Southeast Europe entered the weekend facing one of its most significant power-sector disruptions of the summer after both reactors at Romania’s Cernavodă nuclear power plant were taken offline. Exceptionally low Danube water levels have restricted the availability of cooling water, temporarily removing a facility that normally supplies around 20% of Romania’s electricity demand.
The disruption highlights the increasingly interconnected nature of hydro, nuclear and thermal-generation risks. Cernavodă’s two CANDU reactors do not depend on reservoir inflows for fuel, but their operation remains sensitive to river flow and temperature conditions. Danube discharge has fallen from a seasonal norm of more than 4,000 cubic metres per second to around 1,600 cubic metres per second, with earlier forecasts pointing to a further decline towards 1,500 cubic metres per second.
Romania had already declared an energy-sector state of alert for August. With both nuclear units unavailable, authorities have postponed the retirement or temporary withdrawal of coal-fired capacity, 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.
The Romanian system can compensate for the missing nuclear output as long as regional interconnectors and neighbouring markets retain sufficient spare capacity. The country has aggregate technical import capacity of around 3.3 GW, although commercially available capacity is lower and varies by hour. A combination of extreme heat, weak Balkan hydrology or additional outages in Bulgaria and Hungary could rapidly reduce that buffer.
Moldova is particularly vulnerable to the regional imbalance. Romanian imports can cover a substantial share of Moldovan demand, but higher balancing requirements in Romania could force Moldova to rely more heavily on costlier supplies from Ukraine or western interconnected markets.
The outage is also changing the earnings outlook for Hidroelectrica, Nuclearelectrica, OMV Petrom and Complexul Energetic Oltenia. Nuclear generation normally 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 gains additional dispatch value, while coal-fired assets regain a temporary security-of-supply role despite their high carbon intensity.
Quarter-hourly coupling creates a €1-to-€199/MWh regional price curve
The day-ahead market for delivery on 15 August showed strong price convergence between Hungary and Romania, while Bulgaria remained relatively closely aligned after adjusting for its one-hour time difference.
Hungary’s HUPX market recorded an average price of 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 market averaged around €115.20/MWh, with the same €1/MWh floor and €199.10/MWh peak, although both occurred one hour later in local time.
Bulgaria recorded a lower average of approximately €102.90/MWh. Prices also fell to €1/MWh during the afternoon, while the maximum reached €177.70/MWh. The lower Bulgarian price profile reflects stronger domestic nuclear availability, coal generation and the country’s rapidly expanding battery-storage fleet.
The shape of the curve is more important than the daily average. In Hungary, prices declined from above €150/MWh in the morning to almost zero around midday, before recovering above €175/MWh during the evening and approaching €200/MWh after sunset. Romania followed a remarkably similar pattern despite the Cernavodă outage.
The convergence demonstrates the effectiveness of cross-border market coupling during much of the session, but it does not mean that the underlying systems were equally balanced. 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 and the rapid withdrawal of photovoltaic generation produced a shared scarcity signal.
Intraday and balancing markets remain considerably more exposed than the day-ahead auction indicates. Unexpected changes in wind output, additional thermal deratings or reductions in import capacity can force system operators to procure electricity at prices significantly above day-ahead levels. Romania’s dependence on scheduled imports also leaves less cross-border headroom for correcting forecast errors.
For traders, the opportunity is therefore shifting away from a simple Romania-Hungary baseload spread. More attractive strategies increasingly involve quarter-hourly solar-to-evening shape trades, intraday adjustments around nuclear-return expectations and cross-border capacity optionality when coupled markets begin to separate.
Solar generation is increasing volume while reducing midday value
The €1/MWh midday clearing price in Hungary, Romania and Bulgaria demonstrates that the region’s solar build-out has reached a scale capable of depressing prices simultaneously across several interconnected markets, even during a major nuclear outage.
Hungary’s solar fleet has expanded beyond the point at which domestic afternoon demand can absorb all available generation without greater reliance on exports, curtailment or storage. Romania is moving in the same direction, while Bulgaria’s growing utility-scale and commercial photovoltaic capacity is creating increasingly pronounced summer price troughs.
The development presents a growing challenge for unhedged solar projects. Plants can produce their highest physical output during the very quarter-hours in which wholesale prices are at their lowest. As a result, capture prices can decline even when average baseload prices remain above €100/MWh.
This increases the importance of fixed-price or floor-price PPAs, route-to-market agreements with active intraday optimisation and co-located storage. It also changes how curtailment and imbalance risks are allocated between generators and buyers. PPAs based solely on annual contracted volumes can hide significant exposure to zero-price periods, negative-price provisions and replacement-energy costs after sunset.
