The regional price signal was shaped by two opposing forces. Forecast electricity demand across Hungary and Southeast Europe increased by 1,111 MW, or approximately 3.5%, reaching 32,972 MW, as average temperatures rose by 1.4°C to 25.8°C. At the same time, renewable availability improved significantly. Expected solar generation increased by 508 MW to 7,767 MW, while wind generation rose by 767 MW to 3,207 MW. The combined renewable gain of 1,275 MW exceeded demand growth and reduced the region’s net import requirement by 442 MW, bringing it down to 1,410 MW.

However, the improvement was more visible in the physical supply balance than in market price formation. Imports from Austria and Slovakia into Hungary and Slovenia remained elevated at 2,140 MW, although they declined by 447 MW day on day. Meanwhile, exports from Southeast Europe towards Italy increased slightly to 888 MW, leaving the region exposed simultaneously to central European imports from the north and strong Italian demand from the west.

Hungary remained one of the region’s key price drivers. HUPX settled at €132.14/MWh, almost unchanged from Wednesday despite stronger renewable forecasts. Hungarian consumption increased to 4,672 MW, while domestic generation was forecast at only 3,174 MW, leaving a net deficit of 1,498 MW. The deficit widened from 1,208 MW on the previous day, keeping Hungary dependent on imports even as regional renewable availability improved.

The hourly structure of the Hungarian electricity market was more significant than the daily average. Prices fell to €12.20/MWh in hour 14, when solar generation was strongest, before rising sharply to €296.10/MWh in hour 20. The nearly €284/MWh difference between the daily minimum and maximum shows that additional photovoltaic capacity is suppressing midday prices but remains unable to solve evening system adequacy requirements. The market is increasingly valuing flexibility, ramping capability and cross-border availability rather than only overall energy supply.

Hungary maintained a €10.82/MWh premium over Germany, more than double the previous day’s spread. Germany settled at €121.33/MWh, while Austria remained slightly above Hungary at €134.13/MWh. Slovenia almost exactly matched HUPX at €132.19/MWh, while Croatia followed at €130.96/MWh. This northern price cluster reflected similar exposure to reduced firm generation and continued import requirements. Nuclear output across monitored markets declined by 552 MW to 4,466 MW, following constraints linked to low Danube water levels and reduced production at major nuclear facilities.

Romania reflected the same structural pressure. OPCOM settled at €130.15/MWh, only €1.99/MWh below Hungary, while Romanian consumption was forecast to rise by 172 MW to 5,574 MW. Generation was projected at 5,075 MW, leaving Romania with a 499 MW supply deficit. Despite this, commercial flows remained strong towards Hungary during peak periods, including average Romanian-to-Hungarian peak transfers of 1,224 MW. Romania also relied heavily on Bulgarian electricity imports, with Bulgarian-to-Romanian flows reaching approximately 1,641 MW on a baseload basis.

Bulgaria continued to operate as one of Southeast Europe’s main surplus electricity markets. Forecast generation of 4,998 MW exceeded consumption of 3,840 MW, creating a net export position of 1,158 MW. Nevertheless, IBEX increased by €9.80/MWh to €112.37/MWh. Bulgaria remained €19.77/MWh below Hungary but narrowed part of the previous session’s discount as exports towards Romania absorbed additional domestic surplus production.

The Bulgarian hourly curve remained relatively weak during solar production hours, reaching a minimum of €12.10/MWh in hour 15, while the evening peak was limited to €170.80/MWh. The country’s nuclear fleet and expanding solar capacity provided a more stable supply base than markets farther north. Its ability to export more than 1.6 GW towards Romania during parts of the day was central to balancing the Romanian and Hungarian systems.

Greece recorded one of the lowest liquid-market prices in Southeast Europe. HENEX declined by €3.30/MWh to €92.52/MWh, widening its discount to Hungary to €39.62/MWh. Greek peakload prices averaged only €42.70/MWh, while midday prices reached zero in hour 11. At the same time, Greece moved into a forecast net export position of 1,576 MW, compared with 1,015 MW on Wednesday.

The lower Greek price was supported by cooler weather conditions, with average temperatures expected to decline by 2°C to 26.8°C, reducing cooling demand while renewable and thermal availability remained sufficient. The large price gap between Greece and Hungary created a strong south-to-north trading signal, although transmission constraints and incomplete regional market coupling prevented full monetisation of the arbitrage opportunity.

Serbia recorded the largest day-on-day price decline among established regional exchanges. SEEPEX fell by €40.70/MWh to €104.77/MWh, leaving Serbia €27.37/MWh below Hungary. Electricity consumption was forecast to rise sharply to 3,859 MW, while generation recovered to 3,317 MW. The resulting deficit narrowed from 865 MW to 543 MW because generation growth exceeded demand growth.

The Serbian hourly price profile was less extreme than Hungary’s, with SEEPEX reaching €30.10/MWh in hour 12 and a maximum of €208/MWh in hour 20. Serbia continued importing electricity from neighbouring systems, including approximately 342 MW from North Macedonia, 253 MW from Bulgaria and 85 MW from Romania on average, while maintaining exports of around 156 MW towards Montenegro.

The SEEPEX decline reflected improved domestic availability, stronger regional renewable generation and cheaper imports from southern and eastern neighbours rather than a structural return to surplus. Serbia remained dependent on imports, particularly during peak hours, when the deficit widened to approximately 881 MW.

Montenegro moved in the opposite direction. BELEN increased by €10.90/MWh to €151.71/MWh, becoming the most expensive Southeast European exchange and placing the market €19.57/MWh above Hungary. Consumption increased to 469 MW, while forecast generation reached only 337 MW, leaving a deficit of 132 MW.

The Montenegrin market recorded a minimum price of €53/MWh in hour 9 and a maximum of €250/MWh in hour 21. Off-peak prices averaged €180.30/MWh, indicating that scarcity extended beyond the traditional evening peak. Montenegro continued receiving electricity from Bosnia and Herzegovina, Serbia, Albania and Kosovo, while transferring approximately 514 MW towards Italy through the submarine interconnector.

Italy remained the region’s dominant external price benchmark. The Italian national price increased by €5.30/MWh to €182.43/MWh, creating a premium of €50.29/MWh over Hungary. Northern Italy settled at €180.20/MWh, while the southern zone reached €184.60/MWh. The national minimum remained exceptionally high at €150.10/MWh, indicating persistent Italian market tightness throughout the day.

The Italian premium supported continued westward flows from Slovenia and Montenegro and limited the amount of surplus Balkan electricity available to ease pressure in Hungary and Croatia. Croatia remained a significant deficit market, with consumption of 2,429 MW against generation of only 1,155 MW. Its net import requirement widened to 1,274 MW, although integration with Slovenia and Hungary kept CROPEX close to the northern regional price cluster.

The forward market delivered an even stronger warning about Hungarian system tightness. Hungarian Week 32 increased by €9/MWh to €212/MWh, while Week 33 rose by €11.50/MWh to €157.50/MWh. The Week 32 premium over Germany widened to €84/MWh, compared with Hungary trading at a €32.50/MWh discount to Italy for the same product.

This unusual pricing structure, with Hungary trading above Germany and Italy in some contracts, indicates that traders are assigning a substantial risk premium to Hungarian and interconnected regional supply availability during the first week of August. The move was reinforced by the wider energy complex, with Austrian CEGH gas rising to €60.83/MWh, EU carbon allowances increasing to €82.02/t and API2 coal advancing to $122.50/t.

Thursday’s stronger renewable generation outlook reduced immediate import demand but failed to remove the scarcity embedded in evening prices and forward markets. The main trading opportunity remains the widening gap between lower-priced southern markets and expensive Hungarian and Italian demand centres. Ultimately, the ability to capture that value depends less on regional generation volumes and more on available cross-border transmission capacity.

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The state-controlled producer’s total hydrocarbon output declined 3.2 per cent to 15.67 million barrels of oil equivalent. Natural-gas output fell 3.4 per cent, while gas marketed from domestic production decreased 6.4 per cent to 2.36 billion cubic metres.

Storage withdrawals increased 17.8 per cent to 1.47 billion cubic metres, but injections fell by the same percentage to 764.1 million cubic metres. Romgaz’s electricity production dropped 46.7 per cent to 182 GWh.

The combination matters more than any single figure. Lower production is reducing the volume available for sale and injection, while heavier withdrawals show that storage performed more work during the preceding tight period. Neptun Deep is expected to transform Romania’s supply position from 2027, but it does not solve the immediate 2026–27 winter-balancing requirement.

Elsewhere, Bulgaria’s public supplier is proposing an August regulated gas price of approximately €37.36/MWh, about 0.9 per cent below July’s €37.70/MWh. Most contracted August gas will come from Azerbaijan, although planned maintenance will reduce those deliveries. Bulgargaz intends to use withdrawals from Chiren and LNG arriving through Greece, with no Turkish LNG deliveries currently planned for the month.

Greece has become more important to that balancing strategy. Its gas exports reached 8.72 TWh in the first half of 2026, more than three times the 2.86 TWh recorded a year earlier. Revithoussa supplied 18.61 TWh of imports, up 27 per cent, while the Alexandroupoli FSRU handled 3.46 TWh, more than triple its previous-year volume.

The northern gas corridor is therefore becoming commercially active, but the region remains exposed to international LNG prices and storage availability. Bulgaria can hold its regulated price below the broader European benchmark for a month by combining Azerbaijani gas, inventories and contracted LNG. Sustaining that discount through winter will depend on Chiren replenishment and the continued availability of Greek import infrastructure.

The latest financing activity shows a market becoming more discriminating. Debt is reaching permitted wind farms, strategic substations and established transmission contractors, while multi-billion-euro pumped storage, SMRs and AI-related power systems remain conditional on feasibility, governance and credible revenue arrangements.

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Colenco will assist with procurement, reporting and compliance with the environmental, social and financing requirements attached to the project. The appointment is modest in value but represents the transition from financing preparation towards physical implementation.

The EBRD is providing as much as €30 million of project debt and €268,700 of technical assistance. The European Union is adding an €8.05 million investment grant and €1.2 million of technical-assistance funding. The combined public financing and advisory package therefore approaches €39.5 million before any KESH equity contribution.

Belsh is strategically different from Albania’s traditional hydro portfolio. Solar production can preserve reservoir water during daylight hours, leaving KESH with more dispatchable hydroelectricity for evening demand or exports. That complementary operating profile becomes particularly valuable during droughts, when each unit of stored water carries a higher opportunity cost.

The project’s investor relevance lies less in its 50 MW scale than in its financing structure. EBRD procurement and environmental conditions should improve execution discipline, while the EU grant reduces the effective capital cost. Colenco’s cross-border appointment also demonstrates the development of a regional engineering and owner’s-consultant market rather than complete dependence on Western European advisers.

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The reconstruction of the 220/110 kV Perućica substation is intended to enable the integration of as much as 350 MW of hydropower capacity. Work at the 400/220/110 kV Pljevlja 2 facility will reinforce Montenegro’s connection to the Trans-Balkan Electricity Corridor and prepare the northern network for a gradual reduction in coal dependence.

The sequencing is financially useful. Montenegro has accumulated solar, wind, storage and hydropower development ambitions that substantially exceed current domestic peak demand. Strengthening substations and transmission paths before the associated generation is commissioned reduces curtailment and connection-delay risk.

AFD is making its first energy-sector investment in Montenegro, following technical preparation by RTE International. The combination of concessional debt, an EU grant and a sovereign guarantee should produce a lower financing cost than CGES could achieve through an unsupported commercial loan.

The investment also protects the value of the Italy–Montenegro submarine interconnector. New generation in northern and central Montenegro can earn higher export revenue only if electricity can reach the coastal converter station without being trapped behind internal constraints.

CGES operates 1,512 kilometres of transmission lines and 29 substations. The state owns 55.4 per cent, Italy’s Terna 22.1 per cent and Serbia’s Elektromreža Srbije 15 per cent, giving the company a shareholder structure aligned with Montenegro’s cross-border trading position.

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The project has approximately 50 MW of capacity, all necessary permits and forecast annual net generation of 110 GWh. That implies a capacity factor near 25 per cent, a relatively conservative level that provides some protection against overestimating wind resources in the lender’s base case.

The loan covers at least 60 per cent of project cost. BCR’s wider exposure can reach €61.6 million when the term loan, VAT facility and debt-service reserve arrangements are included. OMV Petrom and Renovatio each own 50 per cent of Electrocentrale Borzești.

Gura Văii forms part of approximately 300 MW of wind projects that reached final investment decision in April. The wider portfolio includes the 100 MW Podu Turcului and 155 MW Poiana projects, while a separate 657 MW Galați development has not yet reached FID. Production from the construction-stage portfolio is expected to begin progressively from the first half of 2027.

The financing demonstrates the threshold now separating credible Romanian renewables from the large speculative pipeline. Gura Văii has named sponsors, permits, a quantified generation forecast, committed equity and a domestic bank prepared to provide construction debt. Many projects holding preliminary grid approvals still lack several of these elements.

At €47 million for 50 MW, the investment loan equals approximately €940,000 per megawatt. If debt represented exactly 60 per cent of total cost, implied project capital expenditure would be around €78 million, or €1.56 million per megawatt. The final capital intensity may be lower because the loan covers at least 60 per cent rather than precisely that amount.

OMV Petrom’s objective is to exceed 2.5 GW of renewable capacity by 2030 with partners. It has about 70 MW operating and 1.5 GW in development. The Gura Văii transaction shows that the group is using joint ventures and project debt to expand without placing every euro of construction expenditure directly on its own balance sheet.

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The operational consequences extend beyond the controlled shutdown of Cernavodă Unit 1. Romania has warned that Unit 2 could also be disconnected if the river reaches its operating limits. Bulgaria’s two approximately 1 GW Kozloduy reactors are designed with a dedicated pumping station, but the depth and duration of the present event have brought cooling-water availability under closer scrutiny.

Serbia faces the broadest exposure. Besides the loss of hydropower generation and reduced cooling at Kostolac, fuel imports during July reached only about 25 per cent of their planned volume because barges were loading at 30–40 per cent of normal capacity. Replacement transport by road and rail raises the delivered cost of fuel and cannot immediately reproduce the scale of river logistics.

The regional price effect is nonlinear. A missing megawatt of hydroelectricity during a well-supplied solar hour may have limited value, but the same shortfall during the evening ramp can require gas-fired generation or constrained imports. Drought therefore magnifies the daily spread even where average renewable output remains substantial.

It also changes the economics of proposed hydro investments. Reservoir and pumped-storage projects retain considerable flexibility value, but lenders will require more conservative assumptions for water availability, operating head and environmental releases. The present event strengthens the case for storage while simultaneously demonstrating that water-dependent storage cannot be treated as immune to climate risk.

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Serbia recorded the region’s highest principal exchange price at €145.13/MWh, an increase of €28.59/MWh or 24.5 per cent from Tuesday. Montenegro followed at €143.21/MWh, Slovenia at €141.59/MWh and Croatia at €138.73/MWh. Austria settled close to Croatia at €138.18/MWh.

Romania rose almost 18 per cent to €132.87/MWh, marginally above Hungary’s €132.34/MWh. Greece strengthened to €125.60/MWh, while North Macedonia cleared at €114.71/MWh.

Bulgaria moved against the regional trend, falling €7.28/MWh to €101.81/MWh. This opened a €43.32/MWh Serbia–Bulgaria spread and a €41.40/MWh Montenegro–Bulgaria spread. Italy was cheaper still at €98.06/MWh, reversing its normal position as the premium destination for Balkan exports.

The price map indicates that the immediate scarcity is no longer concentrated in Hungary or Italy. Serbia, Montenegro, Croatia and Slovenia are carrying the higher marginal value, reflecting weaker hydropower, constraints on thermal generation and the cost of obtaining replacement electricity through congested corridors.

Romania’s rise incorporates the loss of approximately 700 MW from Cernavodă Unit 1, while Serbia’s position is being shaped by exceptionally poor Danube hydrology. Đerdap 1, the country’s largest hydropower plant, has been producing about 5,000 MWh a day—roughly one-third of its normal daily output. Low river levels have also reduced cooling availability at the Kostolac coal complex and constrained the movement of fuel by barge.

Bulgaria’s lower price does not imply a weak domestic market. Electricity production between 1 January and 26 July increased 5.61 per cent to 25.02 TWh, while consumption rose faster, by 6.54 per cent to 23.56 TWh. The country retained a 1.46 TWh export surplus, but this was below the 1.57 TWh recorded a year earlier.

Hydropower supplied the largest improvement, almost doubling from 1.69 TWh to 3.27 TWh. Renewable generation connected to the transmission network rose 11.87 per cent to 2.62 TWh, while distribution-level renewable output increased 4.14 per cent to 2.48 TWh. Bulgaria can therefore maintain a low short-run marginal price, but faster consumption growth is gradually reducing the volume available for export.

The commercial value of cross-border capacity has consequently rotated towards supplying Serbia, Montenegro and Croatia. A trader holding firm capacity out of Bulgaria can access spreads above €35–€40/MWh on the daily average, although physical losses, nomination limits and intermediate congestion will absorb part of that margin.

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The strongest increase was recorded in Serbia, where the SEEPEX baseload price climbed by €29.0/MWh to €145.50/MWh, placing it €13.16/MWh above Hungary and above all neighbouring markets except Albania. Croatia increased by €23.3/MWh to €138.73/MWh, Romania rose by €22.1/MWh to €132.87/MWh, Slovenia gained €16.4/MWh to €141.83/MWh, and Montenegro advanced by €15.7/MWh to €140.79/MWh.

Hungary’s HUPX benchmark increased by €10.3/MWh to €132.34/MWh, remaining close to Germany, where the day-ahead price reached €126.84/MWh. The Hungarian premium over Germany was therefore limited to €5.50/MWh, although this masked a more stressed forward market and significant hourly volatility, particularly during the evening ramp.

In contrast, Greece and Bulgaria experienced lower prices due to strong renewable generation. Greece declined by €11.2/MWh to €95.79/MWh, while Bulgaria fell by €4.4/MWh to €102.59/MWh. Greece traded €36.55/MWh below Hungary and almost €50/MWh below Serbia, reflecting the impact of high solar and wind availability.

Albania remained the most expensive regional market with a baseload price of €148.19/MWh, despite a daily decrease of €10.1/MWh. North Macedonia increased by €7.2/MWh to €114.71/MWh, while Italy continued to represent the region’s premium market at €177.13/MWh, maintaining a wide spread over Southeast European markets.

The main driver behind the price surge was the deterioration of nuclear availability along the Danube. Hungary’s Paks nuclear plant reduced output from unit 1 by around 254 MW due to exceptionally low river levels affecting cooling conditions. At the same time, Romanian producer Nuclearelectrica placed Cernavoda unit 1 into a controlled shutdown. Combined regional nuclear output fell by 542 MW, from 5,560 MW to 5,018 MW.

Hungarian nuclear production dropped from 1,834 MW to 1,577 MW, while Romanian output declined from 1,165 MW to 880 MW. The full impact of the Romanian shutdown was expected to become more visible in Wednesday’s physical balance, as the outage began during Tuesday. With the Danube flow indicator at approximately 4,691 cubic metres per second, river conditions remained a direct operational risk for both Paks and Cernavoda.

The nuclear reduction coincided with higher regional electricity demand, which was forecast to reach 32,490 MW, an increase of 1,417 MW compared with Tuesday. Hungary, Greece, Romania, Bulgaria, Slovenia and Croatia all recorded higher consumption forecasts as temperatures continued to rise and cooling demand increased.

Renewable generation provided important support but was not sufficient to fully offset higher demand and reduced nuclear output. Regional solar production was expected to reach 7,417 MW, while wind generation increased to 2,455 MW. The additional renewable supply helped create deep midday price declines, but it could not eliminate the evening scarcity period after solar production faded.

This imbalance created a strong difference between daytime and evening prices. In Hungary, peak prices averaged €92.00/MWh, while off-peak prices reached €172.60/MWh. The minimum price was €11.80/MWh at hour 14 before rising sharply to €267.60/MWh at hour 21. Germany followed a similar pattern, moving from €0/MWh during the afternoon to €263.60/MWh in the evening.

The evening price spike was even more pronounced in Slovenia and Croatia. BSP reached €305.10/MWh at hour 20, while CROPEX peaked at €289.90/MWh. Although their daily average premiums over Hungary were relatively small, the hourly profile showed that market stress was concentrated during the sunset ramp rather than across the full day.

