The forward risk profile for South-East Europe in February–March can be assessed as a three-axis stress test built on January’s system conditions. The axes are nuclear availability, hydrology and flexibility, and cross-border capacity. Fuel prices, including gas, are treated as secondary variables unless disrupted externally. The exercise is designed to map how the market would reprice under specific degradations rather than to forecast a single price path.
Baseline continuity: near-full nuclear and normal winter hydrology
In the base case, Bulgaria and Romania keep near-full nuclear availability, winter hydrology remains seasonally normal, and interconnectors run as in January. With that configuration, the February–March market stays volatile but controlled. Baseload prices across SEEPEX and CROPEX are expected to stabilise in the €90–120/MWh band during energy-long periods. Peaks would episodically reprice into the €150–200/MWh range during cold spells or wind lulls.
Romania on OPCOM would retain a premium under the baseline. Baseload clustering is described as above €120/MWh, with peak prices structurally higher due to its role as a regional sink during stress. Scarcity in this case is characterised as temporal rather than systemic. Hydro continues to monetise evening ramps while nuclear suppresses prolonged crises, with gas acting as a ceiling rather than a driver.
Market outcomes in the baseline are described as resembling January, with slightly reduced tail risk as daylight lengthens and solar marginally improves. The same conditions keep volatility within a controlled range rather than producing sustained repricing. The role of hydro is linked to intra-day monetisation rather than long-duration replacement of supply. Nuclear availability remains the factor that limits extended crises.
Nuclear availability shock: partial outage in Bulgaria or Romania
A reduction in nuclear availability of 500–1,000 MW in Bulgaria or Romania is presented as the most destabilising variable for the SEE system. The loss is not described as being easily replaced at scale in winter. Instead, it shifts marginal pricing from flexibility-priced hours toward energy-scarcity-priced hours. This change alters regional balance beyond the affected country.
Under this nuclear stress scenario, Bulgaria’s export capability is described as collapsing or reversing. That removes a pressure valve for Romania and the Western Balkans. OPCOM prices are expected to reprice first, with baseload moving into the €160–200/MWh range and peaks breaching €250/MWh on constrained days. Serbia and Croatia are then described as following due to import-anchored price formation referencing a higher marginal cost stack.
The scenario also points to more frequent high-price events on SEEPEX. Peak pricing north of €300/MWh is described as becoming more common rather than exceptional. Hydro alone is not presented as able to compensate because reservoirs can cover ramps but 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.
Hydrology stress: below-average inflows or conservation
A dry February–March or strategic reservoir conservation ahead of summer is framed as producing a different outcome even with nuclear online. In this case, nuclear remains available but intra-day flexibility collapses. Baseload prices may not rise explosively, but peak spreads widen aggressively. The stress is therefore described in terms of shape scarcity rather than energy scarcity.
Under hydro stress, off-peak prices are described as potentially staying near €90–110/MWh. Evening peaks are expected to clear systematically at €180–240/MWh, with extreme days exceeding January levels despite milder temperatures. Systems such as Serbia and Croatia—already exposed to evening ramps—are described as seeing disproportionate cost inflation for peak-weighted loads. Montenegro is described as facing amplified volatility where extreme lows disappear and high-price days become dominant due to reduced import optionality.
The source characterises this configuration as damaging for flat-hedged buyers while supporting fast-response assets tied to flexibility. It also links hydro shortfalls to curtailment risk for wind during off-peak hours because insufficient hydro flexibility limits absorption. The key mechanism remains reduced ability to manage intra-day variability rather than an outright lack of energy over longer horizons.
Grid stress: interconnector congestion or reduced ATC
A degradation in cross-border availability—through planned maintenance, forced outages, or operational derating—is framed as turning January’s fragmentation into a structural feature for February–March. The impact is described as asymmetric across markets and price formation zones. Romania is expected to become more expensive faster, Croatia’s import-dependent hours would reprice sharply, and Serbia’s peaks would decouple from baseload.
The grid stress case is described as preventing price convergence when it is most needed. Bulgaria and Hungary may remain relatively stable internally while neighbouring systems clear at scarcity prices despite adequate regional supply elsewhere. Small markets such as Montenegro are described as experiencing the most extreme outcomes, with price distributions collapsing into a narrow band of high values rather than oscillating between low and high prints.
The source notes that grid stress does not need to be severe to matter operationally. Even modest reductions in available transfer capacity during evening ramps are described as sufficient to force local marginal pricing. The resulting effects include higher volatility and congestion rents alongside lower welfare for consumers.
Combined scenarios: nuclear plus hydro or hydro plus grid constraints
The most dangerous configurations are presented as combinations of stresses rather than single-axis degradations. A partial nuclear outage combined with weak hydrology is described as producing systemic stress beyond volatility alone. In this combined case, February–March would resemble crisis winters with sustained prices above €200/MWh. Peak prints above €300/MWh are described as frequent, alongside limited arbitrage relief.
This combined nuclear-and-hydro scenario is also linked to deteriorating market confidence with forward curves lifting and risk premia returning. A hydro-and-grid combination is characterised differently: it is described as less catastrophic but highly redistributive across constrained areas. Prices spike locally while neighbouring systems remain cheaper due to constraints that limit cross-border balancing.
Implications across market participants under the stress axes
The stress tests are described as confirming that flexibility remains the dominant value driver across adverse cases for generators. Hydro, storage, and fast-ramping assets are stated to outperform in all adverse cases except pure nuclear stress where baseload ownership becomes decisive. Nuclear-anchored exporters are described as gaining the most asymmetric upside when neighbours tighten supply conditions.
For industrial buyers, the message is framed around hedge performance under different constraint types. Flat baseload hedges are described as protecting averages but failing catastrophically under hydro or grid stress because exposure shifts toward peak-weighted outcomes driven by shape scarcity or local marginal pricing effects. Managing exposure to evening ramps is presented through shape hedging, demand response, or contractual flexibility requirements tied to operational constraints.
The highest marginal risk for industrial buyers is identified for Serbia and Croatia due to their position between exporting and importing regimes under these scenarios. For policymakers and transmission system operators, January plus these stress tests point toward a structural conclusion that South-East Europe faces a flexibility-short environment rather than an energy-short one. Investments adding flexibility—hydro optimisation, storage, and grid reinforcement—are described as delivering more price stability per euro than new energy-only capacity within this framework.
Taken together, the February–March outlook is framed as conditional instability rather than inevitable crisis under all conditions. As long as nuclear remains online and hydrology holds, volatility is characterised within the system’s ability to monetise ramps rather than drive prolonged crises across markets. Removing either pillar leads to sharper repricing that redistributes costs and exposes structural weaknesses not visible from averages alone.