SEEPEX settled at €137.92/MWh, down €12.30/MWh from the previous day. Hungary’s HUPX rose €7.60/MWh to €171.27/MWh, leaving Serbian electricity €33.35/MWh cheaper. That gap widened by about €20/MWh in one session.

Romania also moved lower, slipping €2.60/MWh to €161.91/MWh. Elsewhere, prices strengthened. Slovenia reached €188.30/MWh, up €17.50/MWh, while Croatia gained €9.30/MWh to €178.66/MWh.

The divergence increased the potential value of supplying higher-priced markets from Serbia and the eastern Balkans. Realisable margins, however, depend on hourly price differences, transmission capacity and the cost of securing cross-border access.

Montenegro’s BELEN rose €28.70/MWh to €142.87/MWh, reversing much of its recent weakness. Albania recorded the largest daily increase, climbing €61/MWh to €158.90/MWh, while North Macedonia advanced €20.80/MWh to €136.75/MWh.

Despite those gains, all three remained below Hungary. Montenegro traded at a €28.40/MWh discount to HUPX, Albania at €12.37/MWh and North Macedonia at €34.52/MWh.

Greece remained the cheapest market in the report at €120.52/MWh, although its daily average rose €9.40/MWh. Bulgaria increased €3.80/MWh to €138.63/MWh, leaving both markets substantially below Hungary and the western part of the region.

The stronger prices came alongside an improving aggregate supply balance. Forecast average demand across Hungary and southeastern Europe eased to 29,086 MW, about 297 MW lower than the previous day. The region’s net export position increased to 593 MW, from 248 MW.

Forecast solar generation rose by 1,731 MW to 6,539 MW, more than offsetting a 1,016 MW decline in wind output to 4,923 MW. The combined renewable increase therefore coincided with lower demand, although its effect varied considerably between markets and delivery hours.

Net imports from Austria and Slovakia fell to 132 MW, from 479 MW. Commercial exports towards Italy remained substantial at 1,359 MW, slightly below the previous day’s 1,381 MW.

Italy’s national price averaged €216.17/MWh, maintaining a sizeable premium over Balkan markets. Germany stood at €200.50/MWh and Austria at €198.69/MWh, reinforcing the broader east-west price divide.

Daily averages concealed pronounced intraday volatility. Serbia’s hourly prices ranged from €19.40/MWh to €280/MWh, with the maximum in hour 20. Its peak-period average was €101.30/MWh, well below the €174.60/MWh off-peak average.

Montenegro showed a similar pattern, ranging from €15/MWh to €258.90/MWh. Greece briefly fell to minus €1/MWh, yet reached €240.70/MWh later in the day. Croatia’s maximum climbed to €315.10/MWh.

Those profiles underline the commercial importance of when electricity is produced and consumed. Solar-heavy daytime supply can depress prices during conventional peak hours, while evening demand commands substantially higher values.

Forward prices also firmed. Hungarian November power rose €3/MWh to €208/MWh, while week 41 increased to €199.50/MWh. November gas advanced €1.50/MWh to €75.50/MWh, and carbon allowances edged up to €85.64 per tonne.

For Serbian buyers, the lower daily settlement reduced average procurement costs. But an evening maximum of €280/MWh left the sharper message: the widening discount to neighbouring markets did little to remove the cost of covering demand after solar output faded.

The post Serbia power falls as higher prices widen regional trading gaps appeared first on Serbia SEE Energy Mining News.

The temporary measure leaves excise duty at approximately €400 per 1,000 litres. The reduction is worth about €133 per 1,000 litres, equivalent to roughly €0.133 per litre before any related tax effects.

The latest government assessment showed international diesel quotations 63.7% higher and average Romanian retail diesel prices up 35.01% against the comparison levels used in the assessment.

Support is reviewed every two weeks under Law 162/2026.

The same 25% reduction applied throughout September, following a 20% cut during the second half of August.

The extension limits part of the cost increase facing diesel users, but its short duration leaves transport operators uncertain about fuel expenses beyond mid-October.

The post Romania extends 25% diesel excise reduction into October appeared first on Serbia SEE Energy Mining News.

The work is expected to add 13.5 MW of capacity and increase annual generation by about 50 GWh. ESM estimates the additional output could generate at least €5 million in annual revenue.

Financing comprises a €35 million KfW loan and a €10.7 million EU grant through the Western Balkans Investment Framework.

The programme covers Vrutok, Vrben, Raven, Tikveš, Špilje and Globočica, with equipment replacement and upgrades intended to improve reliability, reduce interruptions and extend operating life.

The investment focuses on raising production from existing assets. Actual output gains will also depend on water availability, which remains a central constraint on hydropower generation.

The post North Macedonia starts €46 million hydropower upgrade phase appeared first on Serbia SEE Energy Mining News.

Combined with refinery discounts, the reduction available at petrol stations is expected to reach approximately €0.20 per litre.

Helleniq Energy will maintain its discounts until 14 October, cutting unleaded petrol prices by €0.0795 per litre and diesel by €0.0405.

The government plans to review support every 15 days, allowing adjustments as international prices change.

Attention will next turn to heating oil, whose winter sales season begins on 15 October. Authorities aim to keep the initial retail price below €1.75 per litre, with additional support expected to be announced before sales begin.

The short extensions provide immediate relief while leaving the government room to limit spending if fuel prices remain high.

The post Greece increases diesel subsidy and extends refinery discounts appeared first on Serbia SEE Energy Mining News.

The increase follows a 5.5% rise in September, adding to fuel-cost pressure ahead of the heating season.

Energy regulator KEVR retained the original proposed price, rejecting a subsequent request by Bulgargaz to raise it to €44.41/MWh.

October supplies will combine gas purchased under Bulgaria’s long-term Azerbaijani contract with LNG procured through tenders. A relatively small contribution is expected from the Chiren underground storage facility.

The approved tariff applies to Bulgargaz supplies to regulated customers, including heat producers. VAT, excise duty and network access and transmission charges are excluded.

Natural gas accounts for more than 70% of residential heating prices, making further wholesale increases a significant exposure for heating suppliers and consumers as winter approaches.

The post Bulgaria raises October wholesale gas price by 5.99% appeared first on Serbia SEE Energy Mining News.

The solar plant is expected to produce about 332 GWh annually. More than 250 MW of wind capacity is also planned, with total investment expected to exceed €500 million if all phases are completed.

The solar plant and first battery phase have operated since 2025. The additional storage increases the project’s ability to shift electricity sales away from periods of concentrated solar production.

Solarpro Holding handled engineering, procurement, construction and project management.

Solar financing included €50 million from the EBRD and €53 million from Raiffeisen Bank International. A further €60 million financing package for the second battery phase is expected to be signed shortly.

The development also benefits from an InvestEU guarantee, supporting a project whose commercial performance increasingly depends on flexible delivery rather than solar generation alone.

The post Renalfa and Eurowind expand Bulgaria’s Tenevo solar and battery complex appeared first on Serbia SEE Energy Mining News.

The proposed plants would have capacities of 21.9 MW, 26.5 MW and 26.2 MW, concentrating the portfolio in the same development area.

The company is a subsidiary of Albanian construction group 4 A-M.

Investment costs, financing arrangements, grid connections and commissioning dates have not been disclosed. Those details will determine how quickly the projects can move from planning into construction.

The portfolio would broaden Albania’s generation mix, although its contribution to supply security will depend on delivery timing and the ability to accommodate additional solar output on the network.

The post MD Green Energy plans 74.6 MW solar portfolio in Albania appeared first on Serbia SEE Energy Mining News.

The proposed expansion would support an EU target of importing at least 20 billion cubic metres annually by 2027. Deliveries reached about 11.3 billion cubic metres in 2025, up from 8.1 billion in 2021 but still well below that objective.

Options include increasing TANAP capacity from 16.2 billion to 31.7 billion cubic metres annually and TAP from 10.5 billion to 23.3 billion. The South Caucasus Pipeline could expand from 24 billion to 33.6 billion cubic metres.

A full expansion is estimated to require about five years, making the timing of commercial commitments critical.

The corridor supplies Europe through Georgia and Turkey, with gas entering Greece, Albania and Italy. Additional deliveries can reach Bulgaria and neighbouring markets through the Greece–Bulgaria interconnector.

For European buyers, securing more Azerbaijani gas now depends on accepting longer contractual commitments while the bloc pursues lower fossil-fuel consumption.

The post Azerbaijan seeks firm EU demand before expanding gas corridor appeared first on Serbia SEE Energy Mining News.

At the start of the week, US President’s offer to meet with Iran’s president during the United Nations General Assembly contributed to downward pressure on oil prices. However, Iran’s refusal to accept US demands pushed prices higher on September 23. The following day, Yemen’s Houthis launched missiles toward Saudi Arabia, while a senior Iranian military official warned that Iran could extend the conflict to the Indian Ocean if another country attacked it. These developments drove Brent to its weekly peak. On Friday, Iran’s proposal for an interim agreement that would include reopening the Strait of Hormuz within seven days contributed to a decline in prices.

Front-month TTF gas futures on the ICE market settled at €73.25/MWh on Monday, September 21, 7.9% below the previous Friday’s level. Prices reached their weekly low of €72.01/MWh on September 23, the lowest level since September 5, according to AleaSoft Energy Forecasting. On Thursday, September 24, prices increased by 4.3% to reach a weekly high of €75.11/MWh. By Friday, September 25, the settlement price had fallen to €72.07/MWh, 9.4% below the previous Friday’s level.

Expectations surrounding talks between the United States and Iran on the gradual reopening of the Strait of Hormuz, combined with a rise in the number of vessels using alternative routes, contributed to lower European gas prices. However, European Union gas storage facilities were around 70% full, remaining below the seasonal five-year average.

Meanwhile, futures for CO2 emission allowances under the December 2026 reference contract on the EEX market remained above €86/t throughout the fourth week of September. The weekly low settlement price was €86.03/t on September 23, while the weekly high reached €86.97/t on Thursday, September 24. On Friday, September 25, the contract settled at €86.79/t, just 0.1% below the previous Friday’s level, AleaSoft reports.

The post Europe: Brent prices rebound on Middle East tensions as TTF gas and CO2 prices remain stable appeared first on Serbia SEE Energy Mining News.

Despite the decrease, Italy once again recorded the highest weekly average price, at €201.47/MWh. The Nordic market remained the cheapest, with an average of €109.72/MWh. Across the other markets analyzed by AleaSoft Energy Forecasting, weekly average prices ranged from €144.87/MWh in Spain to €176.70/MWh in Great Britain.

