Hungary’s HUPX baseload price increased by €5.60/MWh to €208.98/MWh, almost matching Romania, where the price settled at €208.46/MWh. Croatia and Slovenia followed closely at €206.74/MWh and €206.58/MWh, respectively.

Bulgaria recorded the strongest increase among the larger coupled markets, with its baseload price rising €12.20/MWh to €200.66/MWh.

The gains came despite slightly cooler weather across Hungary and most of Southeast Europe. Regional electricity demand was forecast to rise by 184 MW to an average 31,668 MW, with Romania and Bulgaria accounting for most of the increase through a combined rise of 449 MW.

Renewable generation prospects weakened. Forecast regional wind output fell by 700 MW to 1,246 MW, more than offsetting a smaller 108 MW decline in solar generation to 5,779 MW. The sharp drop in wind availability increased reliance on thermal generation and imports during periods of stronger demand.

Regional net imports declined by 180 MW to 1,370 MW. Flows from Austria and Slovakia towards Hungary and Slovenia fell by 292 MW to 1,449 MW, limiting access to relatively cheaper electricity from core European markets.

At the same time, Southeast Europe remained a net exporter to Italy, with flows of around 635 MW, up by 50 MW from the previous day. Italy’s price declined sharply but remained the highest among the monitored markets at €216.25/MWh, maintaining an incentive for exports towards the west.

Hungary’s premium over Germany widened to €13.75/MWh, up by €2.20/MWh, while its premium over Greece increased to €26.56/MWh. Germany settled at €195.23/MWh, while Greece eased to €182.42/MWh.

The persistent Hungarian premium points to constrained access to western supply and a tighter Central and Southeast European market balance. Austria traded almost in line with Hungary at €209.03/MWh, suggesting that the price pressure was affecting the wider regional import corridor rather than being confined to HUPX.

Fuel markets added further bullish pressure. Austrian CEGH gas rose by €2.40/MWh to €83.17/MWh, while Greek gas prices increased to €63/MWh. EU carbon allowances edged higher to €85.82/t, adding to the short-run generation costs of gas- and coal-fired power plants.

Forward electricity prices also remained elevated. Hungary’s October baseload contract increased by €4.50/MWh to €198/MWh, while the calendar contract rose by €4 to €154.50/MWh. October and fourth-quarter gas contracts climbed to €83.50/MWh.

Near-term Hungarian contracts moved in the opposite direction. Week 38 fell by €7.50/MWh to €183/MWh, while week 39 declined by €6/MWh to €186.50/MWh. The divergence suggests that the market expects some short-term easing, while continuing to price significant fuel and winter supply risks into October and longer-dated contracts.

Serbia was the main regional outlier. SEEPEX fell by €10.20/MWh to €164.14/MWh, leaving the Serbian market at a discount of €44.84/MWh to Hungary and more than €42/MWh below Croatia.

The unusually wide Serbian discount indicates that local supply conditions and cross-border transmission constraints prevented cheaper Serbian electricity from fully converging with the higher-priced coupled markets to the north and west. Serbia’s average net import position stood at around 650 MW, but imports did not eliminate the substantial price gap.

Prices across the southern Balkans also increased, although they remained below the Hungarian hub. Montenegro rose by €30.70/MWh to €185.33/MWh, while North Macedonia recorded a sharp €46.50/MWh increase to €179.88/MWh. Albania climbed to €197.58/MWh, narrowing its discount to Hungary to €11.40/MWh.

The combination of expensive gas, weaker wind generation and reduced imports from core Europe is leaving Southeast European power markets increasingly vulnerable to sharp daily price movements.

Serbia’s deep discount, however, highlights that transmission availability and local generation conditions remain as important as fuel fundamentals. Electricity was sufficiently abundant to push SEEPEX lower, but not sufficiently transferable across borders to ease prices in markets trading above €200/MWh.

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Both reactors have been offline since Aug. 13. Unit 1 had already stopped in July before unit 2 was subsequently shut down.

Persistently low Danube levels are restricting the cooling conditions required for a restart.

Coal and gas generation and cross-border imports have so far compensated for part of the missing nuclear output, supported by continued nuclear generation in Hungary and Bulgaria.

Expected stronger wind generation could provide additional near-term support, with the Energy Ministry expecting peak imports to remain below 2 GW.

The more difficult test would come if the nuclear outage extends further towards winter.

Romanian summer peak consumption typically reaches around 7.5-8 GW, while winter requirements are substantially higher. Demand reached 9.235 GW on Jan. 19, 2026.

The Energy Ministry plans to reassess the situation after Sept. 15.

Cernavoda’s return has therefore become an increasingly important variable for Romanian and regional winter power balances. Every additional week without nuclear generation leaves more of the country’s requirement dependent on thermal fuel costs, renewable weather conditions and available cross-border capacity. 

The post Romania faces prolonged nuclear outage as low Danube delays Cernavoda restart appeared first on Serbia SEE Energy Mining News.

The battery operates with the existing 92 MW solar plant in Brasov county, giving the site combined installed capacity of 162 MW.

Unlike batteries restricted to charging directly from their associated renewable plant, the Parau system can also charge from the electricity network.

That allows Econergy to buy electricity during low or negative-price periods and sell it when wholesale prices rise, exposing the battery directly to merchant arbitrage opportunities.

Total investment in the combined project reached around €85 million.

Econergy is planning further storage additions across Romania. Its domestic battery pipeline totals 521 MW and more than 1 GWh, including proposed capacity at Ratesti, Oradea and Ovidiu.

The company also has around 13 GW of projects under development across eight European markets, with storage representing roughly half of the overall pipeline.

For Romania, the project illustrates how developers are beginning to use existing grid connections more efficiently. Adding batteries to operational solar sites can increase the commercial value of the connection while allowing generators to shift output away from increasingly crowded midday hours. 

The post Econergy starts 70 MW battery at Romanian solar project appeared first on Serbia SEE Energy Mining News.

The plant generated approximately 442,000 MWh during the three months, operating at an average load of around 200 MW and producing close to 4,800 MWh per day.

EPCG valued the output at more than €51 million. Buying the same volume on Hungary’s HUPX exchange at prevailing prices would have cost about €57.4 million, according to the company.

Pljevlja’s continuous operation was supported by lignite from the nearby mine, which EPCG operates as part of an integrated mining and generation complex.

The thermal plant’s role became more important as dry conditions reduced output from Montenegro’s hydroelectric fleet, normally a dominant part of the country’s generation mix.

The summer performance illustrates the short-term security-of-supply dilemma facing Montenegro as it increases renewable capacity but remains highly exposed to hydrological volatility.

When reservoir conditions deteriorate, Pljevlja still provides a domestic baseload alternative to potentially expensive electricity imports. 

The post Montenegro: Pljevlja supplied 65% of EPCG summer generation as drought hit hydro appeared first on Serbia SEE Energy Mining News.

The intervention was completed in early August at a cost of around €55,000.

Around 300-400 cubic metres of sediment were removed from a 50-metre section of the plant’s bay, lowering the riverbed by approximately 50-100 centimetres.

It was the first dredging operation of its kind during the plant’s more than 110-year history.

Kelenfoldi depends on the bay for cooling and raw water and also provides district energy services. During summer, it supplies hot water to almost 41,000 households and around 1,800 public institutions, while winter operations include district heating.

Conditions deteriorated further in September. The Budapest Danube gauge fell to just 1 centimetre above its reference zero on Sept. 8, the lowest recorded level, although actual river depth through the city remained around 3-3.5 metres on average.

The previous record of 28 centimetres was set only at the end of July.

Rainfall in the upper Danube catchment could provide some relief, but the episode shows how prolonged drought is increasingly affecting not only hydropower output and river transport but also the cooling-water security of thermal plants. 

The post Hungary: Record-low Danube forces emergency dredging at Budapest power plant appeared first on Serbia SEE Energy Mining News.

Deliveries under the arrangement rose from 664,438 MWh in 2023 to 3.34 million MWh in 2024 and 4.38 million MWh in 2025.

Those volumes represented around 2.5%, 12% and 15.8% of Bulgarian annual gas consumption in the respective years. Their share of total imports was considerably smaller, however, at below 1% in 2023, below 4% in 2024 and 5.4% in 2025.

Bulgargaz said BOTAS opposed publication of the financial data despite a Sofia Administrative Court ruling requiring disclosure of both volumes and payments on public-interest grounds.

Previous estimates cited in the report put reserved-capacity costs at around €500,000 per day, potentially rising to €550,000 in 2026 and €600,000 in 2027.

Rumen Radev later said Bulgaria owed BOTAS around $360 million, with arrears accumulating from July 2024.

The contract, signed by a caretaker government in 2023, has also become the subject of a prosecutor’s investigation. Bulgaria and BOTAS agreed in July to suspend implementation for 15 months while terms are renegotiated.

Disclosure of the physical volumes answers part of the debate surrounding the agreement. The larger question – the total cost of securing Turkish terminal and network access relative to the gas actually used – remains unresolved. 

The post Bulgaria: Bulgargaz discloses BOTAS LNG volumes but contract costs remain hidden appeared first on Serbia SEE Energy Mining News.

The latest proposal would convert around €11 million of short-term loans into permanent capital. Shareholders are expected to consider the measure at an extraordinary meeting alongside amendments to the company’s founding documents.

The move follows a €7 million capital injection completed at the end of February. Earlier increases included around €2 million in 2020, €21 million in 2022 and €11 million in 2023.

The funding is intended to support implementation of the Bistrica hydropower construction contract with China’s AVIC.

The overall investment is now valued at around €170 million excluding VAT, significantly above earlier construction estimates of roughly €102 million. Previous financing plans envisaged about €75 million from China’s Export-Import Bank, with ERS providing the remainder.

The repeated capital increases underline the financial demands of bringing the project through construction after years of ownership and development changes. ERS sold HE Bistrica to Kaldera in 2008 for around €3.5 million, before buying it back in 2019 for almost €11 million. 

The post Bosnia and Herzegovina: ERS subsidiary plans another capital increase for Bistrica hydropower project appeared first on Serbia SEE Energy Mining News.

The Dutch TTF October contract traded at €78.77/MWh on Sept. 9, up 3.9% from the previous close and its highest since the second half of December 2022.

Commercial vessel traffic through Hormuz has slowed sharply, with an average of just 10 vessels per day crossing the strait over the previous 10 days, according to data cited in the report, the lowest rate since May.

