Serbia faces renewed pressure on electricity procurement costs heading into November after another Romanian coal-fired unit failed. The outage adds to the prolonged shutdown of Romania’s nuclear plant and reduced hydropower output, while the Serbian power system is already heavily reliant on imports. The simultaneous constraints are increasing supply risks across Southeast Europe as winter consumption approaches.
Romanian outages constrain available generation
Romanian transmission operator Transelectrica data, reported by energy publication Economica.net, show that the 285 MW Turceni 5 unit was disconnected from the grid at 08:02 on Tuesday after a boiler failure. Operated by Complexul Energetic Oltenia, the coal unit had experienced a similar technical failure earlier in October. Its provisional return-to-service date is November 1, subject to repairs and technical readiness.
The failure comes as both reactors at Romania’s Cernavodă nuclear power plant remain offline. The reactors have combined capacity of approximately 1,350 MW and were taken out of service in July and August under controlled safety procedures because 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 Romanian hydropower production. After the Turceni outage, Romanian coal-fired stations were injecting less than 500 MW into the national electricity system, according to the reported Transelectrica operating data. With a substantial share of normally available baseload generation unavailable, the system has relied more heavily on gas-fired generation, wind power, reduced hydropower output and imports.
The constraint extends beyond total installed capacity. Thermal and nuclear plants can typically supply electricity during evening demand peaks, when solar generation declines and consumption rises. Without nuclear generation, Romania has fewer options to meet those periods without increasing imports or calling on other dispatchable plants, and the loss of another coal unit further narrows those options.
Romania’s Energy Ministry has proposed extending extraordinary electricity-market safeguards until November 30, citing generation shortages and uncertainty over the Cernavodă reactors’ restart. The measures would allow 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 powers are contingency measures; they do not indicate that electricity exports have already been prohibited. Under 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 limit the scope for hydroelectric plants to raise output during expensive evening hours without reducing reserves needed later in winter. Unavailable nuclear generation, ageing coal assets and constrained hydropower could leave Romania reliant on imports even during temporary improvements in wind production.
Regional prices and cross-border supply
The supply constraints are affecting a region in which Serbia, Hungary, Bulgaria and Romania compete for available generation and cross-border transmission capacity. When Romania needs additional imports, it competes for electricity available in Hungary, Bulgaria and other European markets; Serbia does not necessarily import directly from Romanian producers. The link to Serbia instead runs through the interconnected market, where demand for imports can alter regional price spreads and cross-border flows, particularly when transmission constraints limit access to lower-priced electricity.
Day-ahead electricity prices for delivery on October 27 fell across much of Southeast Europe, with stronger renewable generation forecasts and some easing in regional supply conditions. Serbia’s SEEPEX baseload price dropped by €43.4/MWh to €241.69/MWh, while Hungary’s HUPX price declined to €241.30/MWh. Romania’s OPCOM price was €255.49/MWh and Bulgaria’s IBEX price was €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 capture a direct market response to that failure. The price pattern showed Romania and Bulgaria above Hungary and Serbia, while the regional market remained vulnerable to sharp increases when low wind output, limited hydropower and high evening demand coincide.
For Serbia, the most sensitive trading periods are the late afternoon and evening, when solar output declines and regional systems rely more on conventional generation and imports. The effect of Romania’s supply difficulties on Serbia depends on its actual hourly net import position, contractual arrangements, domestic generation and the prices at which additional electricity can be secured.
Serbia’s imports and procurement costs
State-owned utility Elektroprivreda Srbije (EPS) has faced weaker-than-planned electricity production, particularly from coal-fired generation, increasing its exposure to wholesale markets. Preliminary trading estimates indicate that Serbia recorded approximately 515 GWh of net electricity imports during October’s first 22 days, at an estimated average cost of €209/MWh. That implies a net import bill of approximately €107.6 million in just over three weeks.
For October 1–22, preliminary estimates put net imports at approximately 23.4 GWh per day, equivalent to almost 1 GW of continuous imported power. If that rate continued throughout October, it would imply approximately 726 GWh of net imports and expenditure of about €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 beginning of 2026 has reached approximately €369 million. Serbia’s import requirement has therefore created significant financial exposure during periods of weaker domestic generation. The amount spent also depends on how much electricity is still to be purchased at prices exposed to the market.
Using the estimated October net import volume of 515 GWh as an illustrative benchmark, a €50/MWh increase in the average procurement price would add approximately €25.8 million to the cost of buying the same quantity. This is a sensitivity calculation, not a forecast of actual additional expenditure. It shows how wholesale price movements can have a substantial financial effect when a system imports hundreds of gigawatt-hours.
Exposure varies among market participants. EPS, independent suppliers, industrial consumers and electricity traders may have different forward contracts, hedging arrangements and spot-market positions. Buyers with substantial fixed-price coverage could face limited immediate additional expenditure, while importers reliant on short-term procurement could be more exposed.
Sustained electricity price increases can weaken operating margins for energy-intensive manufacturers, particularly where supply agreements are indexed to wholesale markets. Steel producers, foundries, cement manufacturers, mining companies and other large industrial consumers are particularly sensitive to electricity costs, although their exposure varies according to contracts and production technology.
November adequacy and financing pressures
The regional supply concern involves simultaneous constraints on several sources of generation that normally provide flexibility to an interconnected electricity system. 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 production is declining. These conditions increase the importance of dispatchable generation, stored energy and dependable cross-border capacity.
For Serbia, steps identified to reduce exposure include improving domestic generation availability, coordinating maintenance schedules, securing competitively priced import contracts and managing peak-hour procurement. Longer-term investments in storage, grid flexibility and diversified generation could reduce dependence on expensive imports, but would not remove the immediate risks of the approaching winter.
Key indicators over the coming weeks include the Cernavodă restart prospects, Romanian coal-unit availability, regional hydropower reserves, cross-border capacity allocations and price movements across SEEPEX, OPCOM, HUPX and IBEX. Romania’s latest unit failure has not yet produced a verified new price shock in Serbia, but it has further constrained a neighbouring electricity system already under pressure.
With Serbia’s October net import bill estimated above €100 million, another prolonged period of tight regional supply could increase the financial burden on the electricity sector. The November challenge will be whether Southeast Europe’s remaining dispatchable capacity and cross-border networks can meet rising demand without import-dependent markets having to secure electricity at increasingly expensive peak-hour prices.