Most markets reached their weekly price peaks on Tuesday, September 22. The British market recorded €230.16/MWh, the highest price among the markets analyzed and its highest level since January 23, 2025. Germany and the Netherlands also exceeded €220/MWh, reaching €226.18/MWh and €223.94/MWh, respectively, while Belgium reached €211.18/MWh. Italy recorded its weekly peak of €224.23/MWh on Monday, September 21, and prices remained above €200/MWh throughout the period from Monday to Friday. France, Portugal and Spain reached their weekly highs on Friday, September 25, at €161.52/MWh, €161.38/MWh and €158.92/MWh, respectively.

At the lower end of the market, the Nordic region recorded the lowest price of the week, at €52.11/MWh on Monday, September 21. Prices declined across all analyzed markets on Sunday, September 27, compared with the previous day. France, Portugal, Spain, Great Britain, Belgium and the Netherlands all recorded their weekly lows that day, with prices ranging from €113.65/MWh in Spain to €118.54/MWh in Great Britain. The Nordic market remained the lowest-priced market, at €56.07/MWh.

Lower wind power generation in most markets contributed to higher electricity prices despite falling gas prices. In Great Britain and Portugal, stronger electricity demand provided an additional upward pressure on prices. In Italy, by contrast, higher wind generation combined with lower demand contributed to the decline in electricity prices.

According to AleaSoft Energy Forecasting, price forecasts for the week beginning September 28 point to higher electricity prices across most of the analyzed European markets. Italy and Great Britain are the main exceptions, with prices expected to decline in both markets, AleaSoft reports.

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In contrast, electricity demand increased in Great Britain and Portugal. The British market registered the largest increase, at 5.3%, following the decline recorded in the previous week. Portugal saw demand rise by 1.2%, marking its fourth consecutive week of growth.

Average temperatures declined in most of the analysed markets during the week. Germany recorded the largest drop, at 3.1°C, followed by Italy with a 2.1°C decrease and Belgium with a 1.9°C decline. Temperatures fell by 0.8°C in both France and Great Britain.

Portugal and Spain moved in the opposite direction, with average temperatures increasing by 1.2°C and 0.8°C, respectively.

For the week of September 28, AleaSoft Energy Forecasting expects electricity demand to increase in Portugal, Great Britain, Belgium and France. In contrast, demand is forecast to decline in Italy, Spain and Germany.

The differing demand trends reflect the combined influence of temperature changes and market-specific consumption patterns as Europe moves further into the autumn period, AleaSoft reports.

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For the week of September 28, AleaSoft Energy Forecasting expects solar generation to increase in Italy, while output is forecast to decline in Germany and Spain. The differing outlooks point to continued variation in solar production across Europe as seasonal conditions change.

Wind generation moved in the opposite direction during the fourth week of September, declining in most major European electricity markets compared with the previous week. Portugal recorded the largest decrease, at 54%, followed by Germany with a 36% decline. Wind generation fell by 30% in France and 27% in Spain, with all four markets reversing the increases recorded during the previous week.

Italy was the main exception, with wind generation surging by 68% after declining during the previous week.

For the week of September 28, AleaSoft Energy Forecasting forecasts further increases in wind generation in France, Portugal and Spain. In contrast, wind output is expected to decline in Germany and Italy.

The contrasting movements in solar and wind generation highlight the continued volatility of renewable electricity output across Europe. Changes in weather conditions and seasonal patterns are expected to remain important factors influencing renewable generation and electricity market dynamics in the coming weeks, AleaSoft reports.

The post Europe: Solar generation rises while wind output declines in major power markets appeared first on Serbia SEE Energy Mining News.

The divergence widened regional trading spreads despite forecasts for higher renewable generation and slightly weaker overall consumption. Germany’s sharper price increase also reversed Hungary’s premium over the German market, accompanying a reduction in electricity imports from Austria and Slovakia.

Hungary’s HUPX settled at €163.72/MWh, up €18.10/MWh, while Romania’s OPCOM rose €20.20/MWh to €164.48/MWh. Their narrow €0.76/MWh spread contrasted with substantially larger differences across the southern markets.

Slovenia climbed €21.70/MWh to €170.77/MWh, and Croatia gained €21.40/MWh to €169.38/MWh. Both remained above Hungary, with premiums of around €7/MWh and €6/MWh, respectively.

Serbia’s increase was the largest among the southeast European exchanges covered. It nevertheless retained a €13.54/MWh discount to Hungary, while its projected net imports averaged 735 MW. Hungary and Croatia also remained net importers, at 995 MW and 896 MW, respectively.

The southern markets showed a different pattern. Albania’s ALPEX fell €48.50/MWh to €97.94/MWh, the lowest price in the surveyed markets. Montenegro’s BELEN eased €1.70/MWh to €114.22/MWh.

Greece rose just €1.60/MWh to €111.17/MWh, Bulgaria gained €1.10/MWh to €134.86/MWh, and North Macedonia increased €7.80/MWh to €115.91/MWh.

Hungary consequently traded €52.55/MWh above Greece and nearly €66/MWh above Albania. These daily average spreads signal potential value for cross-border trading, although executable margins depend on hourly prices, transmission capacity and delivery costs.

Greece and Bulgaria were projected to remain substantial net exporters, averaging 1,826 MW and 1,340 MW, respectively. Their lower prices alongside exports illustrate the uneven distribution of supply across the region.

Across Hungary and southeast Europe, the aggregate balance shifted from 226 MW of net imports on September 30 to 248 MW of net exports for October 1. Forecast consumption slipped by 80 MW to 29,382 MW.

Solar generation was forecast to rise by 1,983 MW to 6,759 MW, more than offsetting a 383 MW decline in wind output to 4,937 MW. Combined wind and solar production therefore increased by about 1,600 MW.

Those forecasts provide little support for a region-wide demand-driven explanation of the price rise. Establishing the cause of individual market moves would require hourly generation, plant availability and transmission data.

The clearest external change came from Germany, where electricity rose €54.40/MWh to €195.18/MWh. Hungary moved from a premium of roughly €4.90/MWh on the previous day to a €31.46/MWh discount.

At the same time, forecast imports from Austria and Slovakia into Hungary and Slovenia fell by 686 MW to 479 MW. Italy remained the highest-priced surveyed market at €209.95/MWh, while net flows towards Italy averaged 1,381 MW.

Forward prices also strengthened. Hungarian week 41 power rose €3.50/MWh to €198.50/MWh, while week 42 gained €7/MWh to €206/MWh. November power increased to €198.50/MWh, around €35/MWh above the October 1 spot average.

Gas added cost pressure: Austrian CEGH rose to €73.73/MWh, and Greek gas reached €66.45/MWh. Carbon allowances eased to €85.09 a tonne, offering some relief to fossil-fuel generators.

For buyers, the immediate exposure remained concentrated in Serbia and the northern markets. Higher forecast renewable output improved the regional balance, but it did not prevent a €47.20/MWh daily increase in Serbian electricity costs.

The post Serbian power prices jump as southeast European markets diverge appeared first on Serbia SEE Energy Mining News.

A consortium of Vodafone Romania and Electromontaj has secured the design-and-build contract. Politehnica Bucharest is also involved.

The project will receive €43 million in non-repayable funding from the Modernisation Fund. Implementation is scheduled over 44 months, with completion planned for May 2030.

The upgrade will integrate power infrastructure with communications, automation, monitoring and equipment-condition analysis.

Planned systems include a private cloud, digital twins, satellite and geographic data, augmented reality and an Asset Health Center for continuous equipment assessment. Cybersecurity and staff training will form part of the programme.

Transelectrica intends to use Alba Iulia as a reference for subsequent network upgrades.

Its wider value will depend on whether the integrated systems improve maintenance decisions, equipment availability and operational visibility sufficiently to justify deployment across other substations.

The post Romania: Transelectrica starts €90.4 million digital substation upgrade appeared first on Serbia SEE Energy Mining News.

The project in Arad county is being developed through West Power Investments and will occupy more than 1,000 hectares.

Expected annual generation is approximately 1,800 GWh, equivalent to around 36% of Romania’s solar output in 2025.

Two contracts for difference awarded in Romania’s second CfD auction cover 520 MW of capacity, providing a contracted revenue base. A separate long-term corporate power purchase agreement will provide additional contracted income.

The financing is Rezolv’s largest package to date, exceeding the €291 million and €331 million arranged for the two phases of its Vifor wind project and €90 million for Bulgaria’s St. George solar plant.

Engineering, procurement and construction contractors are expected to be announced shortly.

With funding secured, attention shifts to construction execution and the 2028 operating target. The CfDs and corporate offtake agreement provide revenue support, while timely delivery remains essential to bringing the planned output to market.

The post Rezolv secures up to €561 million for Romania’s Dama Solar appeared first on Serbia SEE Energy Mining News.

The proposal from Greek company Atlantic–See LNG Trade envisaged deliveries through the Alexandroupoli LNG terminal, with pricing linked to the US Henry Hub benchmark.

Romgaz’s December 2025 assessment estimated delivered costs of approximately €33–42/MWh, compared with European TTF forward prices of €30–40/MWh for 2030–2040.

The company concluded that the offer would become attractive only under a favourable combination of relatively low US prices and higher European prices.

The duration also weighed against the proposal. Romgaz expects Neptun Deep and other domestic developments to strengthen Romania’s gas supply, reducing the case for a two-decade import commitment.

The decision has entered a broader political debate over increasing US LNG deliveries through the Vertical Gas Corridor connecting Greece, Bulgaria and Romania.

For Romgaz, the assessment exposed a commercial tension: diversification through LNG does not automatically justify a long-term commitment when transport costs, benchmark risk and prospective domestic production weaken the economics.

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Dodik said energy cooperation featured in the meeting, alongside discussions about possible gas-sector projects, including gas-fired electricity generation.

An unchanged pricing arrangement would offer continuity for gas buyers in the Bosnian entity at a time of volatile European energy costs. However, the account of the meeting did not disclose a new contract duration, delivery volumes or a detailed pricing formula.

Dodik also said the talks reviewed existing political and economic cooperation and opportunities to expand it.

Potential gas-fired generation remains a separate development prospect. No investment value, plant capacity or construction timetable was disclosed, leaving the immediate commercial significance centred on the expected continuation of current gas pricing.

The post Bosnia and Herzegovina: Republika Srpska expects unchanged Russian gas pricing appeared first on Serbia SEE Energy Mining News.

Funding through the Connecting Europe Facility will cover 35–50% of eligible project costs.

At Romania’s Bilciurești facility, daily withdrawal capacity is set to rise to 20 million cubic metres from 14 million, while working gas capacity will increase by 108 million cubic metres, or about 9%.

