The cost of not having a storage strategy in Romania’s energy market just hit €1.015/MWh

On 30 June, the day-ahead electricity price in the Romanian bidding zone reached 5.321 lei/MWh, equivalent to approximately €1.015/MWh, the highest figure ever recorded on Romania’s day-ahead electricity market. The following evening, prices again ranked among the highest ever recorded during the evening peak.

The day before, on 29 June, Romania’s average day-ahead price reached €224/MWh, the highest in Europe that day, with evening hourly prices climbing above €800/MWh. Bulgaria and Greece cleared at around €90/MWh and €87/MWh respectively over the same period.

Three consecutive days, three of the most expensive trading sessions in Romania’s electricity market history, all in the same heatwave week.

For any company exposed to spot electricity prices, whether directly or through PZU-indexed supply contracts, those three days revealed the full cost of remaining exposed during the evening peak.

The structure behind the number

The immediate trigger was a severe heatwave, with a red weather alert covering 35 counties and Bucharest from 29 June through 1 July. Several major generation sources were simultaneously constrained: one reactor unit at Cernavodă remained offline for modernisation works, the Brazi gas-fired power plant operated at reduced capacity during scheduled maintenance, wind generation stayed minimal across the heatwave period, and low Danube water levels further reduced hydropower output.

The heatwave explains why this particular week became exceptional, and the market structure explains why similar weeks are likely to appear again.

Romania’s solar capacity now covers a meaningful share of daytime demand, often at low or even negative prices around midday. As the sun sets, that production disappears within roughly an hour, while demand, driven this week by air conditioning load, stays elevated through the evening. 

The system closes the gap through dispatchable generation, imports, and cross-border market coupling, transmitting price tension across the region directly into Romania’s evening peak.

Romania sold solar power cheaply during the day, then paid a premium for electricity in the evening

That sentence captures the structural challenge facing Romania’s electricity system.

During sunny hours, Romania regularly exports surplus photovoltaic generation at relatively low prices. Neighbouring markets with significantly larger battery fleets, particularly Bulgaria, are increasingly able to store part of that low-cost electricity and release it back into the regional market during the evening peak, when prices are substantially higher.

Romania entered the summer with well under 1 GW of battery storage capacity, while Bulgaria had already expanded into the multi-gigawatt range, placing it among the European Union’s leading battery storage markets. In practical terms, Bulgaria can sustain its electricity system for roughly two and a half hours using batteries and pumped hydro, while Romania’s available storage covers only around fifteen minutes.

A rooftop solar installation without storage creates the same dynamic at company level: it generates inexpensive electricity during the hours when prices are already low, while leaving the facility fully exposed to the grid during the evening hours when prices move the way they moved this week.

Solar addresses the daytime cost profile, storage addresses the evening risk.

What does this cost a company that stays exposed

For a business with meaningful exposure to spot pricing or PZU-indexed procurement, a week like this translates directly into eroded margins and unpredictable cash flow. An industrial facility consuming 10 MWh during the peak pricing hour on 30 June would have faced an electricity bill of roughly €10.000 for that single hour alone.

Energy-intensive sectors feel this first, since electricity represents a significant share of production costs. But the planning challenge extends well beyond any single sector: a budget built around average electricity prices becomes increasingly unreliable when several heatwave weeks each summer carry their own version of this week’s evening price pattern.

The new economics of staying powered

Companies with on-site generation and adequate storage experienced this week differently. During the hours when grid-exposed competitors paid €800 or even €1.015/MWh, they supplied a significant share of their consumption from energy generated and stored earlier in the day, creating a materially lower average electricity cost across the same operating period.

That’s the part worth bringing into the boardroom conversation. This extends well beyond protection from volatile prices. Companies that combine on-site generation with appropriately sized storage are building a structural cost advantage over competitors whose energy strategy still follows the daily rhythm of the wholesale market.

Romania has programmed around 1,5 GW of new battery storage for installation this year and approximately 4 GW over the next two years. A new 1,7 GW gas-fired power plant at Mintia is also expected to strengthen system flexibility once commissioned. 

The structural gap will narrow gradually, while summers between now and then are likely to keep producing evenings like 30 June and 1 July.

The question worth bringing to the board

Most boards settled the question of whether solar makes sense years ago. The more useful question today is sharper:

How exposed is this company to the next week like 29 June to 1 July, and what would two or three more summers of similar episodes cost if the energy strategy stays unchanged?

This week’s market provided a measurable answer.

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