Serbia also recorded a tight market structure. SEEPEX prices remained above €45.00/MWh throughout the day before rising to €251.10/MWh at hour 21. Serbian peakload averaged €112.90/MWh, while off-peak prices reached €178.00/MWh. The relatively high midday floor reflected limited solar penetration, a tighter domestic balance and continued dependence on imports.

Serbia’s consumption was forecast at 3,457 MW, compared with domestic generation of 2,593 MW, resulting in average net imports of 865 MW. Imports increased during peak hours to 1,173 MW, with Serbia receiving electricity mainly from Romania, North Macedonia, Croatia, Bulgaria and Bosnia and Herzegovina.

The country’s import dependence helps explain the €13.16/MWh SEEPEX premium over HUPX. Serbia was competing for regional supply at a time when Romanian nuclear availability was falling and Croatian demand for imports was increasing. Cross-border capacity availability therefore became a key factor shaping Serbian prices.

Croatia faced an even tighter balance, with consumption rising to 2,369 MW while domestic generation reached only 1,228 MW. The country required average imports of 1,142 MW, including approximately 1,065 MW from Hungary. This explains why CROPEX followed the HUPX trend but experienced stronger evening price pressure.

Montenegro remained a net importer, with consumption of 447 MW and generation of 320 MW. However, exports through the submarine interconnector to Italy continued to provide commercial value, supporting a BELEN price of €140.79/MWh. The Italian market maintained a premium of more than €36/MWh over Montenegro, encouraging westbound electricity flows.

Romania recorded the largest market-position reversal, moving from an average net export position of 350 MW on Tuesday to expected net imports of around 450 MW. Generation declined to 5,036 MW, while consumption increased to 5,486 MW. Bulgaria supplied approximately 1,266 MW to Romania, helping compensate for the loss of nuclear output.

This shift explains the €22.1/MWh increase in the OPCOM price and Romania’s slight premium over HUPX. The Cernavoda outage transformed Romania from a regional balancing source into a market requiring additional external support.

Bulgaria remained the region’s main surplus market, producing around 5,047 MW compared with consumption of 3,915 MW. It exported approximately 1,266 MW to Romania, 294 MW to North Macedonia and 101 MW to Serbia, while importing 517 MW from Greece. Stable nuclear production at Kozloduy and strong solar availability supported Bulgaria’s lower price level.

Greece generated approximately 8,555 MW against consumption of 7,493 MW, creating net exports of 1,061 MW. The country supplied Bulgaria, North Macedonia and Albania, reversing its position from earlier in the week when it had been a net importer.

The Greek market demonstrated the impact of renewable penetration. HENEX peakload averaged only €42.70/MWh, with prices reaching €0/MWh during the afternoon solar peak. However, evening prices remained considerably higher, showing that low daytime prices did not eliminate broader system tightness.

At the regional level, Hungary and Southeast Europe required net imports of 1,753 MW, an increase of 518 MW. Imports from Austria and Slovakia into Hungary and Slovenia rose, while exports toward Italy declined. The region therefore relied more heavily on Central European supply despite continued Italian demand.

Hungary’s own net imports increased to 1,162 MW. The country received electricity from Slovakia, Romania and Slovenia while exporting some power to Croatia. Its balance differed significantly by time period, with relatively stable daytime conditions but heavy dependence on neighbouring markets during evening and overnight hours.

Forward markets indicate that traders expect the pressure to continue. Hungary Week 32 surged to €203.00/MWh, increasing its premium over Germany to €78/MWh. The contract has gained 37.6 per cent since 20 July, reflecting concerns over heat, nuclear availability and regional import capacity.

The Hungarian August contract also increased to €159.50/MWh, while Germany Week 32 eased to €125/MWh and Italy Week 32 remained at €174/MWh. The sharp difference between Hungary Week 32 and Week 33 highlights that the market is pricing the strongest scarcity risk in the immediate period.

Fuel markets did not drive the electricity increase. Gas prices declined, EU carbon allowances weakened slightly and coal markets remained broadly stable. The power-price rally was therefore mainly caused by physical availability constraints, weather conditions and cross-border capacity limitations rather than higher fuel costs.

The main trading risk remains concentrated during evening hours from 19:00 to 22:00, when solar generation falls, cooling demand remains elevated and nuclear output is reduced. Greece and Bulgaria continue to provide important regional support, but Serbia, Croatia and Romania remain the markets most exposed to further supply constraints. With Hungarian forward prices already above €200/MWh, the market is signalling that tight conditions may continue beyond Wednesday’s spot delivery.

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The government suspended the energy-efficiency contribution and the environmental levy on carbon-dioxide emissions from 28 July until 28 September. The two-month measure applies to regulated petrol, diesel and extra-light heating oil sold outside the motorway network.

The intervention is expected to reduce the price of 95-octane petrol by almost €0.10 per litre relative to the level that would otherwise apply. Diesel and extra-light heating oil are expected to be approximately €0.11 per litre cheaper.

Slovenia regulates maximum prices for certain petroleum products sold away from motorway service stations. The government can therefore use changes in taxes, contributions and levies to moderate the transmission of international crude and wholesale-product prices into retail inflation.

The latest intervention followed an increase in oil-market volatility linked to geopolitical tensions involving Iran. Higher crude and refined-product costs had begun feeding into the calculation of regulated maximum prices, prompting the government to temporarily absorb part of the increase through lower fiscal and environmental charges.

For consumers, the measure provides immediate relief during the summer travel period. For transport companies and businesses with significant diesel consumption, a reduction of €0.11 per litre can produce a meaningful operating-cost benefit, particularly when applied across large vehicle fleets.

The policy nevertheless transfers part of the price shock from consumers to the public or quasi-fiscal system. Revenue associated with energy-efficiency programmes and carbon-related charges will be lower during the suspension period. The measure also weakens the short-term price signal intended to encourage lower fossil-fuel consumption.

The government has limited the suspension to two months, maintaining the formal structure of the levies while responding to an exceptional increase in wholesale costs. Their scheduled return at the end of September could result in a renewed retail-price increase unless international oil prices decline in the meantime.

Slovenia’s approach reflects the political difficulty of maintaining carbon-related fuel charges during periods of rapid energy inflation. Temporary levy reductions are quicker to implement than direct subsidies and can be incorporated into the existing regulated-price framework.

The immediate effect will be to stabilise prices for motorists and heating-oil users. The fiscal and environmental trade-off will become more visible when the government decides whether to restore both charges in full on 28 September or extend the relief into the autumn heating season.

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The project is intended to deploy small modular reactor technology at the former coal-power site in Doicești. It is being developed through an equally owned joint venture, with Nuclearelectrica and Nova Power & Gas each holding 50 per cent.

Inspectors concluded that the economic exposure carried by the two shareholders may not be proportionate to their ownership. Nuclearelectrica has provided most of the funding committed to the development process, while Nova Power & Gas contributed initial equity of approximately €4 million and land associated with the project.

The audit’s central concern is that the land itself was reportedly acquired using funds provided by Nuclearelectrica before being transferred into the project structure through the private partner. This has led inspectors to question whether Nova Power & Gas made an economically equivalent contribution sufficient to justify its 50 per cent stake.

The report also found that the selected site was not the preferred location identified during earlier consultancy work. The eventual acquisition price was reportedly materially higher than the valuation used in the consultant’s assessment, raising questions about the decision-making process and the commercial basis for the transaction.

Inspectors argued that the shareholder agreement distributes rights, responsibilities and project risks in a manner that favours the private partner. Their findings suggest that Nuclearelectrica may bear the greater share of development and financial exposure without receiving corresponding control or economic protection.

The review comes at a sensitive stage. The conditions required to reach a final investment decision had not been completed by the end of June, while questions remain over the project’s capital cost, financing structure, electricity-market competitiveness and allocation of construction risk.

Romania’s energy ministry had previously resisted management proposals to reopen the project’s technical and financial assessment. Government representatives argued that insufficient evidence had been presented to justify a new evaluation. The audit now provides a broader governance basis for reconsidering that position.

Small modular reactors are promoted as a potential source of dispatchable low-carbon electricity, but first-of-a-kind projects carry substantial cost and execution risk. The Doicești development must resolve not only technology and licensing questions but also who finances early works, who absorbs overruns and how the value of land and development rights is calculated.

The audit does not itself terminate the project. It does, however, increase the probability of revised shareholder arrangements, additional valuation work and a more detailed review before Romania commits substantial public capital.

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The unit entered a controlled shutdown on 28 July, following revised hydrological forecasts indicating that the Danube was approaching critical operational thresholds. The decision removed one of Romania’s largest generating units from the system during a period of rising summer consumption.

Cernavoda has two operating CANDU reactors and is the foundation of Romania’s low-carbon baseload supply. The loss of one unit therefore has a material effect on the domestic balance and the electricity available for export to Hungary, Serbia, Bulgaria, Moldova and Ukraine.

Romanian nuclear generation had already fallen from an average 1,165 MW to 880 MW during the day on which the shutdown began. Because the reactor operated for part of that period, the full-day reduction following disconnection was expected to be substantially larger.

The market response was immediate. Romania moved from an average net export position of 350 MW to projected net imports of approximately 450 MW. Domestic generation declined to roughly 5,036 MW, while consumption was forecast at 5,486 MW.

Bulgaria became the principal balancing source, delivering approximately 1,266 MW to Romania. At the same time, Romania continued to send electricity toward Hungary and Serbia, demonstrating that contractual and cross-border market flows do not always adjust immediately to the domestic production deficit.

The OPCOM day-ahead price increased by €22.1/MWh to €132.87/MWh, marginally above the Hungarian price. Romania’s convergence with Hungary reflected the shared nuclear constraint: Paks unit 1 was simultaneously derated by approximately 254 MW because of low Danube levels.

Nuclearelectrica described the shutdown as preventive and consistent with established operating procedures. The reactor remained in a safe condition, with no reported danger to personnel, the public or the environment. The company continued to monitor river conditions and warned that further measures could be required if hydrology deteriorated.

Unit 2 could also face restrictions if the Danube falls further, although no immediate shutdown was announced. The loss of both reactors would create a significantly larger regional shock, potentially tightening Romania, Hungary, Serbia and Bulgaria simultaneously.

The shutdown demonstrates that nuclear generation, while low-carbon and generally stable, is not insulated from hydrological risk. Cernavoda’s availability now depends on the recovery of Danube flows, making river conditions a direct driver of Romanian electricity prices and cross-border trading positions.

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The initial investment package includes the 140 MW Stedim solar project and the 50 MW Krupac solar plant. The partners have also agreed to assess pumped-storage projects with combined capacity exceeding 400 MW, adding an energy-storage component that could materially increase the system value of future solar and wind development.

The projects will be developed through a 50:50 joint venture established to pursue as much as 2 GW of renewable capacity in Montenegro. The planned portfolio may include solar, wind, conventional hydropower, pumped storage, batteries and hybrid generation systems.

For Montenegro, the importance of the agreement extends beyond adding renewable megawatts. The country’s electricity balance remains highly dependent on hydrology and the availability of the Pljevlja coal-fired power plant. New solar capacity can reduce daytime imports and preserve reservoir water, but it can also create surplus production during low-demand hours unless accompanied by storage and stronger market integration.

The proposed pumped-storage assets are therefore central to the investment logic. More than 400 MW of flexible storage would allow EPCG and Masdar to absorb low-priced solar output, provide balancing services and release electricity during evening peaks. Such facilities could also support regional trading across Montenegro’s interconnections with Serbia, Bosnia and Herzegovina, Albania and Kosovo.

The submarine cable connecting Montenegro with Italy gives the portfolio an additional commercial route. Italian electricity has frequently traded at a substantial premium to the Western Balkans, creating an export opportunity when interconnector capacity is available. Montenegro’s location could consequently support a hybrid strategy combining domestic supply, regional balancing and sales into Italy.

The economics will depend on network capacity, permitting, land access and the structure of offtake arrangements. Utility-scale solar in the Western Balkans is increasingly exposed to midday price compression, making merchant revenue assumptions less dependable. Storage, bilateral power-purchase agreements and coordinated dispatch with EPCG’s hydropower assets will be important for protecting project returns.

Masdar’s participation brings international development experience and potential access to lower-cost financing. EPCG contributes local generation assets, market knowledge, grid relationships and a central position within Montenegro’s electricity sector.

The first 190 MW establishes a credible starting portfolio, but the more consequential element may be the integration of solar with pumped storage and cross-border trading. That combination could turn Montenegro from a hydrology-dependent small system into a more flexible regional electricity platform.

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A total of 312,171 guarantees of origin, or GOs, were sold through six auctions conducted on the CROPEX trading platform. Because one guarantee generally represents 1 MWh of qualifying electricity, the auction covered environmental attributes attached to more than 312 GWh of renewable generation.

The largest transaction involved 244,413 wind guarantees offered by Croatian energy-market operator HROTE. These certificates, representing electricity produced during the second quarter of 2026, cleared at €1.42 per GO.

HROTE also sold 39,366 biomass guarantees at €1.33 per GO. Together, the two HROTE auctions represented almost 91 per cent of the volume sold, showing the continued importance of centrally administered support structures in Croatia’s renewable certificate supply.

ENNA Next sold 22,698 Croatian wind guarantees, covering generation from March through May, at €1.33 per GO. The company also sold 2,669 guarantees from German wind plants at €1.46 per GO, the highest clearing price among the disclosed auction categories.

Smaller transactions included 1,174 solar guarantees at €1.36, 1,012 biomass guarantees at €1.31 and 136 biogas guarantees at €1.12. Koer sold a further 703 solar guarantees, covering June generation, at €1.31 per certificate.

The relatively narrow price range—generally between €1.31 and €1.46/MWh—suggests that technology and country of origin generated only modest premiums. The German wind certificates cleared slightly above Croatian wind, while solar traded close to the main wind and biomass products.

At these prices, guarantees of origin remain a supplementary revenue stream rather than a central element of project economics. A wind project selling certificates at €1.42/MWh would earn approximately €142,000 for every 100 GWh of eligible annual production. That income can support operating margins, but it is small compared with wholesale power revenue and cannot compensate for sustained price cannibalisation or curtailment.

The certificates are nevertheless becoming more important for industrial consumers seeking to document renewable electricity consumption. Their commercial value depends increasingly on traceability, production period, technology, location and whether buyers can integrate them into broader carbon-accounting and contractual structures.

The complete sale of the offered volume demonstrates continuing corporate demand for renewable attributes. The pricing also establishes a useful benchmark for Croatian producers evaluating whether to sell certificates independently, bundle them with physical electricity or incorporate them into power-purchase agreements.

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The plant was taken offline roughly two weeks ago, only a short period after completing an emergency overhaul lasting approximately 60 days. Its failure to return to sustained production demonstrates that technical maintenance alone cannot stabilise the facility while the associated mining operation is unable to provide sufficient coal of the required quality.

Management has not announced a firm restart date. Existing coal inventories would reportedly support only 10 to 15 days of generation, making an immediate restart commercially unattractive unless a more reliable fuel supply can be secured. Starting a large thermal unit entails significant costs, and a short operating cycle followed by another forced shutdown would further weaken the plant’s financial position.

The central issue is the delayed development of the Ugljevik East 2 surface mine, which is expected to become the plant’s principal long-term source of coal. Acting director Žarko Novaković has identified the start of extraction at East 2 as the company’s immediate priority, but the mine has not yet achieved the stable output required to support continuous electricity generation.

The Republika Srpska government previously awarded a €120 million concession connected with coal production at East 2 to Russian businessman Rashid Serdarov. The arrangement was presented as a strategic solution to Ugljevik’s fuel-security problems. The expected coal volumes have not materialised, leaving the plant dependent on depleted or increasingly difficult mining areas.

The geological and operational challenge is substantial. Union representatives have estimated that approximately 20 million cubic metres of overburden must be removed before the main coal seam can be reached. Existing equipment and staffing levels are considered insufficient for that scale of work. Mining activity has reportedly concentrated on removing soil and rock rather than producing enough usable coal for the generating unit.

The prolonged outage creates several layers of financial exposure. Republika Srpska’s power utility ERS must replace lost Ugljevik generation through other domestic assets or electricity imports, potentially at much higher market prices during summer demand peaks. The outage also removes export volumes that would otherwise support the utility’s cash flow.

The decision on when to restart will therefore depend on both technical readiness and wholesale prices. Management intends to coordinate the timing with ERS, seeking a period in which the value of generated electricity can justify the cost and risk of operating with limited coal stocks.

Ugljevik’s difficulties are no longer a temporary maintenance issue. They reflect the declining reliability of a production model in which the power plant, mine, environmental obligations and electricity-market exposure must all function together. Without accelerated overburden removal, new equipment and a credible mine-development schedule, the plant is likely to remain vulnerable to repeated outages even after the current shutdown ends.

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Thermal power plants accounted for 60 per cent of gross electricity output during the month, while hydropower contributed 27.3 per cent. Wind and solar plants supplied the remaining 12.7 per cent, demonstrating that renewable capacity outside large hydropower is becoming more relevant but is not yet large enough to displace coal as the principal source of system stability.

Net thermal generation reached 594 GWh, an increase of 4.4 per cent year on year. Hydropower production amounted to 281 GWh, slightly below the May 2025 level, while combined wind and solar output rose by 43.9 per cent to 141 GWh. The renewable increase was the strongest component of the monthly balance, reflecting new capacity and better utilisation of recently commissioned projects.

The improvement in domestic generation substantially changed Bosnia and Herzegovina’s cross-border position. Electricity imports fell by 28.6 per cent, from 500 GWh to 357 GWh, while exports increased by 31.7 per cent, from 489 GWh to 644 GWh. The country therefore returned to a net export position of approximately 287 GWh during May.

That trade result is economically important because Bosnia and Herzegovina remains one of the few Western Balkan electricity systems capable of generating recurring export surpluses. The value of those exports, however, is sensitive to hydrology, thermal plant availability and the widening carbon-cost difference between the Western Balkans and the European Union.

Coal production also recovered sharply. Lignite output reached 503,000 tonnes, representing a year-on-year increase of 71.7 per cent, while brown-coal production rose by 2 per cent to 449,000 tonnes. The figures suggest an improvement in fuel extraction compared with the unusually weak base of May 2025, but they do not remove the structural constraints affecting individual mining and generation complexes.

The continued outage at the Ugljevik thermal power plant illustrates the gap between aggregate coal statistics and fuel security at plant level. Higher national lignite production does not automatically translate into coal of the required quality, location and calorific value for each generating unit.

Natural-gas imports reached 9.61 million cubic metres, up 8.7 per cent from 8.84 million cubic metres a year earlier. Gas remains a relatively small part of Bosnia and Herzegovina’s energy balance, but the increase points to growing demand outside the electricity sector and continued dependence on imported supply.

May’s balance was therefore considerably stronger than a year earlier, driven by higher thermal output, expanding wind and solar generation and lower import requirements. The underlying export model nevertheless remains exposed to ageing coal plants, mine productivity, hydrological volatility and the gradual tightening of European carbon rules.

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The stable headline concealed a substantial change in the generation mix. Thermal power production fell by 40% year on year to only 45 GWh, while hydropower increased by 4% to 377 GWh.

The Krško nuclear power plant produced 495 GWh, approximately unchanged from June 2025, and remained the single largest source of Slovenian electricity. Wind and solar generation increased by 7% to a combined 234 GWh.

Nuclear, hydro, solar and wind together accounted for almost the entire reported net generation volume. The decline in thermal production therefore did not reduce overall electricity availability because stronger renewable output and stable nuclear generation filled the gap.

Slovenia imported 881 GWh during the month, 6% less than a year earlier, while exports declined by 12% to 912 GWh. On an energy basis, the country recorded a modest net export position of approximately 31 GWh.

The large gross import and export volumes demonstrate Slovenia’s role as a transit and trading market between Austria, Italy, Croatia and the wider Balkan system. Its monthly net position is small relative to total cross-border flows because electricity moves through the country in both directions according to hourly price differences and network availability.

Household consumption reached 231 GWh, down 4% from May. Commercial and other non-household consumers used 595 GWh, an increase of 5% month on month.

The divergence suggests that seasonal residential demand weakened while commercial activity remained firm. It also places greater importance on the shape of industrial and business consumption, particularly as solar generation increases during working hours.

Slovenia’s commodity data showed a mixed picture. Compared with May, natural-gas supply declined by 15%, liquefied petroleum gas by 8%, hard coal by 4% and coke by 2%. Kerosene supply increased by 27%, other petroleum products by 17%, heating oil by 13%, diesel by 6% and petrol by 4%.

