Serbia is facing renewed pressure on electricity procurement costs ahead of November after another coal-fired generating unit in Romania failed, adding to the prolonged shutdown of the country’s nuclear capacity and reduced hydropower production. The disruption comes as the Serbian electricity system remains heavily dependent on imports, leaving it exposed to tighter regional supply conditions and elevated wholesale prices.
Romania’s 285 MW Turceni 5 coal-fired unit was disconnected from the electricity grid at 08:02 on Tuesday following a boiler failure, according to transmission system operator Transelectrica data reported by Romanian energy publication Economica.net.
The outage comes while both reactors at Romania’s Cernavodă nuclear power plant, representing approximately 1,350 MW of combined capacity, remain offline because exceptionally low Danube water levels have restricted the availability of cooling water.
Romanian authorities have warned that hydrological conditions could prevent either reactor from returning to service during November. Meanwhile, drought and declining reservoir levels continue to constrain domestic hydropower generation, further reducing the electricity available to the regional market.
The simultaneous loss of nuclear and coal-fired capacity is increasing pressure on Southeast Europe’s electricity supply as winter demand approaches. Serbia, Hungary, Bulgaria and Romania are competing for available generation and cross-border transmission capacity, raising the risk of higher procurement costs for import-dependent markets.
For Serbia, the financial exposure is already significant. Preliminary trading estimates suggest the country recorded approximately 515 GWh of net electricity imports during the first 22 days of October, at an estimated average cost of €209/MWh.
That translates into an estimated €107.6 million net import bill in just over three weeks, illustrating how domestic generation shortfalls can rapidly increase electricity expenditure when regional wholesale prices remain high.
Romania’s Turceni outage has further weakened an electricity system already operating with limited flexibility. The coal-fired unit, operated by Complexul Energetic Oltenia, had experienced a similar technical failure earlier in October. Its provisional return-to-service date has been set for November 1, although the actual restart will depend on repair progress and technical readiness.
Following the latest breakdown, Romanian coal-fired power stations were supplying less than 500 MW to the national electricity system, according to the reported Transelectrica operating data. This reduction is particularly significant because the country has already lost a substantial source of dependable generation through the prolonged shutdown of the Cernavodă nuclear reactors.
The two reactors were taken offline in July and August under controlled safety procedures in response to inadequate Danube water conditions. Their continued unavailability has forced Romania to rely more heavily on gas-fired generation, wind power, constrained hydropower output and electricity imports.
The challenge extends beyond the amount of installed capacity available. Nuclear and thermal power plants provide dependable output during periods of high demand, particularly in the evening when solar generation declines and consumption remains elevated. Without nuclear generation, Romania has fewer options for covering these peaks without increasing imports or relying on other dispatchable plants. The loss of another coal unit further narrows those options.
Romania is preparing additional safeguards in anticipation of potentially difficult November operating conditions. The Energy Ministry has proposed extending extraordinary electricity market measures until November 30, citing generation shortages and uncertainty surrounding the restart of the Cernavodă reactors.
The proposed arrangements would allow Transelectrica to intervene if the security of the electricity system were threatened. Existing emergency powers include reducing available export capacity, cancelling scheduled exports and, under more severe circumstances, restricting selected electricity consumption.
These provisions are contingency measures rather than confirmation that electricity exports have already been banned. Under normal market conditions, cross-border electricity flows reflect available transmission capacity, wholesale price differences and scheduled commercial transactions. Emergency interventions can alter these arrangements, potentially reducing the electricity available to neighbouring markets.
Romanian authorities expect evening peak demand to reach approximately 8,500 MW in November, increasing the importance of reliable conventional generation and access to imports. The hydrological situation creates an additional constraint because reduced water reserves limit the ability of hydropower plants to increase output during expensive evening hours without depleting reserves needed later in the winter.
As a result, Romania could remain dependent on imported electricity even during periods of stronger wind generation. The combination of unavailable nuclear capacity, ageing coal assets and restricted hydropower availability is increasing the importance of regional generation and transmission infrastructure.
Serbia enters this period with its own electricity generation and procurement challenges. State-owned utility Elektroprivreda Srbije (EPS) has faced weaker-than-planned production, particularly from coal-fired generation, increasing its exposure to wholesale electricity markets.
