In South-East Europe, most of the meaningful volatility is not created in outright gas markets or in flat power positions. It is created at the interface between gas and electricity, in the narrow set of hours when fuel deliverability, power system constraints, and market design collide. Traders and industrial buyers who focus on average prices or single-commodity exposures consistently miss where risk is generated and monetised. Seasonal system outlooks by ENTSO-E describe adequacy; P&L outcomes reveal that the decisive variable is how gas stress converts into power pricing under constraint.
The gas–power interface is where physics overrides finance. Gas markets clear regionally, with prices reflecting aggregate balance and expectations. Power markets clear locally and temporally, with prices reflecting instantaneous system feasibility. When the two align smoothly, correlations hold. When they do not, electricity prices escape gas anchoring and reprice on scarcity. South-East Europe sits precisely where this misalignment is most frequent, because its power systems have thin dispatchable depth and its gas systems have limited deliverability at peak.
The interface activates under a specific set of conditions. Weather-driven demand rises across Serbia, Romania, and Bulgaria within 24–48 hours. Hydro flexibility is quickly exhausted, coal units face technical or economic limits, and interconnectors approach security thresholds. Gas becomes marginal simultaneously on both sides of the interface: it is needed to generate electricity, and it is constrained by storage withdrawal limits and pipeline rigidity. This coincidence is where volatility is born.
Quantitatively, the interface explains why modest gas signals produce extreme power outcomes. During non-stress periods, a €10/MWh movement in gas benchmarks may produce little change in electricity prices. When the interface is activated, the same gas signal can translate into €50–100/MWh intraday power repricing, and peak prices exceeding €300–400/MWh. The magnitude is not explained by fuel cost; it is explained by the absence of alternatives.
Transmission topology ensures that this volatility is localised. When north–south corridors linking Hungary and Serbia or east–west routes between Romania and Bulgaria saturate, power prices decouple by zone. Gas prices remain uniform; power prices fragment. Traders positioned in spreads capture the repricing; those hedged only in gas do not. In recent winters, €70–120/MWh power spreads have emerged between adjacent markets with identical gas inputs, driven entirely by the interface.
For traders, this reframes strategy. Directional gas views capture only a fraction of available value. The dominant opportunities lie in conditional exposure: positions that activate when gas tightness coincides with power constraints. Intraday liquidity, fast response, and optionality outperform static positions. Empirically, in SEE markets, 30–40% of annual trading returns can be traced to fewer than 20 stress days, nearly all of which involve the gas–power interface.
Balancing markets provide a clear signal. When gas deliverability tightens, balancing activation volumes increase sharply, and prices escalate non-linearly. In low-inertia conditions, balancing prices in SEE have exceeded €600/MWh, far above energy-based valuations. These prices reflect scarcity of response, not energy. Traders who monitor balancing signals gain early warning of interface activation.
Industrial buyers encounter the interface as cost shock. Gas-indexed electricity contracts assume that gas prices anchor power prices. When the interface activates, that assumption fails. Electricity costs spike even if gas invoices do not. Buyers then face imbalance charges, peak adders, or emergency pricing that dwarfs expected savings. In practice, 20–30% of annual electricity spend can be determined in hours when gas contracts offer no protection.
The procurement implication is that gas and electricity must be contracted as a single risk system, not as separate commodities. Buyers who cap peak exposure, secure flexibility, or negotiate defined scarcity pricing convert interface risk into a known cost. Those who do not are exposed to unbounded outcomes. Paying €4–8/MWh more on average to secure such structures frequently prevents €40–80/MWh overruns in interface-driven events.
Carbon convergence heightens the importance of the interface. As coal exits accelerate and renewable penetration rises without commensurate flexibility, gas becomes marginal more often, but with less buffer. This increases the frequency of interface activation. Even if average gas prices decline, volatility at the interface increases, because the system reaches marginal conditions more frequently. Markets already price this through persistent winter peak premia and widening forward bid–ask spreads beyond Y+2.
Infrastructure delays reinforce the pattern. Grid reinforcement projects costing €0.8–1.2 million per kilometre and storage upgrades requiring hundreds of millions of euros lag system needs. Until they are delivered, the interface remains the primary volatility engine. Congestion rents of €30–70 million per year on key corridors are the market’s way of pricing that delay.
The unified conclusion is pragmatic. In South-East Europe, volatility is not a mystery and not a failure of markets. It is the rational pricing of a system where gas and power constraints intersect. Traders who focus on the interface, rather than on single-commodity forecasts, capture the majority of value. Industrial buyers who recognise the interface design contracts that survive stress rather than optimise averages.
As long as gas remains the marginal fuel during critical hours and power systems remain constrained, the interface will continue to generate outsized volatility. The most expensive mistakes will be made by those who assume that gas prices explain electricity outcomes. The most consistent profits—and the most resilient procurement strategies—will belong to those who trade and contract where gas becomes power, and power becomes risk.