Serbia faces renewed pressure on electricity procurement costs heading into November as Romania loses coal-fired capacity while its nuclear reactors remain offline and hydropower output is constrained. These pressures come as the Serbian power system is already heavily reliant on imports. The resulting competition for generation and cross-border capacity is increasing supply risks across Southeast Europe.
Romania loses coal and nuclear generation
Romania’s 285 MW Turceni 5 unit disconnected from the electricity grid at 08:02 on Tuesday after a boiler failure, according to transmission operator Transelectrica data reported by Romanian energy publication Economica.net. The unit is operated by Complexul Energetic Oltenia and had suffered a similar technical failure earlier in October. Its provisional return-to-service date is November 1, subject to repairs and technical readiness.
The outage comes while both reactors at the Cernavodă nuclear power plant, with a combined capacity of approximately 1,350 MW, remain shut. The reactors were taken offline in July and August under controlled safety procedures because exceptionally low Danube water levels restricted cooling-water availability. Romanian authorities have warned that hydrological conditions could prevent either reactor from restarting during November.
Drought and falling reservoir levels have also constrained Romania’s hydropower production. After the Turceni unit’s disconnection, Romanian coal-fired power stations were supplying less than 500 MW to the national electricity system, according to the reported Transelectrica operating data. Romania has therefore lost a significant share of its normally available baseload generation.
The extended nuclear outage has increased reliance on gas-fired generation, wind power, reduced hydroelectric output and imports. Thermal and nuclear plants can generally serve evening demand peaks, when solar output falls as consumption rises, but the loss of nuclear generation leaves Romania with fewer options to meet that demand without imports or other dispatchable plants. The Turceni outage further narrows those options.
Emergency measures could affect regional trade
Romania’s Energy Ministry has proposed extending extraordinary electricity market safeguards until November 30, citing generation shortages and uncertainty about when the Cernavodă reactors can return to service. The proposed measures would allow grid operator Transelectrica to respond if system security is threatened. Existing emergency powers include reducing electricity export capacity, cancelling scheduled exports and, in more severe circumstances, restricting selected electricity consumption.
These are contingency powers, not evidence that Romania has already prohibited electricity exports. In normal market conditions, cross-border flows reflect available transmission capacity, market prices and scheduled commercial transactions. Emergency restrictions could change those conditions and reduce the electricity available to neighbouring systems.
Romanian authorities expect evening peak demand to reach approximately 8,500 MW in November, increasing the importance of reliable conventional generation and imports. Lower water reserves also limit how far hydropower plants can raise output during expensive evening hours without reducing reserves needed later in the winter. The combination of unavailable nuclear generation, ageing coal assets and constrained hydropower could leave Romania reliant on imports even during temporary improvements in wind production.
As winter consumption approaches, Serbia, Hungary, Bulgaria and Romania are increasingly competing for available generation and cross-border transmission capacity. Romania’s generation constraints add to a regional supply risk at a time when the interconnected market must also meet rising demand.
Serbia’s import volumes increase procurement exposure
Serbia faces its own generation and procurement challenges. State-owned utility Elektroprivreda Srbije (EPS) has recorded weaker-than-planned electricity production, particularly from coal-fired generation, increasing its exposure to wholesale markets. Preliminary estimates indicate that Serbia accumulated approximately 515 GWh of net imports during the first 22 days of October, at an estimated average cost of €209/MWh.
The estimated net import bill for that period was €107.6 million in just over three weeks, showing how domestic generation shortfalls can translate into substantial costs when regional wholesale prices are elevated. The preliminary daily average was approximately 23.4 GWh, equivalent to almost 1 GW of continuous imported power. If that pace continued throughout October, it would imply about 726 GWh of net imports and expenditure of approximately €150 million at the same average import price; these figures are extrapolations, not confirmed full-month results.
The estimated cumulative net electricity trade deficit since the start of 2026 has reached approximately €369 million, underscoring Serbia’s reliance on external supply when domestic generation is weaker. Romania’s difficulties do not necessarily mean that Serbia imports electricity directly from Romanian producers. Their financial connection runs through the wider interconnected market.