Compared with June 2025, heating-oil supply fell by 63%, natural gas by 9% and LPG by 7%. The sharp reduction in heating oil indicates a continuing contraction in a fuel segment increasingly displaced by other heating technologies and improved efficiency.

The electricity figures show a system operating with limited thermal generation but substantial cross-border flexibility. Stable output at Krško provides a strong baseload anchor, while hydro and solar increasingly determine Slovenia’s variable position.

That combination supports low-carbon electricity production but also increases the value of interconnection capacity, reservoir flexibility and short-term trading. Slovenia’s energy balance is becoming less dependent on domestic fossil generation, while remaining deeply dependent on the regional network for hourly optimisation.

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The project is being developed by UK-based TDI Renewables. Ameresco Sunel will deliver detailed engineering, equipment procurement, construction and commissioning, as well as long-term operation and maintenance after commercial start-up.

The contract also includes a 33/110 kV substation and the underground cable system required to connect the plant to Romania’s electricity network. Including these assets within the EPC scope reduces interface risk between the generation facility and the grid connection.

That integrated structure is commercially important. Many regional solar projects have experienced delays because the generation plant was completed before the substation, transmission bay or connection line. A single contractor responsible for both packages provides the developer with a clearer basis for schedule control and performance accountability.

The project’s final capital cost was not disclosed. A Romanian utility-scale solar plant of this type could require an indicative investment of approximately €35–50 million, depending on module specifications, land conditions, grid works, financing costs and the extent of owner-supplied equipment.

At a typical annual yield of 1,250–1,450 MWh per installed MW, Iratoșu could generate approximately 72–84 GWh a year. Revenue will depend heavily on the project’s contracting strategy and exposure to increasingly volatile Romanian day-ahead prices.

Romania’s rapid solar expansion is beginning to compress prices during high-output hours. That creates a growing cannibalisation risk for merchant projects: annual average market prices may remain attractive, while the prices captured specifically during solar production hours decline.

The project will therefore benefit from a power-purchase agreement, active hedging or integration with storage. Even without a battery at the initial stage, technical design should preserve the option to add storage later as grid conditions and market spreads evolve.

Ameresco Sunel Energy is a joint venture between US-based Ameresco and Greece’s Sunel Group. It has already announced Romanian solar developments with a combined capacity of 466 MW, principally in the country’s southwest.

The Iratoșu award expands that footprint into western Romania and gives the contractor a broader operational base. Long-term O&M also creates recurring revenue beyond the construction period and aligns the contractor’s incentives with the plant’s operating performance.

For TDI Renewables, the critical delivery issues will be procurement quality, grid-code compliance, energisation sequencing, documentation and performance testing. The substation and underground connection must be commissioned in coordination with the relevant network operator, while the completed plant will require reliable SCADA, metering and forecasting systems.

Romania remains one of Central and Eastern Europe’s fastest-growing solar markets, but scale alone will not determine returns. Projects that combine secure grid access, disciplined EPC execution and a credible route to market will retain a financing advantage as congestion and solar-price cannibalisation become more pronounced.

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The loan has been extended to the company developing the CEE Onești project and will cover at least 60% of total investment costs. The financing implies a project value of no more than approximately €78 million if the debt represents exactly 60%, equivalent to an indicative capital cost of around €1.56 million per MW.

The precise leverage ratio may be higher, but the disclosed figures point to a conventional project-finance structure with a meaningful equity contribution from the sponsors. That balance should provide the lender with a buffer against construction delays, lower production or weaker electricity prices.

Gura Văii is expected to produce around 110 GWh annually, corresponding to an implied capacity factor of approximately 25%. The project has secured the principal permits required for construction and is part of a wider 300 MW group of renewable investments that recently received final approval from OMV Petrom.

At an annual output of 110 GWh, every €10/MWh change in the realised power price would alter gross annual revenue by approximately €1.1 million. That sensitivity makes the project’s route to market, hedging structure and balancing exposure central to debt service.

The financing decision indicates that BCR is satisfied with the project’s permitting position, construction plan and revenue assumptions. Wind financing requires a detailed assessment of turbine technology, resource studies, grid availability, wake losses, availability guarantees and long-term operating expenditure.

Grid delay remains one of the most material risks. A 12-month postponement after major construction expenditure could add interest during construction, defer revenue and weaken equity returns. The effect is particularly severe where turbine deliveries and debt drawdowns occur before the connection is ready.

OMV Petrom entered the underlying portfolio in 2024, acquiring a 50% interest in a company developing around 1 GW of renewable capacity. Gura Văii is among the first projects from that pipeline to reach the financing and implementation stage.

The development forms part of OMV Petrom’s plan to build more than 2.5 GW of renewable capacity with partners by 2030. The company currently reports around 70 MW in operation and approximately 1.5 GW under development across wind, solar and hydropower.

For OMV Petrom, renewable investment diversifies a business still anchored in oil, gas and refining. For Renovatio, the partnership provides access to a larger balance sheet and financing capacity. BCR’s participation demonstrates growing bank appetite for Romanian wind assets with advanced permitting and credible sponsors.

Gura Văii’s relatively modest scale also makes it easier to finance and connect than some of the multi-hundred-megawatt projects accumulating in Romania’s grid queue. The project’s bankability now depends on converting the loan approval into disciplined construction, timely grid energisation and production performance consistent with the 110 GWh forecast.

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The study was prepared with European Union support under IPA II, the Western Balkans Investment Framework and Infrastructure Project Facility 10. It was developed alongside the planned North Macedonia–Serbia gas interconnector and assesses how new infrastructure could form part of a future regional hydrogen corridor.

The analysis places North Macedonia between Greece and Serbia within the emerging Pan-European Hydrogen Network and European Hydrogen Backbone. The country’s geographic position creates a potential transit route connecting renewable production and import infrastructure in Greece with demand centres farther north.

The gas interconnector under construction with Greece has been designed to transport up to 100% hydrogen, according to the Ministry of Energy, Mining and Mineral Resources. Tender requirements for the planned Serbian connection also call for infrastructure compatible with pure hydrogen transmission.

Full technical compatibility is strategically useful, but it does not by itself create a viable hydrogen market. Pipelines need production projects, contracted demand, storage, compression systems, safety rules and certification standards before they can operate economically as hydrogen infrastructure.

The national study therefore examines possible applications in energy, industry, transport and district heating. It also considers the integration of renewable generation with electrolysis, the development of transport corridors and the potential contribution of hydrogen to greenhouse-gas reduction.

For North Macedonia, industrial demand will be decisive. Hydrogen is unlikely to compete efficiently with direct electrification in many heating or transport applications. Its strongest potential lies in sectors where electrification is technically difficult, including certain high-temperature industrial processes, fertiliser production and heavy transport.

The study gives the government a basis for sequencing these markets rather than pursuing infrastructure in isolation. Early projects will require an identifiable offtaker, reliable renewable electricity, water availability and a clear route to certification under European rules.

North Macedonia’s accession process adds another dimension. Hydrogen infrastructure designed around EU technical and environmental standards could strengthen integration with European energy markets. Poorly coordinated investment, by contrast, could leave the country with underused pipelines and expensive public liabilities.

The proposed Greek and Serbian interconnectors may initially operate primarily with natural gas. Hydrogen compatibility protects their future relevance, but conversion would require additional investment in metering, compressors, seals, storage and end-user equipment.

The national framework is therefore best understood as an option-building exercise. It allows North Macedonia to incorporate hydrogen readiness into infrastructure being developed today while waiting for production costs, European demand and cross-border rules to mature.

The country’s location gives it a credible corridor role, but bankable projects will emerge only when physical infrastructure is matched by long-term offtake contracts and a verifiable low-carbon supply chain.

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The intervention follows a government review of injection rates at the Okoli underground gas storage facility. The assessment found that the plans submitted by storage users would not produce sufficient inventories before winter.

Okoli was only 50.4% full, compared with 67.7% during the corresponding period of 2025. The weakness was part of a broader European trend, with average EU storage levels at 53.4%, down from 65.3% a year earlier.

The government attributed the slower injections largely to high wholesale prices. Gas futures were trading around €60–63/MWh, encouraging some suppliers to delay purchases in the expectation that prices might decline before the end of the injection season.

That strategy may be commercially rational for an individual trader but creates a collective security risk. Each supplier has an incentive to wait for cheaper gas, yet widespread delay can leave the system unable to reach the required storage level before winter demand begins.

HEP was selected to execute the procurement because its subsidiary, HEP-Plin, is being designated supplier of last resort through a regulatory process managed by the Croatian Energy Regulatory Agency. The role places the state-owned group at the centre of the country’s emergency supply arrangements.

Croatia has established a near-term objective of filling Okoli to at least 80% by the beginning of October. European rules generally target storage levels of 90% by 1 October, although limited flexibility permits inventories to remain no lower than 80% during the October-to-December period.

Before adopting the measure, the government consulted companies holding storage rights at Okoli. Users with unused allocations agreed to make capacity available voluntarily, allowing HEP-Plin to lease additional space beyond its existing entitlement. The companies involved were not disclosed because their storage positions are commercially sensitive.

The procurement effectively transfers part of the timing and price risk from private suppliers to the state-owned utility. HEP must decide whether to purchase promptly at elevated prices or stage acquisitions in the hope that the market softens without compromising the injection schedule.

The cost implications will depend on the final purchasing strategy and the treatment of the gas after storage. At €60/MWh, a 1.1 TWh purchase would carry a wholesale commodity value of roughly €66 million, before transport, storage, financing and balancing expenses. Even a relatively small price movement can therefore materially affect the cost ultimately borne by HEP, consumers or the state.

Krk LNG is likely to provide a large share of the physical supply. Around 70% of the gas entering Croatia’s transmission system already arrives through the terminal, whose commercial capacity is fully booked for more than a decade.

The intervention highlights the conflict between market optimisation and security-of-supply obligations. Storage holders may prefer to wait for better prices, but governments cannot rely entirely on speculative purchasing behaviour when winter adequacy is at stake. Croatia has chosen to use HEP’s balance sheet to close that gap.

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LNG Hrvatska has completed its part of the expansion investment, while transmission system operator Plinacro is continuing work on approximately 250 kilometres of pipelines needed to carry higher volumes into the Croatian and regional gas networks.

Once the remaining pipeline sections have been completed, tested and permitted, the terminal’s commercial capacity is expected to rise from 3.5 billion cubic metres to between 4.3 billion and 4.5 billion cubic metres a year.

The facility is technically capable of processing around 6.1 billion cubic metres annually, but the operator does not intend to allocate the entire technical volume commercially. Some capacity will be retained as an operational buffer for adverse weather, equipment problems, emergency supply requirements and other disruptions.

This reserve is commercially significant because Krk has developed from a national import facility into critical regional infrastructure. Running the terminal permanently at its technical maximum would increase headline throughput but leave less flexibility to manage delays or emergency cargoes without affecting contracted deliveries.

Director Ivan Fugaš said scheduled shipments have continued to arrive and unload normally despite renewed uncertainty in global LNG markets associated with tensions around the Strait of Hormuz. Europe had been receiving only around 10–12% of its LNG imports from Qatar before the latest disruption, limiting its direct exposure compared with more LNG-dependent Asian markets.

The indirect effect remains important. Competition for flexible cargoes can raise European gas prices even where physical deliveries continue. Krk therefore provides Croatia and neighbouring markets with greater route diversity, but it does not isolate buyers from global LNG pricing.

The terminal’s existing commercial capacity has been fully reserved until 1 October 2037. Between 2037 and 2040, around 1.5 billion cubic metres of annual capacity remains available, although the operator does not expect those volumes to be contracted immediately.

Long-term reservations provide visibility over utilisation and support the economics of the infrastructure expansion. They also demonstrate regional demand for non-Russian supply routes extending through Croatia toward Hungary, Slovenia and other Central European markets.

Approximately 70% of the gas entering Croatia’s transmission system currently arrives through Krk. The terminal is therefore likely to play a central role in replenishing the country’s underground storage facilities and meeting European inventory requirements.

The expansion’s strategic value will depend on more than regasification capacity. The real constraint is the ability of the downstream network to transport additional gas across Croatia and into neighbouring systems. Plinacro’s pipeline works are consequently as important as the terminal upgrade itself.

A larger Krk corridor could strengthen competition between LNG, pipeline gas and stored supply across the region. It may also improve security for industrial consumers and power generators that remain exposed to short-term gas-market shocks.

The decision to preserve unused technical capacity reduces the maximum commercial return but increases the resilience of the system. For critical infrastructure, the value of spare capacity lies precisely in its availability when normal market arrangements fail.

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The Dupnitsa Regional Court confirmed that the Sofia Regional Inspectorate of Environment and Water acted lawfully when it imposed the sanction under Bulgaria’s Environmental Protection Act. The case concerned failures in the operation of the plant’s emissions-control equipment and the uncontrolled release of flue gases.

The breaches were identified during an unannounced inspection on 23 September 2025, initiated after complaints from residents living near the power station. Inspectors found that emissions from an operating boiler had bypassed gas-cleaning and flue-gas desulphurisation systems before being released directly into the atmosphere.

An automatic monitoring station in Golemo Selo, around 700 metres from the plant, recorded sulphur dioxide concentrations above the permitted limit for two consecutive hours. Inspectors also reported a strong sulphur smell in the surrounding area.

The permit violations covered several operational requirements, including the controlled discharge of flue gases, prevention of air-pollution limit exceedances and restriction of odours beyond the plant perimeter. The court rejected the operator’s request to cancel or reduce the fine, concluding that the breaches could not be treated as minor because they affected environmental protection and public health.

The judges also found no material procedural shortcomings in the enforcement process. In assessing the proportionality of the penalty, they considered both the seriousness of the incident and the plant’s history of similar violations.

The ruling follows a separate decision issued earlier in July, when the same court confirmed another environmental fine exceeding €100,000 against Bobov Dol. During the first 11 months of 2025, inspectors issued 17 violation reports involving the facility.

Regulatory pressure has consequently moved beyond isolated monetary penalties. In May, Bulgaria’s Ministry of Environment and Water ordered a partial shutdown after repeated inspections identified recurring breaches of the plant’s integrated permit, including unauthorised releases of waste gases. The ministry subsequently confirmed that the restrictions would remain in place until the operator demonstrated full compliance.

For Bobov Dol, the financial exposure is no longer limited to the nominal value of the fines. Partial operating restrictions reduce available generation, while repeated enforcement action can increase maintenance expenditure, insurance costs and the difficulty of securing finance for refurbishment.

Environmental non-compliance can also undermine revenues at moments when ageing coal plants might otherwise benefit from high regional electricity prices. A unit that is unavailable during evening scarcity periods loses not only baseload production but also the most profitable hours of the day.

The court decision reinforces the increasingly direct connection between environmental systems and plant bankability. Flue-gas desulphurisation, continuous emissions monitoring, operating procedures and maintenance records are no longer peripheral compliance matters. They determine whether a plant can legally operate, whether its output can be contracted and whether lenders can rely on future cash flows.

Bulgaria still uses coal generation to support system adequacy, particularly during winter peaks and periods of low renewable output. That system role, however, does not shield operators from permit enforcement. Bobov Dol’s repeated violations show that coal assets unable to maintain functioning emissions controls face growing operational as well as regulatory risk.

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The increase was not caused by a shortage of renewable generation. On the contrary, forecast solar production climbed by 1.36 GW to 7.49 GW, while wind generation increased by 523 MW to 2.08 GW. The key driver was the growing mismatch between renewable output and electricity demand. Strong solar generation pushed prices close to zero during midday, but the rapid decline in solar production during the evening forced markets to rely on thermal power plants, hydropower flexibility and imports to meet demand, resulting in a sharp price surge.

Hungary provided the clearest example of this evolving market structure. Hourly prices declined from approximately €150–170/MWh overnight and during the morning to single-digit levels between hours 11 and 16 before rebounding rapidly. By hour 19, prices exceeded €170/MWh, climbing above €210/MWh during the evening peak. The nearly €210/MWh intraday swing highlights the growing disconnect between daily average prices and the actual commercial value of flexible generation.

A similar pricing pattern emerged across Romania, Slovenia and Greece. Romanian prices briefly approached zero during peak solar production before recovering above €210/MWh in the evening. Slovenia closely mirrored the Hungarian curve, while Greece experienced a temporary easing during one evening hour before prices strengthened again. Across the region, the defining characteristic was a deep midday price trough followed by a four-to-five-hour period of evening scarcity.

This pricing profile is becoming the dominant summer trend across Southeast Europe. Expanding solar generation is increasingly capable of suppressing daytime prices across interconnected markets, yet it does little to eliminate evening adequacy challenges. As a result, dispatchable generation, reservoir hydropower, battery storage and flexible imports are capturing a growing share of overall market value.

Germany significantly narrowed the pricing gap with Hungary after recording the strongest day-on-day increase among major European markets. German day-ahead prices rose by €39.70/MWh to €116.82/MWh, exceeding Hungary’s daily increase of €26.50/MWh. Consequently, the Hungarian premium over Germany narrowed from €18.46/MWh to just €5.26/MWh.

The shrinking spread suggests Hungary is becoming more closely aligned with the broader Central European market. Imports from Austria and Slovakia remained substantial at 1.89 GW, although they declined by 841 MW compared with the previous session. The combination of lower imports and a narrower price premium indicates that tighter conditions in the core European market reduced the availability of low-cost electricity flowing eastward.

However, daily averages conceal much of the commercial opportunity. Electricity imports from Austria and Slovakia increased significantly during the evening ramp, precisely when Hungarian prices approached or exceeded €200/MWh. During the middle of the day, when abundant solar generation pushed prices sharply lower, the incentive for imports weakened considerably. Consequently, the greatest value of cross-border transmission capacity was concentrated within only a few high-priced evening hours.

Hungary’s €5.26/MWh premium over Germany compared with an Austrian market price of €126.77/MWh, while Slovenia settled at €125.48/MWh. Together, Austria, Slovenia and Hungary continued to form a relatively coherent regional price cluster, although transmission congestion and national generation patterns continued producing meaningful hourly price differences.

Eastern Southeast Europe remained comparatively inexpensive despite stronger electricity demand. Romania settled at €110.78/MWh, Bulgaria and Greece both cleared at €106.99/MWh, while North Macedonia finished at €107.54/MWh. Serbia settled at €116.54/MWh, gaining only €2.10/MWh from the previous session, while Croatia increased to €115.40/MWh.

Romania traded at an €11.30/MWh discount to Hungary, while Bulgaria and Greece remained €15.09/MWh lower. North Macedonia was €14.54/MWh below HUPX, and Serbia maintained a more modest €5.54/MWh discount. Although electricity demand increased by 703 MW in Greece and 584 MW across Romania and Bulgaria, stronger renewable production enabled these markets to maintain relatively low average prices.

Bulgaria remained the region’s largest net exporter with approximately 1.24 GW of surplus electricity, while Romania exported around 494 MW and Greece recorded a modest surplus of roughly 104 MW on average. These export positions explain why Bulgarian and Greek prices remained among the lowest in the region despite tightening conditions during evening peak hours.

By contrast, Serbia, Croatia and Hungary remained structurally dependent on imports. Serbia required approximately 686 MW of net imports, Croatia around 1.03 GW, while Hungary imported roughly 883 MW. These deficits placed the central Southeast European corridor in a tighter supply position than Romania and Bulgaria, although regional renewable production and available imports prevented a more pronounced price spike.

Montenegro settled at €125.06/MWh, almost identical to Slovenia and only €2.98/MWh above Hungary. The market recorded a daily increase of €22/MWh, positioning Montenegro above Serbia, Croatia and the eastern markets. The premium reflects the country’s relatively small and transmission-sensitive market, where hydrological conditions, interconnector scheduling and limited domestic liquidity can significantly influence daily pricing.

Albania emerged as the clear regional outlier. ALPEX surged by €84.50/MWh to €158.30/MWh, creating a premium of more than €36/MWh over Hungary and over €51/MWh above Bulgaria and Greece.

Such a sharp divergence is unlikely to be explained solely by fuel prices. Instead, it points toward local hydrological conditions, constrained import capacity, limited market liquidity or a combination of these factors. Despite abundant solar generation across neighboring countries, Albania remained largely disconnected from the broader regional pricing pattern, highlighting the continuing importance of transmission constraints and national balancing conditions.