The first phase of the Depomureș expansion will add 100 million cubic metres, bringing working capacity to 400 million cubic metres. Injection and withdrawal rates are expected to increase by around 75% to 3.5 million cubic metres a day.

Bulgaria’s Chiren facility is being expanded towards 1 billion cubic metres of storage, with injection and withdrawal capacity expected to reach 8–10 million cubic metres a day.

The projects address a constraint beyond storage volume: how quickly operators can release gas when demand rises. Faster withdrawals could strengthen supply flexibility across neighbouring markets, provided sufficient cross-border transport capacity is available.

The post EU backs gas storage upgrades in Romania and Bulgaria appeared first on Serbia SEE Energy Mining News.

Hungary’s HUPX day-ahead price dropped €24.50 to €145.63/MWh, while Romania’s OPCOM fell €25.60 to €144.31/MWh. Bulgaria recorded the largest absolute decline among the markets covered, with IBEX down €28 to €133.80/MWh.

The supply outlook improved substantially. Forecast average wind generation increased 1,519 MW to 6,206 MW, while solar rose 939 MW to 5,904 MW. Together, the two sources were expected to provide 12,110 MW, equivalent to about 42% of forecast regional consumption.

Demand was forecast to fall 353 MW to 29,112 MW. The combination of lower consumption and stronger renewable production coincided with a decline in the region’s projected net imports to just 88 MW, down from 725 MW a day earlier.

Flows remained substantial on individual borders despite the near-balanced regional position. Imports through the Austrian and Slovak interfaces were forecast at 1,003 MW, down 486 MW, while net exports towards Italy increased 124 MW to 1,326 MW.

Italy’s price slipped only €1.10 to €201.96/MWh, leaving it €56.33/MWh above Hungary, compared with roughly €32.93/MWh a day earlier. The widening differential strengthened the price incentive for deliveries towards Italy, although realised trading margins depend on transmission access and delivery costs.

Within southeastern Europe, prices continued to diverge sharply.

Serbia’s SEEPEX remained the cheapest market covered at €102.94/MWh, down €7.10 and €42.69/MWh below Hungary. North Macedonia’s MEMO fell €24.10 to €108.08/MWh, while Greece’s HENEX declined €12.40 to €109.57/MWh.

Montenegro’s BELEN dropped €15 to €115.92/MWh, maintaining a discount of about €29.71/MWh to Hungary. Albania’s ALPEX, however, eased only €1.10 to €146.47/MWh, placing it close to the Hungarian price and well above several southern neighbours.

Slovenia and Croatia remained more closely aligned with the higher-priced central European markets. Slovenia’s BSP fell €24.90 to €149.11/MWh, while Croatia’s CROPEX declined €24.80 to €147.98/MWh. Austria settled at €155.21/MWh and Germany at €140.75/MWh.

Hungary’s premium over Germany edged up to €4.88/MWh, even as both markets registered substantial declines. Romania traded just €1.32/MWh below Hungary, indicating much closer price alignment than the discounts seen in Serbia, Greece and North Macedonia.

Forward quotations also weakened, but continued to price electricity well above the latest Hungarian spot level. Hungarian week 41 power fell €7 to €195/MWh, week 42 declined €6 to €199/MWh, and October dropped €7 to €197.50/MWh.

The October quotation remained about €51.87/MWh above September 30 spot, showing that the day’s improved renewable balance had not removed the premium embedded in near-term delivery contracts.

Hungary’s week 41 forward spread over Germany widened €11 to €39/MWh, while the October spread edged up to €40/MWh. That divergence suggests the forward market continued to price a regional premium despite the broad decline in outright prices.

Gas quotations provided some additional relief. Austrian CEGH gas fell €3.10 to €71.64/MWh, while the Greek quotation declined €1.90 to €59.60/MWh. October gas dropped €3.50 to €71/MWh, but the fourth-quarter contract held at €74.50/MWh. EU carbon allowances eased €0.20 to €85.95/t.

The day’s figures point to a stronger renewable balance and reduced aggregate import dependence, but persistent price gaps leave cross-border access central to trading economics. Regional supply was close to matching demand; Italy still paid almost €100/MWh more than Serbia, while Hungarian October power remained near €200/MWh.

The post SEE power prices fall as renewable supply rises, Italy premium widens appeared first on Serbia SEE Energy Mining News.

The process aims to preserve the refinery’s industrial assets and technical expertise so that a prolonged shutdown does not undermine its ability to restart.

A restructuring plan is being prepared under Romanian insolvency law. Creditors will be consulted and asked to vote on the proposal, with court approval required where applicable.

The refinery has been out of service for technical work and is also affected by US sanctions.

Maniakhine, a Swiss citizen with previous Lukoil experience, has served as Petrotel’s commercial manager since April. His responsibilities include developing an operating and financial programme with defined milestones and accountability.

The appointment advances the restructuring process, but a return to production will depend on the plan’s approval, operational readiness and resolution of sanctions-related constraints.

The post Lukoil appoints administrator to restructure Romania’s Petrotel refinery appeared first on Serbia SEE Energy Mining News.

An Energy Community assessment of the 2025–2030 period found that the country had met or surpassed several renewable energy commitments.

The target covers total energy consumption, rather than electricity alone. Further progress in heating, cooling and transport will therefore be needed alongside new power generation.

Additional solar and wind capacity will also require network investment, storage and greater balancing capability.

Authorities are preparing reforms to support self-generation, self-consumption, energy communities, batteries and smart meters. Energy efficiency measures aim to reduce primary energy consumption, while regulatory changes are intended to attract investment and deepen market integration.

The next challenge is to extend the gains in renewable electricity across the wider energy system while ensuring the grid can accommodate further capacity.

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Compared with June, generation rose 19.5% and consumption increased 7.5%.

Natural gas consumption reached 166 million cubic metres, up 16.1% month on month and 4.4% year on year. Domestic gas production amounted to just 1 million cubic metres.

Oil-product figures showed contrasting trends. Petrol production increased 7.6% from June to 141,000 tonnes, while consumption fell 34% to 71,000 tonnes.

Diesel output rose 16.1% to 296,000 tonnes, but consumption increased faster, climbing 40.9% to 327,000 tonnes and exceeding domestic production.

Liquefied petroleum gas consumption grew 12.5% to 36,000 tonnes, while output fell 25% to 6,000 tonnes.

Solid-fuel production increased 44.7% month on month to 1.354 million tonnes, alongside a 42.3% rise in consumption to 1.443 million tonnes. The figures point to stronger activity in electricity and solid fuels, while diesel demand outpaced local refinery output.

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Businesses consuming 500–2,000 MWh annually paid an average €118.60/MWh excluding VAT. Households using 2,500–5,000 kWh annually saw prices rise 6.5%, reaching about €83.90/MWh before taxes and €99.50/MWh including VAT and other charges.

The figures show rising electricity costs across both customer groups, with commercial users facing the larger percentage increase.

Gas prices also differed between household and business customers. Residential users paid an average €14.52/GJ including VAT, compared with €12.40/GJ before VAT.

Non-household consumers paid approximately €17.69/GJ including taxes and €15.13/GJ excluding VAT.

The commercial electricity increase adds to operating costs for businesses, particularly those with limited scope to reduce consumption or pass higher energy bills on to customers.

The post Bosnia and Herzegovina: Business electricity prices rise 7.7% in first half appeared first on Serbia SEE Energy Mining News.

Some residents fear the development could restrict access to grazing land and disrupt livestock farming. The detailed regulatory plan is still being prepared, leaving scope to relocate facilities within the concession area and preserve access roads.

Bileća Mayor Miodrag Parezanin said the municipality would seek changes that address local concerns while allowing the investment to proceed. Officials have also raised the possibility of retaining grazing areas around the panels.

The Energy and Mining Ministry said the municipality had supported the project and approved preparation of planning documents, but that support carried conditions still to be resolved. Residents can submit objections before the final plan is adopted.

Solar Agroland is owned by Pinetree Energy, established by Switzerland-based Pinetree. The concession provides a long-term development framework, while land-use arrangements remain the immediate hurdle.

The post Bosnia and Herzegovina: Solar Agroland secures 50-year concession for Bileća solar and storage project appeared first on Serbia SEE Energy Mining News.

Gvozd II will add three Nordex turbines to the operating 55 MW Gvozd I wind farm.

The expansion is expected to produce about 63 GWh annually, lifting output from the combined complex above 200 GWh/year.

EPCG estimates total investment in the two phases at around €105 million.

The milestone matters because Montenegro has a very large renewable development pipeline but relatively few projects already producing electricity.

Gvozd is therefore becoming an important test of EPCG’s ability to convert plans into operating assets.

The additional wind output will diversify a generation mix still heavily dependent on hydro and the Pljevlja coal plant.

Wind can also complement Montenegro’s expanding solar fleet because production is less concentrated in midday hours.

The commercial challenge will be integrating growing variable generation without depressing its market value.

Montenegro is already considering storage and additional export infrastructure, including a second electricity cable towards Italy.

Gvozd II will not transform the national power balance alone.

But it shows EPCG building an expandable renewable portfolio rather than relying solely on one-off projects.

The post Montenegro targets spring 2027 for Gvozd II as EPCG wind complex grows to 76 MW appeared first on Serbia SEE Energy Mining News.

SOCAR said no final investment decision has been taken.

One expansion scenario would increase TAP capacity to 23.3 bcm/year from 10.5 bcm, TANAP to 31.7 bcm from 16.2 bcm and the South Caucasus Pipeline to 33.6 bcm from 24 bcm.

Azerbaijan estimates construction would require roughly five years after commercial commitments are secured.

The constraint is increasingly commercial rather than technical.

Southeast European markets including Greece, Bulgaria, Romania, Serbia, Hungary, Croatia and North Macedonia are actively seeking diversified gas.

But pipeline expansion requires long-term contracts capable of supporting billions of euros of investment.

That creates tension with EU policy.

Buyers want additional non-Russian gas but may be reluctant to sign very long contracts while European policy simultaneously targets lower fossil-fuel consumption.

Without those commitments, Azerbaijan has little incentive to invest in significantly larger export infrastructure.

The stalemate matters for Southeast Europe because the region has already built many of the interconnectors needed to receive additional Caspian gas.

Physical access is improving faster than upstream supply.

The next stage of diversification therefore depends less on constructing Balkan pipelines and more on whether European buyers are willing to guarantee demand for the gas that would fill them.

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Paks cut output by 92 MW between 11:45 and 16:00 on Sept. 27 because of market conditions.

