producing energy at low marginal cost. Coal, lignite, and hydro plants monetised high utilisation, while grids were passive enablers. Today, value is created by preventing failure during rare but extreme stress events. Assets that keep frequency within bounds, absorb shocks, or unblock constrained corridors deliver benefits that propagate across borders. Yet markets still remunerate primarily for megawatt-hours delivered, not for crises avoided.
The economic scale of avoided crises is substantial. During winter stress events, regional price spikes routinely exceed €300–500/MWh, and in isolated zones 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—even marginally—deliver expected value far exceeding their observable market revenues in normal conditions.
Transmission infrastructure illustrates the problem clearly. A new 400 kV line costing €300–500 million may reduce congestion frequency by a few percentage points. From a national regulator’s perspective, the direct benefit appears modest, often insufficient to justify CAPEX. From a regional trading perspective, however, the same line can compress peak spreads by €20–40/MWh, lower winter risk premiums, and reduce congestion rents that amount to €30–70 million per year on affected corridors. The beneficiaries are dispersed across markets and consumers, while the investor sees only a fraction of the value.
Flexibility assets face a similar distortion. 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 its annual EBITDA during fewer than 200 hours, while remaining idle most of the year. Market revenues fluctuate wildly year to year, despite the asset delivering consistent insurance value. This volatility discourages investment precisely where the system needs it most.
Synchronous generation and inertia provision deepen the mismatch. Remaining thermal units in SEE still supply a disproportionate share of inertia and voltage support. Their presence reduces balancing activation volumes and suppresses intraday volatility. Yet by doing so, they erode their own scarcity rents. The more stable the system, the lower the prices they receive. This creates a perverse incentive: assets that stabilise the system earn less than they would in a more fragile environment.
Quantitatively, the gap is visible 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, while assets that reduce balancing needs receive limited direct compensation. The system pays for instability but underpays for stability.
Cross-border effects compound the issue. When one system invests in stabilising assets—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 this benefit back to the investor. Over time, rational actors underinvest in regional public goods, increasing the probability of abrupt failures that markets then price violently.
The trading consequences are already evident. Forward curves embed persistent winter risk premiums, even when near-term adequacy appears comfortable. Peak-to-baseload spreads of €40–60/MWh in winter quarters reflect not just expected scarcity, but uncertainty over whether stabilising assets will be available when needed. Longer-dated products show widening bid-ask spreads beyond Y+2, signalling disagreement over how quickly the remuneration gap will be addressed.
From an investor standpoint, this mismatch elevates required returns. Projects that would be economically justified on a system-value basis struggle to clear hurdle rates when evaluated solely on merchant revenues. The result is delayed or downsized investment, reinforcing the very volatility that raises prices. It is a feedback loop that markets recognise but cannot resolve on their own.
Policy responses lag market reality. Capacity mechanisms, where they exist, often remain nationally scoped and energy-focused. Ancillary service markets undervalue fast response and inertia substitutes. Congestion income allocation does not reflect regional benefit distribution. As SEE markets become more interconnected, these misalignments grow more costly.
For traders, the mismatch translates into opportunity and risk. Volatility persists because stabilising investment is insufficient. Those positioned to monetise stress events benefit, while those exposed to extreme prices suffer. Over time, however, excessive volatility erodes confidence, increases hedging costs, and discourages long-term contracting—outcomes that undermine market depth.
The structural conclusion is unavoidable. South-East Europe’s power system now generates value primarily by reducing tail risk, yet remunerates primarily for average output. Until this mismatch is addressed—through regional coordination, revised market design, or explicit stability payments—underinvestment will persist. Markets will continue to price risk rather than resolution.
In practical terms, the region faces a choice. Either it evolves remuneration frameworks to recognise and share the value of stability, or it accepts a future of higher volatility, sharper price spikes, and episodic crisis interventions. For investors and traders, understanding this mismatch is critical. It explains why rational behaviour at the asset level produces fragile outcomes at the system level—and why volatility, for now, remains structurally embedded in South-East Europe’s power markets.