Italy remained the most expensive major market despite a daily decline of €9/MWh, settling at €176.07/MWh. Its premium over Hungary widened to nearly €54/MWh, maintaining a powerful commercial signal for electricity exports from Southeast Europe toward the Italian market. Average exports to Italy reached approximately 1.02 GW, reinforcing the country’s role as the region’s strongest demand center.

This westward export flow continued to shape the regional supply balance. Although Bulgaria and Romania maintained significant surpluses, Hungary, Serbia and Croatia remained net importers while electricity continued flowing toward higher-priced Italy. Overall, Southeast Europe recorded net imports of approximately 897 MW, despite several countries maintaining positive export balances.

Regional import requirements nevertheless declined by 642 MW from Monday as stronger renewable generation improved the overall physical balance. Yet higher renewable output alone was insufficient to prevent rising electricity prices. The decisive factor remained the uneven hourly distribution of renewable generation rather than total daily energy availability.

The Hungarian forward curve continues to reflect expectations of near-term market tightness. Week 32 traded at €174.50/MWh, compared with €146.50/MWh for Week 33, €152.50/MWh for the 2026 average and €126.50/MWh for calendar 2026.

The €28/MWh backwardation between Weeks 32 and 33 illustrates a concentrated summer risk premium driven primarily by weather conditions, electricity demand and short-term system availability. Week 33 declined by €7/MWh during the latest session, while Week 32 eased by only €1/MWh, indicating that traders continue assigning the highest risk to the immediate delivery period.

Hungary’s Week 32 premium over Germany widened to €46/MWh, while Week 33 traded at a €23.50/MWh premium. Longer-term spreads narrowed to approximately €26.50/MWh for the 2026 average and €20/MWh for calendar 2026, suggesting that current market dislocations remain largely concentrated within the summer season.

Fuel markets moved in the opposite direction. Austrian CEGH natural gas fell by €4.90/MWh to €59.54/MWh, while EU carbon allowances declined by €1.10/t to €82.33/t. API2 coal prices also weakened, with the 2026 average contract falling to $118/t and the fourth-quarter contract to $123/t.

Ordinarily, lower gas, coal and carbon prices would reduce thermal generation costs. However, persistently elevated Hungarian power prices indicate that electricity markets are currently being driven less by fuel costs and more by hourly supply tightness, cross-border transmission availability and the steep evening ramp.

At current fuel and carbon prices, a modern combined-cycle gas turbine operating at approximately 55–58% efficiency carries an estimated short-run generation cost of roughly €135–150/MWh, excluding start-up costs and commercial margins. While Hungarian Week 32 forward prices provide sufficient profitability for efficient gas-fired generation, the daily spot average of €122.08/MWh masks the reality that thermal plants generate most of their revenue during evening peak hours when prices exceed €170–210/MWh.

Looking ahead, market fundamentals continue pointing toward elevated intraday volatility rather than a sustained increase in baseload prices. Regional temperatures are forecast to rise modestly from 24.3°C to 24.7°C, with Greece approaching 28.9°C, while electricity demand increases to 31.74 GW. At the same time, stronger solar and wind generation should limit total regional imports to around 897 MW.

The greatest market exposure remains concentrated in the evening hours, when electricity systems transition rapidly from abundant solar generation to thermal scarcity. This leaves prices increasingly sensitive to thermal outages, hydropower dispatch decisions, forecasting errors and available cross-border transmission capacity. Battery energy storage systems with two-to-four-hour discharge capability continue to benefit from exceptionally attractive arbitrage opportunities, while flexible hydropower retains significant commercial value despite relatively moderate daily average prices.

Hungary is expected to remain firmer than Romania, Bulgaria and Greece, although the narrower €5.26/MWh spread versus Germany reduces the likelihood of a broad Hungarian scarcity premium throughout the entire trading day. Italy continues to provide the region’s strongest export signal with a premium approaching €54/MWh, while Albania remains the principal source of local congestion and liquidity risk.

The overall trading picture is becoming increasingly defined by both time and location rather than simple daily averages. Near-zero midday prices driven by abundant solar generation, a steep regional evening ramp, sustained Italian demand and persistent premiums in Hungary, Montenegro and Albania continue to reshape market dynamics. As renewable penetration increases across Southeast Europe, the widening gap between midday generation value and evening system flexibility is becoming more commercially significant than movements in the daily baseload index itself.

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Recent publications from ENTSO-E, the Energy Community Secretariat, regional transmission system operators and industry organizations illustrate a market that is evolving far beyond renewable deployment alone. Southeast Europe is becoming increasingly integrated into the European Internal Electricity Market, where commercial success depends on flexibility, interconnected networks and the efficient movement of electricity across borders rather than simply producing power for domestic consumption. This shift is reshaping investment priorities across the Western Balkans, Romania, Bulgaria, Greece and neighboring markets.

One of the strongest indicators of this transformation comes from ENTSO-E’s latest assessment of European electricity markets. Covering the period from June 2025 to May 2026, the report highlights continued progress in market coupling, cross-border capacity allocation and balancing market integration. Although these developments appear highly technical, they have major commercial implications. As electricity markets become more interconnected, pricing is increasingly influenced by regional supply and demand rather than national generation alone.

Historically, electricity prices across Southeast Europe were largely determined by domestic generation portfolios. Coal production in Serbia, hydrological conditions in Montenegro and Bosnia and Herzegovina, nuclear output in Romania and gas-fired generation in Greece shaped local market dynamics. While these national characteristics remain important, they are now operating within a much broader European trading environment where cross-border electricity flows increasingly determine market prices.

This evolution is fundamentally changing how investors evaluate new projects. Renewable energy developers are no longer focusing exclusively on domestic electricity demand. Instead, they assess regional price spreads, available transmission capacity and balancing market revenues before making investment decisions. A solar project in Montenegro, for example, may achieve higher profitability by exporting electricity through the Italy interconnector during periods of elevated Italian market prices, while battery storage facilities in Romania or Hungary can generate revenue across multiple regional markets rather than relying solely on national balancing mechanisms.

The Energy Community Secretariat has also confirmed that regulatory reforms throughout Southeast Europe are beginning to deliver measurable results. Serbia, Montenegro, North Macedonia, Albania and Bosnia and Herzegovina continue aligning their electricity legislation with European market rules, improving investor confidence and facilitating greater participation in regional electricity markets. Although implementation progresses at different speeds, the overall direction is clear. Regulatory convergence is reducing market fragmentation, increasing investment certainty and encouraging greater private-sector participation in energy infrastructure.

Among the most important developments currently reshaping the regional electricity sector is the rapid emergence of battery energy storage. According to ENTSO-E’s latest assessment, Southeast Europe has become one of Europe’s most attractive regions for battery investment. Hungary currently offers the strongest commercial opportunities, followed closely by Greece, while Romania, Bulgaria, Croatia and Slovenia also demonstrate highly competitive revenue potential.

Only a few years ago, battery storage was viewed primarily as an optional addition to renewable energy projects. Today, it has become a central element of modern investment strategies. Storage allows renewable generators to shift electricity production toward higher-priced periods, reduce curtailment and participate in balancing services. As solar capacity continues expanding across the region, midday electricity prices increasingly weaken during periods of abundant sunshine, making storage an economically attractive solution.

The commercial value of battery systems extends far beyond simple energy arbitrage. Modern storage facilities increasingly provide frequency regulation, reserve capacity, congestion management and ancillary services, creating multiple revenue streams while simultaneously improving electricity system stability. As a result, developers across Southeast Europe are increasingly pursuing integrated renewable-plus-storage projects instead of stand-alone generation facilities.

The growing importance of renewable integration has also elevated transmission infrastructure to one of the region’s highest investment priorities. During the initial phase of renewable expansion, generating capacity increased much faster than electricity networks. This imbalance has led to greater congestion, renewable curtailment and delays in connecting new projects to the grid. Transmission operators are now responding with major investment programs aimed at strengthening domestic networks while expanding cross-border interconnections.

Montenegro’s transmission system operator CGES, for example, plans significant infrastructure investments over the coming three years while reinforcing its strategic role as the operator of the submarine electricity interconnector linking the Western Balkans with Italy. Similar transmission expansion projects are advancing across Serbia, Romania, Bulgaria and Greece. These investments are increasingly viewed not merely as engineering upgrades but as critical commercial infrastructure supporting regional electricity trading.

High-capacity transmission networks create opportunities to export surplus renewable electricity, import lower-cost power during shortages and participate more effectively in regional balancing markets. As market integration accelerates, transmission assets are becoming strategic economic infrastructure that directly influences electricity prices, investment opportunities and regional competitiveness.

Renewable energy development itself continues to accelerate throughout Southeast Europe. Türkiye recently announced another major renewable energy auction totaling approximately 2.4 GW, including significant new wind capacity. Although Türkiye operates outside the European Union, its expanding renewable sector increasingly influences electricity markets throughout Southeast Europe due to growing commercial relationships and regional interconnections.

Elsewhere in the region, renewable investment is constrained less by financing than by permitting procedures, environmental approvals and grid availability. Investor interest remains strong as Europe’s electricity demand continues rising through industrial decarbonization, transport electrification, digital infrastructure and artificial intelligence. In this environment, access to grid connections has become one of the industry’s most valuable competitive advantages.

Hydropower continues to play an essential role despite the rapid expansion of wind and solar generation. Existing hydroelectric facilities across Montenegro, Bosnia and Herzegovina, Albania and Romania provide valuable operational flexibility for electricity systems. At the same time, growing attention is being directed toward pumped-storage hydropower, which offers large-scale energy storage capable of supporting long-duration renewable integration.

Rather than competing with battery storage, pumped-storage facilities complement it. Batteries are ideally suited for short-duration balancing services and rapid response, while pumped hydro provides longer-duration energy shifting and seasonal flexibility. Together, these technologies form a critical foundation for future low-carbon electricity systems.

Cross-border electricity trading continues expanding alongside these infrastructure investments. The development of European balancing platforms such as MARI and PICASSO allows transmission system operators to share balancing resources more efficiently while reducing overall system costs. Participation by Southeast European operators continues increasing, further integrating the region into continental electricity markets.

Commercial trading strategies are evolving accordingly. Portfolio optimization increasingly extends across multiple countries rather than focusing on individual national markets. Traders now analyze weather conditions, renewable output, hydrology, transmission constraints and fuel availability across wide geographic areas before determining market positions. Artificial intelligence and advanced forecasting technologies are becoming indispensable tools for predicting renewable generation, electricity demand, congestion and price movements, enabling more efficient market participation.

Climate policy is reinforcing these structural changes. The Energy Community is expanding its focus beyond traditional electricity market reforms toward hydrogen development, carbon dioxide infrastructure, climate legislation and energy security. Future investments across Southeast Europe are therefore expected to encompass integrated energy systems rather than individual generation technologies alone.

At the same time, industrial electricity demand is evolving. Data centers, advanced manufacturing, electrified transport and industrial decarbonization are steadily increasing electricity consumption while changing demand patterns. These developments create additional commercial opportunities for flexible generation, storage technologies and smart-grid solutions.

Countries capable of combining abundant renewable resources with modern transmission infrastructure are expected to benefit the most. Romania continues strengthening opportunities in offshore wind, nuclear power and battery storage while expanding interconnection capacity. Greece is positioning itself as a regional renewable export hub supported by extensive international interconnections. Serbia continues modernizing its transmission system alongside major renewable investments, while Montenegro is reinforcing its position as a renewable electricity exporter through the Italy interconnector. Albania and Bosnia and Herzegovina continue providing valuable hydropower flexibility that supports the broader regional market.

Investment strategies are therefore becoming increasingly regional rather than national. Instead of developing projects solely to satisfy domestic electricity demand, investors are designing portfolios capable of participating across interconnected European markets. Electricity value is now determined not only by production costs but also by timing, flexibility, transmission access and participation in balancing markets.

The broader economic implications extend well beyond the electricity sector itself. Reliable and flexible electricity infrastructure strengthens industrial competitiveness, attracts manufacturing investment and improves national energy security. Countries with efficient transmission networks and flexible electricity systems will be better positioned to attract battery manufacturing, hydrogen production, digital infrastructure and other energy-intensive industries seeking competitively priced low-carbon electricity.

Transmission system operators are therefore assuming an increasingly strategic role within regional economies. Their investment decisions influence not only grid reliability but also renewable deployment, industrial competitiveness and cross-border electricity trade. This growing recognition explains the accelerating transmission investment programs now visible across Southeast Europe.

Perhaps the most significant conclusion emerging from recent regional market assessments is that Southeast Europe is no longer viewed as Europe’s peripheral electricity market. Instead, it is becoming an increasingly important component of the continent’s integrated energy system. Strong renewable resources, expanding transmission infrastructure, improving regulatory alignment and increasing market sophistication are gradually transforming the region into a strategic electricity corridor connecting Central Europe, the Mediterranean and neighboring markets.

The coming decade is unlikely to be defined simply by the construction of additional wind farms and solar parks. Instead, long-term success will depend on effectively integrating renewable generation, energy storage, transmission infrastructure, digital market platforms and cross-border electricity trading. Countries capable of combining these elements into coherent investment strategies are likely to emerge as regional electricity hubs, while those that fail to modernize their infrastructure risk limiting future renewable growth.

For investors, utilities and policymakers, the message from the latest regional market reports is increasingly clear. Southeast Europe’s next investment cycle will not be driven solely by new megawatts of renewable generation, but by the intelligence, flexibility and connectivity of the systems that enable those megawatts to deliver lasting economic value in an increasingly integrated European electricity market.

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The project is being developed by Vjetro Park Korita and is expected to require investment of approximately €132 million. This corresponds to an indicative development cost of €1.5 million per MW, within the range associated with onshore wind projects facing mountainous terrain, road-access requirements and substantial grid works.

Korita is planned across approximately 162 hectares near the village of the same name. The scheme would comprise 11 wind turbines, implying an average turbine rating of around 8 MW. Commercial operation is currently scheduled for 2030.

The connection agreement follows an administrative setback. Montenegro’s Ministry of Spatial Planning rejected the developer’s construction-permit application on 18 June 2026, partly because a CGES connection agreement had not yet been concluded. The grid agreement was signed five days later, resolving that specific deficiency but not automatically reversing the permitting decision.

The Environmental Protection Agency approved the project’s environmental impact assessment in December 2025. Further planning, technical and construction procedures must still be completed before physical works can begin.

At 88 MW, Korita would become one of Montenegro’s larger renewable-energy assets. Its output could support domestic supply, reduce reliance on seasonal imports and potentially contribute to exports through Montenegro’s links with Serbia, Bosnia and Herzegovina, Albania and Italy.

The project’s economics will depend on the final grid-connection scope, access-road and turbine-transport requirements, wind-resource validation and the commercial route to market. A 2030 operating date also leaves substantial exposure to equipment prices, financing costs and possible changes to balancing and market-integration rules.

The CGES agreement therefore improves bankability but does not yet make the project construction-ready. The next critical stage is alignment of the connection design with the renewed permitting process and the conversion of environmental approval into executable construction documentation.

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Gross electricity consumption reached 479,603 MWh, with domestic production covering 96.5% of demand. Imports amounted to 87,978 MWh, down from 109,220 MWh in May 2025, while exports increased to 71,028 MWh from 67,840 MWh.

Thermal power plants generated 146,647 MWh, representing 31.7% of total output. Production from the segment fell 13.6% year on year, illustrating the continuing pressure on North Macedonia’s ageing lignite fleet and domestic coal-supply system.

Hydropower production increased 33.2% to 138,015 MWh, accounting for 29.8% of generation. Wind farms supplied 31,435 MWh, or 6.8%, after recording annual growth of 50.6%.

Solar plants and prosumers generated 143,419 MWh, equal to approximately 31% of total electricity output. Solar production was nevertheless 2.5% lower than in May 2025, suggesting that installed-capacity additions were offset by weaker irradiation or differences in the reporting perimeter and operating conditions.

Biogas plants contributed a further 2,993 MWh. The near-equal shares of thermal, hydro and solar generation produced a more diversified monthly mix than North Macedonia historically maintained, although the balance remains sensitive to weather and lignite availability.

Natural-gas consumption during May stood at 4.46 million cubic metres, coal consumption reached 264,997 tonnes, and petroleum-product consumption amounted to 78,468 tonnes. Approximately 99.9% of coal consumption was used for electricity production.

The reduction in net imports improves the monthly trade balance, but it does not remove North Macedonia’s structural exposure to winter supply risk. Hydropower and solar output are seasonal, while the reliability of domestic thermal production remains tied to mine productivity, plant availability and maintenance at the country’s lignite-fired facilities.

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The transaction is being implemented through PPC Renewables, the group’s wholly owned renewable-energy subsidiary. Greenvolt is backed by global investment firm KKR, placing the deal within a broader pattern of portfolio recycling by international renewable-energy investors.

The solar facility is located near Királyegyháza in southern Hungary and has been operating commercially since July 2024. It benefits from a 25-year government-backed fixed-price support arrangement, providing greater revenue visibility than a fully merchant solar asset. Its expected operating life exceeds 30 years.

PPC has also obtained the right to acquire a neighbouring battery energy storage system with 49 MW of power capacity and a four-hour duration. That specification implies approximately 196 MWh of usable energy capacity, subject to the final technical configuration.

Pairing the two assets could allow PPC to retain low-priced midday solar production and discharge during higher-value evening hours. Hungary’s power market has experienced increasingly pronounced intraday spreads as solar capacity expands, making battery storage strategically valuable even where the associated solar plant already benefits from fixed-price support.

The investment is the first completed transaction under PPC’s 2026–2030 business plan, which envisages approximately €24 billion of investment and aims to almost double the group’s installed generation capacity.

Hungary adds another market to PPC’s expanding regional platform, complementing its positions in Greece and Romania. The group is developing a portfolio across Central and Southeast Europe in which solar, wind, hydropower and batteries can be optimized across markets rather than managed as isolated national assets.

The solar acquisition provides immediate operating cash flow, while the battery option gives PPC flexibility to defer the storage investment until connection, equipment-price and revenue conditions are sufficiently clear.

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The programme covers rooftop solar installations intended for self-consumption, heat pumps used for heating, cooling and domestic hot water, and battery systems that allow households to retain surplus photovoltaic generation for later use.

Standard applicants may receive grants covering as much as 50% of eligible expenditure. Households classified as being at risk of energy poverty may qualify for support covering up to 70% of the investment.

Individual grants for standard applicants will range from €6,000 to €17,850, while vulnerable households may receive between €8,400 and €24,990 in non-refundable support. The structure gives Croatia a stronger residential electrification package than programmes limited solely to photovoltaic panels because it also addresses heat demand and behind-the-meter flexibility.

Battery eligibility is the most consequential addition. Croatia’s growing solar fleet is increasing midday production while household demand frequently peaks later in the day. Storage can raise self-consumption, reduce evening withdrawals from the distribution system and improve the economics of rooftop installations where exported electricity receives less value than power purchased from the network.

The programme will be financed from revenues generated through the auctioning of greenhouse-gas emission allowances under Croatia’s proposed 2026–2030 spending plan. Only new investments are generally eligible. Costs must be incurred after publication of the call, although advance equipment payments and expenditure related to preparing HEP ODS metering points may qualify when paid on or after 1 January 2026.

Projects fully paid before the programme was announced are excluded. A separate retroactive mechanism is planned for households that installed and commissioned solar systems after the previous call closed but before the new programme opened. Eligible applicants under that arrangement will be able to recover up to 50% of project costs.

The programme shifts Croatian residential policy from simple renewable-capacity support towards coordinated household energy management. Its effectiveness will depend on distribution-connection processing, equipment availability, installer capacity and whether grant payments are made quickly enough to avoid imposing excessive bridge-financing requirements on households.

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The revised purchase price is estimated at approximately €0.50 per cubic metre. Federation Energy, Mining and Industry Minister Vedran Lakić said the adjustment was determined by Gazprom Export and was not negotiated or set by the Bosnian importer.

The increase adds another layer of cost pressure to a gas market that remains structurally exposed to a single supplier and limited physical import options. Bosnia and Herzegovina receives most of its gas through the eastern route connected to the Turkish Stream system, leaving the country vulnerable to changes in Russian contract prices and regional transmission conditions.

At €0.50 per cubic metre, the commodity cost is equivalent to roughly €47–€50/MWh, depending on the gas calorific value, before transmission, distribution, balancing, taxes and supplier margins. The final cost to industrial and district-heating consumers will therefore be materially higher.