MVM has reported at least eight similar scheduled reductions since May, including a 104 MW cut on Aug. 30 and 69 MW on Sept. 6.

The reductions are distinct from technical outages.

They occur when wholesale prices fall sufficiently low that full nuclear production cannot be economically placed in the market.

Hungary now has more than 8 GW of solar, creating increasingly large midday surpluses during sunny, low-demand periods.

That is pushing price cannibalisation beyond photovoltaic generators themselves.

Nuclear plants, traditionally expected to operate almost continuously, are increasingly being asked to respond to electricity-market conditions.

The trend strengthens the case for batteries and other flexible demand capable of absorbing excess daytime power.

Without enough storage, Hungary can simultaneously curtail low-cost nuclear or solar generation at midday and face expensive evening scarcity after photovoltaic output collapses.

The repeated Paks reductions therefore highlight a broader change in market structure.

Hungary is no longer simply short of generation.

It increasingly has too much electricity during some hours and insufficient flexibility during others.

That tension will be central to the government’s review of Paks II and its broader storage strategy.

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Developers OMV Petrom and Romgaz said seven of the project’s ten development wells have been completed, while the offshore platform and main pipeline infrastructure are already installed.

Plateau production is targeted by the end of the third quarter of 2027 at around 140,000 barrels of oil equivalent per day, equivalent to roughly 8 bcm of gas annually.

Recoverable resources are estimated at about 100 bcm.

The tighter timetable matters beyond Romania.

At plateau, Neptun Deep could produce volumes comparable with a significant share of current Romanian consumption, potentially freeing additional gas for export into Hungary, Bulgaria, Moldova and other regional markets.

Romania is already becoming an important northbound gas transit market as supplies from Greece and Bulgaria move towards Central Europe.

New domestic production would strengthen that role and reduce reliance on imported gas.

The key commercial question will be how much of Neptun Deep is absorbed domestically and how much reaches neighbouring markets.

Pipeline capacity, storage and long-term sales contracts will determine that balance.

The project is now moving from development risk towards execution risk.

With most wells completed and major offshore infrastructure installed, the remaining challenge is delivering first gas on schedule and ramping output rapidly enough to influence regional supply by winter 2027-28.

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The government approved an annex to its agreement with developer consortium Energy 2, allowing the development phase to last up to 36 months from the original contract date and construction up to 60 months after issuance of a building permit.

The project near Kolašin will comprise 17 turbines and received environmental approval in August 2025.

A significant part of the development involves transmission infrastructure. Energy 2 is expected to construct a 35/110 kV substation, a 110 kV line and the Kolašin 110/400 kV substation. CGES would subsequently acquire the assets for about €40 million.

Energy 2 secured a 30-year land lease in October 2023 and submitted its building permit application in July 2026.

The revised timetable illustrates how transmission works and administrative procedures are increasingly determining the commissioning schedule of Montenegro’s next generation of renewable projects.

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The derogation concerns rules requiring cross-border pipeline capacity to be sold as a single bundled product on both sides of an interconnection.

Serbia, which is outside the EU, has not yet completed the regulatory and technical arrangements needed to implement the system.

The issue is commercially important because the Serbian corridor has become a major supply route for Hungary. Much of Hungary’s TurkStream gas enters through Serbia at Kiskundorozsma, where annual import capacity is around 8.5 billion cubic metres.

Hungarian regulator MEKH requested the exemption in February. The European Commission concluded that the temporary arrangement would not materially disrupt the EU gas market or threaten security of supply.

The decision gives operators and regulators additional time to align Serbia-Hungary capacity procedures while preserving flows along an increasingly important regional gas corridor.

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The operator has moved early to reserve production capacity for critical equipment, particularly high-voltage cables, as European manufacturing capacity remains tight.

Contracts cover AC cables for the Dodecanese and Northeastern Aegean interconnections and the DC cable system for the 1 GW Corinth-Kos link.

Funding for the 2026-2029 programme includes a €530 million capital increase at ADMIE Holdings, its proportional participation in ADMIE’s €1 billion capital increase and financing from the European Investment Bank.

The roughly 1,290-km Corinth-Kos project is moving forward, while the Northeastern Aegean interconnection linking Lemnos, Lesvos, Chios, Skyros and Samos is targeted for completion in 2030.

ADMIE and Terna are also developing a second 1 GW Greece-Italy interconnector, with commercial operation currently targeted for 2033.

The procurement strategy highlights cables and manufacturing slots as increasingly important constraints on Europe’s transmission expansion.

The post Greece: ADMIE locks in equipment for €3.5 billion of grid projects appeared first on Serbia SEE Energy Mining News.

Gross production reached 529 GWh, up 15.8% from 457 GWh in August 2025.

Thermal generation accounted for 65.2% of the total, hydropower 29.7% and wind farms 5.1%. Net production was 473 GWh, including 305 GWh from thermal plants, 141 GWh from hydro and 27 GWh from wind.

Imports dropped to 83 GWh from 172 GWh, while exports fell to 60 GWh from 168 GWh.

Coal production weakened. Brown coal output fell about 28% to 210,117 tonnes, while lignite production declined 17.7% to 114,580 tonnes.

The figures point to a stronger domestic electricity balance in August, although generation remained heavily dependent on thermal plants and hydro availability.

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Thermal plants remained the largest source, accounting for 60.7% of gross production, followed by hydropower at 28% and wind and solar at 11.3%.

Net hydro production increased 9.5% year on year to 301 GWh, while thermal generation fell 2.1% to 603 GWh. Wind and solar output rose 5.9% to 126 GWh.

The improved generation balance strengthened Bosnia’s export position. Electricity exports increased 12% to 654 GWh, compared with 584 GWh in July 2025, while imports edged down to 419 GWh.

Coal trends were mixed. Lignite production jumped 55.9% to 558,000 tonnes, while brown coal output fell 17.4% to 461,000 tonnes. Natural gas imports dropped 39.1% to 6.3 million cubic metres.

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The programme will modernise around 1,700 km of medium- and low-voltage lines and replace roughly 43,000 poles, covering about 12% of the company’s network.

Elektrokrajina aims to cut distribution losses to around 6% from 10%, which it estimates could generate annual savings exceeding €2 million. Works will focus particularly on peripheral areas where outages and network problems are more frequent.

The programme will be financed through a €38 million EBRD loan, with €30 million allocated to reconstruction and €8 million refinancing existing obligations. The financing includes a four-year grace period and 20-year maturity.

Procurement will be divided into three lots under EBRD procedures, opening a potentially significant pipeline of grid work for regional contractors.

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Hungary’s HUPX base price rose €8.9/MWh to €170.11/MWh, while Romania climbed €15.6 to €169.92/MWh and Bulgaria gained €15.7 to €161.82/MWh. Croatia reached €172.76/MWh and Slovenia €174.01/MWh. By contrast, Serbia’s SEEPEX slipped to just €110.06/MWh, Greece fell to €121.97/MWh, Montenegro to €130.96/MWh and North Macedonia to €132.21/MWh. 

The result was an unusually fragmented regional market. Serbia traded almost €60/MWh below Hungary, Greece was €48/MWh below HUPX, while Montenegro and North Macedonia were around €38-39/MWh cheaper. Albania, at €147.58/MWh, remained about €23 below Hungary. At the other end of the market, Italy averaged about €203/MWh, almost €93 above Serbia and €81 above Greece. 

The strongest shift occurred between Hungary and Germany. German day-ahead prices fell to around €165.83/MWh, leaving Hungary about €4.3/MWh above Germany. Only a day earlier Hungary had traded roughly €34/MWh below Germany, representing a swing of nearly €39/MWh in the bilateral spread. Austria stood at €180.55/MWh, while Italy remained the region’s highest-priced major market at about €203/MWh. 

That reversal coincided with a major change in the regional physical balance. Combined Hungary and SEE consumption increased to 29,105 MW, up around 740 MW day on day, while the region shifted from a net export position of 1,288 MW on Sept. 28 to net imports of 555 MW on Sept. 29 — a swing of more than 1.8 GW. Imports from the Austria-Slovakia/core direction reached about 1,367 MW, reversing the previous day’s 501 MW flow in the opposite direction. 

The change helps explain the rebound in HUPX and nearby markets, but not the entire regional price structure. Hungary remained a net importer of roughly 1,007 MW, compared with 731 MW a day earlier, while its domestic consumption increased to 4,516 MW against generation of around 3,509 MW. Commercial flows showed particularly strong imports from Slovakia and Romania, while Hungary continued exporting towards Croatia and Slovenia. 

Romania remained a net exporter, but its surplus dropped sharply to about 187 MW from 866 MW on Monday. Bulgaria’s exports also fell to 571 MW from 1,212 MW. These reductions tightened the northern and eastern SEE balance just as regional demand recovered from the lower weekend levels.

The southern markets told a different story.

Greece fell €13.1/MWh to €121.97/MWh, despite exporting more than 1 GW on average. Its hourly profile showed one of the clearest examples of renewable-driven price compression: the Greek peak-period average was only €55.7/MWh, compared with an off-peak average of €188.2/MWh, while the minimum hourly price reached zero. The shape points to very strong daytime renewable availability followed by a steep evening recovery. 

Serbia was even cheaper on a baseload basis. SEEPEX averaged €110.1/MWh, with peak power at only €103.1/MWh and a daily minimum of €9.8/MWh. The maximum nevertheless reached €240.1/MWh, showing that the market remained highly volatile despite the low daily average. Montenegro fell by more than €34/MWh to €131/MWh, while North Macedonia dropped by about €18/MWh to €132.2/MWh. 

The different timing of the low-price hours is important. Greece’s deepest price compression occurred during the solar-heavy daytime period, while Serbia’s minimum was recorded in the early hours. That suggests the Balkan discount was not driven by a single renewable factor but by a combination of local supply, hourly demand, cross-border capacity and transmission constraints.

Italy continued to provide the main high-price outlet for surplus SEE electricity. Regional exports towards Italy averaged about 1,245 MW, while Italy traded around €203/MWh. Montenegro’s interconnector flows illustrate the commercial pull: the country exported about 532 MW towards Italy on a baseload basis even while its overall system remained a small net importer, effectively drawing electricity from neighboring Balkan systems and sending power west through the submarine link. 

Forward markets also pointed to continued firmness in Hungary. Hungarian Week 41 power rose to around €202/MWh, Week 42 to €205/MWh and October to €204.50/MWh. However, forward Hungary-Germany premiums narrowed, suggesting traders still see some scope for stronger central European supply relative to SEE. Gas remained expensive, with CEGH around €74.75/MWh, while EUA carbon allowances stood near €86.17/t. 