Industrial consumers, meanwhile, have an opportunity to benefit from the same volatility. Energy-intensive companies capable of shifting production towards midday can access wholesale electricity at prices close to zero, although network charges, taxes, supplier margins and balancing costs remain. Electrolysers, pumping facilities, refrigeration, water-treatment plants and flexible industrial processes are particularly well positioned to exploit these price patterns.
Evening prices also demonstrate that solar generation is not reducing the value of electricity across the entire day. Instead, it is widening 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’s battery expansion begins to reshape regional scarcity
Bulgaria’s lower average price and less pronounced evening peak highlight the growing system value of battery storage. The country has commissioned a significant battery fleet through its RESTORE support programme, 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 the national price curve, but a growing portfolio of similar systems can reduce balancing requirements, limit price spikes and preserve export capacity when neighbouring markets are short.
The economics are visible in the day-ahead curve. The difference between a €1/MWh minimum and evening prices around €165/MWh implies a gross spread of almost €164/MWh. A four-hour battery capturing a realised spread of €120–€160/MWh could theoretically generate approximately €72,000–€96,000 of gross daily arbitrage revenue per 150 MW of discharge capacity, before accounting for round-trip losses, degradation, market fees and imbalance costs.
Such returns will not remain constant. As storage capacity increases, batteries will compete against one another, pushing midday prices higher and evening prices lower. The long-term revenue stack will therefore need to include intraday optimisation, balancing energy, frequency services and other capacity-related products where available.
The next wave of Bulgarian investment is increasingly focused on hybridisation. OMV Petrom and Enery’s Gabare project in the Byala Slatina region combines approximately 415 MWp of solar capacity with 600 MWh of storage. The partners estimate total investment at around €300 million, including approximately €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.
Gabare’s commercial model depends less on selling all photovoltaic production immediately and more on converting a variable generation profile into a more predictable product. The battery can reduce exposure to low and negative prices, shift deliveries towards higher-value hours and limit balancing costs, although 600 MWh remains relatively modest compared with the potential daily output of a 415 MWp solar plant.
Romania’s storage pipeline moves towards bank financing
Romania’s nuclear disruption strengthens the investment case for battery storage while also highlighting the limitations of relying on projects that remain in development.
The country is preparing a €150 million support programme for standalone storage, with market estimates suggesting that it could enable approximately 3–4 GWh of capacity depending on grant intensity and eligible costs. The strongest projects are likely to be those capable of combining public support with merchant revenues rather than relying on subsidies to compensate for weak grid locations or inadequate trading strategies.
Private lenders have already demonstrated a willingness to finance storage at a much larger scale. Enery’s Ogrezeni hybrid project in Giurgiu County combines 761 MWp of solar, 534 MW of grid-connected photovoltaic capacity and more than 1 GWh of BESS. The company secured a €460 million syndicated green financing led by UniCredit and supported by Intesa Sanpaolo, ING, Banca Transilvania, National Bank of Greece, Exim Banca Românească and Alpha Bank. An accordion facility of up to €79 million allows for additional battery expansion.
The financing structure demonstrates that regional storage is becoming increasingly project-financeable when integrated into a large renewable portfolio, backed by an experienced sponsor and supported by multiple facilities covering term debt, VAT, working capital and contingencies. Standalone merchant batteries without contracted revenues or bankable optimisation agreements continue to face greater leverage constraints.
MORE’s Stâlpu 2 project, currently in trial operation, provides a smaller operational example. The facility combines 63 MW of solar with a 10 MW/21 MWh battery and is expected to generate approximately 76 GWh annually. MORE’s participation in nine regional power exchanges enables it to optimise the asset within a broader trading portfolio rather than treating storage simply as an extension of the solar plant.
That operating model is becoming a competitive advantage. Utilities and traders with access to multiple markets can combine physical generation, storage, cross-border capacity and customer portfolios. Standalone developers must acquire these capabilities through route-to-market agreements, transferring part of the potential storage margin to aggregators.
Danube weakness reduces Serbian hydro output and complicates coal logistics
The same hydrological conditions affecting Cernavodă are also reducing generation from Serbia’s largest hydropower complex. Đerdap 1, jointly operated across the Serbian-Romanian section of the Danube, has recently produced approximately 5,000 MWh per day, around one-third of its normal daily generation. The Serbian side forms part of a combined complex with roughly 1,140 MW of installed capacity.