When Romania needs additional imports, it competes for electricity available in Hungary, Bulgaria and other European markets. This can affect regional price spreads and cross-border flows, particularly when transmission constraints restrict access to lower-priced electricity elsewhere. The impact on Serbia depends on its hourly net import position, contractual arrangements, domestic generation and the prices available for additional electricity.
Day-ahead prices remain high across Southeast Europe
Day-ahead baseload prices for delivery on October 27 fell across much of Southeast Europe, following forecasts of stronger renewable generation and some easing in regional supply conditions. Serbia’s SEEPEX price dropped by €43.4/MWh to €241.69/MWh, while Hungary’s HUPX price declined to €241.30/MWh.
Romania’s OPCOM price remained higher at €255.49/MWh, followed by Bulgaria’s IBEX at €254.58/MWh. Romania’s premium over Serbia was approximately €13.80/MWh. The prices were set in the previous day’s auction, before the Turceni outage on October 27, and therefore do not represent the market’s direct response to that equipment failure.
The price structure nevertheless showed a continuing scarcity premium in Romania and Bulgaria compared with Hungary and Serbia. The regional market remains vulnerable to sharp price increases when low wind output, limited hydropower and high evening demand occur together. For Serbia, late afternoon and evening remain critical trading periods as solar generation declines and power systems rely more heavily on conventional generation and imports.
Higher market prices could increase Serbia’s costs
The financial effect on Serbia depends on how much electricity still needs to be bought at prices exposed to the market. Using October’s estimated 515 GWh net import volume as an illustrative benchmark, a €50/MWh increase in the average procurement price would add approximately €25.8 million to the cost of purchasing the same quantity. This is a sensitivity calculation, not a forecast of additional actual expenditure.
The calculation shows how relatively modest wholesale price movements can have a material cost effect when a system imports hundreds of gigawatt-hours. Exposure varies between market participants: EPS, independent suppliers, industrial consumers and electricity traders may have different forward contracts, hedging arrangements and spot-market positions. A buyer with substantial fixed-price coverage could face limited immediate additional expenditure, while an importer relying on short-term procurement could be more exposed.
For energy-intensive manufacturers, sustained electricity price increases can weaken operating margins, particularly when supply agreements are indexed to wholesale markets. Steel producers, foundries, cement manufacturers, mining companies and other large industrial consumers are especially sensitive to electricity costs, although exposure varies according to contract terms and production technology.
November will test generation availability and cross-border supply
The regional challenge involves more than the failure of one Romanian coal unit: several sources of flexibility in the interconnected electricity system are constrained at the same time. Romania’s nuclear shutdown has removed a major source of continuous generation, drought has reduced hydropower availability, coal plants have faced reliability problems and seasonal solar output is declining. These conditions increase the importance of dispatchable generation, stored energy and dependable cross-border capacity.
For Serbia, possible steps to reduce exposure include improving domestic generation availability, coordinating maintenance schedules, securing competitively priced import contracts and managing peak-hour procurement. Over the longer term, investment in storage, grid flexibility and diversified generation could reduce dependence on expensive imports. Such investment cannot eliminate the immediate risks of the approaching winter.
Indicators to monitor in the coming weeks include the Cernavodă reactors’ restart prospects, Romanian coal-unit availability, regional hydropower reserves, cross-border capacity allocations and the relationship between SEEPEX, OPCOM, HUPX and IBEX prices. Romania’s latest unit failure has not yet produced a verified new price shock in Serbia, but it has weakened a neighbouring electricity system already under stress. With Serbia’s October net import bill estimated above €100 million, a prolonged period of tight regional supply could increase the financial burden on the electricity sector.
The key issue for November will be whether Southeast Europe’s remaining dispatchable capacity and cross-border networks can meet rising demand without forcing import-dependent markets to buy electricity at increasingly expensive peak-hour prices.