Both reactors at Romania’s Cernavodă nuclear power plant were taken offline, leaving Southeast Europe facing one of the most significant summer power-sector disruptions. Exceptionally low Danube water levels have limited cooling-water availability, temporarily removing a facility that normally supplies around 20% of Romania’s electricity demand. The outage comes as Romania had already declared an energy-sector state of alert for August.
The two CANDU reactors at Cernavodă do not rely on reservoir inflows for fuel, but their operation remains sensitive to river flow and temperature conditions. Danube discharge has dropped from a seasonal norm of more than 4,000 cubic metres per second to around 1,600 cubic metres per second. Earlier forecasts indicated a further decline towards 1,500 cubic metres per second.
With both nuclear units unavailable, Romanian authorities postponed the retirement or temporary withdrawal of coal-fired capacity. They also encouraged consumers to reduce evening demand and increased reliance on imports from Bulgaria, Hungary, Serbia and Ukraine. Dacia and Ford have reportedly suspended automotive production until 19 August, reducing industrial consumption during the most critical period.
Romania’s system can compensate for missing nuclear output if regional interconnectors and neighbouring markets maintain sufficient spare capacity. The country has aggregate technical import capacity of around 3.3 GW, though commercially available capacity is lower and varies by hour. Extreme heat, weak Balkan hydrology or additional outages in Bulgaria and Hungary could quickly reduce that buffer.
Regional price curve shows scarcity signal across coupled markets
The disruption is also affecting earnings expectations for Hidroelectrica, Nuclearelectrica, OMV Petrom and Complexul Energetic Oltenia. Nuclear generation typically provides Romania with stable baseload electricity at low marginal cost. Its temporary removal increases the value of gas-fired and coal generation, while weak hydrological conditions limit Hidroelectrica’s ability to fully benefit from higher prices.
OMV Petrom’s Brazi gas-fired plant is expected to gain additional dispatch value under the altered supply mix. Coal-fired assets are also taking on a temporary security-of-supply role despite high carbon intensity. The day-ahead market for delivery on 15 August showed quarter-hourly coupling effects across the region.
The day-ahead session recorded strong price convergence between Hungary and Romania, while Bulgaria remained relatively closely aligned after adjusting for its one-hour time difference. Hungary’s HUPX averaged approximately €115.10/MWh, with prices falling to €1/MWh at 13:15–13:30 and reaching a maximum of €199.10/MWh at 19:45–20:00. Romania’s OPCOM averaged around €115.20/MWh with the same €1/MWh floor and €199.10/MWh peak occurring one hour later in local time.
Bulgaria recorded an average price of approximately €102.90/MWh, with prices also falling to €1/MWh during the afternoon. The maximum reached €177.70/MWh, reflecting stronger domestic nuclear availability, coal generation and a rapidly expanding battery-storage fleet. The curve shape mattered more than the daily average as prices declined from above €150/MWh in the morning to almost zero around midday before recovering above €175/MWh in the evening.
The convergence reflected cross-border market coupling during much of the session, but it did not indicate equal underlying system balance. Romania’s generation deficit was partially transferred into regional imports while Hungarian and Bulgarian solar surpluses helped establish the common midday price. During the evening ramp, rising demand alongside rapid photovoltaic withdrawal produced a shared scarcity signal.
Intraday and balancing markets remained more exposed than day-ahead pricing suggested. Unexpected wind changes, additional thermal deratings or reductions in import capacity can force procurement at prices significantly above day-ahead levels. Romania’s dependence on scheduled imports also reduces cross-border headroom for correcting forecast errors.
Solar troughs drive midday clearing at €1/MWh
The midday clearing price at €1/MWh in Hungary, Romania and Bulgaria showed that solar output had reached a scale capable of depressing prices simultaneously across interconnected markets even during a major nuclear outage . Hungary’s solar fleet has expanded beyond what domestic afternoon demand can absorb without greater reliance on exports, curtailment or storage. Romania is moving in the same direction while Bulgaria’s utility-scale and commercial photovoltaic capacity contributes to summer price troughs.
The pattern creates challenges for unhedged solar projects because highest physical output coincides with quarter-hours when wholesale prices are lowest. Capture prices can therefore decline even when average baseload prices remain above €100/MWh. Fixed-price or floor-price PPAs, route-to-market agreements using active intraday optimisation and co-located storage become more relevant under these conditions.
The same volatility also creates opportunities for energy-intensive consumers able to shift production towards midday hours where wholesale prices can approach zero . Network charges, taxes, supplier margins and balancing costs still apply to end users purchasing electricity under such conditions. Electrolysers, pumping facilities, refrigeration, water-treatment plants and flexible industrial processes are identified as particularly suited to exploit these price patterns.
Evening pricing indicates that solar does not reduce electricity value across the entire day by itself; it widens the gap between solar hours and firm supply . Wind projects retain a different revenue profile because their generation is less concentrated around the midday solar trough and can continue after sunset.
Bulgaria adds batteries; Romania prepares standalone storage support
Bulgaria’s lower average price profile and less pronounced evening peak highlight growing system value from battery storage . Through its RESTORE support programme, Bulgaria has commissioned a battery fleet including Enery’s 150 MW/600 MWh Nova Zagora BESS developed with Sungrow and Sunotec. A four-hour battery of this size can absorb surplus photovoltaic generation during low-price periods and release up to 150 MW during the evening ramp.