The rise in gas prices followed a further escalation involving Iran and the United States, increasing concern that disruption to one of the world’s most important energy shipping routes could tighten international LNG availability.

The timing is particularly sensitive for Europe. Utilities are trying to rebuild inventories ahead of the winter heating season, creating additional demand for available cargoes.

Any prolonged reduction in shipping through Hormuz would therefore compete directly with Europe’s seasonal storage requirements and could keep LNG and European hub prices elevated even before heating demand begins to rise materially.

For European power markets, the implications extend beyond gas itself. At current gas prices, gas-fired generation becomes substantially more expensive, increasing the potential for sharp electricity price movements during periods when renewable supply is weak. 

The post Europe: Gas prices hit highest level since 2022 as Hormuz risks grow appeared first on Serbia SEE Energy Mining News.

Hungary’s HUPX base price climbed €42.7/MWh to €203.34/MWh, while Romania reached €202.46, Slovenia €201.43 and Croatia €201.38/MWh. Serbia recorded the strongest daily increase among the main regional markets, with SEEPEX jumping €65.1 to €174.39/MWh.

Bulgaria rose to €188.50/MWh and Greece to €183.60/MWh, while the southern Balkan markets diverged, with Montenegro falling to €154.67/MWh and North Macedonia to €133.35/MWh.

The regional rally came despite slightly weaker demand. Combined Hungary and Southeast European consumption was forecast at around 31.59 GW, about 227 MW below the previous day.

The bigger change was on the supply side. Regional generation fell to around 29.61 GW, widening the shortfall against consumption and pushing total net imports toward 1.98 GW, around 700 MW higher day on day.

Imports from the Central European core increased to around 1.99 GW, while the Hungary-Germany day-ahead spread narrowed to about €11.5/MWh from €17.5/MWh.

Hungary turns sharply more import dependent

Hungary provided the clearest example of tightening fundamentals.

Consumption was broadly unchanged at around 4.75 GW, but domestic generation fell to roughly 3.37 GW from 4.14 GW. Hungary’s net import requirement consequently more than doubled to around 1.38 GW from 631 MW.

That deterioration in the Hungarian power balance helped pull prices higher across interconnected Central and Southeast European markets.

HUPX remained one of the region’s most important price references, particularly for Serbia, Croatia, Slovenia and Romania.

The hourly profile showed that the pressure was concentrated around the evening ramp.

HUPX reached a maximum of about €425.7/MWh in hour 20, compared with a daily minimum of €124.8/MWh. Germany reached roughly €460.9/MWh, while Croatia and Austria also recorded maximum hourly prices above €400/MWh.

The pattern reflects the growing impact of solar generation on regional price formation. Solar output helps suppress prices during the middle of the day, but the rapid decline in photovoltaic production toward sunset leaves the system more dependent on thermal generation, imports and flexible capacity.

Serbia records €65/MWh daily jump

Serbia showed one of the clearest examples of this volatility.

SEEPEX rose to €174.39/MWh from €109.3/MWh, an increase of roughly 60% in a single day.

The maximum hourly Serbian price reached €350/MWh, while off-peak electricity averaged about €188.2/MWh, higher than the nominal peak average of around €160.5/MWh.

The physical balance, however, changed comparatively little.

Serbian consumption stood at around 3.55 GW, generation at approximately 3.04 GW, and average imports at about 516 MW, only slightly above the previous day.

The price increase therefore appears to have reflected regional scarcity and cross-border price transmission rather than a sudden increase in Serbian demand.

Serbia nevertheless retained a substantial discount to Hungary of almost €29/MWh.

That spread shows that Southeast European markets remain only partially converged. Local generation structures, available interconnector capacity and congestion continue to create significant differences between neighbouring exchanges.

Romania remains structurally tight

Romania remained another tight point in the regional system.

Consumption was around 5.66 GW, compared with generation of about 5.19 GW, leaving the country dependent on approximately 472 MW of net imports.

The absence of nuclear generation remained particularly important. With Cernavoda unavailable, Romania has become more reliant on gas, coal, hydro, wind and cross-border electricity.

Romania imported heavily from Bulgaria while also receiving substantial electricity through Hungary during peak hours.

The combination helped push OPCOM to €202.46/MWh, almost level with Hungary.

Bulgaria remained a major regional exporter, with average net exports of around 1.47 GW, although that was lower than roughly 1.77 GW the previous day.

Its large nuclear fleet continued to provide an important anchor for regional supply.

Montenegro and North Macedonia buck rally

Southern markets moved in the opposite direction.

Montenegro’s BELEN base price fell to €154.67/MWh, down about €16.6/MWh, as the country’s supply balance improved.

Montenegrin generation recovered to around 253 MW from 117 MW, while average imports narrowed to roughly 147 MW from 296 MW.

North Macedonia recorded an even sharper divergence.

Its day-ahead price dropped to €133.35/MWh, around €70/MWh below Hungary, while generation increased to approximately 697 MW from 449 MW.

The country shifted to an average export position of around 285 MW, compared with only 73 MW a day earlier.

The result was a highly fragmented regional market, with base prices ranging from approximately €133/MWh in North Macedonia to above €203/MWh in Hungary, while Italy remained higher still.

Gas adds another layer of pressure

Electricity markets are also facing a much more expensive fuel environment.

Austrian CEGH gas rose to around €80.80/MWh, while European gas markets have been trading at their highest levels since late 2022.

Hungarian Week 38 power increased to about €190.50/MWh, while the October contract rose to around €193.50/MWh.

October and fourth-quarter gas forwards were around €81/MWh and €80.50/MWh, respectively, while EU carbon allowances remained close to €85.6/t.

High gas and carbon prices increase the marginal cost of flexible thermal generation precisely when the region needs it most — during evening hours when solar output falls.

For traders, Sept. 10 therefore illustrates a market increasingly shaped not simply by total daily supply and demand, but by when flexible megawatts are available.

The widening gap between solar-heavy daytime periods and the evening ramp is increasing the value of batteries, hydro flexibility, demand response and hourly hedging. In such a market, a daily baseload price is becoming an increasingly incomplete measure of commercial exposure.

The post SEE power prices jump as Hungary tightens, Serbia posts sharpest rise appeared first on Serbia SEE Energy Mining News.

Serbia’s SEEPEX baseload price dropped by €69/MWh, or almost 39%, to €109.33/MWh, the lowest among the monitored markets. Hungary fell €15.90 to €160.65/MWh, while Romania declined to €162.70, Croatia to €162.74 and Slovenia to €167.29. Bulgaria settled at €153.31/MWh and Greece at €140.54/MWh. 

The southern Balkan markets also weakened, with Albania dropping €32.10 to €150.20/MWh, Montenegro falling €21.10 to €171.27 and North Macedonia easing to €153.63. Serbia consequently traded at a €51.32/MWh discount to HUPX, while Montenegro retained a €10.62/MWh premium over Hungary. Italy was about €64/MWh above HUPX, preserving a strong westward price gradient. 

The most striking feature was not only Serbia’s lower daily average but the shape of its hourly curve. SEEPEX fell to just €5/MWh around hour 11 before climbing to €246/MWh in the evening. Serbia’s peak-period average of €102.10/MWh was below its €116.50/MWh off-peak average, an increasingly important inversion as daytime renewable output compresses conventional peak pricing. 

Similar price compression was visible elsewhere. Greece’s peak average was €89.40/MWh compared with €191.60/MWh off peak, while Hungary recorded €123.80/MWh for peak hours against €197.50/MWh off peak. The regional forecast showed solar generation rising to around 7.52 GW, up about 1.67 GW from the previous day, while wind was broadly unchanged at 2.09 GW. 

The price decline came without a material fall in overall demand. Combined Hungary and Southeast European consumption was forecast at 31.62 GW, effectively unchanged from the previous day. Net regional imports, however, fell to around 479 MW from 970 MW, while inflows from the Austria-Slovakia core declined to 1.59 GW from 1.96 GW. 

Serbia’s unusually deep discount developed even though the country remained a net importer. Average Serbian consumption rose marginally to 3.55 GW, while generation increased to 3.01 GW from 2.81 GW, cutting the net import requirement to about 540 MW from 730 MW a day earlier. The combination of higher domestic availability and accessible imports appears to have loosened the Serbian balance sufficiently to produce a much deeper spot correction than in neighbouring markets. 

The Serbian market nevertheless remained connected to substantial surrounding flows, importing on a baseload basis from Bulgaria, North Macedonia and Romania while exporting toward Montenegro and, during some periods, Hungary. The resulting price discount despite net imports points to short-term congestion, bidding patterns and hourly supply conditions rather than a simple regional surplus.

Bulgaria remained one of the strongest supply centres, with average exports of about 1.72 GW against domestic consumption of 3.88 GW and generation of 5.60 GW. At the wider regional level, roughly 1.48 GW continued to flow toward Italy, where substantially higher prices maintained the economic incentive for westbound exports. 

The spot correction was not matched by a broad decline in the forward complex. Hungarian week-38 power slipped €1 to €180/MWh, but week 39 rose €4.50 to €192.50/MWh. October power eased to €187/MWh, while the calendar contract increased to €146.50/MWh. Austrian CEGH gas rose €2.30 to €77.38/MWh and EU carbon allowances gained €0.70 to €85.42 a tonne. 

Wednesday’s trading therefore points more to short-term spot fragmentation than a broad bearish repricing of Southeast European power. Serbia has moved to an exceptional discount, while the Italian premium remains intact and the Hungarian forward curve continues to price substantially higher power later in September.

For traders, the widening gap between low midday prices and expensive evening hours is becoming as important as the traditional country-to-country spread. The €5-to-€246/MWh Serbian intraday range, combined with Italy near €225/MWh, highlights a market increasingly driven by hourly renewable availability, cross-border capacity and the ability to shift electricity between periods and bidding zones.

The post Serbia power price plunges to €109/MWh as SEE markets diverge from Italy appeared first on Serbia SEE Energy Mining News.

Domestic consumption increased 7.77% to 28.04 TWh, while the power trade balance showed a surplus of 2.60 TWh, compared with 1.93 TWh in the same period last year, data from Bulgaria’s Electricity System Operator showed.

The increase in available generation was particularly strong in hydropower.

Hydroelectric output jumped to 3.60 TWh from 2.01 TWh, a rise of almost 80%.

Renewable electricity connected to the transmission network increased 23% to 3.57 TWh, while renewable generation in distribution networks rose 8.4% to 3.19 TWh.