The Sept. 29 session therefore showed less a uniformly tightening SEE market than a fragmented system in which transmission capacity increasingly determines value. Hungary and Romania responded to the shift back towards regional imports, Italy maintained a strong pull on Balkan electricity, yet Serbia and Greece remained isolated in much cheaper hourly structures.

For traders, the key signal is the spread rather than the regional average: a market stretching from roughly €110/MWh in Serbia to €203/MWh in Italy is offering substantial cross-border value, but the persistence of those gaps shows how much of that value remains trapped behind congestion and limited transfer capacity.

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Projects involving transmission operator IPTO, distribution operator HEDNO, power company PPC, market operator HENEX and flexibility-platform provider NODES are examining how distributed resources can sell flexibility to both transmission and distribution networks without creating conflicting dispatch instructions.

The commercial significance is straightforward.

Today, an industrial consumer, EV charging operator or commercial building primarily manages electricity as a cost.

Under a functioning local flexibility market, the same customer could also be paid for changing when it consumes or produces electricity at locations where that change has value to the grid.

For HEDNO, meanwhile, procuring flexibility could create a new option alongside reinforcing cables, transformers and substations.

That creates an entirely new local electricity-market value chain.

HEDNO becomes a buyer of flexibility

A Greek demonstration under the European OPENTUNITY programme is testing a market in which IPTO and HEDNO act as flexibility buyers.

Aggregators combine distributed resources and offer them into a system where national and local network requirements can be coordinated.

Those resources can include commercial and residential demand, water heaters, air-conditioning systems, distributed generation and other controllable electricity assets.

The key commercial change is the emergence of the DSO as a potential customer.

A distribution operator normally solves network constraints primarily through infrastructure investment and operational measures.

A flexibility market gives it another option: pay customers to temporarily change electricity behaviour when and where the network is constrained.

If a transformer is overloaded only during a limited number of hours each year, purchasing demand reduction during those hours could potentially be cheaper than immediately replacing the transformer.

Flexibility would not eliminate conventional grid investment, particularly where constraints are structural.

But it could defer some expenditure, improve utilisation of existing assets and allow network companies to target capital more efficiently.

For market participants, that means network congestion itself can become a source of revenue.

Location creates a new electricity price

The important distinction is that local flexibility is not worth the same amount everywhere.

Reducing one megawatt of demand in an unconstrained area may provide little value to HEDNO.

Reducing the same megawatt behind an overloaded transformer could be substantially more useful.

That creates a market for locational flexibility.

A factory, supermarket, hotel, office building or EV-charging depot could therefore have a commercially valuable asset simply because it is capable of changing demand at the right network location.

This is different from conventional wholesale electricity trading.

The product is not merely electricity.

It is a verified change in electricity consumption or production at a specified place and time.

If Greece commercialises that model, electricity customers could begin receiving payments based partly on where they are connected to the grid.

Aggregators gain another revenue pool

The model could significantly expand the business case for aggregators.

An aggregator already participating in balancing markets could add local DSO flexibility as another source of revenue.

A portfolio containing factories, EV chargers, commercial buildings, heat pumps or distributed generation could therefore be optimised across several potential markets.

At one moment, an industrial load might be most valuable to IPTO for national balancing.

At another, the same asset might earn more by helping HEDNO relieve a local network constraint.

The aggregator’s job becomes deciding where each megawatt of flexibility has the highest value.

That makes portfolio optimisation increasingly important.

The commercial advantage could be particularly significant for distributed assets whose economics are difficult to justify from electricity-price optimisation alone.

Local network payments could provide an additional revenue stream without requiring the asset owner to become an electricity trader.

EV fleets and commercial buildings become market participants

Consider an EV fleet.

Its primary business is transport, not electricity.

But if dozens or hundreds of vehicles remain connected for several hours, charging can often be shifted within operational limits.

An aggregator could use that flexibility to reduce charging during a local network constraint and increase consumption later.

The fleet operator could receive a flexibility payment while still ensuring every vehicle is sufficiently charged when required.

The same principle applies to commercial buildings.

Air-conditioning, heating, refrigeration or ventilation systems may be capable of temporarily modifying electricity consumption without materially affecting occupants or operations.

Industrial consumers could participate through pumps, compressors, thermal processes or other flexible loads.

Local flexibility therefore creates a mechanism for turning operational flexibility into a new source of income.

Grid investment becomes a buy-versus-build decision

The biggest commercial impact may ultimately sit with distribution companies.

Traditionally, network planning is heavily capital-intensive.

When demand increases or distributed generation creates congestion, operators frequently need new transformers, substations, cables or other equipment.

Local flexibility introduces a buy-versus-build decision.

Should the DSO invest immediately in additional physical capacity, or procure flexibility during the relatively small number of hours when the constraint occurs?

In some areas, infrastructure will clearly remain the better solution.

In others, flexibility could defer reinforcement for several years.

That turns flexibility into something with a measurable economic benchmark: the avoided or deferred cost of conventional grid investment.

It also creates the possibility of longer-term flexibility contracts rather than purely short-term electricity-market transactions.

A DSO that knows a particular network area will face constraints for several years could potentially procure guaranteed flexibility from local resources.

That would give aggregators and asset owners more predictable revenues and make investment in automation easier to finance.

HEDGE-IoT creates the data business around the market

Greece is also examining related concepts through HEDGE-IoT, involving IPTO, HEDNO, PPC and HENEX.

The programme combines flexibility procurement with the exchange of operational data among market participants.

That data layer creates another commercial market.

A local flexibility system needs to know where participating assets are located, how much flexibility they can provide, when they are available and whether an activation actually solved the relevant network problem.

That creates demand for meter-data platforms, grid analytics, forecasting software, automated dispatch, flexibility verification and settlement systems.

The infrastructure behind the market may therefore become as commercially important as the flexibility itself.

A successful local market requires software capable of connecting thousands of customer assets with network operators in close to real time.

One asset can serve several buyers

The Greek model also tests a fundamental issue for the emerging flexibility economy: the same asset can have several potential customers.

IPTO may want an industrial load to reduce consumption for national balancing.

HEDNO may simultaneously need that asset to behave differently because of local congestion.

A supplier or aggregator may have another commercial incentive altogether.

The market therefore needs rules governing priority, availability and settlement.

That challenge creates opportunities as well as complexity.

Companies able to coordinate assets across several markets could capture more revenue from the same physical infrastructure.

An EV charger, heat pump or industrial process could potentially generate value from electricity-price optimisation, balancing services and local network flexibility at different times.

The objective is revenue stacking without double selling the same capacity.

Greece could create a new energy-services market

If the pilots move into commercial procurement, the consequences would extend beyond the electricity sector’s traditional players.

Aggregators would gain a new market.

Industrial companies could monetise flexible operations.

EV charging companies could add grid services to charging revenues.

Building-management companies could turn HVAC systems into dispatchable assets.

Energy-software providers could sell optimisation and settlement platforms.

HEDNO could gain an alternative to some network reinforcement.

And electricity customers could begin earning revenue from assets they already own.

That is what makes the Greek experiments commercially more significant than another smart-grid pilot.

They are testing whether local network capacity itself can become a market.

If that transition occurs, Greece would move from a power system in which congestion is largely solved through engineering investment to one in which part of the solution can be purchased competitively from customers already connected to the grid.

The commercial question would then no longer be simply how much electricity an asset can produce or consume.

It would be how much its behaviour is worth to the grid at a particular location and moment.

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Two developments illustrate the shift.

Transmission operator Transelectrica activated Romania’s first balancing reserve group made entirely from controllable electricity consumption in September, while Huawei Romania, Bamboo Energy and Flexumers are developing a virtual power plant that aggregates batteries installed at telecom sites.

The technologies are different, but the commercial model is the same.

Instead of building another power station, an aggregator identifies flexibility already embedded in the economy, combines hundreds or thousands of smaller assets and sells their coordinated response into electricity markets.

That could substantially expand the pool of capacity available for balancing Romania’s increasingly complex power system.

Factories start selling electricity they do not consume

On Sept. 1, a portfolio aggregated by Flexumers supplied 3 MW of upward manually activated frequency restoration reserve, or mFRR, entirely by reducing electricity consumption.

No generator or storage unit was involved.

For industrial consumers, that represents an important change in their relationship with the power market.

Factories traditionally buy electricity as a production input. Demand response allows them to sell another product: the ability to temporarily reduce or shift that consumption when the system needs it.

The factory does not necessarily stop production.

Flexible loads can include pumps, compressors, refrigeration, heating and ventilation systems, water treatment or other processes where electricity use can be moved for limited periods without materially affecting output.

An aggregator identifies those loads, establishes a consumption baseline and combines flexibility from several customers into a portfolio large enough to participate in electricity markets.

When Transelectrica requests an activation, the aggregator distributes the required response among participating consumers.

The customer can then receive part of the flexibility revenue.

The economic calculation is relatively straightforward: a company participates when the payment received for changing consumption exceeds the operational cost of doing so.

Regulation creates a new industrial service

Romania has also started putting the regulatory structure around that business.

Energy regulator ANRE approved rules in August allowing eligible consumers to provide consumption-flexibility services directly or through suppliers and aggregators, with remotely readable metering supporting measurement and verification.

That gives aggregators access to a potentially large pool of assets requiring little conventional energy investment.

Flexumers has estimated Romania could have about 700 MW of potential aggregation capacity, although only part of that theoretical resource will ultimately be technically available and commercially viable.

The importance is nevertheless considerable.

A steel plant, food processor, cement producer or logistics centre could become an electricity-market participant without owning a power plant.

Its flexible consumption becomes the asset.

Telecom batteries create a different kind of power plant

The second Romanian experiment takes the same principle into infrastructure that already contains physical energy storage.

Telecommunications networks require batteries to maintain service during electricity outages. Thousands of these installations spend most of their operating lives waiting for an emergency.

The partnership involving Huawei Romania, Bamboo Energy and Flexumers aims to determine whether part of that dormant capacity can also provide electricity-market services while preserving the batteries’ primary backup function.

Bamboo Energy provides optimisation technology, while Flexumers provides aggregation and market access.

The partners plan to test charging and discharging against market conditions and participation in mFRR and aFRR balancing services.

The concept differs from constructing a conventional grid-scale battery.

The batteries already exist.

The investment opportunity lies largely in software, communications, market access and optimisation needed to turn geographically dispersed devices into a single controllable portfolio.

A virtual power plant could therefore consist of thousands of relatively small assets that the electricity market sees as one resource.