The pricing decision strengthens the commercial rationale for the proposed Southern Gas Interconnection, which would connect Bosnia and Herzegovina to Croatia’s gas system and provide access to the Krk LNG terminal, European trading hubs and non-Russian supply. The project has advanced slowly because of political and institutional disagreements over ownership and system operation.

Diversification would not automatically guarantee cheaper gas. LNG prices, Croatian transmission charges and the cost of new infrastructure would all affect the delivered price. It would, however, introduce competitive tension into procurement and reduce the ability of a single supplier to dictate quarterly terms without an immediately available alternative.

The increase also matters for Sarajevo’s district-heating system and industrial consumers whose operating margins are sensitive to imported energy costs. Without alternative physical capacity, Bosnia’s negotiating position will remain weak even when wider European gas markets are adequately supplied.

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The authorization, issued by the US Treasury’s Office of Foreign Assets Control, had been due to expire on 25 July. It permits potential buyers to conduct due diligence, negotiate conditional agreements and carry out activities needed to preserve the assets while talks continue. The latest decision represents the eighth extension granted since Lukoil announced its intention to dispose of overseas operations.

The process carries particular significance for Southeast Europe, where Lukoil owns strategically important refining, wholesale and retail infrastructure. Its portfolio includes the Lukoil Neftohim Burgas refinery in Bulgaria, the Petrotel refinery in Romania and more than 800 petrol stations across Bulgaria, Romania, Serbia, Croatia, Montenegro, Moldova and North Macedonia.

Lukoil previously said it had reached an agreement to sell most of its international operations to US investment group Carlyle in a transaction reportedly valued at around $22 billion. Other international energy companies, including ExxonMobil and Chevron, have also been associated with interest in selected assets.

The changing deadline illustrates the difficulty of completing a large cross-border disposal while sanctions, regulatory approvals and national energy-security concerns remain unresolved. The refineries in Bulgaria and Romania are not merely financial assets: they form part of the region’s fuel-supply infrastructure, and any ownership transfer would require close scrutiny by national governments and competition authorities.

OFAC has separately extended authorization for Lukoil’s international filling-station network to continue operating until 29 October 2026. Specific transactions involving the group’s Bulgarian subsidiaries also remain permitted under separate sanctions-related arrangements.

For Southeast European governments, the prolonged sale process reduces the immediate risk of an operational interruption but leaves ownership and future investment decisions unsettled. Refinery maintenance, crude-supply arrangements, working-capital lines and fuel-retail continuity will remain sensitive until buyers, financing and regulatory approvals are firmly in place.

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The Monday comparison should be treated with some caution because the preceding session covered a Sunday. Nevertheless, the scale of the changes pointed to more than a routine weekday recovery. Germany remained heavily affected by midday renewable generation, while Serbia and parts of the central and southern Balkans faced materially tighter residual-load conditions. The result was wider cross-border price dispersion, even as Hungary, Romania, Bulgaria, Croatia and Slovenia remained relatively closely aligned.

Serbia emerged as the regional premium market. SEEPEX’s baseload price almost doubled from Sunday, rising by €56.9/MWh to €114.43/MWh. This was the highest price among the monitored Balkan and Central European exchanges outside Italy, placing Serbia at a premium of €18.85/MWh to Hungary, €19.40/MWh to Romania, €21.40/MWh to Bulgaria and €17.38/MWh to Croatia.

The Serbian price curve was also structurally different from those of the more strongly coupled Hungarian-Romanian-Croatian corridor. SEEPEX recorded a minimum hourly price of €70/MWh, compared with approximately €10/MWh in Hungary, Romania, Bulgaria, Greece and Croatia. Serbia therefore avoided the deep solar-driven midday trough visible across neighbouring markets, while its maximum reached €187.40/MWh in hour 22 as the evening ramp tightened after solar production disappeared.

Serbian peak power averaged €104.50/MWh, while off-peak power was even higher at €124.30/MWh. The inverted relationship partly reflected the low midday prices included in the standard peak block, but the Serbian trough remained significantly shallower than elsewhere. The pattern indicated that domestic supply tightness and restricted cross-border access outweighed the regional solar surplus during the central hours.

Serbia was forecast to consume 3,471 MW, up 408 MW from Sunday, while generation was expected to reach only 2,871 MW. The resulting net-import requirement stood at 600 MW, compared with 627 MW on Sunday. Serbia was scheduled to import electricity from Croatia, North Macedonia, Bosnia and Herzegovina, Hungary and Romania while continuing to export approximately 147 MW to Montenegro.

The market separation was reinforced by the absence of scheduled commercial flows on the Bulgaria-Serbia border. Bulgaria cleared at only €93.03/MWh, yet no direct commercial flow was recorded between the two markets. Imports from Hungary averaged only 106 MW despite Hungary trading almost €19/MWh below Serbia. The price difference therefore reflected a combination of local supply tightness, limited exchange liquidity and border-allocation constraints, rather than a shortage across the entire region.

Hungary cleared at €95.58/MWh, only €3.6/MWh above Sunday. Romania was virtually identical at €95.48/MWh, while Croatia reached €97.05/MWh and Slovenia €98.17/MWh. The narrow €2.69/MWh range between Hungary and Slovenia showed that the northern Southeast European corridor remained effectively coupled at the baseload level.

Bulgaria was slightly cheaper at €93.03/MWh, a discount of €2.55/MWh to Hungary. Greece cleared at €101.76/MWh, establishing a €6.18/MWh premium to HUPX and an €8.73/MWh premium to Bulgaria. Strong scheduled Bulgarian exports towards Greece, averaging 775 MW, helped bridge the difference but did not eliminate it.

Montenegro rose by €23.3/MWh to €103.11/MWh, while North Macedonia gained €25.9/MWh to €97.69/MWh. Albania moved in the opposite direction, falling €8.9/MWh to €73.80/MWh, the lowest Balkan price. This created a discount of €21.78/MWh to Hungary and almost €41/MWh to Serbia.

Albania’s low baseload price was accompanied by a considerably more volatile hourly profile. Its minimum fell to €2.90/MWh, while the maximum reached €200/MWh. The combination pointed to a relatively shallow market in which hydrological availability, limited domestic demand and border schedules can produce large hourly movements without generating stable convergence with neighbouring exchanges.

Italy remained the dominant high-price destination. The national Italian price reached €185.06/MWh, while the northern zone cleared at approximately €183.40/MWh. The region was scheduled to export an average of 1,197 MW towards Italy, including almost 599 MW over the Montenegro-Italy interconnector. Italy’s premium of almost €90/MWh to Hungary continued to pull available western Balkan and Slovenian supply westward, reducing the energy available to relieve local Serbian and central Balkan tightness.

Germany fell by €13.1/MWh to €77.09/MWh, opening an €18.49/MWh discount to Hungary. German peak power averaged only €39.90/MWh, compared with off-peak power at €114.30/MWh. The minimum hourly price was slightly negative at minus €0.70/MWh, while the evening maximum recovered to €179/MWh.

Hungary followed a similar curve but with less severe midday compression. HUPX recorded a minimum of €10.50/MWh in hour 13 and a maximum of €179.30/MWh in hour 22. Peak power averaged €66.70/MWh, against off-peak power at €124.50/MWh.

The widening Germany-Hungary spread coincided with a strong increase in imports from Austria and Slovakia into Hungary and the wider Southeast European region. CORE imports were forecast at 2,813 MW, up 2,097 MW day on day. These flows were essential to cover the Monday demand recovery but were insufficient to produce full price convergence farther south, particularly in Serbia.

The latest complete generation data, covering Sunday, showed total regional output falling to 26,275 MW, down 1,354 MW from Saturday. The most significant change was wind production, which declined by 1,742 MW, or approximately 56 per cent, to only 1,396 MW.

Gas-fired generation increased by 315 MW to 3,767 MW, partly compensating for the loss of wind. Solar production rose by 589 MW to 5,684 MW, while nuclear generation remained stable at 5,604 MW. Coal output eased marginally to 5,570 MW, and hydropower fell by 268 MW to 3,854 MW.

The decline in hydroelectric generation is becoming increasingly important for Serbia and the inland Balkan markets. Serbian hydropower averaged 586 MW on Sunday, down from 638 MW on Saturday, while coal generation declined to 2,008 MW. Total Serbian generation consequently fell to 2,437 MW, leaving the country dependent on imports for roughly one-fifth of demand. Reported Danube flows of approximately 4,786 cubic metres per second remained weak enough to constrain hydro flexibility during higher-value hours.

For Monday, regional generation was forecast to recover to 28,876 MW, while solar output was expected to rise to 7,734 MW and wind generation to 2,042 MW. These renewable gains were not sufficient to match the 4,777 MW increase in consumption, leaving a 1,646 MW system deficit to be covered through net imports.

The largest individual demand increases were forecast in Romania, up 1,170 MW to 5,375 MW, Greece, up 1,049 MW to 6,658 MW, Hungary, up 690 MW to 4,364 MW, and Bulgaria, up 671 MW to 3,727 MW. Greece shifted from a Sunday export position of 148 MW to imports of 385 MW, while Hungary’s deficit expanded from 235 MW to 1,101 MW.

Bulgaria remained the region’s principal exporter at 1,322 MW, supported by nuclear generation and stronger forecast solar output. Romania was expected to export 251 MW, while Bosnia and Herzegovina retained an export balance of 227 MW. Croatia’s import requirement widened to 1,050 MW, reflecting forecast generation of only 1,100 MW against demand of 2,150 MW.

The forward market retained a strong weather and scarcity premium. The Hungarian Week 31 contract stood at €143/MWh, carrying a €15/MWh premium to Germany’s equivalent contract at €128/MWh. Italy remained substantially higher at €179/MWh. Week 32 showed a steeper Hungarian risk premium, with Hungary trading at €175.50/MWh, Germany at €144.50/MWh and Italy at €181/MWh.

The increase from €143/MWh for Week 31 to €175.50/MWh for Week 32 indicated that the forward market was pricing a material increase in residual-load and weather risk. Hungary’s Week 32 premium to Germany widened to €31/MWh, more than double the Week 31 spread. Italy’s premium to Hungary, by contrast, narrowed from €36/MWh to only €5.50/MWh, suggesting that Central and Southeast European tightness could approach Italian levels.

Fuel and carbon markets continued to provide a firm thermal floor. Austrian CEGH gas was assessed at €64.46/MWh, the Greek gas reference at €45/MWh and EU allowances at €83.40/tCO₂. Gas forwards stood near €64.50/MWh for the 2026 average and €65/MWh for the fourth quarter, while coal was indicated at $121/t for the annual average and $126/t for the fourth quarter.

At these input levels, gas-fired generation remains expensive enough to support elevated evening power prices whenever solar output falls and wind availability disappoints. The decisive trading feature for the next sessions is therefore the contrast between very weak German and regional midday prices and a much tighter evening ramp.

Serbia remains particularly exposed to any further deterioration in hydrological or wind conditions. Its exceptionally high minimum price, continued dependence on imports and limited access to cheaper Bulgarian supply leave SEEPEX more vulnerable than the better-coupled northern markets to local supply tightness. The 27 July session therefore highlighted a widening structural divide within the region: cheap renewable-driven midday electricity in the north and a much tighter, import-dependent evening market in Serbia and parts of the central Balkans.

The post Trading Note 27/7: Serbia decouples as demand rebounds and German solar widens regional spreads appeared first on Serbia SEE Energy Mining News.

The proposed sale consists of three 100 MW blocks and two 50 MW blocks. Full subscription would represent approximately 3.5 TWh of electricity annually and nearly 70 TWh over the 20-year period. The minimum aggregate contract value is estimated at around €5.6 billion, implying a floor price of approximately €80/MWh before indexation and detailed delivery adjustments.

The contracts will be auctioned through the Romanian Commodities Exchange under EFET documentation. Pricing mechanisms may include inflation-linked floors and caps or references to the day-ahead market, while counterparties will be required to meet financial qualification criteria. Delivery reductions will be permitted during specified outages, an important provision given that Unit 1 is scheduled to undergo major refurbishment between 2027 and 2030.

The structure sits between a conventional corporate PPA and a project-finance offtake agreement. Nuclearelectrica would gain long-term revenue visibility to support debt service and capital planning, while industrial buyers would secure access to low-carbon baseload generation without taking full exposure to the extreme volatility of Romania’s spot market, where prices on 24 July ranged from approximately €13/MWh to more than €200/MWh.

The implied €80/MWh price floor is significantly below Romania’s current baseload price but nearly six times the 24 July afternoon minimum. Buyers are therefore paying for long-term supply security, predictable volume and baseload availability, rather than attempting to capture the cheapest spot-market intervals.

The central commercial question will be whether creditworthy industrial consumers are willing to commit to contracts lasting up to 20 years while electricity regulation, industrial demand and renewable generation capacity continue to evolve. For Nuclearelectrica, however, the auction could provide a valuable mechanism for converting future nuclear production into long-term revenue certainty ahead of one of Romania’s largest power-sector investment programmes.

The post Nuclearelectrica launches 20-year power auction to support Cernavodă Unit 1 refurbishment appeared first on Serbia SEE Energy Mining News.

Hydroelectric generation increased by 32.4 per cent to 3.13 TWh, while output from transmission-connected wind and solar plants rose 16.1 per cent to 0.64 TWh. In contrast, coal-fired generation fell 16.9 per cent to 3.07 TWh, marking a substantial reduction in the contribution of the country’s traditional thermal fleet.

The stronger domestic generation balance enabled Bosnia and Herzegovina to reduce electricity imports by almost 40 per cent, following a record expenditure of BAM 629 million, or approximately €321.6 million, on imported power during 2025. Exports nevertheless declined by around 20 per cent, suggesting that the additional hydroelectric generation was used primarily to displace imports and weaker thermal output rather than restore the country’s former export surplus.

Hydropower and coal each accounted for roughly 41–42 per cent of first-half electricity production, while grid-connected wind and solar contributed approximately 9 per cent. The resulting mix is considerably more balanced than Bosnia and Herzegovina’s traditional dependence on ageing lignite-fired generation, although the improvement remains highly exposed to hydrological conditions.

A return to dry conditions would remove a significant volume of low-variable-cost hydroelectric generation at the same time as the thermal fleet continues to face challenges linked to mine performance, environmental requirements and ageing equipment. Utilities can therefore achieve substantial reductions in import expenditure during favourable water years without resolving the structural availability problems affecting the country’s coal assets.

For regional power traders, the decline in Bosnia and Herzegovina’s import requirement removes one source of demand during wet periods, while lower exports create an opposing effect. The country is becoming less consistently directional in cross-border electricity trading. Hydrological conditions, coal plant outages and reservoir management decisions can now shift the market between importer and exporter more rapidly than its historical generation profile would suggest.

The post Bosnia’s hydro recovery cuts imports as coal generation retreats appeared first on Serbia SEE Energy Mining News.

The 257 hours represented approximately 2.9 per cent of the year, equivalent to almost 10.7 full days of continuously negative pricing. These events were concentrated mainly in spring and on sunny Sundays, when electricity demand was weak, photovoltaic generation was strong and some subsidised generators continued operating under mandatory-offtake obligations or legacy support arrangements.

The commercial impact extends well beyond the hours when prices actually turn negative. Solar developers must also contend with a much larger number of periods in which prices remain positive but fall below project operating assumptions. A plant selling electricity at only €5–€20/MWh during its highest-output hours can suffer severe capture-price erosion without technically operating during a negative-price event.

Newer Croatian market-premium contracts can suspend support when prices remain negative under specified conditions, transferring more of the market signal to generators. This can improve dispatch discipline and market responsiveness, but it also increases revenue volatility for lenders and equity investors unless projects are equipped with storage, curtailment rights or more sophisticated power-offtake arrangements.

Croatia had only approximately 11 MW of battery storage capacity in March 2026, although the country’s first large-scale system entered trial operation early in the year. The regulatory framework for wider deployment is still being completed, with more meaningful additions expected from 2027.

The resulting mismatch is increasingly pronounced: negative-price exposure is already becoming structural, while utility-scale storage remains at an early stage of development. Early battery projects could benefit from relatively less crowded balancing and arbitrage markets, but they also face unresolved questions regarding network tariffs, charging status, licensing requirements and the treatment of potential double grid fees.

For solar investors, the Croatian data provides a clear warning against valuing new projects solely on the basis of annual average CROPEX prices. Capture-rate forecasts must account for at least 257 negative-price hours, additional near-zero-price periods and the possibility that continued photovoltaic expansion will deepen the midday price discount before sufficient storage capacity comes online.

The trend points to a broader shift in Croatia’s power market: as solar capacity grows faster than flexibility resources, the value of electricity will increasingly depend not only on how much power a plant produces, but also on when that power reaches the market.

The post Croatia’s growing negative-price exposure makes storage a market necessity appeared first on Serbia SEE Energy Mining News.

Prices in Romania fell to approximately €13.25/MWh during the afternoon solar period before climbing to €200.76/MWh at 22:00. The gap between the daily low and high therefore exceeded €187/MWh, creating one of the most pronounced intraday spreads in the regional market.

This price inversion has direct consequences for renewable project valuations. A Romanian solar plant may appear to be operating in a €130/MWh baseload market, yet much of its physical generation is delivered during hours when prices clear at only €13–€30/MWh. Using the arithmetic daily average as a proxy for solar capture prices can therefore significantly overstate merchant cash generation, unless the project is supported by a contract for difference, a fixed-price PPA or colocated storage.

A similar pattern emerged further west. Hungary’s electricity price fell to €13.52/MWh at 14:00 before reaching €200.88/MWh at 21:00. Slovenia dropped to €13.62/MWh during the same central European hour and later peaked at €199.76/MWh in the evening.

Hungary’s intraday range reached €187.36/MWh, while Slovenia recorded a spread of €186.14/MWh. In theory, a battery buying electricity at the daily minimum and selling at the maximum would face a gross spread approaching €187/MWh. At an 85 per cent round-trip efficiency, electricity purchased at €13.52/MWh would translate into a charging cost of approximately €15.91/MWh per discharged megawatt-hour, leaving a theoretical energy margin of nearly €185/MWh before accounting for degradation, connection charges, trading fees and imbalance exposure.

The maximum spread, however, was available only for a limited period and cannot be extrapolated across every battery cycle. As storage deployment increases, it will also tend to lift afternoon prices and reduce evening scarcity. Nevertheless, the 24 July price curve provides a stronger commercial signal for short-duration flexibility than a conventional annual baseload forecast. The value of storage becomes particularly evident when aggregate demand declines but the evening marginal price still approaches €200/MWh.

Bulgaria and Greece displayed a flatter price profile. Both markets fell to approximately €72.23/MWh around midday and reached daily highs of about €162.09/MWh during the morning. Their solar-driven price discount was therefore significant but considerably less severe than in Romania, Hungary and Slovenia.

Bulgaria’s nuclear baseload, regional interconnection capacity and growing battery fleet helped limit the depth of its afternoon price trough, while Greece remained more dependent on gas-fired generation throughout the day. The contrast underlined the importance of generation mix, storage capacity and interconnection availability in determining how strongly solar production translates into intraday price volatility.

The post Romania’s €90.81/MWh peak price highlights the growing impact of solar cannibalisation appeared first on Serbia SEE Energy Mining News.

Between July 20, 2026 and July 26, 2026, 76 articles were published.

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The approximate monthly average was €44.8/MWh. The movement from the monthly high to the low represented a decline of about 19.2%, while the closing price remained approximately 9.8% below the opening level.

Beneath that downward curve, Europe continued to face a difficult combination of storage requirements, global LNG competition and geopolitical uncertainty. Higher temperatures lifted gas demand from power generation as cooling-related electricity consumption increased across most European markets. Storage injections continued, but elevated prompt prices and constrained LNG availability limited the incentive to accelerate replenishment.

Pipeline supplies from Norway and North Africa provided an important stabilising influence. The TTF decline through the middle of June suggests that the market did not expect an immediate loss of large physical volumes. The late recovery from €40.19/MWh to €43.58/MWh, however, showed that traders continued to price risks around LNG availability, storage adequacy and shipping security.

Concern over Middle Eastern maritime routes added a premium to global LNG optionality. Qatar’s position as one of the world’s largest LNG exporters means that disruption around the Strait of Hormuz can influence European prices even before physical deliveries are materially reduced. European buyers are competing with Asian markets for flexible cargoes, while vessel availability, shipping costs and insurance conditions determine how quickly LNG can be redirected.

Sanctions policy introduced a separate shipping risk. Proposed restrictions on Russian LNG transshipment and transportation by EU-owned vessels created tension between reducing Russian energy revenue and protecting the competitiveness of European maritime companies.