The wider power surplus strengthens Bulgaria’s potential role as an exporter into neighbouring markets during periods when domestic generation exceeds demand.

That is relevant for Southeast European price formation because Bulgaria sits between Romania, Serbia, North Macedonia, Greece and Turkey and can influence flows across several important regional corridors.

The hydro recovery is particularly important.

Hydropower can respond more rapidly to changing system conditions than baseload generation and therefore provides both electricity and flexibility during peak-price periods. Stronger hydro availability can also reduce dependence on thermal generation when solar and wind production weaken.

The Bulgarian data come after drought and low Danube levels created concerns over hydro and nuclear availability across parts of Southeast Europe during the summer.

The improvement does not remove those structural risks, and generation conditions can change rapidly with hydrology and nuclear availability.

But the 2.60 TWh year-to-date surplus gives Bulgaria a materially stronger position than a year earlier.

For regional traders, the key question is increasingly not simply whether Bulgaria has excess generation, but during which hours that surplus reaches neighbouring markets.

As solar penetration rises across Bulgaria and Greece, daytime export availability may increase while evening scarcity remains comparatively more valuable — reinforcing the importance of storage, hydro flexibility and cross-border capacity allocation.

The post Hydro rebound widens Bulgaria’s electricity surplus appeared first on Serbia SEE Energy Mining News.

Enercon will provide seven 7-MW turbines, its largest onshore machine currently available, with 175-metre rotor diameters mounted on 112-metre steel towers.

Installation is scheduled to begin in July 2027, with the first turbine expected to be commissioned by the end of August. Enercon will also provide long-term servicing.

Cobadin is planned as two 50-MW phases, taking the overall complex to 100 MW.

Cobadin I secured a Romanian Contract for Difference in January 2025, while Qair subsequently obtained a separate CfD for the second phase.

The agreement is the first Romanian wind project jointly developed by Enercon and Qair and gives the German manufacturer an entry point for its latest high-capacity onshore turbine platform into a market entering a new wind-investment cycle supported by CfD-backed projects. 

The post Enercon to supply 7-MW turbines for Qair’s Romanian wind project appeared first on Serbia SEE Energy Mining News.

Trading volume reached 199,699 MWh, up 58.1% from about 126,292 MWh in August 2025 and 32.8% from July.

Market operator MEMO reported an average clearing price of €136.87/MWh, up 29.3% month on month.

Average daily trading volume was around 6,442 MWh, while the reported average peak price was €110.50/MWh.

The increase continues the development of the North Macedonian organised electricity market, which began operations in May 2023, with higher participation in exchange-based procurement strengthening the role of transparent short-term price formation in the country’s power sector. 

The post North Macedonia power-exchange volumes jump 58% year on year in August appeared first on Serbia SEE Energy Mining News.

The average HUPX day-ahead baseload price reached €152.17/MWh, up 24.4% from €122.35/MWh in July.

The reported average peak price rose 37.6% to €123.17/MWh.

Day-ahead traded volume reached 2.92 TWh, an increase of 15.5% from 2.52 TWh in July and 13.6% from 2.57 TWh in August 2025.

Intraday continuous-market turnover reached almost 1.31 TWh, up 0.9% month on month.

HUPX had 133 registered day-ahead members in August, three more than in July, and 130 intraday continuous-market members.

The combination of higher turnover and sharply higher baseload prices highlights the tightening that affected the Hungarian market during August, while continued growth in participation and traded volumes reinforces HUPX’s role as a core price reference for Southeast European power trading. 

The post Hungary: HUPX August power price rises 24% as day-ahead volumes increase appeared first on Serbia SEE Energy Mining News.

The existing Paks plant consists of four Soviet-era units with combined capacity of about 2 GW, whose shutdowns are expected to begin between 2032 and 2037.

Paks II is designed to replace and expand that capacity with two VVER-1200 reactors totalling 2.4 GW.

An internal Rosatom construction timetable cited in the report places provisional acceptance of unit 6 on Dec. 30, 2034. Because commercial operation would follow that milestone, completion could move into 2035.

That would be later than earlier Hungarian government indications that the reactors could be completed in 2031-2032.

The project has already missed earlier milestones. First concrete for unit 5, originally expected in March 2025, was poured in February 2026. First concrete for unit 6 is scheduled for September 2026.

Rosatom has said construction is proceeding according to the timetable agreed with Hungary but has not publicly given a firm commissioning date. Foundation work on unit 5 was reported to be about 80% complete and expected to finish by year-end.

Further delays would increase the risk of a period in which Hungary’s existing reactors begin retiring before Paks II is fully operational, raising longer-term questions over replacement capacity, imports and security of supply. 

The post Hungary’s Paks II nuclear project could slip to 2035 appeared first on Serbia SEE Energy Mining News.

The review focuses on several hours between Aug. 17 and Aug. 23, when solar production unexpectedly fell around midday despite conditions when output would normally have been close to its daily peak.

Market participants have suggested that some generators may have voluntarily curtailed production to avoid selling electricity at negative prices.

Regulator RAAEY is examining whether the reduction resulted from technical or system conditions or reflected deliberate operating decisions by generators.

It has requested detailed operational data from transmission system operator ADMIE to assess the cause of the output decline and determine whether the cuts affected wholesale price formation or balancing costs.

Negative pricing creates an incentive for unsubsidised or market-exposed renewable generators to reduce output rather than pay to inject electricity into the system. The investigation could therefore become an important test of how increasingly frequent surplus-renewable periods are treated under Greek market rules.

If deliberate curtailment is established, regulators will need to determine whether the behaviour represented legitimate commercial optimisation or affected market-price formation in a way that raises compliance concerns. 

The post Greek regulator examines solar output cuts during negative-price hours appeared first on Serbia SEE Energy Mining News.

Prime Minister Kyriakos Mitsotakis presented the programme at the Thessaloniki International Fair.

Funding is expected to include about €2.3 billion from the Islands Decarbonisation Fund, €600 million through the EU fiscal escape clause and additional resources from the Social Climate Fund.

Storage is a central part of the strategy. Greece is targeting 3-4 GW of batteries by 2028 and 5-7 GW by 2030. Around €400 million has already been allocated through the Recovery and Resilience Facility, with another €200 million planned from the Social Climate Fund.

The additional funding will be divided among small businesses, municipalities, large renewable projects and standalone storage.

The programme comes as Greek solar capacity has reached 13.8 GW, already above the country’s 2030 target cited in the report, increasing pressure on the system to absorb surplus midday generation.

Around €1.1 billion is planned for island interconnections and €970 million for renewable-plus-storage projects comprising about 316 MW of solar and 295 MW of batteries. A further €200 million is earmarked for dams and dual-purpose reservoirs and €56 million for electric-vehicle charging.

Energy-efficiency measures are expected to receive about €2.1 billion, including support for residential renovation, 32,000 heat pumps and 68,000 solar water heaters.

The government also plans to simplify self-consumption rules, including collective schemes for apartment buildings, micro-solar systems of up to 800 watts and standalone batteries that do not inject electricity into the grid. 

The post Greece plans €5 billion energy package targeting 30% power-price reduction appeared first on Serbia SEE Energy Mining News.

From Sept. 8, petrol will remain capped at €1.67/litre and diesel at €1.79/litre. Without government intervention, official calculations indicated prices would have risen to €1.73 and €1.93 respectively.

The government cut petrol excise duty by another €0.025/litre and diesel excise by €0.09/litre, while supplier margins for both fuels were reduced by a further €0.02/litre.

The diesel excise rate is now seven cents below the EU minimum normally permitted, following temporary approval from the European Commission.

Other products will rise. Blue diesel will increase to €1.34/litre, LPG to €1.33/kg and bottled LPG to €1.90/kg.

The government estimated that without any intervention petrol would cost about €1.88/litre and diesel around €2.10/litre, underscoring the growing fiscal and regulatory role of price controls as international fuel costs rise. 

The post Croatia extends petrol and diesel price caps as wholesale costs rise appeared first on Serbia SEE Energy Mining News.

A total of 3.03 TWh was traded on the Independent Bulgarian Energy Exchange’s day-ahead segment, up 3% month on month and 20.6% year on year. Average daily volume reached about 97,586 MWh.

The average baseload price climbed 28% from July to €143.15/MWh, compared with €111.74/MWh a month earlier. The reported average peak price was €111.15/MWh, up 44%.

IBEX had 155 registered day-ahead participants, unchanged from July.

Activity also increased on the intraday continuous market, where traded volume reached 1.12 TWh, up 25%, while the weighted average price rose 41.8% to €141.35/MWh.

The data point to a stronger August trading environment in Bulgaria, with rising liquidity accompanied by a substantial repricing of short-term electricity. 

The post Bulgarian day-ahead trading rises as August power prices jump appeared first on Serbia SEE Energy Mining News.

State-owned utility ERS launched a €95 million tender in late August for the project near Berkovici, almost 11 years after obtaining the concession. The planned wind farm is expected to produce about 160 GWh a year.

The procurement is structured under an EPC+F model, requiring the selected contractor to provide engineering, equipment, construction and financing. Bidders must also demonstrate experience delivering at least one wind farm of 30 MW or more, worth at least €25 million excluding VAT, during the previous five years, as well as experience with substations and transmission lines.

ERS received a formal complaint about the procedure only 12 days after launching the tender and confirmed that the appeal process had begun. The procurement cannot proceed on its original timetable until the objection is resolved.

The setback comes just as ERS had taken one of its most concrete steps towards moving Hrgud from prolonged development into construction. 

The post Bosnia and Herzegovina: Hrgud wind project faces fresh delay after tender appeal appeared first on Serbia SEE Energy Mining News.

The proposal, COM(2026) 464, would create a framework for mutual recognition of renewable certificates issued in qualifying Energy Community markets including Serbia, Montenegro, Albania, North Macedonia and Bosnia and Herzegovina.

If adopted and followed by country-level approval, renewable generators in those markets could gain broader access to the EU certificate market.

That would improve the economics of corporate power purchase agreements and create an additional revenue stream for wind, solar and hydro producers.

But the change would not mean that an EU-recognised Guarantee of Origin, or GO, is sufficient to prove low-carbon electricity under the Carbon Border Adjustment Mechanism.

That distinction is likely to become increasingly important for utilities, renewable developers and industrial exporters across the Western Balkans.

A GO demonstrates the renewable origin of a corresponding quantity of electricity.

CBAM requires a more demanding chain of evidence where actual electricity emissions are claimed.