From stranded capacity to recurring revenue

That creates a wider business opportunity.

Telecom operators traditionally treat backup batteries as a resilience expense.

Aggregation could potentially convert part of that expenditure into a revenue-generating asset.

The same principle could apply to other sectors.

Data centres, hospitals, logistics facilities, commercial buildings and industrial plants often maintain batteries, generators, thermal systems or other equipment whose primary purpose is not participation in electricity markets.

Some of that infrastructure may contain flexibility that can be monetised without undermining its core function.

The value lies in identifying exactly how much capacity can safely be made available, at what time and under what operational constraints.

That is essentially the aggregator’s business.

Romania becomes a test for the aggregator model

The emerging Romanian market therefore has two sides.

Industrial demand response converts controllable consumption into flexibility.

Virtual power plants convert distributed physical assets into flexibility.

An aggregator can eventually combine both.

A single portfolio could include factories temporarily reducing demand, telecom batteries discharging, commercial buildings adjusting HVAC systems and EV fleets delaying charging.

The electricity system would see the combined portfolio as controllable capacity rather than thousands of separate devices.

This makes aggregation fundamentally different from another renewable-energy or storage-development cycle.

The scarce asset is not necessarily generation capacity.

It is the ability to identify, verify and coordinate flexibility distributed across the economy.

The software layer becomes the market

The larger commercial opportunity therefore sits increasingly in software.

Aggregators need to forecast customer behaviour, determine asset availability, optimise bids, issue dispatch instructions, collect meter data and prove that requested flexibility was actually delivered.

They must also manage conflicts between different revenue opportunities.

A telecom battery cannot simultaneously provide its full capacity to several balancing products while retaining the reserve needed to protect the communications network.

Similarly, an industrial consumer cannot promise flexibility that its production schedule cannot reliably deliver.

Portfolio optimisation becomes the central product.

That creates potential markets for virtual power plant platforms, automated demand-response systems, industrial energy-management software and flexibility verification services.

Romania is therefore moving beyond the first stage of electricity-market liberalisation.

The emerging question is no longer only who can generate and trade electricity.

It is who can control the thousands of smaller loads and assets already connected to the system — and turn their flexibility into a bankable electricity-market product.

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Recent Slovenian pilots have shown that EV charging can be shifted towards cheaper periods without disrupting fleet operations, while the country’s regulator has identified a second problem: if thousands of customers respond to the same price signal simultaneously, flexibility can simply create a new electricity-demand peak.

That tension is pushing the market beyond conventional time-of-use tariffs towards a more sophisticated model in which consumption responds simultaneously to electricity prices, network conditions and operational requirements.

The commercial opportunity is substantial.

Instead of selling only electricity, suppliers, aggregators and energy-management companies can increasingly sell optimisation — deciding when vehicles charge, buildings consume electricity or industrial equipment operates.

Slovenia already has much of the infrastructure needed to support that model.

Its widespread smart-meter deployment provides granular consumption information that can be used to establish customer baselines, forecast flexible demand and verify whether an agreed reduction or shift in electricity consumption actually occurred.

The meter therefore becomes more than billing equipment.

It becomes part of the infrastructure required to operate a flexibility market.

EV fleets provide an early test

Electric vehicles provide one of the clearest examples.

Results from Slovenian pilots involving Avantcar and Kolektor sETup showed that fleet charging could be optimised against electricity-market conditions while maintaining vehicle availability.

The principle is straightforward.

A vehicle connected to a charger for eight hours may only need two or three hours of actual charging.

The difference between when the vehicle connects and when it must be ready gives an aggregator a window in which electricity demand can be moved.

Across hundreds or thousands of vehicles, those small windows become a significant flexible electricity portfolio.

For fleet operators, the immediate benefit is lower energy procurement costs.

For aggregators, the same flexibility could eventually be offered into balancing or local distribution-network markets where regulations permit.

That transforms an EV fleet from a passive electricity consumer into a potential grid resource.

Cheap electricity can create another peak

Slovenia’s national flexibility assessment, however, highlights the limitations of simple price optimisation.

If electricity or network tariffs become cheaper after a certain hour, automated chargers may all react simultaneously.

Instead of reducing system pressure, thousands of vehicles could begin charging together and create a new night-time peak.

The same risk applies increasingly to heat pumps, electric boilers and other automated loads.

The challenge therefore changes.

The first generation of demand-side programmes tried to persuade customers to move electricity consumption away from peak hours.

The second generation must prevent too many flexible devices from moving in exactly the same direction at exactly the same time.

That requires more granular signals.

Dynamic network tariffs add location to the equation

Dynamic network pricing offers one possible solution.

Traditional electricity tariffs primarily tell customers when electricity is expensive.

A more sophisticated network tariff can also signal when particular parts of the electricity grid are constrained.

That distinction becomes increasingly important as distributed solar, EVs, heat pumps and other flexible assets spread across distribution networks.

A megawatt of additional consumption may be beneficial in one location where local solar production is high and network capacity is available.

The same megawatt could worsen congestion elsewhere.

Future optimisation therefore cannot be based only on the question:

When is electricity cheapest?

It increasingly becomes:

When and where does the power system have capacity for additional consumption?

That is a fundamentally different market.

Smart-meter data becomes commercially valuable

Slovenia’s advanced metering infrastructure gives energy-service providers access to the type of consumption data required to answer that question.

Detailed meter data can reveal when customers consume electricity, how predictable that consumption is and how much could potentially be moved.

For an industrial consumer, that could mean identifying flexible pumps, compressors, cooling systems or production processes.

For a commercial building, it could involve heating, cooling or ventilation.

For an EV fleet, it means determining how long vehicles remain connected and how much energy each requires before departure.

Software can then combine hundreds of these individual profiles into a portfolio large enough to participate in electricity markets.

This creates a new commercial layer around meter-data analytics, automated demand response, consumption forecasting and flexibility verification.

The valuable infrastructure is no longer only the meter.

It is the software that converts meter readings into an asset the electricity system can dispatch.

From tariff response to automated flexibility

The longer-term model could become considerably more sophisticated.

A fleet-management platform could simultaneously examine wholesale electricity prices, network tariffs, local grid conditions, balancing-market revenues and the charging requirement of each vehicle.

An industrial energy-management system could perform the same calculation for production equipment.

The customer would set operational boundaries.

Software would decide when electricity should be consumed inside those limits.

That turns electricity flexibility into an automated service rather than a behavioural response to cheaper night-time tariffs.

It also gives aggregators a potentially important role between consumers and the power system.

Aggregators can combine thousands of small assets, forecast their availability and sell the resulting flexibility to parties that need it.

Those buyers could ultimately include suppliers, transmission operators and distribution companies.

Slovenia points towards the next SEE electricity business

The model has implications well beyond Slovenia.

Southeast European countries are investing heavily in smart-meter infrastructure, while EV charging, electric heating and distributed generation are increasing the amount of flexible electricity demand connected to distribution networks.

Most of those investments are still discussed in terms of equipment deployment.

The larger commercial question is what markets can be built once the equipment exists.

Slovenia suggests the next stage will centre on the interaction between smart-meter data, dynamic tariffs and automated consumption.

EVs are an early use case, but the same infrastructure could eventually coordinate commercial buildings, industrial processes, heat pumps, electric boilers and other controllable loads.

That creates an electricity-market business model with relatively little new generation capacity.

The asset already exists.

What is missing is the digital layer capable of determining when that asset should consume electricity — and turning the resulting flexibility into revenue.

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Recent regulatory and technical developments in Europe point towards a market increasingly built around aggregators, demand response, peer-to-peer trading, electric-vehicle charging, energy communities and digitally controlled distributed assets.

For Southeast Europe, that could gradually change the economics of electricity markets that have traditionally revolved around large power plants, wholesale trading and transmission capacity.

Two developments in September illustrate the shift.

EU energy regulator ACER has revised the frameworks governing the European MARI and PICASSO balancing platforms, introducing alternative qualification routes intended to make participation more accessible to smaller flexibility providers.

At the same time, Slovenian distribution company Elektro Ljubljana has highlighted a new European framework for assessing how peer-to-peer electricity trading affects distribution grids, helping move local electricity sharing from pilot projects towards systems that can be measured and integrated into grid operations.

Taken separately, the measures appear technical.

Together, they point towards a more significant structural change: thousands of smaller electricity assets could increasingly be coordinated into commercially useful portfolios.

From generators to aggregators

European balancing markets were historically designed around power stations capable of increasing or decreasing production when system operators needed additional flexibility.

Hydropower plants, thermal generators and, increasingly, large battery installations have dominated that role.

But electricity systems are accumulating millions of smaller flexible assets.

Factories can temporarily modify production schedules. Refrigeration systems can shift consumption without affecting temperatures. Commercial buildings can adjust heating and cooling. Electric vehicles can delay charging. Industrial boilers can respond to electricity prices. Distributed generators can alter exports.

Individually, these assets are usually too small to participate meaningfully in wholesale balancing markets.

Aggregated digitally, they can behave like a virtual power plant.

That is where ACER’s latest balancing-market changes become commercially important.

The revised framework introduces traditional activation testing alongside ex-post verification and fast-track qualification, giving national transmission operators additional ways to determine whether balancing-service providers can reliably deliver promised flexibility.

The objective is partly to prevent qualification procedures designed around conventional generators from becoming disproportionate barriers for smaller participants.

This could reduce one of the less visible obstacles facing aggregation businesses.

A company controlling 10 MW at a single power station is relatively straightforward to test. An aggregator controlling the same capacity through hundreds of factories, commercial loads, EV chargers or distributed generators faces a substantially different technical and administrative challenge.

Lower qualification barriers could therefore increase the number of assets capable of generating balancing-market revenues.

For electricity markets in Romania, Bulgaria, Greece, Hungary, Croatia and Slovenia, the opportunity is not simply greater participation in European balancing platforms.

It is the creation of an entirely new intermediary industry.

Electricity flexibility becomes a service

Aggregators do not necessarily own the assets they control.

Their business is coordinating them.

Software monitors electricity prices, balancing requirements, network constraints and customer operating conditions, then decides when individual assets should increase or reduce consumption or production.

A factory could therefore earn electricity-market revenue without becoming an electricity trader.

An aggregator could identify short periods when part of the factory’s electricity consumption can be reduced, combine that flexibility with dozens of other industrial sites and offer the resulting portfolio into the balancing market.

The customer receives part of the revenue while the aggregator manages forecasting, dispatch, market participation and settlement.

The same model could eventually extend to supermarkets, warehouses, water utilities, telecom infrastructure and commercial buildings.

Electric vehicles could become particularly important.