Greece’s position is particularly sensitive because Greek-controlled fleets play a major role in global LNG transportation. Measures applying to EU-owned vessels could shift part of the business towards non-EU operators without necessarily removing the underlying Russian LNG from the global market. The dispute therefore reaches beyond energy security into shipping competitiveness, fleet ownership and the effectiveness of sanctions enforcement.

The physical gas-flow data demonstrate that South-East Europe is better placed to respond to such risks than it was several years ago. LNG terminals in Greece, Croatia and Italy, Romanian domestic production, the Greece-Bulgaria interconnections and Hungary’s transit network now provide several overlapping routes for consumption, storage and cross-border trade.

Greece received slightly more than 3 TWh through LNG terminals during June, based on rounded chart totals, together with approximately 1.1 TWh from Bulgaria. Domestic final-consumer exits were around 4.2 TWh, while distribution accounted for approximately 0.8 TWh. Direct exports back to Bulgaria remained limited.

The Greek system’s immediate role in June was therefore more domestic than transit-oriented. LNG receipts and Bulgarian inflows supplied consumption and distribution, with only modest volumes physically moving north from Greece. That does not diminish the strategic value of the Greek entry system: it shows that LNG infrastructure can alternate between domestic security and regional supply depending on price spreads, nominations and network conditions.

Bulgaria operated as a much larger transmission platform. Its aggregate entry and exit flows were dominated by network transmission, supplemented by supplies through the Greece-Komotini, Trans Adriatic Pipeline and Greece-Bulgaria Interconnector routes. Additional volumes moved towards Romania.

This configuration gives Bulgaria a central role in linking Greek LNG and Southern Gas Corridor supplies with Romania and Central Europe. The country’s value lies not only in domestic demand but in the ability to receive gas from the south, move it north and east, and use storage or reverse-flow capability when market conditions change.

Romania remained the strongest indigenous production centre in the covered SEE gas market. Domestic output reached approximately 7 TWh during June, while inflows from Bulgaria were around 2.5 TWh. Storage injections approached 3.6 TWh, and exports towards Hungary reached approximately 1.9 TWh.

Romanian production was therefore serving three markets simultaneously: domestic consumption, inventory rebuilding and westbound regional trade. This makes the pace of Romanian production development, transmission availability and storage injection commercially significant well beyond the country’s borders.

The ability to direct more than one-third of the combined domestic production and Bulgarian inflow towards storage highlights the importance of Romania’s seasonal flexibility. The same infrastructure can become a source of withdrawal capacity during winter, reducing pressure on imports through Central Europe and supporting neighbouring markets when LNG prices rise.

Croatia’s position was shaped by the Krk LNG route. LNG terminal inflows were approximately 2.7 TWh, compared with domestic production of roughly 0.45 TWh. Around 1.45 TWh moved towards Hungary, approximately 0.75 TWh was directed into storage and close to 0.8 TWh supplied final consumers.

The Croatian market therefore used LNG not only for national consumption but also as an export and storage resource. Croatia’s role is especially notable because its electricity system moved in the opposite direction during June, relying on net electricity imports of 772.3 GWh while the gas system supplied neighbouring markets.

Hungary combined multiple entry routes with domestic production and significant transit activity. Transmission entries reached approximately 6 TWh, supplemented by around 2.4 TWh of domestic production, 1.9 TWh from Romania, 1.5 TWh from Croatia and roughly 0.5 TWh from Austria.

Transmission exits approached 4.7 TWh, while approximately 1.2 TWh was directed towards storage. Distribution absorbed close to 1.9 TWh. These flows reinforce Hungary’s position as both a consuming market and a routing centre connecting the Adriatic, Romanian, Austrian and wider Central European systems.

Hungary’s import diversity provides optionality, but it also exposes the market to congestion and competing regional nominations. During periods of strong storage injection, heat-driven power demand or disruption on one route, the value of firm transmission capacity can rise significantly above the underlying commodity spread.

Italy operated on a much larger scale. The country received approximately 16.5 TWh through LNG terminals and around 28 TWh through its wider transmission entry system, supplemented by inflows from Switzerland and Austria. Domestic production contributed roughly 2.5 TWh.

Final-consumer exits approached 28 TWh, while storage absorbed close to 17 TWh. Distribution accounted for approximately 9 TWh. Italy was therefore simultaneously supporting summer consumption, gas-fired electricity generation and a substantial storage-injection programme.

The relationship between the Italian gas and electricity markets was especially visible in June. Gas-fired electricity output increased by 30.7%, while Italy’s power price rose to €132.51/MWh, the highest in the regional comparison. Every €5/MWh movement in TTF changes the fuel cost of a 50%-efficient gas plant by approximately €10/MWh, before carbon and operating costs. Italy’s power market remains highly sensitive to even moderate gas-price movements.

The June gas network was not organised around a single dominant direction. Greek LNG supplied domestic demand and potential northbound access; Bulgaria provided transmission flexibility; Romania combined domestic production with storage and exports; Croatia directed LNG towards Hungary; Hungary connected several regional routes; and Italy absorbed the largest volumes for consumption and storage.

This diversity reduces dependence on any single entry point, but it does not eliminate price risk. LNG terminals require competitively priced cargoes, interconnectors require available capacity, storage must be filled at commercially viable spreads, and pipeline systems need compatible nomination and balancing arrangements.

The most valuable assets are consequently those able to switch between several revenue functions. LNG terminals gain value from regasification, capacity reservation and regional exports. Interconnectors benefit from congestion spreads and security-of-supply demand. Storage facilities capture seasonal spreads while providing balancing and emergency withdrawal capability. Transmission capacity becomes most valuable precisely when physical flows need to change direction.

June ended with TTF below its opening level, but with Europe still rebuilding inventories, consuming more gas in the power sector and carrying a material geopolitical premium. South-East Europe’s expanding network of LNG terminals, production centres, storage facilities and interconnectors has turned the region from a peripheral end-market into an increasingly important corridor for European gas flexibility.

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Across the seven interconnected European markets covered by the data, the simple average day-ahead price reached approximately €112.54/MWh. Italy retained its position as the region’s most expensive market at €132.51/MWh, followed by Hungary at €124.67/MWh and Romania at €122.99/MWh. Croatia averaged €115.90/MWh, Serbia €100.71/MWh, Bulgaria €98.08/MWh and Greece €92.93/MWh. Türkiye remained structurally detached from the European price formation mechanism, averaging only €23.37/MWh.

The regional price ladder reveals several distinct market zones. Hungary and Romania formed a Central European scarcity cluster, separated by only €1.68/MWh. Serbia and Bulgaria were also relatively closely aligned, with a spread of €2.63/MWh, while Italy traded €39.58/MWh above Greece. Türkiye’s discount to Greece reached €69.56/MWh, and its discount to Italy widened to €109.14/MWh.

Hungary recorded the strongest monthly price increase among the interconnected European markets, rising 17.05% from May and 48.25% from June 2025. Romania followed with a 12.25% monthly and 42.79% annual increase. Croatia rose 11.89% month on month and 34.76% year on year, while Italy gained 11.02% and 18.54% respectively. Greece and Serbia recorded more moderate monthly increases of 4.45% and 4.23%. Bulgaria was the only covered European market to register a decline, falling 2.97% to €98.08/MWh, although its price remained 15.01% higher year on year.

The rise in cooling demand was uneven but substantial. Electricity consumption increased by 19.5% in Greece, 18.6% in Hungary, 11.0% in Croatia, 10.4% in Türkiye and 10.0% in Italy. Romania recorded a comparatively modest 1.4% increase, while Bulgaria remained broadly stable. Serbia moved against the regional pattern, with reported demand falling by 13.5%.

Supply conditions diverged even more sharply. Renewable generation increased by 27.6% in Türkiye, 13.5% in Bulgaria and 10.7% in Greece, but fell by 43.8% in Serbia, 24.0% in Croatia, 22.9% in Romania and 6.2% in Italy. Hungary recorded only a 2.3% increase despite the surge in demand.

Hydropower, normally one of the region’s most important sources of flexibility, weakened across much of the market. Output fell by 37.9% in Hungary, 19.6% in Greece, 11.3% in Romania, 10.0% in Türkiye and 3.2% in Croatia. Serbian hydro production was effectively unchanged at -0.1%. Bulgaria and Italy were the exceptions, with increases of 11.1% and 6.6%.

The interaction between stronger consumption and weaker flexible generation became visible on 30 June, when daily averages reached €293.44/MWh in Romania, €290.36/MWh in Hungary, €263.59/MWh in Croatia, €250.98/MWh in Serbia and €148.44/MWh in Bulgaria. Several markets had recorded their monthly lows on 13 June, including €35.12/MWh in Serbia, €39.66/MWh in Croatia, €46.03/MWh in Romania and €49.70/MWh in Bulgaria. The common timing points to a region-wide transition from renewable-led surplus conditions to heat-driven scarcity rather than isolated national events.

Hungary sat at the centre of that tightening balance. Demand increased by 18.6%, while gas-fired generation rose 68.2%, nuclear output increased 20.5% and coal and lignite production gained 9.6%. Renewables excluding hydro increased by only 2.3%, while hydro output contracted sharply.

Imports represented 30.81% of Hungary’s electricity balance. Net imports reached 1,312.39 GWh, increasing by 21.93%, or 236.08 GWh, from May. Hungary imported electricity from Austria, Croatia, Romania and Slovakia while exporting towards Serbia and Ukraine. HUPX traded 2,382.87 GWh, down 8.05% month on month but around 4.1% higher year on year.

Romania reached almost the same monthly price through a different generation configuration. Renewable output fell by 22.9% and hydro production by 11.3%, but nuclear generation increased by 122.5%, apparently reflecting the return of capacity following outages or maintenance. Gas-fired generation rose 10.8%, while coal and lignite output increased 7.1%.

The nuclear recovery prevented an even tighter Romanian balance but did not eliminate the need for imports. Romania ended June with net imports of 543.45 GWh, receiving its largest incoming volume from Bulgaria while exporting primarily towards Hungary.

Liquidity weakened at the same time as Romania’s price and volatility increased. OPCOM cleared only 888.35 GWh, down 20.05% from May and 63.42% from June 2025. This combination of higher prices, extreme daily movements and reduced exchange turnover creates additional basis and execution risk for utilities, industrial consumers and trading companies attempting to hedge Romanian exposure.

Croatia experienced a more direct renewable and import shock. Electricity demand increased by 11.0%, renewable generation fell 24.0% and hydro output declined 3.2%. Net imports consequently rose by 32.27% to 772.3 GWh, accounting for 52.18% of the reported electricity balance.

Croatia received electricity from Hungary and Slovenia while exporting to Bosnia and Herzegovina and Serbia. CROPEX volume increased 12.42% to 986.15 GWh, although year-on-year growth was limited to 1.52%. The market’s daily range of €223.93/MWh, measured between the €39.66/MWh low and €263.59/MWh peak, showed that growing exchange activity had not reduced the underlying physical volatility.

Italy remained the regional price ceiling. Its average increased to €132.51/MWh, and daily prices stayed above €100/MWh on all but four days. The highest daily average was recorded on 24 June at €162.66/MWh, alongside electricity demand of 722 GWh. The monthly low of €91.15/MWh occurred on 14 June.

Italian demand increased 10.0%, while gas-fired generation rose 30.7%. Coal generation more than doubled, increasing 124.2% from a low base. Renewable output fell 6.2%, although hydro production increased 6.6%.

Italy’s reliance on gas explains much of the persistent premium. At an approximate June TTF average of €44.8/MWh, a gas-fired unit operating at 50% efficiency faced a fuel cost close to €90/MWh before carbon allowances, start-up costs and variable operations and maintenance. A more efficient plant operating at 55% still carried a fuel cost of about €81.5/MWh.

Net electricity imports increased 14.92% to 4,259.03 GWh, with supplies arriving from France, Switzerland, Austria, Greece, Montenegro and Slovenia. Italy exported only to Malta. Imports provided important system support but could not displace gas as the marginal price-setting technology.

IPEX cleared 25,620.73 GWh, an increase of 11.42% from May and 3.97% year on year. Italy represented approximately 68% of the 37.64 TWh traded across the seven exchanges for which June volume data were available, highlighting the difference between Italian liquidity and the much thinner markets of Romania, Serbia and Croatia.

At the lower end of the interconnected market, Greece and Bulgaria converted comparatively favourable low-carbon supply into export capacity. Greece averaged €92.93/MWh, up 4.45% from May and 8.79% year on year. HEnEx volume increased 15.57% to 4,482.02 GWh, although it remained 7.03% below June 2025.

Renewables supplied 56.01% of Greek generation and increased output by 10.7%. Gas-fired production rose 23.7% to balance higher cooling demand, while hydro fell 19.6% and lignite production declined 41.3%. Greece nevertheless exported a net 726.98 GWh to Albania, North Macedonia, Bulgaria and Italy. Türkiye was its only import source. Greek exports to Bulgaria reached 390.98 GWh, the country’s largest reported bilateral electricity flow.

Bulgaria’s monthly price declined to €98.08/MWh as nuclear generation rose 11.0%, renewables increased 13.5% and hydropower gained 11.1%. Coal and lignite output fell 23.9%, while gas-fired generation declined 28.2%. Nuclear accounted for 34.65% of generation, renewables 31.91% and hydro 18.72%.

This combination allowed Bulgaria to export a net 386.55 GWh while reducing thermal dispatch. It exported towards North Macedonia, Romania and Serbia and received electricity from Greece and Türkiye. IBEX volume reached 2,708.01 GWh, increasing 1.20% from May and 18.50% year on year.

Serbia’s June balance was particularly revealing. The SEEPEX average increased to €100.71/MWh, or 17.49% above June 2025, despite the reported 13.5% decline in demand. Coal and lignite generation rose 22.9%, while gas-fired output increased 135.4% from a low base. Renewables fell 43.8%, and hydro production was nearly unchanged.

Coal and lignite represented 63.72% of Serbian generation, compared with 30.42% for hydro, 4.22% for other renewables and 0.91% for gas. Serbia moved into a net exporting position of 100.63 GWh, sending electricity towards Bulgaria, Montenegro, Croatia and Kosovo while importing from Hungary, North Macedonia, Bosnia and Herzegovina and Kosovo.

The monthly average hides a much more significant intraday development. Serbia’s average hourly price fell towards approximately €40/MWh around midday, when solar production was strongest, before climbing to almost €200/MWh during the evening peak. No other covered market displayed such a pronounced average transition between daytime surplus and post-sunset scarcity.

This two-speed price curve creates an increasingly credible commercial case for battery storage. A theoretical 50 MW/100 MWh battery charging at €40/MWh and discharging at €200/MWh, with 85% round-trip efficiency, would generate a gross daily arbitrage margin of roughly €15,300. That spread would not be available every day, but a combined arbitrage and balancing model could potentially support gross annual revenue of approximately €100,000-€150,000 per MW under favourable market-access conditions.

At an indicative installed cost of €260-€360 per kWh, the investment envelope for such a project would be approximately €26-€36 million. A diversified revenue model combining day-ahead trading, intraday optimisation and balancing services could target a base-case unlevered return in the low-to-mid teens, with an upside case in the high teens. A 12-18 month connection delay would remove at least one summer trading season, increase interest during construction and could reduce equity IRR by approximately 1.5-3.5 percentage points.

SEEPEX volume reached 569.14 GWh, only 0.5% higher than in May and 5.01% lower year on year. The limited liquidity increases route-to-market and basis risk, making access to balancing services and bankable optimisation arrangements as important as the visible day-ahead spread.

Türkiye presented the region’s sharpest statistical rebound but remained commercially detached from European price levels. Its average more than doubled from May, rising 109.28% to €23.37/MWh, yet remained 52.20% below June 2025.

Turkish demand increased 10.4%, renewable generation rose 27.6% and coal-fired output increased 56.7%. Hydropower declined 10.0% but still accounted for 41.01% of the generation mix. Coal and lignite supplied 26.11%, other renewables 22.73%, gas 9.94% and oil 0.21%. Gas-fired output declined 3.3%, insulating the Turkish market from Europe’s higher gas-based marginal costs.

Türkiye exported 286.88 GWh, including 184.12 GWh to Georgia, 75.44 GWh to Bulgaria and 27.32 GWh to Greece. These exports were small relative to the theoretical value implied by the cross-border spreads, reflecting the limits imposed by interconnection capacity, market arrangements and system-security requirements.

June confirmed that South-East Europe is becoming more interconnected without becoming uniformly priced. Solar generation is compressing midday prices, but hydro variability, thermal availability, grid constraints and evening ramping requirements are concentrating value into fewer hours. The result is a market offering stronger signals for storage and flexible generation while exposing import-dependent countries to increasingly severe late-day scarcity.

The post June heatwave redraws South-East Europe’s electricity price map appeared first on Serbia SEE Energy Mining News.

The project carries an estimated investment cost of €18.8 million, equivalent to approximately €411,000 per MW or €206 per kWh of storage capacity. The EU Modernisation Fund will contribute €1.55 million, covering around 8.3% of the total, while PPC will finance the remaining €17.3 million.

The battery will be integrated with the 262.5 MW Fântânele-Vest wind farm, comprising 105 turbines. The asset forms part of the 600 MW Fântânele-Cogealac complex, acquired by Greek utility PPC in 2024. The wider complex generates approximately 1.25 TWh annually.

At 91.44 MWh, the battery cannot shift a large share of the wind farm’s daily production. Its value lies instead in short-duration optimisation: reducing imbalance exposure, responding to forecast errors, shifting output between low- and high-price hours and providing ancillary services.

The economics will depend on access to multiple revenue streams. Day-ahead arbitrage alone may be insufficient to support the investment during periods of compressed spreads. Balancing services, intraday trading, congestion management and reduced curtailment can provide a broader earnings base.

PPC has announced similar storage investments at the Corugea wind farm and Colibași solar plant, indicating that batteries are becoming a standard component of its Romanian renewable portfolio rather than isolated pilot projects.

The company currently operates approximately 1.6 GW of renewable capacity in Romania and plans to reach 3.6 GW by the end of 2028 and 4.7 GW by 2030. That expansion will increase portfolio-level forecasting and balancing requirements, strengthening the strategic value of distributed storage.

The relatively modest grant contribution also gives the project commercial significance. PPC is committing most of the capital itself, suggesting that flexibility revenues and portfolio optimisation are beginning to support investment independently of heavy subsidy.

The post PPC adds two-hour battery to Romania’s largest wind complex appeared first on Serbia SEE Energy Mining News.

The Dutch-registered subsidiary of Russian producer Lukoil holds an 88% interest in the block, while Romanian state-controlled gas company Romgaz owns the remaining 12%. The application has been submitted to the National Agency for Mineral Resources, Petroleum and Geological Carbon Dioxide Storage.

The extension request comes amid sanctions, ownership uncertainty and unresolved legal proceedings. Lukoil Overseas has sought judicial recognition of force majeure, arguing that external circumstances prevent it from continuing normal operations in Romania. The Bucharest Tribunal had not yet scheduled the first hearing.

Lukoil has also referred to negotiations over a possible sale of its European assets to a US-based investment fund. A completed ownership change could remove the Romanian business from the sanctions regime, but any transaction would require regulatory scrutiny of the buyer, funding structure and ultimate beneficial ownership.

Romania placed Lukoil-controlled companies under extended state supervision in February, citing national security and domestic energy-market stability. Those measures remain in force while the company’s status is reviewed.

For Romgaz, the minority interest provides exposure to a potentially important offshore resource but little control over the operator’s sanctions position. A licence extension without a credible work programme could merely defer the underlying problem, while allowing the concession to expire could eliminate optionality before a new investor is secured.

The authorities must balance resource development against the risk of leaving an offshore block tied to a company unable to finance, procure or execute exploration work. Any extension is likely to require enforceable milestones, evidence of financing and a clear pathway for replacing the sanctioned controlling shareholder.

The Trident decision will therefore function as both a petroleum-licensing judgment and a test of Romania’s approach to Russian-owned strategic energy assets.

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The areas cover approximately 4,000 square kilometres of maritime territory and are divided into three development stages. The first stage contains three fixed-bottom zones with total potential of 3.1 GW, broadly aligned with Romania’s objective of installing around 3 GW of offshore wind by 2035.

Development Zone 1 covers 631 square kilometres and could accommodate 1.9 GW. Zones 2 and 3 cover 149 and 168 square kilometres, respectively, with an estimated 600 MW available in each. Water depths range from 55 to 75 metres, while average wind speeds are estimated at 7.7–7.9 metres per second at 150 metres.

