Flexibility assets in South-East Europe are no longer best understood as domestic arbitrage machines smoothing hourly price curves. They are increasingly regional trading instruments whose value is realised during short, violent episodes of system stress rather than through steady cycling between day-night spreads. The decline of dispatchable baseload, rising congestion frequency, and shrinking system inertia have repositioned storage, pumped hydro, and fast-ramping capacity as instruments that monetise volatility, scarcity, and deliverability risk across borders. Seasonal system framing by ENTSO-E sets the context; market outcomes quantify the shift.
Historically, flexibility economics in SEE were modest. Daily spreads were narrow, balancing markets shallow, and the system relied on coal and hydro to absorb shocks. Batteries and pumped storage, where they existed, earned incremental revenue by arbitraging predictable intraday patterns. That paradigm has broken. As congestion and inertia decline reshape price formation, value concentrates into a small number of hours when systems approach physical limits. Flexibility assets now earn most of their revenue when everything else fails.
The revenue concentration is stark. Market observations across SEE indicate that 50–70 % of annual EBITDA for grid-scale batteries can be captured in fewer than 150–250 hours per year, overwhelmingly during winter stress events and congestion-driven scarcity. In those hours, balancing and intraday prices routinely exceed €250–400/MWh, compared with annual average day-ahead prices in the €70–100/MWh range. Arbitrage between baseload and peak explains only a fraction of these returns; the dominant driver is response scarcity.
Battery economics illustrate the point. A 100 MW / 400 MWh lithium-ion system, with installed CAPEX of roughly €200–260 million (at €500–650 thousand per MWh), may cycle lightly in normal conditions, generating limited arbitrage margins. Its financial viability hinges on extreme events. During corridor-binding winter days, the same asset can earn €5–10 million in gross margin over a few dozen hours by supplying balancing energy, frequency response, and intraday relief. The market is paying for immediacy, not energy volume.
Pumped hydro assets display similar concentration, albeit at a different scale. Facilities capable of 300–600 MW of rapid ramping can monetise scarcity during multi-hour stress events, capturing peak prices while providing system stability. Although their CAPEX—often €1.5–2.5 million per MW for modernisation or expansion—is high, their lifetime and scale allow them to function as regional shock absorbers. A single severe winter can materially alter their annual revenue profile.
What differentiates today’s environment is that flexibility value is regional, not local. A battery or pumped hydro unit located near a constrained interface earns revenue not because its domestic market is short, but because it can respond when cross-border flows are blocked. In effect, these assets trade congestion. Their profitability correlates more strongly with corridor saturation probability than with national demand profiles. This is a fundamental shift from arbitrage logic to network logic.
Balancing markets provide the clearest signal. Activation volumes in SEE have risen by 30–50 % over the past five years, while average activation prices have more than doubled in stress periods. Fast-response assets increasingly set the marginal price. Inertia-substituting services, such as frequency containment, command premiums because they prevent cascading failures. The scarcity rent embedded in these services is now large enough to underpin investment cases independently of energy arbitrage.
Intraday markets reinforce the trend. As forecast errors interact with constrained corridors, prices reprice violently close to delivery. Assets capable of reacting within minutes capture intraday spreads of €50–100/MWh repeatedly during stress windows. Liquidity thins as risk rises, further amplifying price moves. Flexibility assets effectively monetise this illiquidity premium.
From a trading-desk perspective, flexibility assets function as physical options. They pay out when volatility spikes, when corridors bind, and when balancing scarcity emerges. Their payoff profile is convex, with limited downside and open upside tied to system stress frequency. This makes them natural complements to trading portfolios exposed to winter risk. Rather than hedging volatility with financial instruments alone, desks increasingly seek physical optionality.
The regional nature of value also reshapes siting decisions. Location near constrained interfaces, major load centres, or balancing nodes can increase revenue potential by 30–50 % compared with assets sited solely on domestic arbitrage considerations. Grid connection points that provide access to multiple markets or balancing zones enhance monetisation. In SEE, where corridors define outcomes, geography is destiny.
Carbon convergence strengthens the case. As coal exits accelerate and synchronous generation declines, stress frequency increases unless offset by flexibility. Markets implicitly price this future by elevating balancing and peak premiums in forward curves. Flexibility assets thus benefit from both current scarcity and anticipated future scarcity. Their risk, conversely, lies in overbuild: if grid reinforcement and storage deployment accelerate simultaneously, volatility compresses and revenues normalise.
Regulatory frameworks lag this reality. Many SEE markets still evaluate storage and flexibility under domestic rules that underestimate regional value. Revenue stacking—combining energy, balancing, and ancillary services—is often constrained by design rather than physics. From an investor perspective, this creates upside optionality: regulatory evolution can unlock additional revenue streams without new CAPEX.
For system operators, flexibility assets reduce emergency interventions and curtailment costs. For traders, they are instruments that monetise precisely the events that drive portfolio risk. For consumers, they are insurance against extreme prices. These roles converge during winter stress, when the system reveals its true marginal needs.
The strategic conclusion is that flexibility in South-East Europe has outgrown its original economic framing. It is no longer a domestic smoothing tool but a regional trading asset whose value is expressed in volatility suppression and scarcity monetisation. Investment cases that rely solely on average spreads miss the point. The market is paying for resilience in moments of failure, not efficiency in moments of balance. As long as dispatchable capacity continues to shrink faster than grids are reinforced, flexibility assets will remain among the most powerful instruments in the SEE power market.