A fleet of several thousand vehicles represents a substantial electricity load, but most vehicles do not need to charge continuously.

Charging software can decide whether a vehicle should consume electricity immediately or several hours later, provided it is sufficiently charged when needed.

That difference in timing is flexibility.

Once aggregated, it becomes potentially tradeable.

The distribution grid becomes part of the market

The second emerging development is occurring lower in the electricity system.

Traditional wholesale electricity markets largely determine the value of electricity according to time and bidding zone.

But increasing distributed generation means location inside the distribution network is becoming more important.

Two identical megawatt-hours may have different system values if one is generated behind a congested transformer while another is produced where the network has spare capacity.

Peer-to-peer electricity trading and energy communities expose this problem particularly clearly.

A household or company can financially sell locally generated electricity to another participant, but that transaction still relies on physical distribution infrastructure.

If many participants export simultaneously, voltage can increase and local lines or transformers can become constrained.

Conversely, local consumption coordinated with local generation can reduce electricity flowing through higher network levels.

The new CWA 50784:2026 framework highlighted by Elektro Ljubljana addresses precisely this issue.

It provides a methodology for assessing peer-to-peer electricity transactions using data exchange, interoperability, grid visibility and measurable performance indicators.

That is important because it moves energy communities away from the simple concept of sharing solar production between participants.

The next stage is grid-aware electricity sharing.

Local electricity acquires a location value

A mature local electricity market could eventually send participants signals reflecting both wholesale electricity prices and local network conditions.

Imagine a commercial district with rooftop solar, EV chargers, heat pumps and several large electricity consumers.

During periods of strong solar generation, the local grid may benefit if EV fleets increase charging or commercial buildings shift cooling demand into those hours.

Instead of curtailing generation or reinforcing the grid, a distribution operator could potentially procure local flexibility.

The aggregator would coordinate participating assets.

The energy community would provide local generation.

Smart meters would provide verified consumption and generation data.

Software would determine the optimal response.

The electricity market would effectively gain another layer beneath traditional wholesale trading.

This creates opportunities for local flexibility markets, in which distribution operators procure congestion relief or voltage support from assets located in specific parts of their networks.

Several European countries are already experimenting with such models.

For Southeast Europe, where distribution systems will increasingly have to absorb distributed solar, EV charging and electrification of heating, the concept could become particularly relevant.

Smart meters become commercial infrastructure

The transition also changes the economic role of smart meters.

Utilities frequently present smart-meter programmes primarily as improvements in billing, remote reading and network management.

Their larger value could eventually lie elsewhere.

High-frequency consumption data allows suppliers and aggregators to understand when customers can provide flexibility.

A conventional electricity bill measures consumption.

A flexibility platform asks a different question: how much of that consumption could have occurred at another time?

That difference becomes commercially valuable.

Smart-meter infrastructure can therefore support dynamic tariffs, automated demand response, peer-to-peer settlement, energy communities and local flexibility markets.

This creates another emerging business category around meter-data management.

Companies capable of processing millions of consumption points, forecasting behaviour and converting that information into dispatch instructions could occupy a strategically important position between electricity customers, suppliers, aggregators and network operators.

Dynamic tariffs need smarter optimisation

Dynamic tariffs are another component of the emerging system.

They allow consumers to respond to electricity-market prices rather than paying one fixed price throughout the day.

But price-based optimisation alone creates new risks.

If thousands of electric vehicles receive the same signal that electricity becomes cheap at 2 a.m., they could all begin charging simultaneously.

A new demand peak could simply replace the old one.

The more advanced model therefore combines several signals.

A fleet-management platform might consider the wholesale electricity price, local network congestion, distribution charges, balancing-market opportunities and the time by which every vehicle must be charged.

The optimisation problem is no longer simply:

When is electricity cheapest?

It becomes:

When and where is electricity consumption most valuable to the entire system?

That difference defines the emerging flexibility economy.

Southeast Europe has substantial untapped flexibility

The region has several characteristics that could make these markets commercially significant.

Electricity systems across Southeast Europe contain large industrial consumers, district-heating systems, water utilities, commercial refrigeration, tourism infrastructure and increasingly large EV-charging portfolios.

Many of those loads contain some degree of flexibility.

Countries also face rising costs associated with network reinforcement and integrating distributed renewable generation.

Using flexibility cannot eliminate the need for grid investment.

But it can change when and where investment is required.

A transformer constrained for only a few dozen hours each year may not immediately need replacement if consumption can be shifted during those specific periods.

Similarly, a distribution network experiencing midday solar congestion may benefit more from flexible local demand than from additional grid infrastructure.

The economic calculation therefore changes from building capacity for every possible peak towards combining infrastructure with digitally managed flexibility.

A new electricity-market value chain

The emerging market could produce a value chain substantially different from the traditional utility model.

Generators will still sell electricity.

Traders will still manage wholesale-market positions.

Grid operators will still maintain networks.

But another group of companies will increasingly monetise flexibility, information and coordination.

Aggregators will combine distributed assets.

Software providers will optimise consumption.

Energy communities will organise local generation and demand.

EV platforms will control charging.

Smart-meter systems will provide settlement data.

Distribution operators may procure local flexibility.

And industrial consumers could become electricity-market participants without changing their core businesses.

This is already visible in the regulatory architecture now being developed.

ACER’s balancing reforms address how smaller distributed assets can enter European balancing markets.

Slovenia’s work around peer-to-peer electricity trading addresses how distributed transactions interact with physical distribution networks.

The next step is connecting the two worlds.

An electricity consumer could eventually provide flexibility locally to a distribution operator, nationally through an aggregator and indirectly to European balancing markets.

The same physical asset could therefore generate multiple forms of value.

The critical question will be avoiding double counting and determining which market has priority when several parties want access to the same flexibility.

Those issues will require new contractual arrangements, metering systems and market rules.

But they also represent commercial opportunities.

Southeast Europe’s electricity market is therefore entering a phase in which investment opportunities will not be limited to another wind farm, solar project, battery or transmission line.

Increasingly, value will come from the digital layer connecting assets already attached to the system.

The region’s next power-market winners may not necessarily own the most generation.

They may control the software that decides when thousands of other assets consume, produce or stop consuming electricity.

The post Southeast Europe’s next power market is flexibility, not just electricity appeared first on Serbia SEE Energy Mining News.

Production was also 7% lower than in July.

Thermal generation dropped 42% year on year to 42 GWh, while hydropower fell 33% to 191 GWh.

Output from the Krsko nuclear power plant declined 9% to 458 GWh.

Wind and solar moved in the opposite direction, rising 19% to 228 GWh, but the increase was insufficient to offset lower conventional generation.

Slovenian electricity imports rose 12% year on year to 869 GWh, while exports fell 14% to 716 GWh.

The combination widened Slovenia’s dependence on neighbouring markets during the month.

Household electricity consumption reached 251 GWh, up 7% from July, while commercial consumption fell 4% to 593 GWh.

The August figures illustrate how weaker hydro and conventional generation can rapidly change Slovenia’s cross-border position even as renewable capacity expands.

For the regional market, Slovenia’s import requirement increases the importance of available flows from Austria, Hungary, Croatia and Italy, particularly during periods of tighter hydro availability.

The post Slovenia power output falls 13% as imports rise appeared first on Serbia SEE Energy Mining News.

The permit allows Bulgargaz to conduct commercial gas trading on the Serbian market.

The company already holds licences in Greece, Romania, Hungary and Slovakia, while subsidiary Bulgargaz North is authorised to trade in Moldova.

Bulgargaz is also registered as a transmission-network user in several regional markets, including Serbia, giving it access to cross-border infrastructure required to move gas between supply zones.

The Serbian licence strengthens a business model increasingly focused on regional trading rather than Bulgaria alone.

For Serbia, the arrival of another licensed regional supplier potentially broadens commercial sourcing options as the domestic market becomes more connected with Bulgaria, Hungary and other neighbouring gas systems.

For Bulgargaz, combining transmission access with wholesale licences across multiple jurisdictions should improve its ability to redirect volumes in response to regional price spreads, infrastructure availability and customer demand.

The post Bulgargaz secures 10-year Serbian gas-trading licence appeared first on Serbia SEE Energy Mining News.

Thermal plants produced 153,556 MWh, or 33.4% of total generation, down 16.5% from July 2025.

Hydropower increased 23.7% to 99,349 MWh, while wind production rose 28.3% to 30,810 MWh.

Solar remained the country’s largest individual generation source during the month, producing 167,044 MWh, or 36.3% of total output, although solar production was 7.6% lower year on year.

Electricity consumption reached 486,007 MWh, with domestic generation covering 94.7% of demand.

Imports fell to 93,154 MWh from 114,930 MWh a year earlier, while exports dropped much more sharply to 67,182 MWh from 151,919 MWh.

The figures show a power system increasingly shaped by renewable generation but still dependent on thermal plants and cross-border trading to balance demand.

The sharp fall in exports also indicates that lower domestic production is reducing North Macedonia’s ability to place surplus electricity into neighbouring markets.

The post North Macedonia power output falls 22% despite stronger hydro and wind appeared first on Serbia SEE Energy Mining News.

The project will consist of two units of approximately 499 MW each, providing dispatchable generation and balancing capacity as Hungary adds more variable renewable electricity.

Testing and commercial operation of the first unit are planned for the third quarter of 2029, with the second scheduled for the first quarter of 2030.

Calik Enerji Swiss and Ansaldo Energia were selected to deliver the project and major equipment.

Construction is currently focused on foundations capable of supporting the plant’s turbines and generators, with activity expected to accelerate from 2027.

The project is strategically significant for Hungary because rapid solar expansion is creating increasingly large differences between daytime and evening power balances.

A 1 GW flexible gas plant would provide additional capacity during low-renewable periods while supporting balancing requirements when solar generation falls rapidly.

Hungary’s extensive gas-storage infrastructure also gives the project a domestic flexibility advantage, although its long-term economics will remain linked to gas, carbon and electricity-price spreads.

The post Hungary starts work on 1 GW Tiszaujvaros gas-fired power plant appeared first on Serbia SEE Energy Mining News.

The river level has fallen to around 20.64 metres under the Baltic measurement system following prolonged dry conditions across Europe.

Unit 5 is currently the only reactor affected.

Kozloduy operates a staged procedure for low-water conditions. Monitoring intensifies below 21.5 metres, while additional reserves and preparations for controlled shutdown are introduced around 21 metres.

Output reductions can become necessary at about 20.5 metres if the shore pumping station cannot provide sufficient water.