That can include the identity of the generating installation, physical contractual arrangements, metering and generation records, hourly allocation, transmission-system documentation and, for electricity imported directly into the EU, evidence linking generation to nominated cross-border capacity.

The practical effect is that GO recognition would strengthen one layer of a CBAM evidence package without replacing the others.

For a Serbian wind or solar producer, an EU-recognised certificate could make the renewable attribute of its electricity easier to sell and more credible to European corporate buyers.

For a Serbian industrial company exporting CBAM-covered goods into the EU, however, buying green certificates alone would not automatically justify the use of actual low-carbon electricity values.

The electricity supply would still need to satisfy the relevant CBAM methodology.

That creates the possibility of a two-tier market for renewable electricity.

The first tier would consist of ordinary green electricity backed by recognised GOs.

A second, higher-value product could combine the certificate with a named generating installation, physical PPA, meter and SCADA data, hourly matching, controlled allocation and a verifier-ready evidence package.

Such a product could effectively become CBAM-ready renewable electricity.

The distinction may become increasingly valuable as European importers ask suppliers outside the EU to provide more granular carbon evidence.

Industrial exporters in Serbia, Montenegro and Bosnia are already beginning to examine how electricity procurement affects the embedded emissions reported for EU-bound products.

For those companies, the main issue is not simply whether electricity is renewable.

It is whether the claim can survive independent verification.

That could give state utilities such as EPS, EPCG, ERS and EPBiH an opportunity to develop premium electricity products for industrial customers.

Instead of supplying only standard power or green electricity backed by certificates, utilities could offer installation-specific renewable supply supported by metering, contractual and allocation records.

Independent renewable suppliers may also benefit.

A supplier sourcing power from a specific wind or solar installation can potentially create a simpler evidence chain than a large utility allocating renewable electricity from a mixed generation portfolio.

That could make private suppliers more competitive in serving exporters that want traceable electricity rather than a generic renewable claim.

The proposal could also change how generators value their certificates.

Selling a GO separately into the EU market may generate immediate certificate revenue.

But bundling that GO with the physical electricity and a complete CBAM evidence package may prove more valuable for industrial customers facing carbon-verification requirements.

That creates a trade-off between short-term GO monetisation and premium bundled electricity sales.

The regulatory proposal does not automatically grant EU recognition to every Energy Community certificate system.

Each country would still need to meet requirements covering registry integrity, issuing bodies, electronic transfer and cancellation, fraud prevention and avoidance of double counting before being accepted.

That means Serbian, Montenegrin or Bosnian certificates should not yet be treated as automatically equivalent to EU-issued GOs.

The more important shift is that the legal route towards recognition is being created.

For the Western Balkans, that could eventually align two previously separate markets: renewable attribute trading and CBAM-compliant electricity evidence.

The commercial hierarchy would then become increasingly clear.

A standard MWh would carry only its electricity value.

A green MWh would add a recognised renewable certificate.

A CBAM-ready MWh would add physical delivery, hourly traceability, controlled allocation and independent verification.

The Commission proposal strengthens the second category.

Its larger impact may be that it makes the third category commercially viable at scale.

For Western Balkan renewable producers and industrial exporters, the next competitive advantage may therefore be less about simply owning renewable generation and more about being able to prove, MWh by MWh, where the electricity came from, who consumed it and whether the entire evidence chain can withstand EU verification.

The post EU green-certificate proposal could reshape CBAM electricity market in Western Balkans appeared first on Serbia SEE Energy Mining News.

The Montenegro Just Energy Transition, or M-JET, project is being prepared with the World Bank and focuses on replacing part of the energy services currently tied to the Pljevlja coal complex.

Measures include a sustainable heating system, expansion of district-heating infrastructure, cleaner household heating and energy-efficiency investment.

The project is significant because Pljevlja is not only Montenegro’s main coal-fired generation centre.

The thermal plant and associated mine are also major local employers and economic anchors.

Any reduction in coal dependence therefore requires replacement infrastructure as well as generation investment.

Heating is one of the most immediate issues.

Coal and other polluting fuels remain deeply embedded in the local energy system.

A modern district-heating network could reduce household emissions while decoupling part of the city’s heating demand from direct fossil-fuel use.

That makes the project more consequential than another general decarbonisation strategy.

It begins to address the physical systems that must exist before coal can be reduced without creating a local energy-security problem.

The investment also comes as Montenegro expands wind and solar generation.

Projects such as Gvozd and Gvozd 2 are increasing non-hydro renewable output, while a much larger pipeline of solar and wind projects is under development.

But replacing coal generation is not only a question of annual renewable electricity volumes.

Pljevlja provides firm generation, employment and local economic activity.

A credible transition therefore needs flexible electricity supply, grid investment, alternative employment and replacement heat.

The M-JET programme addresses only part of that equation, but it tackles one of the most tangible local dependencies.

The World Bank’s involvement may also help Montenegro structure the project around broader just-transition requirements rather than treating heating infrastructure as an isolated municipal investment.

That could become important as the country moves closer to EU membership and greater exposure to European climate policy.

Montenegro’s coal sector will face increasing pressure from carbon costs, environmental rules and regional electricity-market integration.

At the same time, closing or reducing Pljevlja too quickly would increase reliance on imports during weak-hydro periods.

The transition therefore has to be sequenced.

New renewable generation and flexibility must arrive before coal capacity can be reduced without undermining security of supply.

Local infrastructure must also be built before communities can absorb the economic and social effects.

The proposed €50 million package is small compared with the total cost of transforming Montenegro’s electricity system.

Its importance lies elsewhere.

It starts converting the concept of a just transition into specific replacement infrastructure in the country’s most coal-dependent municipality.

The post Montenegro plans €50 million World Bank-backed transition project for Pljevlja appeared first on Serbia SEE Energy Mining News.

Nuclearelectrica technical director Emil Macovei said Danube conditions remained insufficient to support the restart of even one unit.

Unit 1 has been offline since July 28 and Unit 2 since Aug. 13.

Earlier expectations had focused on a reassessment around Sept. 10.

The latest hydrological outlook pushes a meaningful nuclear recovery beyond mid-September.

That matters because Cernavodă normally supplies a large block of Romania’s low-marginal-cost baseload generation.

Its absence has materially changed the country’s power balance.

Romania has relied more heavily on coal, gas, hydro, renewables and cross-border imports since the reactors went offline.

The effect is strongest during evening hours after solar production declines.

Recent day-ahead markets have repeatedly shown prices above €250/MWh during the evening peak across Romania and neighbouring markets.

The prolonged outage increases that exposure.

It also puts more pressure on Hungary and Bulgaria, which are among Romania’s main potential import sources.

This means Cernavodă availability has become a regional rather than purely domestic trading factor.

The extended shutdown comes after low Danube levels affected nuclear generation elsewhere in the region.

Hungary’s Paks plant and Bulgaria’s Kozloduy also faced hydrological restrictions during August.

Kozloduy has since restored part of the lost output, but Romania remains the most severe case.

The situation highlights a growing climate-risk problem for large thermal and nuclear plants that depend on river water for cooling.

Nuclear generation is normally treated as firm supply.

But prolonged drought can reduce that firmness precisely when hydro output may also be weak.

That creates correlated hydrological risk across several technologies.

Romania has already been forced to consider emergency measures, including water-management interventions and temporary support for thermal generation.

The longer the nuclear outage continues, the more important those measures become.

The impact also extends into forward power prices.

Traders will price in uncertainty over restart timing, hydrology and the availability of flexible thermal generation.

Even a partial restart would materially improve Romania’s position.

But until there is enough water to operate safely, the system remains exposed.

The key risk is not only the lost 1.3-1.4 GW of nuclear capacity.

It is the fact that the missing generation is concentrated in the part of the supply stack that normally provides stable, low-cost power around the clock.

That leaves Romania unusually dependent on imports and expensive flexibility during evening scarcity hours.

The post Romania pushes Cernavodă restart beyond mid-September as Danube drought persists appeared first on Serbia SEE Energy Mining News.

The proposal, submitted on Sept. 7, would allow renewable certificates issued under compatible Energy Community systems to be recognised across EU member states.

That could give Western Balkan generators access to a much larger market for renewable attributes and strengthen the economics of corporate power-purchase agreements.

Guarantees of Origin, or GOs, certify the renewable origin of electricity and are widely used by companies seeking to document renewable-power consumption.

The change could therefore give regional generators an additional revenue stream beyond wholesale electricity sales.

Montenegro issued around 1.35 million Guarantees of Origin in 2024, while Serbia already operates a domestic GO registry.

The commercial value of such certificates has so far been limited by differences in recognition between national systems and the EU market.

Mutual recognition could reduce that fragmentation.

For renewable developers, the effect would be most visible in project financing and corporate PPAs.

A project selling electricity to an industrial buyer can potentially monetise both the physical power and the associated renewable certificate.

That creates a more valuable bundled product, particularly for exporters seeking to document lower-carbon electricity use.

The proposal could also make Western Balkan projects more attractive to multinational companies with EU-wide renewable-energy procurement targets.

But GO recognition should not be confused with automatic acceptance of renewable electricity under the EU Carbon Border Adjustment Mechanism.

CBAM electricity claims require a broader evidence chain covering physical delivery, contractual arrangements, metering and other verification requirements.

A GO demonstrates renewable origin but does not by itself prove the physical electricity pathway required for every carbon-accounting purpose.

That distinction will become increasingly important as companies in Serbia, Montenegro and other Energy Community markets try to combine renewable procurement with EU carbon-compliance strategies.

The proposal nevertheless represents a potentially material improvement in the commercial position of Western Balkan renewable generators.

It also brings the region closer to integration with the EU electricity market at a time when project economics are becoming more dependent on revenue stacking.

Wholesale prices alone are increasingly volatile because solar-heavy systems can produce very low midday prices and expensive evening power.

The ability to sell renewable attributes separately can partially offset that pressure.

If approved, the measure would therefore add another financial layer to regional wind, solar and hydro projects and could make cross-border corporate PPAs more bankable.

The next question for developers will be whether mutual recognition translates into sufficient certificate demand and liquidity to create a durable price premium for Western Balkan renewable generation.

The post EU moves to open green-certificate market to Western Balkan renewable producer appeared first on Serbia SEE Energy Mining News.

July’s average baseload price was €120.14/MWh.

Day-ahead trading volume reached 1.188 million MWh, around 1.1% below August 2025 but slightly above July. The average hourly traded volume was 1,597.4 MWh.

