Building directly on January’s observed system anatomy, the forward risk profile for South-East Europe in February–March can be framed as a three-axis stress test: nuclear availability, hydrology/flexibility, and cross-border capacity. Fuel prices, including gas, remain secondary variables unless disrupted externally. The purpose of this stress test is not to forecast a single price, but to map how the system would reprice under specific degradations and where value and risk would migrate.
Baseline continuity case: High nuclear availability, normal winter hydrology
In the base case, Bulgaria and Romania maintain near-full nuclear availability, hydrology remains seasonally normal, and interconnectors operate as in January. Under this configuration, the February–March market remains volatile but controlled. Baseload prices across SEEPEX and CROPEX would likely stabilise in the €90–120/MWh band during energy-long periods, with peaks episodically repricing into the €150–200/MWh range during cold spells or wind lulls. Romania on OPCOM would retain a premium, with baseload clustering above €120/MWh and peak prices structurally higher, reflecting its role as a regional sink during stress.
In this case, scarcity remains temporal, not systemic. Hydro continues to monetise evening ramps, nuclear suppresses prolonged crises, and gas remains a ceiling rather than a driver. Market outcomes resemble January but with slightly reduced tail risk as daylight lengthens and solar marginally improves.
Nuclear stress case: Partial outage or reduced availability in Bulgaria or Romania
A reduction in nuclear availability of even 500–1,000 MW in Bulgaria or Romania fundamentally alters the regional balance. This is the single most destabilising variable in the SEE system. Nuclear is not easily replaced at scale in winter, and its loss shifts the marginal hour from “flexibility-priced” to “energy-scarcity-priced.”
Under this scenario, Bulgaria’s ability to export collapses or reverses, eliminating a key pressure valve for Romania and the Western Balkans. OPCOM prices would reprice first, with baseload quickly moving into the €160–200/MWh range and peaks breaching €250/MWh on constrained days. Serbia and Croatia would follow, not because of domestic shortage, but because import-anchored price formation would now reference a higher marginal cost stack. SEEPEX peak pricing north of €300/MWh would become more frequent rather than exceptional.
Critically, hydro alone cannot compensate. Reservoirs can cover ramps, but they cannot replace lost baseload across weeks. Gas would step up as a marginal supplier, but at significantly higher clearing prices due to carbon and efficiency penalties. This is the scenario in which average prices, not just tails, reset upward, and where industrial buyers face sustained cost pressure rather than episodic shocks.
Hydro stress case: Below-average inflows or strategic conservation
A dry February–March, or deliberate reservoir conservation ahead of summer, produces a different but equally important outcome. Nuclear remains online, but intra-day flexibility collapses. In this case, baseload prices may not explode, but peak spreads widen aggressively.
Under hydro stress, off-peak prices could remain near €90–110/MWh, while evening peaks systematically clear €180–240/MWh, with extreme days exceeding January’s levels despite milder temperatures. The defining feature here is not energy scarcity, but shape scarcity. Systems such as Serbia and Croatia, already exposed to evening ramps, would see disproportionate cost inflation for peak-weighted loads. Montenegro would face amplified volatility, with extreme lows disappearing and high-price days becoming dominant due to reduced import optionality.
This is the most profitable environment for fast-response assets and the most damaging for flat-hedged buyers. It also accelerates curtailment risk for wind during off-peak hours, as insufficient hydro flexibility limits absorption.
Grid stress case: Interconnector congestion or reduced ATC
A degradation in cross-border availability—planned maintenance, forced outages, or operational derating—turns January’s fragmentation into a structural feature. The impact is asymmetric. Romania becomes more expensive faster, Croatia’s import-dependent hours reprice sharply, and Serbia’s peaks decouple violently from baseload.
In this scenario, price convergence fails precisely when it is most needed. Bulgaria and Hungary may remain relatively stable internally, while neighbouring systems clear at scarcity prices despite adequate regional supply. Small markets such as Montenegro experience the most extreme outcomes, with price distributions collapsing into a narrow band of high values rather than oscillating.
Grid stress does not need to be severe to matter. Even modest reductions in ATC during evening ramps are enough to force local marginal pricing. The result is higher volatility, higher congestion rents, and lower welfare for consumers.
Combined stress case: Nuclear + hydro or hydro + grid
The most dangerous configurations are combinations. A partial nuclear outage combined with weak hydrology produces systemic stress, not just volatility. In this case, February–March would resemble crisis winters, with sustained prices above €200/MWh, frequent peak prints above €300/MWh, and limited arbitrage relief. Market confidence deteriorates, forward curves lift, and risk premia return.
A hydro + grid stress combination is less catastrophic but highly redistributive. Prices spike locally while neighbouring systems remain cheaper, transferring value to asset owners behind constraints and penalising import-reliant buyers.
Portfolio-level implications
For generators, the stress tests confirm that flexibility remains the dominant value driver. Hydro, storage, and fast-ramping assets outperform in all adverse cases except pure nuclear stress, where baseload ownership becomes decisive. Nuclear-anchored exporters gain the most asymmetric upside when neighbours tighten.
For industrial buyers, the message is sharper. Flat baseload hedges protect averages but fail catastrophically under hydro or grid stress. Exposure to evening ramps must be explicitly managed through shape hedging, demand response, or contractual flexibility. Serbia and Croatia face the highest marginal risk due to their position between exporting and importing regimes.
For policymakers and TSOs, January plus these stress tests point to a structural conclusion: SEE is no longer energy-short, but flexibility-short. Investments that add flexibility—hydro optimisation, storage, grid reinforcement—deliver more price stability per euro than new energy-only capacity.
Taken together, the February–March outlook is not one of inevitable crisis, but of conditional instability. As long as nuclear remains online and hydrology holds, volatility is monetisable rather than destructive. Remove either pillar, and the same system that absorbed January’s shocks smoothly will reprice sharply, redistributing costs and exposing structural weaknesses that averages alone never reveal.
By virtu.energy