Preliminary estimates for October 1–22 indicate that Serbia recorded net electricity imports of approximately 23.4 GWh per day, equivalent to nearly 1 GW of continuous imported power. If that daily rate continued throughout October, total net imports would reach approximately 726 GWh, with expenditure of around €150 million at the same average procurement 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, highlighting the financial consequences of Serbia’s reliance on external supply during periods of weaker domestic generation.
Romania’s difficulties do not necessarily mean Serbia is purchasing electricity directly from Romanian producers. Instead, the impact is transmitted through the interconnected regional electricity market. When Romania requires additional imports, it competes for available electricity in Hungary, Bulgaria and other European markets. This can change regional price spreads and cross-border flows, particularly when transmission constraints limit access to cheaper generation elsewhere.
The eventual impact on Serbia will depend on its hourly net import requirements, domestic generation availability, contractual positions and the prices at which additional electricity can be secured. The degree of exposure will also vary between market participants, depending on their hedging strategies and procurement arrangements.
Regional day-ahead prices remained elevated despite a correction on October 27. Stronger renewable generation forecasts and some improvement in supply conditions contributed to lower prices across much of Southeast Europe.
Serbia’s SEEPEX baseload price fell 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, with Bulgaria’s IBEX reaching €254.58/MWh.
The Romanian premium over Serbia stood at approximately €13.80/MWh, illustrating the continuing price differential between markets facing different supply conditions. These prices were established in the previous day’s auction, before the October 27 Turceni outage, and therefore do not represent a direct market reaction to the latest equipment failure.
Nevertheless, the price structure highlights continued pressure in Romania and Bulgaria relative to Hungary and Serbia. The regional market remains vulnerable to sharp increases when weak wind output, limited hydropower availability and strong evening demand coincide. For Serbia, late-afternoon and evening trading periods are particularly important as solar generation declines and electricity systems become more reliant on conventional generation and imports.
The financial consequences of tighter supply could be substantial if Serbia must continue purchasing large volumes of electricity at exposed market prices. Using the estimated 515 GWh of net imports recorded during October 1–22 as an illustrative benchmark, an increase of €50/MWh in the average procurement price would add approximately €25.8 million to the cost of purchasing the same volume.
This is a sensitivity calculation rather than a forecast of additional expenditure. It demonstrates how relatively modest wholesale price increases can generate significant costs when an electricity system imports hundreds of gigawatt-hours.
Actual exposure will depend on the procurement structure of individual market participants. EPS, independent suppliers, electricity traders and industrial consumers may have different forward contracts, hedging arrangements and spot-market positions. Buyers with substantial fixed-price coverage could face limited immediate increases, while those relying heavily on short-term purchases may be more vulnerable to price volatility.
For energy-intensive industries, sustained increases in electricity costs can weaken operating margins, particularly where supply contracts are linked to wholesale market prices. Steel producers, foundries, cement manufacturers, mining companies and other large industrial consumers may be particularly sensitive, although the impact depends on contractual terms, energy efficiency and production technology.
November is therefore shaping up as a combined electricity adequacy and financial resilience test for Southeast Europe. The central issue is not simply the failure of one Romanian coal unit, but the simultaneous restriction of several generation sources that normally provide flexibility to the interconnected regional system.
Romania’s nuclear shutdown has removed a major source of continuous generation, while drought has reduced hydropower availability. Coal plants are experiencing reliability problems, and seasonal declines in solar output are increasing the importance of dispatchable generation, stored energy and dependable cross-border capacity.
For Serbia, limiting the financial impact will require improving domestic generation availability, coordinating maintenance schedules, securing competitively priced import contracts and managing peak-hour procurement more effectively. Over the longer term, investments in energy storage, grid flexibility and diversified generation could help reduce dependence on expensive imports. However, these measures cannot eliminate the immediate risks associated with the approaching winter.
The most important indicators over the coming weeks will be the restart prospects for Cernavodă, the availability of Romanian coal-fired units, regional hydropower reserves, cross-border transmission capacity and price movements across SEEPEX, OPCOM, HUPX and IBEX.
Romania’s latest generating-unit failure has not yet established a new, verified price shock in Serbia, but it has weakened a neighbouring electricity system already under considerable pressure. With Serbia’s October net import bill estimated at more than €100 million, another prolonged period of tight regional supply could significantly increase the financial burden on the electricity sector.
The decisive question for November is whether Southeast Europe’s remaining dispatchable generation and cross-border networks can meet rising demand without forcing import-dependent markets to secure electricity at increasingly expensive peak-hour prices.