The higher price pushed the value of day-ahead transactions to €179.6 million, up from €143.3 million in July and €97.1 million a year earlier.

Romania’s intraday market showed an even sharper price increase. Around 120,528 MWh changed hands during August at an average €141.04/MWh, up 37.5% month on month and more than double the level recorded a year earlier. Intraday volumes fell 13.1% from July and 26.4% year on year.

The source also gives a 31.41% day-ahead share of forecast net consumption but labels that figure as August 2025 rather than 2026. 

The post Romanian day-ahead power price jumps 26% in August appeared first on Serbia SEE Energy Mining News.

Two battery containers have entered operation and a third is scheduled to be commissioned in the coming months.

Once completed, the installation will provide around 3 MW of power and 6 MWh of storage capacity. OKTA estimates the system could store about 2,100 MWh of electricity over a year.

The battery will allow solar production to be shifted from periods of high generation into hours with stronger demand or more favourable market prices, giving the plant greater control over its wholesale-market exposure.

For OKTA, traditionally associated with petroleum supply and conventional energy infrastructure, the project also represents a broader move into renewable generation and flexibility assets. 

The post OKTA adds 3 MW battery to North Macedonia solar plant appeared first on Serbia SEE Energy Mining News.

Karavasta, in southwestern Albania, began producing electricity in December 2023. Half of its annual output is sold to distribution operator OSHEE under a 15-year power purchase agreement, while the balance is contracted to private buyers under long-term arrangements.

The structure gives Voltalia a combination of contracted state-backed demand and private-market exposure, reducing the plant’s dependence on short-term wholesale prices.

Voltalia is also developing the 100 MW Spitalle solar project, where construction was announced in 2024. The project received a 30-year generation licence in late 2025, extending the company’s position in a market where utility-scale solar is becoming an increasingly significant part of Albania’s generation mix.

The post Albania: Voltalia’s Karavasta solar output holds steady at 132 GWh in first half appeared first on Serbia SEE Energy Mining News.

Hungary’s HUPX baseload price was broadly stable at €176.58/MWh, with Romania following closely at €176.65/MWh. Serbia declined by €12.2/MWh to €178.33/MWh, while Montenegro recorded a sharp €51.4/MWh increase to €192.33/MWh. Albania rose by €14.1/MWh to €182.25/MWh. Greece and Bulgaria remained considerably cheaper, averaging €145.93/MWh and €157.98/MWh, respectively. Italy continued to command the strongest premium in the region at €224.46/MWh, creating a €78.53/MWh spread between Greece and Italy and leaving Italy €47.88/MWh above Hungary.

The widening geographic price spread emerged despite relatively balanced regional fundamentals. Electricity demand across SEE and Hungary was forecast at 31.47 GW, approximately 827 MW higher day on day, while solar generation was expected to increase by more than 2 GW to 7.98 GW. Wind generation remained broadly stable at 2.33 GW. The region was still a net importer of around 1.26 GW, with inflows from Austria and Slovakia increasing to 2.19 GW, while approximately 1.45 GW continued to flow toward Italy.

This market configuration underlines the growing importance of cross-border transmission constraints. Strong solar availability was enough to significantly depress prices during the middle of the day, but it failed to eliminate the premium associated with westbound transmission capacity toward Italy or the local premiums emerging in parts of the Western Balkans.

Hungary provides a clear example of the growing intraday volatility. HUPX prices dropped to just €25/MWh in hour 13 before surging to €297.1/MWh in hour 20. As a result, the baseload average of €176.58/MWh masked an intraday price swing of more than €270/MWh.

Comparable solar-driven price troughs were visible across several other markets. Greece reached €0/MWh, while Bulgaria fell to €20.2/MWh, before both markets climbed above €260/MWh during the evening ramp. Croatia followed a similar pattern, falling to €28.1/MWh before rising as high as €304.5/MWh.

The Western Balkans displayed a markedly different price profile. Serbia’s minimum price remained at €96/MWh, with a maximum of €284.1/MWh, while Montenegro did not fall below €150/MWh and reached €270/MWh. The solar-driven midday discount therefore remained much less pronounced in Serbia and Montenegro than in Greece, Bulgaria and several Central European markets.

Serbia was nevertheless among the clearest bearish movers of the day. Its net import requirement narrowed to approximately 458 MW, from 578 MW a day earlier, as average generation increased to 3.07 GW from 2.91 GW. Generation growth outpaced the rise in demand, which reached 3.53 GW from 3.49 GW. Serbia continued to receive electricity from several neighboring markets while maintaining exports toward Montenegro, reducing its premium over HUPX to just €1.75/MWh.

Montenegro moved in the opposite direction. BELEN’s €192.33/MWh settlement placed the market €15.75/MWh above Hungary. Montenegro remained a net importer of approximately 105 MW, even as average flows toward Italy reached roughly 503 MW. Imports from Bosnia and Herzegovina and Serbia therefore effectively supported both domestic demand and continued exports through the Adriatic corridor. This combination helps explain why Montenegro maintained a substantial local premium despite significantly lower prices in other SEE markets.

Forward electricity prices also strengthened. Hungarian Week 38 power increased by €6.5/MWh to €181/MWh, while Week 39 gained €5/MWh to €188/MWh. October power rose by €3.5/MWh to €188/MWh. CEGH gas prices climbed to €75.06/MWh, while EU carbon allowances increased to €84.74/tonne. Coal prices edged lower.

The latest market signals increasingly point to hourly and geographic exposure rather than regional baseload averages as the key factor shaping power-market risk. Hungary, Romania, Croatia, Slovenia and Serbia all clustered around €176-179/MWh on a baseload basis, but these averages concealed midday prices near zero or in the €20-30/MWh range in several markets, followed by evening prices approaching or exceeding €300/MWh.

With Italy continuing to draw roughly 1.45 GW from the region while more than 2.1 GW enters SEE and Hungary from the Central European core, transmission capacity, energy storage and flexible generation are becoming increasingly valuable. The September 8 price curve once again demonstrates why a flat baseload hedge is becoming a weaker proxy for the actual physical exposure faced by generators, traders and large industrial consumers across Southeast Europe.

The post Southeast Europe power prices diverge as solar output reshapes September 8 market appeared first on Serbia SEE Energy Mining News.

GEN energija’s supervisory board appointed former minister Andrej Vizjak as chief executive for a four-year term, while Jure Soklič was named to lead GEN-I.

Vizjak said GEN would continue work on the proposed JEK2/Krško 2 nuclear plant and the Mokrice hydropower project, signalling continuity in the group’s main generation strategy despite the leadership change.

The appointments matter because GEN energija sits at the centre of Slovenia’s long-term electricity investment programme.

A second reactor at Krško would be one of the largest energy infrastructure investments undertaken in Southeast Europe and could reshape Slovenia’s generation balance, financing requirements and regional trading position for decades.

The project remains at the development and decision-making stage, leaving major questions over technology, capacity, cost, ownership and financing.

Changes in senior management therefore attract particular attention as the company approaches decisions that could lock in billions of euros of capital expenditure.

GEN also faces the task of managing the existing Krško nuclear plant while expanding renewable and flexible generation.

The country’s electricity system combines nuclear, hydro, thermal generation and increasingly solar power, but recent weak hydrology has demonstrated the value of maintaining diversified firm supply.

Slovenian generation fell sharply during parts of 2026 as hydro output weakened.

That increased dependence on imports and gas-fired generation, reinforcing the strategic case for additional reliable domestic capacity.

JEK2 is intended to address that longer-term requirement, but its scale creates substantial financial risk.

Large European nuclear projects have faced construction delays and cost overruns, increasing scrutiny of contracting structures and the allocation of risk between utilities, governments, suppliers and consumers.

Any Slovenian project would also have to be assessed against alternative combinations of renewables, storage, interconnection and flexible generation.

The leadership changes at GEN energija and GEN-I are therefore more than a personnel issue.

GEN-I is one of the region’s major electricity traders and suppliers, while GEN energija controls strategic generation assets.

Their relationship gives the wider group exposure across production, wholesale trading and retail markets.

Vizjak has also identified the group’s circular ownership relationship as an issue requiring attention, adding a governance dimension to the management transition.

For investors and counterparties, continuity on Krško 2 reduces immediate uncertainty about strategic direction.

It does not remove the larger questions surrounding project economics.

The next phase will require Slovenia to move from broad support for additional nuclear generation towards decisions on technology, capital structure, risk allocation and the price consumers would ultimately pay for the electricity.

The post Slovenia reshuffles GEN leadership as Krško 2 investment decisions approach appeared first on Serbia SEE Energy Mining News.

Dutch front-month TTF rose to around €74.4/MWh, reflecting concerns over LNG supply and European storage availability.

Bulgaria’s regulated gas price is therefore almost €33/MWh lower, providing a potentially significant cost advantage for industrial consumers and gas-fired generation compared with buyers more directly exposed to hub-linked supply.

The difference reflects Bulgaria’s diversified supply portfolio, including contracted Azerbaijani gas, rather than insulation from the wider European market.

The size of the discount could narrow if European prices remain elevated and more expensive market-indexed gas enters Bulgaria’s supply mix.

But for September, the gap is substantial.

It matters most for energy-intensive industries where natural gas represents a large proportion of marginal production costs.

Fertiliser, chemicals, glass, ceramics and other industrial sectors can see competitiveness shift quickly when gas-price differentials reach several tens of euros per megawatt-hour.

The regional consequences extend beyond Bulgaria.

Southeast Europe’s gas system has become more interconnected since the European supply crisis, with Greece emerging as an increasingly important LNG entry point and Bulgaria serving as a transit route for northbound flows.

LNG arriving through Greek terminals can move towards Bulgaria and other markets through expanded interconnection infrastructure.

That makes global LNG conditions increasingly relevant to the entire SEE price structure.

Any prolonged disruption to international LNG supply would therefore affect more than Greece’s domestic market.

It could tighten gas availability through the north-south corridor at the same time European buyers begin increasing winter demand.

Gas prices also feed directly into regional electricity economics.

Gas-fired plants frequently provide flexible generation during hours when solar and wind output are insufficient.

When TTF rises sharply, the short-run marginal cost of those plants increases, potentially pushing evening power prices higher.

That link is particularly important in Southeast Europe, where recent electricity markets have shown pronounced differences between cheap solar-heavy midday hours and expensive evening periods.