At indicative European offshore wind construction costs of approximately €3–4 million per MW, the initial 3.1 GW phase could require around €9–12 billion before major onshore grid reinforcement and financing costs. Final economics will depend on turbine scale, foundation type, port infrastructure, local-content obligations and the support mechanism adopted for concession auctions.

Two further zones offering 2.4 GW have been deferred because they overlap with military areas and the safety perimeter of an active firing range. Their development would require the relocation or redesign of defence activities before concessions could proceed.

The largest zone is planned for after 2035. It covers 2,195 square kilometres, reaches water depths of 135 metres and has an estimated capacity of 6 GW. Development could combine conventional fixed-bottom structures, deep-water foundations and floating wind technology.

The proposed zones also overlap with the Istria, Midia, Luceafărul and Neptun hydrocarbon blocks, creating potential conflicts around safety corridors, subsea infrastructure and marine logistics. Environmental screening identified risks involving migratory birds, marine mammals, fisheries, protected habitats, cultural heritage and navigation.

Inclusion in the plan does not create a development right. Each project will still require a concession, environmental assessment, grid solution and complete permitting package. Romania has defined the scale of its offshore opportunity; concession design and transmission planning will determine whether the mapped 11.5 GW becomes an investable market.

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Kazakhstan stopped pumping crude to the CPC marine terminal while damage and security conditions were assessed. Loading operations had been suspended since 19 July, interrupting the country’s principal export route from western production fields to international markets.

The disruption has direct implications for Romania because Kazakh crude accounts for more than 50% of the feedstock processed by Romanian refineries. Domestic production covers less than 30% of refining requirements, with additional imports coming principally from Azerbaijan and Iraq.

Romania therefore has alternative sources, but replacing CPC barrels at short notice could involve higher freight costs, different crude qualities and operational adjustments at refineries. Even where physical supply is available, substituting feedstock may reduce refining margins if plants are optimised for a particular crude blend.

The interruption also highlights the geopolitical complexity of Kazakhstan’s export system. The oil is produced outside Russia, but the main pipeline terminates at a Russian port. Kazakh exporters and European buyers consequently remain exposed to security events, sanctions complications and operational decisions affecting Russian Black Sea infrastructure.

Interim Economy Minister Irineu Darău said the Government would consider measures should the disruption produce a significant increase in domestic fuel prices. He indicated that any intervention would seek to avoid unnecessary market distortions.

Romania’s strategic response will depend on the duration of the outage. A short suspension can be covered through commercial inventories and cargo rescheduling. A prolonged interruption would increase competition for alternative Black Sea and Mediterranean crude, raising working-capital requirements and potentially widening wholesale fuel prices.

The CPC event turns crude diversification from a procurement question into an energy-security priority. Romania has domestic production and several import options, but the loss of a route supplying more than half of refinery demand would be difficult to absorb without a visible cost.

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The Association of Independent Gas Stations said imported diesel has become more expensive than fuel available at domestic retail prices. That pricing imbalance makes supplementary imports commercially unattractive even though Hungary depends on external supply to balance its market.

Low Danube water levels have reduced the amount of fuel that can be carried by individual barges, raising the transport cost per tonne. Railway infrastructure works in neighbouring countries have simultaneously slowed rail deliveries, limiting the market’s ability to replace river shipments. Some wholesalers have reportedly begun restricting deliveries to customers.

Hungary released 58,800 tonnes of strategic diesel stocks between 30 June and 9 July, although the allocation and reason for the withdrawal were not publicly detailed. The movement suggests that authorities have already used part of the security buffer during a period of tightening logistics.

The Ministry of Economy and Energy rejected claims of an imminent shortage. It said the replenishment programme that began in late March had raised total strategic petroleum reserves to the equivalent of 87 days of consumption, close to the internationally recommended 90-day level.

Independent retailers argue that aggregate petroleum stocks do not fully address a product-specific diesel imbalance. A country may comply with total reserve requirements while individual grades, terminals or delivery regions remain commercially constrained.

The dispute exposes the tension between retail price restraint and supply security. Prices that do not cover replacement imports can protect consumers temporarily but discourage the marginal cargoes needed to maintain competition and physical availability. Smaller retailers are particularly vulnerable because they lack integrated refining, large storage networks and the purchasing power available to major suppliers.

Hungary’s immediate stock position may remain adequate, but the combination of restricted river transport, rail disruption and negative import margins is weakening the commercial mechanisms that normally prevent local shortages.

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The total was down from approximately €3.4 billion in 2024, representing a reduction of about 12%. The improvement is material, but the remaining balance continues to affect supplier liquidity and ultimately increases the cost carried by customers who pay their bills on time.

Low-voltage consumers, including households and smaller businesses, accounted for approximately €2.1 billion. Medium-voltage customers owed €683.8 million, while high-voltage users were responsible for another €214.3 million.

Commercial, industrial and other business customers connected at low voltage represented the largest individual category, with arrears of approximately €819 million. Households owed about €710 million. Medium-voltage companies accumulated around €577 million, while high-voltage businesses were responsible for €55 million.

The most difficult receivables are associated with customers who have already moved to another supplier. Approximately €1.53 billion, more than half of the outstanding market debt, relates to former customers. Once a customer changes supplier, the previous provider retains the debt but loses the continuing commercial relationship that could support repayment or restructuring.

Greek energy regulator RAAEY estimates that these unpaid balances add around €0.0593/kWh to market costs. The burden is transmitted through provisions, financing charges, collection expenses and higher risk premiums demanded by suppliers.

The problem also affects competition. Larger companies with stronger balance sheets can absorb delayed payments more easily, while smaller suppliers may need expensive working-capital facilities or tighter customer-selection policies. Persistent arrears therefore favour consolidation and raise entry barriers.

A durable solution requires stronger data-sharing between suppliers, enforceable payment arrangements and protection for genuinely vulnerable customers without allowing strategic non-payment to migrate between providers. Greece has reduced the headline debt, but the concentration of €1.53 billion among former customers remains the market’s most difficult structural liability.

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The compromise forms part of the EU’s 21st sanctions package against Russia and will be reviewed annually by the European Council. European operators will be unable to sign new contracts for transporting Russian LNG, but pre-war agreements can continue within their existing volumes.

Greece played a central role in negotiating the exemption. Athens argued that a blanket prohibition on European LNG carriers would do little to reduce Russian export revenue because the trade could migrate to non-European shipping companies. Such a shift could reduce transparency while transferring freight income and market share away from EU operators.

The question is commercially important for Greece because Greek-controlled companies represent a substantial share of the global LNG carrier fleet. Greek-owned vessels have also remained active in Russian oil transportation since the G7 price-cap mechanism was introduced at the end of 2022.

Greek shipping companies are estimated to have earned more than $3.8 billion from transporting Russian oil during the past three years. Greek-owned ships reportedly carried close to 15% of Russian crude exports in May 2026, demonstrating the continuing importance of European maritime capacity to Russian commodity logistics.

The exemption creates a managed phase-out rather than an immediate rupture. Existing contracts retain value, but their annual review introduces political and compliance risk. Shipowners will have to demonstrate that cargoes, volumes, counterparties and contracts fall within the permitted framework, increasing the importance of sanctions screening and documentary controls.

Alongside the LNG provision, the package establishes a Russian oil price cap of $44.10 per barrel for the next 12 months and expands restrictions targeting finance, energy, cryptocurrency activity and trade.

The shipping compromise protects legacy Greek commercial interests, but it does not provide a basis for fleet expansion around Russian LNG. The permitted market is now finite, politically exposed and subject to progressively tighter scrutiny.

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EU underground storage facilities were 54% full on 19 July 2026, compared with 64.8% at the same point in 2025. Working inventories stood at approximately 59 billion cubic metres, around 11 billion cubic metres, or 16.8%, below the previous year. Storage was also reported to be 15.52% below the five-year seasonal average.

The shortfall is significant because Europe entered the second half of the injection season without the inventory cushion available a year earlier. The region still has time to rebuild stocks before winter, but the remaining requirement is becoming concentrated into a narrower operational window.

Commercial incentives are complicating the refill cycle. Near-term TTF contracts have traded above winter delivery products, making it unattractive for companies to buy gas now, pay injection and financing costs, and sell the fuel later at a lower forward price. Storage operators need either a positive summer-winter spread, public support or a sufficiently high security premium to justify additional injections.

The market structure creates a mismatch between commercial behaviour and system security. Traders are responding rationally to the forward curve, while governments and transmission operators require higher inventories to protect against cold-weather demand, LNG competition and further reductions in Russian supply.

The deficit also strengthens the influence of Asian LNG prices on European winter contracts. A recovery in Chinese, Japanese or South Korean demand could redirect flexible cargoes away from Europe precisely when storage withdrawals accelerate.

For Southeast Europe, the exposure is amplified by limited storage capacity, dependence on interconnected supply routes and the use of gas-fired generation during periods of weak hydroelectric production. High gas prices would feed directly into evening electricity prices in Greece, Hungary, Romania and Italy, where flexible thermal plants frequently set the marginal power price.

The combination of 54% storage, an unfavourable injection spread and continuing geopolitical risk leaves Europe’s winter balance dependent on stronger injections later in the summer, when competition for LNG cargoes may already be increasing.

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Hungary’s HUPX settled at €131.01/MWh, just €0.48/MWh above Germany, compared with a spread of approximately €12.5/MWh one day earlier. The convergence was driven primarily by Germany’s €12.9/MWh price increase to €130.53/MWh, rather than by a significant increase in physical supply to Hungary. Imports from Austria and Slovakia into Hungary and Slovenia actually declined by 316 MW to an average of 1,611 MW.

That distinction is important. Hungary’s near-perfect convergence with Germany does not mean that its structural dependence on imports has disappeared. Hungarian generation was forecast at 3,560 MW against consumption of 4,195 MW, leaving the country dependent on approximately 635 MW of net imports. The balance nevertheless improved sharply from Thursday, as domestic generation increased by 243 MW while demand fell by 299 MW. Hungary remained exposed to imported marginal pricing and transmission availability.

The eastern market experienced a more fundamental tightening. Romanian OPCOM rose by €10.8/MWh to €129.98/MWh, Bulgarian IBEX advanced €12.4/MWh to €124.08/MWh, and Greek HENEX gained €13.1/MWh to €124.85/MWh. Combined consumption forecasts for Romania and Bulgaria increased by 523 MW, even as total regional demand declined by 220 MW to 30,514 MW.

Greece’s generation was forecast to fall by approximately 921 MW, from 7,719 MW to 6,798 MW, while consumption declined by only 515 MW. The country consequently moved from a 340 MW export position to a 66 MW import requirement. Romania’s balance deteriorated even more sharply: generation fell by 604 MW while consumption rose by 94 MW, converting Thursday’s 424 MW net export position into a 274 MW net import requirement. Bulgaria’s demand increased by 429 MW, reducing its export surplus from 1,354 MW to 909 MW.

Together, the three systems lost approximately 1.55 GW of day-on-day balance strength, explaining the broad eastern price rebound.

Western Balkan fundamentals moved in the opposite direction. Croatian generation increased by 592 MW to 1,852 MW, cutting its net import requirement from 857 MW to 183 MW. Bosnia and Herzegovina increased generation by 157 MW while demand fell, expanding net exports to 472 MW. Montenegro’s generation almost doubled from 163 MW to 304 MW, reducing imports to 110 MW despite higher consumption. These improvements helped keep the western Balkan price cluster below both HUPX and the Bulgarian-Greek zone.

Serbia’s SEEPEX price recovered by €16.7/MWh to €102.64/MWh, but remained €28.37/MWh below HUPX, €27.34/MWh below Romania and more than €67/MWh below Italy. Serbia was still forecast to import an average of 431 MW, with generation of 2,875 MW covering only around 87% of projected consumption of 3,306 MW.

Commercial schedules included average imports of approximately 308 MW from Bosnia and Herzegovina, 151 MW from Croatia, 116 MW from Romania and 112 MW from Hungary. These flows were partly offset by exports of 189 MW to Montenegro and 67 MW to North Macedonia.

Serbia’s discount therefore cannot be interpreted simply as evidence of a domestic generation surplus. It reflects fragmented exchange liquidity, separately allocated cross-border capacity and commercial nominations that do not automatically follow day-ahead price signals. Serbia’s simultaneous import requirement and €28/MWh discount to Hungary demonstrate the limits of price convergence across uncoupled borders.

Montenegro recorded the region’s lowest price at €92.19/MWh, down €14.6/MWh day on day. BELEN traded at a discount of €38.81/MWh to HUPX and €78.04/MWh to Italy. The country’s commercial position was dominated by transit: Montenegro imported electricity from Bosnia and Herzegovina, Serbia, Albania and Kosovo while scheduling approximately 591 MW towards Italy through the submarine interconnector.

This does not mean that traders could freely capture the full Montenegro–Italy price difference. Cable nominations, previously acquired transmission rights, market liquidity and contractual schedules determine the margin that can actually be accessed. The price structure nevertheless demonstrates the commercial value of Montenegro’s Italy-facing corridor. Montenegro’s exchange price remained linked to the cheaper Western Balkan pool even as its transmission system carried close to 600 MW towards Europe’s most expensive regional market.

Total Southeast European and Hungarian exports towards Italy declined by 227 MW to 1,137 MW, reflecting Italy’s €10.8/MWh price correction and higher prices across Romania, Bulgaria and Greece. Italy nevertheless retained a premium of €39.23/MWh over HUPX, €45–46/MWh over Bulgaria and Greece, and almost €68/MWh over Serbia and Albania.

The Italian market therefore remained the dominant westward pull on regional commercial flows.

The most important signal appeared in the hourly price curves. HUPX recorded a minimum of €13.50/MWh in hour 14 and a maximum of €200.90/MWh in hour 22, producing an intraday range of €187.40/MWh. Germany showed an almost identical pattern, falling to €6.50/MWh in hour 15 before rising to €203.20/MWh in hour 22. Romania, Slovenia and Croatia also fell to approximately €13/MWh around midday before approaching €200/MWh during the evening.

The result was a significant inversion of traditional peak and off-peak economics. HUPX peakload averaged only €92/MWh, compared with €170/MWh for off-peak hours. The corresponding inversion was €81.9/MWh in Germany, €78.3/MWh in Romania, €80/MWh in Slovenia and €73.6/MWh in Croatia.

The traditional off-peak block now includes late-evening hours when solar output has disappeared and residual demand is at its tightest. The conventional peak/off-peak classification is therefore becoming increasingly misleading for operational trading.

Forecast solar output increased by 705 MW to 6,861 MW, while wind generation was expected to fall by 810 MW to 1,817 MW. The combination explains the extreme hourly price profile. Additional solar supply depressed midday prices, but weaker wind generation left less renewable output available during the evening ramp. Thermal generators and imports consequently had to cover a much steeper increase in residual load after sunset.

For battery storage, the HUPX minimum-to-maximum spread represented a theoretical gross price range of €187.40/MWh. At 85% round-trip efficiency, purchasing one megawatt-hour at the daily minimum and selling the resulting 0.85 MWh at the maximum would produce approximately €157/MWh of gross energy margin before fees, degradation and balancing costs.

Comparable opportunities existed in Germany and Croatia, while Albania’s hourly range reached almost €198/MWh. The persistence of such spreads continues to support storage economics even when daily baseload prices appear relatively stable.

Solar capture economics were considerably weaker than the €131.01/MWh HUPX baseload price suggests. The midday price of €13.50/MWh was barely one-tenth of the daily average, while the most valuable hours arrived after photovoltaic production had declined. Merchant solar exposure is therefore increasingly dependent on shaping arrangements, storage integration, intraday optimisation and offtake contracts capable of protecting revenues during solar-heavy delivery periods.

The forward market reinforced the scarcity signal. Hungarian Week 31 increased by €5/MWh to €145/MWh, while Week 32 rose by €7.5/MWh to €172/MWh. The Week 32 Hungary–Germany premium expanded to €27/MWh, while Hungary moved to within only €2.5/MWh of Italy. August Hungarian baseload stood at €158/MWh, carrying a €25.5/MWh premium over Germany.

These increases occurred despite weaker main thermal inputs. CEGH gas eased to €62.85/MWh, EU allowances fell by €2.8/t to €83.88/t and August coal declined to 121. The power rally was therefore driven less by rising fuel costs than by regional electricity scarcity premiums, expected renewable variability, transmission constraints and thermal-availability risk.

Friday’s market left traders facing two distinct exposures. Baseload convergence between Hungary and Germany tightened dramatically, but Hungary’s forward premium indicates that the market does not expect the physical balance to remain comfortable. At the same time, discounts of €28–39/MWh across Serbia, Albania, Montenegro and North Macedonia preserve substantial cross-border basis risk.

Solar generation will continue to pressure midday prices, while low wind output, constrained hydrology and regional import dependence keep the evening ramp as the principal source of upside volatility.

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The project, nominated in the 2026 Projects of Energy Community Interest (PECI) process, would connect the planned 400/110/35 kV Brezna substation in Montenegro with the Sarajevo 20 substation in Bosnia and Herzegovina. It also includes a new 400/220 kV Piva’s Mountain substation, creating a stronger connection around the existing Piva hydropower complex and transmission routes between northern Montenegro and eastern Bosnia and Herzegovina.

The promoters are CGES, Montenegro’s transmission system operator, and NOSBiH/Elektroprijenos BiH, working with the relevant energy authorities. The latest preliminary project documentation indicates commissioning around 2032, with stated CAPEX of approximately €70 million in Montenegro and €6.7 million in Bosnia and Herzegovina, giving an initial combined investment envelope of approximately €76.7 million.

The configuration is intended to be developed in two phases. The first would cover construction of the Piva’s Mountain substation, a new 400 kV overhead line towards the Buk Bijela area in Bosnia and Herzegovina, use of the existing high-capacity continuation towards Sarajevo 20 and a stronger connection between the Piva hydropower plant and the new substation. The second phase would extend the 400 kV line from Brezna to Piva’s Mountain.

This structure allows the grid to be reinforced incrementally rather than waiting for the complete corridor to be finished. It also creates interfaces with several other regional projects, including the proposed Gacko–Brezna 400 kV line, the Bajina Bašta–Višegrad–Pljevlja Trans-Balkan Corridor and the rehabilitation of the existing Trebinje–Perućica–Podgorica–Vau Dejës 220 kV route.

Taken together, these investments could reshape electricity flows among Serbia, Bosnia and Herzegovina, Montenegro and Albania. They would also strengthen the inland network feeding Montenegro’s submarine electricity connection with Italy.

The existing Montenegro–Italy HVDC link gave the Western Balkans a direct physical route into one of Europe’s larger and historically higher-priced electricity markets. Its initial operational pole provides approximately 600 MW of capacity. However, the commercial value of the cable depends heavily on the strength of the networks behind it. A submarine interconnector cannot continuously absorb wider Balkan exports when congestion, voltage limitations or security constraints restrict flows inside Montenegro and neighbouring systems.

Brezna–Sarajevo is therefore not simply a bilateral transmission line. It could become part of a wider transmission spine linking hydropower and renewable production in Bosnia and Herzegovina, Montenegro and Serbia with demand and trading opportunities in Italy. This broader function helps explain why ENTSO-E identifies the Bosnia–Montenegro border as an area where additional capacity could reduce congestion and support renewable integration.

The regional investment plan estimates that a more fully optimised 2040 grid could reduce the marginal-cost difference across the Italy–Montenegro interface by approximately €20–30/MWh. The calculation reflects a package of grid reinforcements rather than the Brezna project alone, but it indicates the scale of economic value currently constrained by transmission bottlenecks.

The same analysis suggests that an optimised Continental Southeast European grid could reduce renewable-energy surplus by approximately 5 TWh, avoid around 10 million tonnes of CO₂ and lower regional electricity costs by roughly €7/MWh. These are system-level benefits that do not automatically translate into revenue for an individual TSO. The financing structure must therefore convert part of that regional value into regulated cost recovery, cross-border cost allocation or grant support.

The original €76.7 million CAPEX estimate should be treated carefully. It is a promoter-level planning figure rather than a final bankable budget. A 400 kV corridor through mountainous terrain can face substantial costs related to geotechnical conditions, access roads, foundations, conductors, substations, land acquisition and environmental mitigation. Inflation in transformers, switchgear and other high-voltage equipment has also increased the cost of European transmission projects.