EPS reported that generation during May and June was the weakest for those months since Đerdap 1 entered service in 1970. The loss of low-cost hydro generation increases dependence on the Nikola Tesla and Kostolac lignite plants, imports and other reservoir generation within the EPS portfolio.
Low river levels are also affecting thermal generation and fuel logistics. Cooling-water constraints have reduced flexibility at Kostolac, while barges and tankers operating on the Danube have reportedly carried only 30–40% of normal cargo volumes. At one point, July fuel imports were approximately 25% of the monthly target.
The financial impact is asymmetric. Hydro shortfalls remove EPS’s cheapest and most flexible generation precisely when regional evening prices are strengthening. Coal plants can replace part of the missing energy, but at higher operating, 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 increases the strategic value of Serbia’s planned 1 GW solar and storage programme, being developed by EPS with Hyundai Engineering and UGT Renewables. The project covers six locations and is expected to include approximately 1.2 GWp of photovoltaic modules, 1 GW of connection capacity and at least 200 MW/400 MWh of battery storage.
K-SURE has indicated support for up to €900 million of financing within an estimated investment of approximately €1.1 billion. The financing structure is linked to Korean equipment exports and Swedish export-credit reinsurance. However, the proposed battery provides only two hours of full-discharge duration and represents a relatively small share of the solar portfolio’s installed capacity. It can support ramp management and balancing but cannot compensate for prolonged hydro or nuclear outages.
The financing model will therefore need to account for multi-day low-hydro conditions, solar curtailment, EPS counterparty strength and potential grid-connection delays. A 12–18-month transmission delay could postpone energy revenues while interest during construction and battery warranty periods continue, potentially reducing a projected 10–12% equity return to high-single-digit levels unless EPC and connection agreements allocate delay risks effectively.
East Mediterranean gas gains a route to European markets
One of the most significant gas developments is emerging from Cyprus, where Eni and TotalEnergies are targeting the 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.
The proposed US$2 billion development would connect Cronos with Egypt’s offshore Zohr infrastructure before sending the gas to the Damietta LNG terminal for export to European buyers. Using existing Egyptian processing and liquefaction infrastructure avoids the cost and delays associated with constructing a new LNG plant in Cyprus.
Most of the production is expected to be directed towards Europe, while around 20% could supply Egypt’s domestic market. The arrangement links Cypriot upstream resources with Egyptian infrastructure and European LNG demand, creating an eastern Mediterranean supply chain without requiring a direct pipeline connection to Greece.
The project also complements the regional Vertical Gas Corridor, through which Greece, Bulgaria, Romania, Hungary, Slovakia, Ukraine, Moldova, Serbia and North Macedonia are seeking to move LNG and Caspian gas northwards. Serbia’s Srbijagas has reserved approximately 300 million cubic metres annually for 10 years at the Alexandroupolis LNG terminal.
The investment case will depend on liquefaction availability, shipping costs, European gas prices and political stability in the eastern Mediterranean. Cronos is relatively small compared with total European gas consumption, but its strategic importance lies in diversifying supply through infrastructure outside the Russian transit system.
Grid resilience gains measurable commercial value
The current regional stress combines several risks that are often modelled separately in energy projects: low hydro inflows, nuclear cooling restrictions, coal-plant deratings, reduced river transport, high cooling demand and volatile solar generation. In reality, these risks are increasingly correlated because they are driven by the same heat and drought conditions.
The market impact is already measurable. Romania and Hungary moved from around €1/MWh at midday to €199.10/MWh during the evening, while Bulgaria’s expanding storage fleet helped contain part of the equivalent price ramp. Interconnection prevented Romania’s generation deficit from developing into a physical supply shortage, but it also transmitted the scarcity premium across neighbouring markets.
The changing price curve is reshaping the hierarchy of investable assets. Unshaped solar faces increasing capture-price erosion. Wind retains greater system value when it generates outside the main solar hours. Batteries benefit from volatility but require sophisticated dispatch strategies and multiple revenue streams. Gas plants and flexible coal capacity retain security-of-supply value but remain exposed to fuel and carbon costs.
Nuclear generation continues to offer low-cost baseload power, but the Cernavodă outage demonstrates that water availability is becoming an increasingly important operational risk for thermal generation, including nuclear.
The Danube has therefore become more than a transport or hydropower resource. It is simultaneously a generation asset, a nuclear cooling source, a constraint on thermal plants and a critical fuel-transport corridor. Its exceptionally low levels are exposing the value of flexibility across Southeast Europe and demonstrating how tightly interconnected the region’s electricity and gas systems have become.