A further decline toward 20.3 metres could require substantially deeper reductions in electricity generation. At around 19.7 metres, almost all shore pumps would be shut down.

The immediate effect is therefore reduced available generation rather than a safety issue.

For the regional electricity market, however, the episode again highlights the exposure of thermal and nuclear generation along major rivers to increasingly volatile hydrological conditions. Further declines in Danube levels could remove additional firm generation from an already weather-sensitive SEE power system.

The post Bulgaria: Low Danube levels force Kozloduy nuclear output cut appeared first on Serbia SEE Energy Mining News.

The investigation is examining how movements in crude-oil prices, refinery costs and other inputs are reflected in wholesale petrol and diesel prices.

The latest request covers the period from May 1 to Sept. 28, 2026 and requires detailed information on deliveries, production expenses and the individual components used to calculate wholesale prices.

The companies have also been asked to explain how costs are calculated and allocated and have seven days to submit the requested information.

The regulator plans to compare movements in underlying production costs with changes in wholesale prices to assess how quickly lower or higher input costs are transmitted to the Bulgarian market.

The latest request extends an existing examination of Lukoil’s position in Bulgaria’s fuel sector rather than opening an entirely new case.

The investigation comes at a sensitive moment for regional fuel markets, where refinery economics, crude-price volatility and changing supply routes continue to influence retail and wholesale pricing.

The post Bulgaria expands Lukoil fuel-pricing investigation appeared first on Serbia SEE Energy Mining News.

The October TTF contract traded at €71.16/MWh, about 10.5% below the previous week’s €79.51/MWh. The contract had briefly recovered to €74.94/MWh on Sept. 24 as uncertainty over US-Iran contacts and LNG shipments returned before weakening again.

EU gas storage was 70.24% full on Sept. 24, compared with more than 80% a year earlier. Lower inventories have so far failed to generate sustained upward price pressure as demand remains below levels seen during the 2021-2022 energy crisis and Europe has expanded LNG import capacity and diversified supplies.

The latest decline accelerated after reports that Iran could consider reopening the Strait of Hormuz if talks with the United States resumed and restrictions affecting Iranian ports were removed.

The market remains highly exposed to developments around the strait. A prolonged disruption could force European and Asian buyers into stronger competition for alternative LNG cargoes just as heating demand begins to rise.

European authorities are due to reassess storage, supply conditions and winter preparedness in early October, leaving geopolitical developments and LNG availability as the main near-term risks to the softer gas-price trend.

The post European gas prices retreat as Hormuz fears ease, but winter supply risk remains appeared first on Serbia SEE Energy Mining News.

Hungary’s HUPX base price rose €47.3/MWh to €161.19/MWh, while Romania climbed to €154.34/MWh, Bulgaria to €146.11/MWh and Greece to €135.11/MWh.

Croatia settled at €166.14/MWh, Montenegro at €165.13/MWh, Slovenia at €168.95/MWh, North Macedonia at €150.41/MWh and Albania at €129.40/MWh.

Serbia recorded the region’s lowest average at just €111.69/MWh, little changed from Sunday and around €49.5/MWh below HUPX. The unusually wide Serbian discount persisted despite the country remaining a net electricity importer.

Western markets were substantially stronger. Germany traded around €195.40/MWh, Austria at €174.51/MWh and Italy at about €203.55/MWh, preserving a strong economic incentive for electricity to move west where cross-border capacity was available. 

Regional consumption increased by about 3.65 GW from Sunday to 28.83 GW, helping restore the weekday premium after the weekend price collapse.

At the same time, the combined Hungary and SEE system moved from an almost balanced position on Sunday to net exports averaging around 1.39 GW. About 1.26 GW flowed toward Italy, while roughly 547 MW moved toward Austria and Slovakia.

The change in cross-border direction was one of the strongest drivers behind Monday’s market recovery.

Bulgaria exported an average 1.33 GW, Romania about 754 MW, Greece 1.35 GW and Bosnia and Herzegovina around 530 MW. Hungary remained a net importer of about 821 MW, Croatia imported around 859 MW and Serbia about 394 MW.

Romania emerged as an important east-to-west transit source, with flows toward Hungary reaching around 1.92 GW on average. Bulgaria simultaneously supplied approximately 1.15 GW to Romania and almost 390 MW to Serbia, highlighting the increasingly interconnected flow structure across the eastern SEE markets.

Hungary then redistributed part of those imports west and south, exporting around 851 MW toward Austria, 679 MW toward Slovenia and 515 MW toward Croatia.

The resulting pattern shows that Hungary is increasingly functioning not simply as an import-dependent market but as a major transit hub linking lower-priced eastern generation with Central European demand.

Serbia remained the most important pricing anomaly.

SEEPEX traded around €34/MWh below Bulgaria, almost €43/MWh below Romania and close to €50/MWh below Hungary. Yet Serbia was still importing electricity overall, demonstrating that a national net balance alone increasingly provides little explanation for day-ahead price formation.

Instead, individual interconnector constraints, hourly commercial schedules and congestion determine whether cheaper electricity can reach neighbouring premium markets.

The hourly curves also showed the growing value of flexibility.

HUPX fell to around €5.6/MWh during the midday renewable period before climbing to €342.2/MWh at hour 20. Serbia ranged from around €20/MWh during the low-price period to €276.6/MWh in the evening.

Greece briefly reached €0/MWh around midday before recovering toward an evening maximum of about €271/MWh.

The result was another day in which the difference between individual hours was considerably larger than the difference between many national daily averages.

Strong solar production continues to compress midday prices, while the evening decline in renewable output rapidly restores premiums for flexible hydro, gas generation, storage and imports.

For traders, the Sept. 28 session therefore carried two signals. Weekday demand and stronger westbound exports restored higher average prices across most of SEE, but the region remains far from fully converged.

The increasingly valuable trade is not simply exposure to the regional base price. It is the ability to capture the widening spreads between countries and, increasingly, between oversupplied midday hours and the evening flexibility premium.

The post SEE power prices rebound as weekday demand returns, Serbia stays sharply discounted appeared first on Serbia SEE Energy Mining News.

The distinction is becoming increasingly important as CBAM, corporate carbon reporting and EU buyer requirements converge.

How the model works

A guarantee of origin establishes a renewable-energy attribute.

That remains valuable for corporate renewable sourcing.

But an actual-emissions methodology can require much more.

Depending on the applicable rule, the buyer may need evidence concerning the generating installation, contractual chain, physical delivery, allocation, metering and verification.

A GoO alone does not prove all of those elements.

Commercial impact

That creates two green-power tiers.

The first is certificate-backed electricity.

The second is evidence-controlled electricity designed for a defined carbon-accounting purpose.

The second product is more expensive to build because it requires greater contractual discipline, data quality and record keeping.

But it can also be more valuable to customers facing regulatory or buyer-driven emissions requirements.

Who benefits

Renewable producers capable of providing granular data can differentiate their electricity.

Suppliers gain a premium industrial product.

MRV and verification providers gain new service demand.

Industrial customers can select energy products according to the emissions claim they actually need to support.

Why it matters now

EU electricity and indirect-emissions methodology continues to evolve, increasing the importance of separating renewable marketing claims from verified carbon claims.

The emerging market is therefore no longer simply green versus conventional electricity.

It is certificate-backed green electricity versus electricity engineered from the outset to support a controlled and verifiable emissions claim.

By Virtu.Energy

The post Green electricity splits into certificate-backed and verification-ready products appeared first on Serbia SEE Energy Mining News.

CBAM is pushing that question into renewable-energy due diligence.

The issue is especially important where project revenues depend on exports to the EU or premium supply to export-oriented industry.

How the model works

Traditional renewable-project due diligence examines resource, construction, grid connection, permits, operating costs and contracted revenues.

The additional layer examines the commercial usability of the electricity attributes.

If a project assumes that its output will command a premium because it supports the customer’s carbon strategy, lenders need to determine whether the contractual and evidence structure actually supports that claim.

That can include PPA architecture, metering, generation allocation, certificates and delivery arrangements.

Commercial impact

A PPA may look bankable from a conventional power-market perspective but be weaker if part of its premium depends on a carbon claim that cannot be substantiated.

Conversely, strong documentation and allocation systems can make renewable output more valuable to sophisticated industrial buyers.

Banks may therefore increasingly add a carbon and evidence due-diligence workstream alongside legal, technical and financial reviews.

Who benefits

Projects with strong evidence architecture gain an advantage.

Banks get better visibility over green-premium revenue assumptions.

Industrial offtakers receive electricity products designed around their sourcing needs.

Technical, legal and verification advisers gain additional due-diligence work.

Why it matters now

Renewable projects across Southeast Europe are being financed with increasingly diverse combinations of merchant exposure, CfDs, guarantees and corporate offtake.

The next lending question is therefore not simply:

Who buys the electricity?

It is:

Can that buyer use the renewable and carbon characteristics in the way the project’s revenue model assumes?

By Virtu.Energy

The post Renewable lenders add CBAM evidence risk to project bankability appeared first on Serbia SEE Energy Mining News.

They may increasingly have to preserve and transmit the information attached to that power.

That could turn larger trading houses into intermediaries between renewable generators, industrial consumers, EU importers and verification systems.

How the model works

A conventional trader can blend electricity from multiple producers into one commercial portfolio.

That is efficient when the buyer cares primarily about price and volume.

It becomes more difficult when the buyer wants to demonstrate that electricity is linked to a specific low-carbon installation or needs evidence for an emissions calculation.

The trader must then preserve a chain involving installation identity, contracts, meter records, allocation, schedules and potentially cross-border delivery information.

Commercial impact

That creates a higher-value trading product.

Instead of selling anonymous portfolio electricity, a trader can sell identified electricity with a controlled evidence chain.

The package may include physical supply, balancing, renewable certificates, allocation and documentation.

This requires stronger back-office systems and tighter coordination between traders, meter-data platforms, contract teams and counterparties.

The administrative chain becomes part of the commodity.

Who benefits

Large traders with strong scheduling and settlement capabilities are well positioned.

Renewable generators gain market access without building their own cross-border trading operations.

Industrial buyers gain an intermediary capable of assembling data from multiple upstream sources.

Software providers gain opportunities around chain-of-custody and allocation systems.

Why it matters now

Current CBAM electricity rules have already shown that actual-emissions claims can be difficult to use commercially without a strong evidence trail.

The emerging electricity trader is therefore not only an intermediary for electrons and money.

It is an intermediary for electricity, carbon attributes and the evidence connecting them.

By Virtu.Energy

The post CBAM turns electricity traders into evidence intermediaries appeared first on Serbia SEE Energy Mining News.