A more conservative development envelope could reach €90 million–€120 million once detailed surveys, contingencies, owner’s costs, environmental mitigation, compensation, financing costs and schedule risks are included. The final figure will depend heavily on the length of new line sections, the extent to which existing corridors can be reused and the technical scope of the Piva’s Mountain substation.

The split between Montenegro and Bosnia and Herzegovina is another bankability issue. Montenegro carries the majority of the stated investment, while regional benefits extend well beyond its domestic consumers. Without grant funding or cross-border cost allocation, CGES customers could bear a disproportionate share of an asset that also supports Bosnia and Herzegovina, Serbia, Albania and electricity trading with Italy.

PECI status can improve access to technical assistance, regulatory coordination and financing through EU and Energy Community channels. It can also support applications for funding through the Western Balkans Investment Framework, EBRD or EIB. The designation, however, does not remove the requirement for a robust cost-benefit analysis, environmental assessment or enforceable agreements between the project promoters.

The environmental and social process will be central. The corridor crosses mountainous areas with potentially sensitive habitats, forests, water resources and local communities. Civil-society concerns around the Brezna area have already entered the PECI consultation process. These concerns cannot be treated as a communications issue to be addressed only after route selection.

Early routing should examine biodiversity, bird and bat interactions, protected areas, landscape impacts, cultural heritage, forestry, erosion and cumulative impacts from connected hydropower, renewable and transmission projects. Alternatives analysis must demonstrate that the selected route balances system need with environmental and social effects.

Land acquisition could become the critical path. Overhead transmission lines affect long corridors containing numerous parcels and rights holders. The legal right to construct towers and maintain conductors does not eliminate compensation disputes or local resistance. A credible schedule requires cadastral verification, access planning, stakeholder engagement and grievance management before the EPC contractor mobilises.

The planned 2032 commissioning date leaves a nominal six-year development and construction window. That is reasonable for a cross-border 400 kV investment, but it contains little room for institutional delay. Intergovernmental agreements, regulatory approvals, environmental permits, spatial plans, expropriation, financing, procurement and cross-border technical coordination must advance in parallel.

A 12–18-month delay would increase interest during construction, extend exposure to equipment inflation and postpone congestion benefits. For regulated TSOs, the effect differs from that faced by a merchant renewable project: equity returns may be protected through the regulatory asset base, but timing mismatches can still pressure cash flow, debt drawdowns and tariff recovery.

Technical design must account for the region’s long-standing voltage-management challenges. Long 400 kV lines can generate reactive power during lightly loaded periods and may require shunt reactors or other compensation equipment. The Balkan system already experiences significant seasonal and hourly flow changes driven by hydrology, tourism demand, thermal availability and exports towards Italy.

The 2024 regional blackout demonstrated how rapidly voltage deterioration can spread across several systems when operators lack complete visibility and corrective measures. Brezna–Sarajevo can strengthen system security, but it will also change regional power-flow patterns. The project therefore requires coordinated dynamic, voltage-stability and contingency studies covering the wider network rather than only the two terminal substations.

Protection settings, telecommunications, SCADA, synchrophasor measurements and operational procedures should be designed as one regional system from the outset. CGES and NOSBiH will need aligned data exchange, outage coordination and emergency controls, supported by the relevant Regional Coordination Centres.

The renewable connection benefit must also be translated into transparent transmission capacity. Developers in eastern Herzegovina and western or northern Montenegro will want to know whether the new corridor creates firm connection capacity, reduces curtailment or simply accommodates transit flows already expected elsewhere. Connection studies should distinguish between thermal limits, voltage constraints, stability limits and N-1 security requirements.

Wind and solar will affect the corridor differently. New solar capacity can create concentrated midday exports followed by steep evening reversals. Wind output is less synchronised with the solar profile and generally has a higher capacity factor, giving it different transmission and system value. Hydropower around Piva can provide controllable output and balancing, although reservoir and environmental constraints limit its availability.

The most valuable configuration is therefore not maximum renewable export in every hour. It is the coordinated use of wind, solar, hydropower, storage and cross-border capacity to reduce curtailment and serve the highest-value market periods. The line’s commercial benefit increases when generators can participate in coupled day-ahead, intraday and balancing markets rather than relying solely on explicit border capacity.

Brezna–Sarajevo sits at the point where transmission planning, renewable investment and Western Balkan market integration converge. Its relatively modest stated CAPEX could unlock a much larger portfolio of generation and cross-border trading opportunities, but only if environmental permitting, cost allocation and operational integration are treated with the same seriousness as the overhead line itself.

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This mismatch is becoming increasingly difficult to justify as renewable generation expands. The region is already experiencing simultaneous periods of solar oversupply, hydropower shortages, thermal outages and sharp evening demand ramps. Physical interconnections can move electricity between these conditions, but commercial fragmentation prevents traders, generators, storage operators and industrial consumers from using the network as efficiently as participants in the EU’s coupled market.

The Energy Community estimates that as much as 70% of electricity passing through the Western Balkans may represent flows between different EU countries. Serbia sits at the centre of this transit structure, with connections to Hungary, Romania, Bulgaria, North Macedonia, Kosovo, Montenegro, Bosnia and Herzegovina and Croatia. Montenegro adds the 600 MW first pole of the submarine interconnector with Italy, while Albania and North Macedonia connect the western and southern parts of the regional system with Greece.

The hardware is European. The market treatment is not.

ENTSO-E’s 2026 Market Report shows that the EU electricity market has moved towards 15-minute trading intervals in the day-ahead and intraday markets. Intraday cross-border gate closure times have been reduced from 60 minutes to 30 minutes on many participating borders. At the same time, balancing integration through the MARI and PICASSO platforms is expanding, while flow-based capacity allocation is being prepared for larger European regions.

European balancing platforms generated more than €1.18 billion in surplus in 2025 through imbalance netting and more efficient reserve activation. The figure demonstrates that market integration is not simply a regulatory exercise. It allows spare flexibility in one system to become a tradable service for another, lowering balancing costs and reducing the volume of reserves that each TSO must procure domestically.

In the formal Southeast Europe Capacity Calculation Region, however, the 2026 assessment still focuses on Bulgaria, Romania and Greece. Western Balkan TSOs remain in a transitional position, even though EMS, CGES, MEPSO, NOSBiH, KOSTT and OST have agreed with EU neighbours on a framework intended to integrate their coordinated system operation and capacity calculation with established European regions.

Serbia has the region’s most developed electricity trading structure. SEEPEX, now part of the wider ADEX group alongside Slovenia’s BSP SouthPool and Hungary’s HUPX, operates day-ahead and intraday markets. Day-ahead trading volume in 2024 represented approximately 17.41% of Serbian electricity consumption, while intraday trading accounted for only around 0.34%.

That imbalance reveals the next major market-development challenge. A functioning intraday platform exists, but liquidity remains too low to provide a reliable adjustment market for a rapidly expanding wind and solar fleet. Generators can buy or sell electricity closer to delivery, but thin order books increase transaction costs and leave larger balancing exposures with EPS, traders and EMS.

SEEPEX’s introduction of negative prices in May 2026 was therefore a necessary development. A zero-price floor concealed the economic signal created when renewable output and inflexible thermal generation exceeded demand and export capacity. Negative prices allow the market to value curtailment, charging demand, storage and flexible consumption. They also expose weaknesses in fixed-premium support schemes and PPAs designed around the assumption that wholesale electricity prices could not fall below zero.

Montenegro, Albania, North Macedonia and Kosovo have established day-ahead markets through MEPX, ALPEX and MEMO-related arrangements, but liquidity remains constrained by small domestic demand, limited numbers of market participants and the absence of full cross-border coupling. Bosnia and Herzegovina remains further behind, with fragmented institutional responsibilities adding to the difficulty of establishing a credible organised electricity market.

Regional prices already show strong correlation. This reflects interconnected generation fundamentals: Balkan hydrology, Bulgarian and Romanian nuclear availability, Greek gas-fired marginal generation, Serbian coal output, Hungarian imports and Italian demand all influence the same physical system. Correlation, however, is not the same as convergence. Explicit border auctions, uncoordinated capacity calculations and administrative barriers can preserve significant price spreads even when underlying supply conditions are similar.

Flow-based market coupling could fundamentally change how regional transmission capacity is used. Bilateral net-transfer capacities treat each border separately and cannot fully capture how a commercial exchange affects parallel flows across several countries. A Serbian export to Hungary, for example, can alter physical flows in Romania, Croatia or Bosnia and Herzegovina. Flow-based calculation uses a regional network model to allocate capacity according to actual system constraints, potentially increasing tradable capacity while maintaining operational security.

The transition would be technically and politically demanding. TSOs would need to exchange sufficiently detailed grid models, agree common contingencies and remedial actions, harmonise calculation methodologies and accept regional scrutiny of internal constraints. Regulators would need to approve compatible terms and conditions, while power exchanges and market participants would need operational procedures aligned with European algorithms and gate times.

The 70% minimum capacity requirement adds further pressure. European rules require TSOs to make at least 70% of transmission capacity available for cross-border trade, subject to justified security limitations and approved action plans or derogations. Western Balkan grids often use internal and cross-border elements to carry the same transit flows, making it difficult to separate domestic constraints from capacity available for regional electricity trading.

This is also where the lessons of the June 2024 Balkan blackout remain relevant. Physical integration without complete regional visibility can amplify disturbances. Market integration therefore cannot advance independently of coordinated security analysis, voltage assessment, contingency planning and real-time data exchange. More commercial capacity is valuable only when TSOs and Regional Coordination Centres can identify and manage the resulting flow patterns.

The economic value of deeper integration could be substantial. Serbia’s hydropower and future battery projects could sell balancing and flexibility services into a larger market. Montenegro could use its Italian interconnector more efficiently, particularly when hydrological conditions and Italian prices diverge. Albania could monetise reservoir flexibility beyond day-ahead exports. North Macedonia could reduce its exposure to expensive emergency imports, while Bosnia and Herzegovina could improve the utilisation of its hydro and thermal portfolio while preparing for the commercial impact of carbon pricing.

Battery economics are particularly sensitive to market integration. A BESS relying solely on domestic day-ahead arbitrage may struggle to produce a bankable revenue case in a small market. Access to intraday volatility, balancing capacity, balancing energy and cross-border products can materially improve annual gross revenue. A diversified revenue stack also reduces dependence on any single price spread or market mechanism.

Industrial consumers face a different form of exposure. Fragmented markets reduce their ability to hedge electricity costs across borders, while limited forward-market liquidity restricts the availability of credible reference prices for long-term PPAs. An exporter buying renewable electricity in Serbia may have the physical power, guarantees of origin and metering data required for a low-carbon claim, yet still face basis risk because the local PPA price cannot be efficiently hedged against a liquid regional forward product.

CBAM reinforces the commercial case for greater integration. The EU’s definitive carbon-border regime places increasing value on transparent electricity sourcing, verifiable emissions and credible market prices. Western Balkan electricity exports will increasingly compete on their carbon content rather than solely on marginal production costs. Coal-heavy systems can no longer rely indefinitely on an implicit carbon advantage when selling into neighbouring EU markets.

Market coupling would not eliminate the region’s structural price differences. Serbia’s lignite fleet, Montenegro’s hydro concentration, Albania’s exposure to rainfall, Greece’s gas dependence and Bulgaria’s nuclear and coal portfolio will continue to produce different hourly fundamentals. Coupling would instead make those differences visible, tradable and more efficiently priced, while reducing artificial spreads created by inefficient capacity allocation.

The main obstacles are now institutional. VAT treatment, collateral requirements, licensing, financial settlement and cross-border taxation remain uneven across the region. Market participants operating across several Western Balkan jurisdictions can face duplicated registrations, incompatible invoicing practices and higher working-capital requirements. These costs are particularly significant in markets where traded volumes remain relatively small.

A credible integration sequence would combine coordinated capacity calculation, day-ahead coupling, intraday coupling and staged access to European balancing platforms. Advancing only the day-ahead layer would leave renewable generators exposed close to real time. Opening balancing markets without sufficiently liquid intraday trading would transfer too much forecasting risk directly from generators to TSOs.

Serbia is positioned to become the region’s liquidity anchor because it combines the largest Western Balkan power system, the deepest organised exchange, extensive interconnections and ownership links with EU exchanges through ADEX. That position is not automatic. Liquidity must expand beyond the current concentration in day-ahead trading, while market rules must support negative prices, aggregation, storage participation and shorter trading products.

The Western Balkans no longer lack electricity exchanges. What they lack are the final commercial and regulatory links that would allow those exchanges to operate as part of one European market. The region’s physical grid already carries European electricity. Its trading architecture, however, continues to price that grid as a collection of national systems.

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ENTSO-E’s new technical guidance on forced oscillations, published in July 2026 after two years of work with WindEurope, addresses periodic fluctuations injected into the network by power-generating equipment. The guidance supports two new provisions proposed for the revised Network Code on Requirements for Grid Connection of Generators, or RfG 2.0, covering the permissible amplitude and duration of oscillations produced by power park modules.

Although the immediate work focuses on wind farms, the regulatory direction extends much further. ENTSO-E has stated that the requirements will also apply to solar photovoltaic plants and electricity-storage modules, making the issue relevant to almost every utility-scale renewable project now under development in Serbia, Montenegro, Bosnia and Herzegovina, North Macedonia, Albania, Bulgaria, Romania, Croatia and Greece.

Forced oscillations differ from more familiar grid-code requirements such as fault ride-through, reactive-power control, active-power control and frequency response. They occur when generating equipment repeatedly injects power variations at a particular frequency. In wind turbines, these variations can be caused by tower movement, blade-passing effects, wind shear, turbulence, waves or active tower-damping systems. Solar and battery installations can create different oscillatory behaviour through converter controls, plant controllers, filters and interactions between multiple power-electronic devices.

The risk becomes serious when the injected frequency is close to a natural mode of the transmission system. The grid can amplify the disturbance through resonance, producing fluctuations significantly larger than those at the original source. A local control problem can then propagate across a synchronous area, stress equipment, trigger protection systems or contribute to cascading disconnections.

The draft RfG 2.0 provisions address oscillations in the range of 0.1–20 Hz for larger Type C and Type D power park modules. The lower part of this range overlaps with inter-area and local electromechanical modes traditionally associated with synchronous power systems. Frequencies between approximately 2 Hz and 20 Hz increasingly reflect interactions among converters, control systems and network equipment.

The upper boundary is partly practical. Measurements above 20 Hz would generally require point-on-wave equipment that is not yet standard across European transmission systems. The proposed framework therefore allows much of the compliance assessment to rely on high-resolution phasor measurements, specialised power-quality recorders and advanced data-processing tools.

That technical detail carries a substantial commercial consequence. Grid compliance can no longer be demonstrated solely through generic OEM certificates and conventional RMS dynamic models. Developers may increasingly need site-specific measurements, validated frequency-domain behaviour, higher-resolution simulation models and evidence showing that interactions between turbines, inverters, plant controllers, transformers, compensation equipment and the surrounding network remain stable under credible operating conditions.

This is particularly relevant to projects using equipment from Chinese or Turkish manufacturers. The issue is not the origin of the technology itself. Several non-European OEMs offer strong hardware, competitive pricing and extensive operating experience. The risk lies in whether their control models, source-code protections, validation procedures and technical support are compatible with European and Serbian grid-compliance processes.

An OEM may provide a black-box RMS model suitable for load-flow, short-circuit and conventional dynamic studies while declining to release the more detailed electromagnetic-transient representation required to investigate converter interactions. A model may perform correctly in the manufacturer’s simulation environment but produce different results after translation into the software used by EMS, CGES, HOPS, ESO, Transelectrica or IPTO. Version control creates another exposure: a turbine or inverter firmware update during construction can invalidate studies completed during the development phase.

For a 150 MW wind farm, the resulting compliance package can include turbine-level and plant-level RMS models, EMT models, harmonic impedance data, plant-controller logic, reactive-power-control validation, fault ride-through simulations, frequency-response tests, oscillation studies and field measurements during staged energisation. The studies must also cover the main transformer, collection system, shunt reactors, STATCOM or synchronous condenser where applicable, as well as the characteristics of the grid at the connection point.

Wind must be treated separately from solar. Wind turbines combine converter controls with rotating mechanical structures and aerodynamic excitation. Larger turbine rotors and taller towers introduce different natural frequencies and damping requirements. Wind projects also have higher capacity factors and frequently connect in remote areas through long 110 kV, 220 kV or 400 kV lines, making their system value and stability behaviour materially different from those of a solar plant with the same nominal capacity.

Solar presents another challenge: scale combined with limited visibility. A transmission-connected solar park can be monitored at one point of common coupling, but distribution networks increasingly contain hundreds of smaller inverter-based installations whose combined behaviour is not fully observable to the TSO. ENTSO-E plans a separate expert process during the fourth quarter of 2026 to examine non-observable embedded generation, particularly solar PV.

Battery projects add bidirectional operation and rapidly changing control modes. A BESS can switch between charging, discharging, frequency response, reactive support and standby within short intervals. Its value to the grid depends on this flexibility, but control transitions can create interactions that are not captured by a simple steady-state model. Grid-forming batteries may improve system strength, yet they require a more demanding verification process than conventional grid-following systems.

The financial exposure begins well before commissioning. A medium-sized Southeast European wind project can carry total investment costs of approximately €1.2 million–€1.6 million per MW, depending on terrain, turbine supply, balance-of-plant costs and grid infrastructure. For a 150 MW project, that implies an indicative investment envelope of €180 million–€240 million. A comprehensive grid-compliance workstream involving specialised studies, instrumentation, OEM model development and independent verification may absorb 0.5–1.5% of project CAPEX, or roughly €0.9 million–€3.6 million.

That cost is manageable when incorporated during FEED and procurement. It becomes significantly more expensive after equipment selection. Late discovery that the selected turbine or inverter requires a STATCOM, control-system redesign or additional harmonic filtering can add several million euros and delay energisation by six to 18 months.

A 12-month grid-connection delay can reduce project equity returns by approximately 1.5–3 percentage points, depending on leverage, interest during construction, the power-price environment and whether the EPC contractor or OEM accepts liability. Delays can also place pressure on debt availability periods, PPA long-stop dates, equipment warranties and eligibility deadlines under support schemes.

The contract structure therefore matters as much as the engineering. Turbine and inverter supply agreements should contain binding obligations to provide usable and validated models, support TSO studies, participate in factory and site testing, correct non-compliance and maintain model consistency following firmware changes. Grid-code compliance should remain an OEM performance obligation rather than a loosely worded cooperation commitment.

EPC contracts should allocate responsibility for the complete plant response at the point of connection. The EPC contractor cannot reasonably guarantee grid performance when the OEM controls the underlying converter logic but refuses access to the necessary models. A bankable arrangement requires aligned obligations across the EPC contractor, OEM, plant-controller supplier, transformer vendor and compensation-system provider.

Owner’s Engineer oversight becomes central at these interfaces. The OE needs a live grid-compliance matrix linking every requirement to its design evidence, simulation model, responsible party, test protocol, acceptance criterion and final certificate. Model submissions should be version-controlled alongside actual equipment settings. Factory acceptance testing must verify that the delivered controller matches the model used for the approved studies.

Commissioning should then proceed through staged energisation. Initial tests can confirm transformer and collection-system behaviour before individual generating units are introduced. Turbines or inverter blocks can be added progressively while recording voltage, frequency, active and reactive power, harmonics and oscillatory behaviour. Final plant-controller tests should cover normal dispatch, ramping, curtailment, voltage control, frequency response and credible disturbances.

The underlying regulatory timetable gives developers some room, but not much comfort. ENTSO-E expects the European Commission to complete the amended RfG during 2026, after which national implementation may take up to three years. Projects entering procurement or construction during that period will face a moving compliance baseline. A plant designed only around today’s minimum national requirements could be technically outdated before receiving final operational notification.

Serbia and other Energy Community markets will not remain isolated from this change. Their transmission systems are synchronously connected to Continental Europe, their TSOs participate in ENTSO-E structures and their market integration depends on regulatory alignment. Lenders financing projects with operating lives of 25–30 years are unlikely to accept equipment that meets only a narrow local interpretation but cannot demonstrate compatibility with the emerging European standard.

The new stability rules favour projects that treat grid compliance as a design discipline rather than a final permitting exercise. They also reward OEMs willing to provide transparent models, testing support and enforceable performance guarantees. In a region where grid connection has already become one of the main constraints on renewable deployment, model quality, controller behaviour and documented commissioning evidence are becoming bankability assets in their own right.

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