A single project cannot determine national pricing outcomes, but a growing portfolio can reduce balancing requirements, limit price spikes and preserve export capacity when neighbouring markets are short . Day-ahead curve economics show a gross spread of almost €164/MWh between a €1/MWh minimum and evening prices around €165/MWh. A four-hour battery capturing a realised spread of €120–€160/MWh could theoretically generate about €72,000–€96,000 of gross daily arbitrage revenue per 150 MW of discharge capacity before round-trip losses, degradation, market fees and imbalance costs.
Bulgaria’s next investment wave is increasingly focused on hybridisation . OMV Petrom and Enery’s Gabare project in Byala Slatina combines approximately 415 MWp of solar with 600 MWh of storage. Total investment is estimated at around €300 million including about €100 million for the battery component, with first generation expected in 2028; OMV Petrom has agreed to purchase half of the solar output under a PPA.
The Gabare commercial model relies less on selling all photovoltaic output immediately and more on converting variable generation into a more predictable product . The battery can reduce exposure to low or negative prices, shift deliveries towards higher-value hours and limit balancing costs even though 600 MWh remains modest compared with potential daily output from a 415 MWp solar plant.
Romania’s nuclear disruption strengthens the investment case for battery storage while also highlighting limitations tied to projects still under development . The country is preparing a €150 million support programme for standalone storage expected to enable roughly 3–4 GWh depending on grant intensity and eligible costs . Stronger projects are expected to combine public support with merchant revenues rather than relying solely on subsidies tied to weak grid locations or trading strategies.
Lenders have already financed larger storage projects in Romania . Enery’s Ogrezeni hybrid project in Giurgiu County combines 761 MWp solar with 534 MW grid-connected photovoltaic capacity plus more than 1 GWh BESS . The company secured a €460 million syndicated green financing led by UniCredit with support from Intesa Sanpaolo, ING, Banca Transilvania, National Bank of Greece, Exim Banca Românească and Alpha Bank; an accordion facility allows up to €79 million for additional battery expansion .
An example of smaller operational scale is MORE’s Stâlpu 2 project currently in trial operation . It combines 63 MW solar with a 10 MW/21 MWh battery expected to generate about 76 GWh annually. MORE participates in nine regional power exchanges enabling optimisation within a broader trading portfolio rather than treating storage as an extension of the solar plant . Standalone developers are described as needing route-to-market agreements that transfer part of potential storage margin to aggregators .
Danube low levels cut Serbian hydro output; coal logistics tighten
The same hydrological conditions affecting Cernavodă are reducing generation from Serbia’s largest hydropower complex . Đerdap 1 is jointly operated across the Serbian-Romanian section of the Danube and recently produced about 5,000 MWh per day, roughly one-third of its normal daily generation . On the Serbian side it forms part of a combined complex with roughly 1,140 MW installed capacity.
The EPS reported that May and June generation was the weakest for those months since Đerdap 1 entered service in 1970 . With low-cost hydro curtailed, EPS faces higher reliance on Nikola Tesla and Kostolac lignite plants as well as imports and other reservoir generation within its portfolio . Low river levels are also affecting thermal-generation flexibility through cooling-water constraints at Kostolac .
Barges and tankers operating on the Danube have reportedly carried only 30–40% of normal cargo volumes . At one point in July fuel imports were approximately 25% of the monthly target . The financial impact is described as asymmetric because hydro shortfalls remove EPS’s cheapest flexible generation during periods when regional evening prices strengthen . Coal plants can replace missing energy but at higher operating costs plus maintenance and carbon-adjusted costs . Imports protect physical security while exposing EPS to HUPX- and OPCOM-linked prices approaching €200/MWh during evening peaks .
This environment increases strategic relevance for Serbia’s planned 1 GW solar-and-storage programme developed by EPS with Hyundai Engineering and UGT Renewables . The project covers six locations with expected components including about 1.2 GWp photovoltaic modules, 1 GW connection capacity and at least 200 MW/400 MWh battery storage . K-SURE has indicated support for up to €900 million, within an estimated investment near €1.1 billion** .
The financing structure is linked to Korean equipment exports and Swedish export-credit reinsurance , while the proposed battery provides only two hours full-discharge duration relative to installed solar capacity share . It can support ramp management and balancing but cannot compensate for prolonged hydro or nuclear outages . The financing model needs to account for multi-day low-hydro conditions, solar curtailment risks, EPS counterparty strength and potential grid-connection delays; a 12–18-month transmission delay could postpone energy revenues while construction interest continues during building plus battery warranty periods . That timing could reduce projected equity returns from an indicated 10–12% down to high-single-digit levels unless EPC and connection agreements allocate delay risks effectively .
Cronos gas project targets European deliveries via Egypt LNG chain
A separate gas development is emerging from Cyprus where Eni and TotalEnergies plan first European deliveries from the Cronos field during the first half of 2028 . The field is estimated to contain around 3 trillion cubic feet of natural gas. A proposed development budget is US$2 billion connecting Cronos with Egypt’s offshore Zohr infrastructure before sending gas to Damietta LNG terminal for export to European buyers.
The plan uses existing Egyptian processing and liquefaction infrastructure rather than building new LNG capacity in Cyprus . Most production is expected for Europe while about 20% could supply Egypt’s domestic market . The arrangement links Cypriot upstream resources with Egyptian infrastructure and European LNG demand without requiring direct pipeline connection to Greece.
The project complements Greece-led efforts under the Vertical Gas Corridor aiming to move LNG and Caspian gas northwards across Greece, Bulgaria, Romania, Hungary, Slovakia, Ukraine, Moldova, Serbia and North Macedonia . Serbia’s Srbijagas has reserved approximately / / / .