A higher gas price raises the cost of covering that evening gap.

Bulgaria’s lower regulated gas price could therefore provide some protection to domestic generation and industry if the wider European market remains elevated.

But the position should not be interpreted as permanent structural insulation.

Contract mix, Azerbaijani volumes, seasonal demand and European hub prices will continue to influence Bulgarian costs in subsequent months.

The widening September differential instead highlights a broader regional trend.

As Southeast Europe diversifies its gas routes, the next source of competitive advantage is increasingly not simply access to gas but the price and contractual structure of that supply.

The post European gas surge widens Bulgaria’s price advantage as SEE autumn risks rise appeared first on Serbia SEE Energy Mining News.

The programme covers solar systems for self-consumption, heat pumps and battery energy storage.

Standard households can receive support for up to 50% of eligible costs, with grants reaching €17,850, while households classified as being at risk of energy poverty can receive up to 70%, capped at €24,990.

The addition of batteries is the most important change from an electricity-market perspective.

Croatia has expanded rooftop solar rapidly, reducing household grid demand during daylight hours.

But solar production falls before the evening consumption peak, leaving the system increasingly exposed to demand after sunset.

Croatia recorded a summer electricity-demand peak of 3,400.5 MWh at 21:00 in August, exceeding both its previous summer record and the latest winter maximum.

That timing strengthens the case for behind-the-meter batteries capable of shifting solar electricity from the afternoon into evening consumption.

Without storage, additional rooftop photovoltaic systems can deepen midday supply surpluses while doing relatively little to reduce the system’s highest post-sunset demand.

Household batteries can change that profile.

Consumers can store excess solar output rather than export it during low-value hours and then draw on the battery when electricity demand and wholesale prices are higher.

At sufficient scale, that could also reduce distribution-grid stress and limit evening imports.

The impact will initially depend on participation.

A €38 million programme is relatively small compared with the investment required for system-wide storage deployment, and economics will vary according to battery prices, household load profiles and future electricity tariffs.

But subsidy design can influence a market before storage reaches large absolute volumes.

Including batteries alongside solar signals that Croatian energy policy is beginning to focus on the timing of renewable generation rather than simply increasing installed capacity.

That shift is visible elsewhere across Southeast Europe.

Rapid solar expansion has pushed prices towards zero or occasionally negative levels during high-output hours in several regional markets, while evening electricity can rise above €200/MWh.

The widening intraday spread increases the value of technologies capable of shifting electricity between those periods.

Croatia can use reservoir hydropower and imports for system-level flexibility, but household batteries add flexibility closer to consumption.

They may become particularly relevant on distribution networks with high concentrations of rooftop photovoltaic systems.

The new programme therefore marks a small but important transition in Croatia’s renewable policy.

The question is moving from how many additional solar panels households can install to how much of their daytime electricity can be retained for the evening peak.

The post Croatia opens €38 million household energy scheme with battery support appeared first on Serbia SEE Energy Mining News.

The project on the Krnovo plateau is expected to generate around 63 GWh a year once commissioned, adding new domestic wind output to a system whose import requirements can rise sharply during weak hydrological periods.

Gvozd 2 is being developed with turbine manufacturer Nordex and follows the first phase of the Gvozd wind complex.

Once the extension is completed, total capacity at the site is expected to reach 75.6 MW, with annual generation of more than 200 GWh.

The expansion is backed by European Bank for Reconstruction and Development financing.

The latest foundation milestone is important because Montenegro’s renewable project pipeline is considerably larger than the volume that has so far reached physical construction.

Solar, wind and storage projects have multiplied, but grid access, permitting, financing and construction remain the points at which development risk is increasingly concentrated.

Gvozd 2 has moved beyond those earlier development stages.

Its additional output will also diversify EPCG’s portfolio, which remains heavily dependent on hydropower.

That dependence gives Montenegro a relatively low-carbon electricity system in favourable hydrological years but leaves earnings and import requirements exposed to rainfall and reservoir levels.

Wind provides a different production profile and can reduce that exposure, although it introduces its own variability.

The value of Gvozd 2 will therefore depend not only on annual generation but on when that electricity is available.

Wind can be particularly useful when output coincides with periods of weak solar production or high regional prices.

Montenegro also has significant hydro flexibility, allowing reservoirs to complement variable wind production more effectively than in systems dominated by inflexible generation.

That creates potential portfolio value beyond the individual project’s output.

The expansion comes as EPCG develops a much wider renewable investment pipeline, including solar projects and additional wind capacity.

Montenegro is also increasingly connected to regional trading conditions through its domestic network and the subsea electricity interconnector with Italy.

Every additional unit of competitively priced domestic generation therefore has both security-of-supply and trading implications.

Gvozd 2 remains modest relative to the multi-hundred-megawatt renewable projects proposed elsewhere in Southeast Europe.

But its significance is different.

At 21 MW, the project represents capacity that is actually moving through construction rather than remaining in the development pipeline.

For Montenegro’s electricity balance, completing those projects is becoming more important than announcing new ones.

The post EPCG advances €26 million Gvozd 2 wind expansion in Montenegro appeared first on Serbia SEE Energy Mining News.

The programme, approved with the European Commission and European Investment Bank, allocates about €1.1 billion to electricity interconnections and related infrastructure across the Dodecanese, Cyclades and North Aegean.

A further €977 million is earmarked for renewable-energy projects combined with storage, while €200 million will support multipurpose dams and reservoirs and €56 million will fund electric-vehicle charging infrastructure.

The scale of the grid component makes the programme more significant than a conventional renewable-support package.

Many Greek islands have historically relied on isolated electricity systems supplied largely by expensive oil-fired generation. Connecting them to the mainland network allows cheaper generation to reach the islands while creating new outlets for local wind and solar production.

It can also reduce the need to maintain thermal generation solely for security of supply.

The investment programme therefore addresses two of the main constraints on Greek island decarbonisation: insufficient transmission capacity and the inability of small isolated systems to absorb large volumes of intermittent renewable generation.

Storage will become increasingly important as more solar and wind capacity is connected.

Batteries and other flexible assets can absorb surplus production during high-renewable periods and release electricity when generation falls, reducing curtailment and limiting dependence on fossil backup.

The strategy also strengthens Greece’s broader role in Southeast Europe’s electricity transition.

The country is rapidly expanding solar and wind generation while investing in domestic transmission and cross-border links. Island interconnections extend that process into systems that have traditionally operated at the edge of the continental market.

Projects across the Cyclades have already demonstrated how interconnection can reduce reliance on local oil generation. Extending the model towards the Dodecanese and North Aegean would bring a larger share of island demand into the interconnected market.

For renewable developers, the programme could open areas where generation potential has previously been constrained by weak networks.

But the value of future projects will depend increasingly on the combination of generation, storage and connection capacity rather than installed renewable megawatts alone.

The programme also includes investment in water infrastructure, creating potential links between energy management, water supply and climate resilience on islands where both electricity and water demand rise sharply during the tourism season.

Available funding is currently estimated at around €2 billion, with the final amount partly dependent on the value of EU carbon allowances.

That introduces some funding-price exposure but does not change the programme’s strategic direction.

Greece is moving from subsidising isolated renewable assets towards financing the infrastructure needed to operate a much more integrated island power system.

The €2.3 billion programme puts transmission and storage at the centre of that shift.

The post Greece secures €2.3 billion for island grids, renewables and storage appeared first on Serbia SEE Energy Mining News.

SEEPEX jumped €130.4/MWh day on day to €190.54/MWh, placing Serbia €14.17/MWh above Hungary, almost €29/MWh above Bulgaria and more than €48/MWh above Greece and Montenegro. HUPX, OPCOM and CROPEX formed a relatively tight central cluster at €176.38/MWh, €175.71/MWh and €176.84/MWh, respectively, while Slovenia settled slightly higher at €179.82/MWh. 

The southern markets remained considerably softer. Bulgaria cleared at €161.65/MWh, North Macedonia at €158.31/MWh, Albania at €168.12/MWh, Greece at €142.34/MWh and Montenegro at only €140.95/MWh. Italy remained the regional high at €218.93/MWh, maintaining a strong westward price pull. 

The Monday rebound was primarily associated with the return of weekday load. Combined Hungary-SEE consumption rose about 3.1 GW from Sunday to 30.77 GW, while regional generation recovered to roughly 30.20 GW. Despite higher demand, the aggregate net-import requirement fell to only 568 MW, compared with 1.26 GW a day earlier. 

The important signal for traders was therefore not regional scarcity but where the available generation was located and whether cross-border capacity could move it toward the higher-priced zones.

Serbia remained the clearest deficit market. Average consumption increased to 3,518 MW, while generation reached only 2,913 MW, leaving the system around 605 MW net short. Domestic generation rose by just 84 MW from Sunday while demand increased by almost 290 MW, materially widening Serbia’s dependence on imports. 

Bulgaria was one of the main suppliers. Bulgarian flows towards Serbia averaged about 336 MW, increasing to 393 MW during peak hours, while Romania supplied Serbia by about 114 MW on average and 321 MW during peak hours. 

The Serbia-Hungary route was more significant for the price formation signal. Recorded commercial flows were zero throughout all 24 hours on Sept. 7, after substantial two-way trading on preceding days. 

That separation helps explain why SEEPEX detached sharply from HUPX despite Hungary itself trading at a relatively elevated €176.38/MWh.

Romania, by contrast, sat almost exactly on the Hungarian price at €175.71/MWh, only €0.67/MWh below HUPX, indicating strong price coupling despite large changes in hourly Romanian-Hungarian flows. Bulgaria retained a €14.73/MWh discount to Hungary, reflecting a much stronger domestic balance and substantial export availability. 

At the southern end of the curve, Montenegro remained anomalously cheap. BELEN settled €35.43/MWh below HUPX even though Montenegro itself was around 68 MW net short. The country imported from surrounding Balkan systems while simultaneously sending an average 539 MW towards Italy, where day-ahead prices were nearly €78/MWh higher. The pattern underlines Montenegro’s role as both a domestic deficit system and a transit corridor feeding the Italian premium market.

Cross-border signal

The broader Hungary-SEE region imported around 1.63 GW from Austria and Slovakia, but approximately 1.43 GW was simultaneously moving toward Italy. Regional balance therefore remained heavily shaped by transit rather than simple aggregate shortage. 

The resulting market structure was clear:

Serbia represented the scarcity premium, Hungary-Romania-Croatia-Slovenia formed the central price cluster, Bulgaria and North Macedonia provided the intermediate discount, while Greece and Montenegro remained the low-price southern zone.

Italy continued to provide the strongest external pull at €218.93/MWh.

Next-session signal

The immediate risk is that SEEPEX retains a premium if Serbia’s import requirement stays around current levels while Hungarian access remains constrained. Even moderate additional Serbian demand could therefore translate quickly into higher SEEPEX spreads rather than being absorbed through regional convergence.

Conversely, Bulgaria’s substantial export position provides downward pressure on the eastern SEE complex and limits the likelihood that the Serbian premium automatically spreads into Romania and Bulgaria.

Renewable conditions do not point to a major near-term supply boost. Regional solar was forecast broadly flat around 6.14 GW, while wind was expected to decline by roughly 233 MW. 

The trading focus for the next session should therefore remain on Serbian import availability, Bulgaria-to-Serbia and Romania-to-Serbia flows, restoration of Serbia-Hungary commercial exchange, and the strength of the Italian premium.

For now, the main market signal is one of congestion-driven fragmentation rather than region-wide generation scarcity: adequate power exists across SEE, but transmission availability is determining which markets can access it and at what price.

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The contract was awarded by EPC contractor Ansaldo Nucleare.

ABB will install a centralised automation platform incorporating cybersecurity features, replacing ageing equipment and strengthening the systems required for continued operation of the reactor.

Cernavoda Unit 1 entered commercial service in 1996 and is one of two CANDU-6 reactors operating at the site. Unit 2 entered service in 2007 and already uses ABB technology.

The two units normally provide approximately 18-20% of Romania’s electricity, making Cernavoda one of the country’s principal sources of baseload generation.

The control-system upgrade is one component of the larger Unit 1 refurbishment programme, which is designed to allow the reactor to operate substantially beyond its original design life.

Preserving nuclear generation is particularly important as Romania adds more variable renewable capacity. Wind and solar can expand the country’s low-carbon generation base, while Cernavoda provides a relatively stable block of output that is less exposed to weather variability.

Extending Unit 1’s life would therefore allow Romania to retain a substantial volume of existing low-emission generation rather than having to replace the capacity in the near term. 

The post Romania: ABB selected for Cernavoda Unit 1 control-system overhaul appeared first on Serbia SEE Energy Mining News.

The Galati county project was developed by the Romanian business of OX2 for Nala Renewables, whose shareholders include commodities trader Trafigura.

Green Breeze was connected to the grid and energised in May 2026.

The project uses 16 Vestas V162-6.2 MW turbines and is expected to generate approximately 312 GWh annually, equivalent to the electricity consumption of about 51,000 households.

Estimated avoided carbon emissions are around 150,000 tonnes of CO2 per year.

Construction began in mid-November 2024, bringing the project from the start of works to near-commercial operation in less than two years.

Under Romanian regulations, generation facilities must secure permanent grid connection, complete testing and receive a conformity certificate from the relevant network operator before qualifying for a commercial operating licence.

Those technical stages have been completed at Green Breeze. Once the licence is issued, market registration will be the remaining step before electricity sales can begin.

The project adds another large-scale wind asset to a Romanian market where renewable development is increasingly being accompanied by investment in batteries and other flexibility resources. 

The post Romania’s 99.2-MW Green Breeze wind farm approaches commercial operation appeared first on Serbia SEE Energy Mining News.

The Calan project, located in Hunedoara county, is designed to provide four hours of storage at full output and is scheduled for commissioning in January 2029.

It joins an 80 MW/160 MWh battery under development at Selimbar in Sibiu county and a 5 MW/10 MWh installation at Baleni in Galati county.

The Baleni battery will operate alongside Engie’s existing 50 MW wind farm, creating what the group describes as its first hybrid wind-and-storage project in Europe.

Engie’s Romanian programme forms part of a larger battery expansion across Europe.

During July and August, the company progressed battery acquisitions, construction and commissioning activities in Romania, Poland, Belgium, Portugal, the Netherlands and Britain representing approximately 1.1 GW of power capacity and 3.3 GWh of storage.

The company is expanding storage as growing wind and solar output increases the need to absorb surplus electricity, shift production into higher-value demand periods and provide balancing services.

The programme also supports Engie’s global target of reaching 95 GW of combined renewable and storage capacity by 2030. 

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The government opted to expand MEMO’s mandate rather than establish a separate gas-market institution.

The decision comes as North Macedonia develops two strategically important pipeline connections. The interconnector with Greece is expected to enter operation around mid-2027, while the connection with Serbia is planned for completion by the end of 2028.

Together, the projects could broaden access to alternative suppliers, including LNG entering Southeast Europe, while creating additional cross-border trading opportunities.

MEMO will be required to prepare an implementation plan addressing staffing, technical systems, IT infrastructure, legislation and financing.

Authorities considered different European market structures, ranging from more fully liberalised models in Austria and Hungary to hybrid arrangements in Greece, Croatia, Bulgaria and Romania.

Using MEMO was judged faster and less costly because the operator already has settlement systems, trading infrastructure and an established IT platform.

North Macedonia has had a legal basis for organised gas trading since its 2018 Energy Law, but institutional development has lagged behind electricity-market reform.

Establishing the operator is expected to improve price formation, competition and balancing while bringing the domestic market closer to EU and Energy Community rules. 

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Day-ahead turnover accounted for 1.041 TWh, while the intraday market handled another 471,421 MWh.

The average day-ahead baseload price rose to €151.63/MWh, an increase of 27.5% month on month.

Average euro-peak prices reached €124.38/MWh, up 43%, while the average intraday price increased 29.7% to €153.96/MWh.

Average daily day-ahead volume stood at approximately 33,571 MWh.

The increase in both turnover and prices shows that Croatia entered the late-summer period with stronger wholesale market activity even as the broader Southeast European region experienced increasingly volatile hourly price formation.

The growth of intraday trading is also becoming more relevant as Croatia adds variable renewable generation, increasing the requirement for market participants to rebalance portfolios closer to physical delivery.

CROPEX operates both day-ahead and intraday markets and is integrated with neighbouring European markets through Croatia’s cross-border market coupling arrangements. 

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Electricity imports cost approximately €322 million last year, more than twice the previous year’s amount. Exports were still higher at around €444 million, leaving the country a net exporter in value terms, but the gap has narrowed substantially.

The deterioration extends across the generation fleet. National thermal generation fell 7% in 2025, while hydropower output declined 8%.

Fuel availability is becoming an additional constraint. Brown coal production has fallen 29.6%, while lignite production declined 19.4%, adding pressure to an ageing thermal fleet already facing operational problems at mines and generating units.

More recent Federation of Bosnia and Herzegovina data show little improvement. Net electricity generation fell 6.3% year on year to 462 GWh in July 2026, while thermal output declined to 273 GWh from 300 GWh.

The weakening supply balance has also increased pressure on retail electricity prices. Households supplied by EPBiH saw tariffs increase 10% from August 2024, followed by another average increase of 6.85% in September 2025.

Unless generation recovers, Bosnia could become increasingly dependent on imports at the same time utilities need substantial capital to maintain mines, refurbish ageing generating assets and replace capacity.

That shift would represent a structural change for a market that historically relied on domestic coal and hydro generation to maintain a substantial regional export position. 

The post Bosnia power import bill doubles as coal and hydro output weaken appeared first on Serbia SEE Energy Mining News.

Brussels is instead relying on flexibility contained in the existing storage framework as governments prepare for the 2026/27 winter.

While the EU’s general filling objective is 90%, member states have been told that inventories of around 80% could be sufficient for the coming winter under current market and supply conditions.

Commission spokesperson Anna-Kaisa Itkonen said existing rules and security-of-supply measures were considered adequate following discussions within the EU Gas Coordination Group.

The legislation also allows the Commission to reduce the filling objective by another 5 percentage points through a delegated act if market or supply conditions warrant it.

Authorities will continue monitoring national storage positions, with the Gas Coordination Group expected to review the situation again during September.

The lower inventory buffer nevertheless leaves Europe more exposed to a major supply disruption than in recent years. A prolonged interruption to Middle Eastern gas or LNG flows could tighten balances rapidly and amplify winter price volatility.

For now, however, the Commission sees no immediate need to add further market measures, indicating that policymakers remain prepared to tolerate lower storage levels rather than force additional injections at any cost. 

The post EU holds off additional gas measures despite lower storage levels appeared first on Serbia SEE Energy Mining News.

Serbia’s Transportgas and North Macedonia’s Nomagas signed a memorandum of understanding in Thessaloniki during the 10th Energy Forum for Southeastern Europe.

Their participation expands the group of transmission operators involved in the corridor to Greece, Bulgaria, Romania, Hungary, Slovakia, Ukraine, Moldova, Serbia and North Macedonia.

The initiative is intended to improve access to alternative gas sources and reduce dependence on a limited number of transport routes. Serbia and North Macedonia’s entry could also provide additional options for moving gas between Balkan markets and Central and Eastern Europe.

The next phase is expected to concentrate on coordination between transmission system operators, including identifying bottlenecks, improving use of existing pipelines and assessing infrastructure that could increase cross-border capacity.

Bidirectional operation will be a particular focus, allowing gas to move in different directions as market conditions and security-of-supply requirements change.

The project goes beyond physical infrastructure. Operators are also expected to align technical, regulatory and commercial arrangements to make capacity along the corridor easier for suppliers and traders to use.

For Serbia and North Macedonia, participation strengthens their position within the emerging north-south gas architecture connecting southern supply entry points with markets further north. 

The post Serbia, North Macedonia join Vertical Gas Corridor as Balkan gas integration widens appeared first on Serbia SEE Energy Mining News.

Energy Community monitoring for the second quarter showed the Western Balkan contracting parties becoming net importers of EU electricity overall, while some exports toward EU markets continued on selected corridors.

The change suggests traditional arbitrage economics are already being disrupted.

Before CBAM, a Serbian, Bosnian or Montenegrin exporter could focus primarily on the price difference between its domestic market and Hungary, Croatia or Italy.

Under the definitive CBAM regime, EU importers must also account for embedded carbon emissions.

That creates a structural disadvantage for lignite-heavy electricity unless actual emissions can be demonstrated and verified at a materially lower level than the applicable default.

The effect should become more visible during autumn scarcity events.

A €20-30/MWh wholesale spread may look attractive but can disappear once the CBAM liability of high-carbon generation is included.

Renewable and hydro electricity should theoretically retain stronger export economics, but the Energy Community has warned that renewable producers are encountering practical difficulties proving compliance with the requirements for actual emissions.

The European Commission’s August guidance reinforces the importance of monitoring, contractual traceability and verification.

The commercial consequence is the emergence of two parallel values for Western Balkan electricity.

One is the ordinary domestic or regional wholesale price.

The other is the CBAM-adjusted EU netback after carbon and evidence costs.

That could increasingly influence how EPS, EPCG, ERS, EPBiH and independent producers allocate generation between domestic buyers, EU exports and other non-EU markets.

For autumn traders, the key border spread is therefore no longer simply SEEPEX-HUPX or Montenegro-Italy.

It is the wholesale spread after carbon exposure and verification risk are priced in.

The post CBAM turns EU electricity border into carbon-adjusted trading market appeared first on Serbia SEE Energy Mining News.

Solar and wind output created some of the region’s largest price swings this summer.

Those swings generate balancing requirements when actual production differs from day-ahead schedules, creating costs for generators but revenue opportunities for flexible assets.

Europe’s balancing market is becoming increasingly integrated through common platforms, while regulators are gradually lowering barriers for batteries, aggregators and smaller flexibility providers.

Romania is emerging as the regional test market.

Its operating BESS fleet has passed 1 GW, with energy capacity above 2.3 GWh, while hundreds of additional megawatts have received regulatory approvals.

Four-hour batteries are also beginning to replace the earlier focus on one- and two-hour projects.

The revenue model is changing accordingly.

Early batteries could rely heavily on frequency and balancing services.

As competition increases, developers will need to combine balancing revenue with day-ahead and intraday arbitrage, renewable optimisation and congestion management.

Renewable generators face the opposite pressure.

Projects that remain poorly forecast or unable to rebalance positions close to delivery will face increasing imbalance exposure as their market share grows.

This should encourage solar and wind producers to contract with aggregators, traders and BESS operators rather than sell fixed production profiles.

Autumn should accelerate that shift.

More variable wind generation and rapidly changing solar ramps will increase the value of trading closer to real time.

The next stage of SEE renewable integration will therefore be determined less by how much renewable capacity is connected and more by how efficiently that capacity is forecast, traded and balanced.

The post Renewables move deeper into SEE balancing trade as batteries challenge thermal flexibility appeared first on Serbia SEE Energy Mining News.

European industrial activity entered the second half of 2026 without strong momentum.

EU industrial production rose only 0.6% year on year in June, while output of intermediate goods fell on the month.

Serbia’s industrial production fell 2.3% year on year in July, with manufacturing down 1.6% and electricity, gas and steam supply down 8.8%.

Higher gas, diesel and electricity costs could add pressure to energy-intensive producers through September and October.

Chemicals, fertilisers, cement, steel, aluminium, mining and heavy manufacturing are particularly exposed.

The effect will differ by country.

Romania and Bulgaria retain relative advantages from domestic or contracted gas supply, while Serbian and Bosnian industry can benefit from locally generated electricity but face increasing carbon exposure when supplying EU markets.

Croatia and Slovenia are more tightly connected to EU industrial cycles and imported energy pricing.

A weak industrial load would soften daily electricity consumption and could prevent average autumn power prices from rising as aggressively as fuel costs suggest.

But it would not eliminate evening scarcity.

Household demand, commercial load and declining solar production can still create steep peaks even if factories reduce consumption.

For power traders, the distinction matters.

Industrial weakness is bearish for baseload volumes, while gas costs, generation outages and renewable variability can remain bullish for peak and balancing prices.

Autumn 2026 could therefore combine disappointing industrial demand with surprisingly expensive electricity during selected hours.

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Summer 2026 produced repeated zero and negative-price periods across Greece, Bulgaria, Romania, Hungary, Croatia and Slovenia as solar generation expanded faster than storage and flexible demand.

By early September, several markets were trading around or below zero during midday before exceeding €225/MWh in the evening.

That pattern should begin to change in October.

Lower solar output and fewer daylight hours should reduce the duration of zero-price periods and improve the captured price achieved by photovoltaic projects.

But less solar production will also remove cheap electricity from the late afternoon, moving the evening scarcity ramp earlier.

Wind should become relatively more valuable.

Autumn typically brings stronger and less daylight-dependent wind conditions, allowing projects to produce outside the heavily cannibalised solar window.

Hydro remains the most valuable renewable flexibility source where water is available because operators can preserve reservoir output during weak-price hours and dispatch into evening peaks.

The market therefore favours diversification rather than simply adding more renewable megawatts.

Solar-plus-storage projects should outperform equivalent standalone PV during volatile days, while wind and hydro retain stronger natural production profiles.

The autumn question will be whether batteries are being deployed quickly enough to absorb growing renewable surpluses.

Romania already has more than 1 GW and 2.3 GWh of operating BESS and a rapidly expanding pipeline, but regional storage remains small relative to total peak demand.

October should therefore reduce solar cannibalisation without eliminating the underlying flexibility premium.

The post Shorter autumn days may lift solar captured prices but deepen evening scarcity appeared first on Serbia SEE Energy Mining News.

Brent crude has moved above $95/barrel, but European diesel markets have tightened even more sharply.

Physical diesel refining margins reached around $95-100/barrel in early September, more than double June levels, as European buyers competed for limited supplies from the United States, Middle East and Asia.

That creates particular exposure for Southeast Europe, where diesel remains central to road freight, agriculture, construction and mining.

Serbia faces an additional country-specific risk.

The OFAC licence allowing NIS to import crude, operate the Pančevo refinery and conduct supply-security transactions expires on Sept. 30, making an extension or ownership solution a major October market variable.

Croatia is comparatively better positioned after INA completed its nearly €700 million Rijeka refinery upgrade, which is designed to raise diesel output by around 30% and reduce import dependence.

Romania also retains substantial domestic refining capacity.

For the broader region, September prices are likely to stay elevated while Russia’s diesel export restrictions remain in place and global refining capacity is stretched.

October could soften if export flows normalise and refinery maintenance ends.

But a crude-price retreat would not automatically produce an equivalent fall in diesel.

The main autumn risk is therefore a refined-product shortage premium, which could raise logistics, agricultural and industrial costs even without another major rise in Brent.

The post Diesel, not crude, emerges as main autumn oil risk for Southeast Europe appeared first on Serbia SEE Energy Mining News.

European hub gas was trading around €70-73/MWh in early September, with October contracts near similar levels.

EU storage is only about two-thirds full, substantially below normal early-September levels, increasing sensitivity to weather and LNG availability.

For Southeast Europe, the main improvement is infrastructure.

Greece has expanded its role as an LNG gateway through Revythoussa and Alexandroupolis, while the Vertical Gas Corridor is being extended toward Serbia and North Macedonia.

Bulgaria retains access to lower-cost Azerbaijani volumes and entered September with a regulated gas price of €41.60/MWh, materially below European hubs.

Romania has the region’s strongest indigenous gas position and should become still less import-dependent as Black Sea production increases over coming years.

Hungary and Serbia retain access to Russian gas through the southern route while progressively adding alternative connections.

Those supply options lower the risk of physical shortages.

They do not eliminate price exposure.

If international LNG remains constrained, Greece and other markets buying hub-linked gas will continue paying near European benchmark prices.

September should benefit from falling cooling demand, but continued storage injections will support demand.

October introduces the first heating load and could keep TTF and CEGH firm even as power-sector gas consumption declines from summer highs.

The base case is therefore for adequate physical gas but expensive marginal supply, with upside risk if Middle East disruptions intensify or Europe enters winter with inventories below target.

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Romania entered September as one of the most exposed markets.

Average consumption was around 5.43 GW in August, while the system was a net importer by roughly 341 MW, with domestic generation covering about 94% of demand.

Nuclear availability will be decisive for the autumn balance.

Hungary should remain structurally dependent on imports despite Paks nuclear generation, particularly during high-demand periods when solar output falls.

Croatia and Slovenia are also likely to remain import-oriented, although reservoir hydro can materially change their positions after periods of stronger rainfall.

Bulgaria has the strongest potential to remain a regional exporter when Kozloduy is fully available. In June, its exports substantially exceeded imports as nuclear, hydro and rapidly growing solar generation supported the balance.

Greece will continue oscillating between renewable surplus and gas-backed deficit periods.

Its import requirement should weaken as summer cooling demand falls, but gas generation will remain critical during weak wind and post-sunset hours.

The Western Balkans will remain more weather-sensitive.

Serbia’s lignite and hydro fleet can cover domestic demand during favourable periods but outages or drought rapidly increase imports. Montenegro’s balance remains highly dependent on Pljevlja thermal availability and hydro conditions.

Albania remains the region’s clearest hydrological swing market, moving from exporter in wet periods to expensive importer during drought.

North Macedonia is likely to remain structurally import-dependent, while Bosnia can return to export when hydro conditions improve but remains exposed to ageing coal assets.

The autumn market will therefore not divide simply between exporters and importers.

The more important distinction will be between systems with firm domestic flexibility and those forced to buy electricity during expensive evening hours.

The post Autumn demand shift to expose winners and losers in SEE import balance appeared first on Serbia SEE Energy Mining News.

Summer trading repeatedly showed that additional generation alone does not guarantee price convergence.

Hungary traded almost €91/MWh above Germany on Sept. 4 even as west-to-east imports increased, while Serbia, Bulgaria and Greece frequently formed separate price zones depending on renewable availability and border capacity.

ACER has identified insufficient cross-zonal capacity and evening flexibility as the main structural causes of previous SEE price spikes and has urged grid operators to implement the EU requirement to make at least 70% of transmission capacity available for cross-border trade.

The issue should become more visible in autumn.

September will still produce strong solar output and occasional regional surpluses, but October brings shorter daylight hours and an earlier evening ramp.

Hungary is likely to remain the main regional optimisation hub, absorbing electricity from Austria, Slovakia and Romania before redistributing supply toward Serbia, Croatia and Slovenia.

Romania’s position will depend heavily on nuclear and hydro availability.

Bulgaria should retain greater export potential when Kozloduy operates normally, while Croatia and Slovenia remain structurally more dependent on imports during periods of weak hydro.

Serbia can move between importer and exporter within days, making the SEEPEX-HUPX spread particularly volatile.

The main autumn trading risk is therefore not a lack of electricity across Europe.

It is insufficient capacity to move lower-priced electricity into SEE during the hours when the region needs it most.

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