Ugljevik supply plan

Most of the financing is earmarked for Ugljevik, where coal purchases are linked to local supplier Drvo-export. The wider supply agreement is reported to be worth more than €100 million and involves coal from the Bukova Kosa deposit near Prijedor. The arrangement would provide an additional fuel source as the power plant works to secure sufficient feedstock for generation.

Environmental scrutiny

The procurement has also raised environmental questions. Local reporting cited in the energy bulletin alleges that extraction at Bukova Kosa began without the necessary environmental permit and points to concerns over coal quality and sulphur content. Those issues carry particular significance because Ugljevik’s flue-gas desulphurisation equipment is reportedly not operating. The allegations and the plant’s operating conditions require regulatory scrutiny rather than being treated as established findings.

Gacko mine funding

A smaller part of the guarantees will support the Gacko mine, financing overburden removal, excavation, hauling and related works expected to be carried out by outside contractors. Unlike Ugljevik’s largely procurement-focused borrowing, the Gacko programme is intended to preserve access to workable coal reserves.

The guarantees underline the financial and operational challenge of keeping coal-dependent generation supplied. The immediate test for both facilities will be whether new borrowing translates into reliable deliveries without adding unresolved environmental or compliance risks.

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Winter prices and supply costs

The proposed adjustment follows a 32.5% rise in the November tariff compared with October. Bulgargaz maintains that its requested December level would still be more than 20% below prevailing European wholesale quotations, reflecting the mix of contracted and market-based supply available to Bulgaria.

The company’s supply portfolio includes Azerbaijani pipeline gas, liquefied natural gas arriving through Greece’s Alexandroupolis terminal and routes via Turkey, as well as withdrawals from the Chiren underground storage site. Expected customer demand and the cost of drawing from these sources shape its monthly pricing proposal.

Gas-market quotations cited for November 9 showed Dutch TTF around €82/MWh, German and Austrian hubs above €83/MWh and Bulgaria’s Balkan Gas Hub at €80.46/MWh. Those prices illustrate the contrast between traded-market values and the regulated wholesale offer, although they refer to a different date from the December proposal.

Business groups and trade unions have warned that successive gas increases, alongside pressure from electricity and petroleum prices, could raise production expenses and heating bills. The December figure remains a proposal, but its direction signals further winter-cost pressure on Bulgarian consumers.

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Assessing geothermal prospects

The partnership will concentrate on the Pannonian region, where geological conditions are considered suitable for geothermal development. HEP and AZU plan to screen potential sites and assess whether subsurface resources can support commercially viable investments before individual projects move into development.

The agreement will combine AZU’s geological records and exploration expertise with HEP’s engineering, generation and infrastructure capabilities. Their work is expected to cover resource assessment, technical design and financial feasibility, helping to establish which prospects are sufficiently advanced to justify further spending.

Rules and commercial potential

The initiative follows changes to Croatia’s rules on the exploration and use of energy-related geological resources, including geothermal waters. The revised framework is intended to make permitting more predictable and improve conditions for investors, although the agreement itself does not announce project capacities, investment commitments or construction schedules.

Geothermal power and heat can complement variable solar and wind generation by supplying energy when weather conditions are less favourable. For Croatia, the commercial opportunity lies in converting promising geological resources into bankable generation or heating assets rather than leaving them at the exploration stage.

The post Croatia’s HEP and hydrocarbon agency agree to advance geothermal power and heating projects appeared first on Serbia SEE Energy Mining News.

Funding for businesses

Under the government’s plan, €1.5 billion would be drawn from the Electricity System Security Fund and €500 million channelled through the Bulgarian Development Bank. A state-aid arrangement notified to the European Commission would raise compensation for eligible electricity expenditure at energy-intensive companies from 50% to 70%.

The development bank is also expected to provide additional assistance of €15/MWh to non-household electricity users, with the scheme covering eligible consumption from October. Individual payment amounts will depend on assessments of applicants’ support needs.

For residential customers, electricity and district-heating tariffs are to remain unchanged, while €10 million is allocated to help households meet natural-gas heating costs during winter. The government said Bulgargaz would continue efforts to supply gas to industrial customers at competitive prices.

Officials described the package as a response to external energy-market disruption and its effects on inflation and competitiveness, saying the measures would not require additional central-budget expenditure. The effectiveness of the programme will depend on the terms of the compensation scheme, its approval and the speed with which support reaches industrial users.

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Project structure and flexibility

The project is being developed by a joint venture established in 2026, owned 60% by Tsakos and 40% by Metlen. Despite its minority equity interest, Metlen will undertake construction and manage the facility’s subsequent operations and power-market activities, including electricity trading.

The storage component is designed to give the project more flexibility than a conventional solar plant by retaining some daytime output for delivery during other trading periods. The ability to shift energy across hours may help limit exposure to low midday electricity prices, although revenues will remain dependent on market conditions and operating performance.

Expanding energy portfolios

For Tsakos, the venture represents an expansion from transporting energy through its shipping businesses into electricity production. For Metlen, it adds to an expanding portfolio of storage-backed power assets in Greece.

Metlen has also worked with Karatzis Group on a separate battery installation reported to have 330 MW of power capacity and 790 MWh of storage. The Domokos development reinforces a broader shift towards combining renewable generation, storage and active electricity-market management in a single investment strategy.

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Consumption and bills fall

State power utility EPCG reported household usage of 111.9 million kWh during the month, 7.75% below September and 4.66% lower than in October 2025. The figures show a simultaneous fall in consumption and the amount billed to an average household, without establishing how much of the change was driven by weather, consumption habits or other factors.

Bills vary by municipality

Bills varied by municipality. Herceg Novi recorded the lowest average at approximately €24.60, while Nikšić had the highest at about €37.30. Across the customer base, 64.05% of households were billed less than €30, a further 18.43% between €30 and €50, and 13.69% between €50 and €100. Around 3.82% received bills above €100.

Discounts and winter outlook

EPCG said 128,401 customers with regular payment records received a discount, representing about 30.7% of electricity consumers. Those discounts helped lower bills for qualifying households, although the report does not quantify their effect on the national average.

The October figures offer an early view of household demand ahead of the winter heating season. Consumption trends over the following months will be more informative about pressure on EPCG’s electricity supply and retail operations.

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Facility specifications

The proposed facility is expected to generate about 11 GWh a year, an amount EPCG equates to the annual electricity consumption of roughly 1,800 households. Its design envisages two generating units fitted with horizontal Francis turbines.

EPCG has selected domestic contractor Vigoris Ecotech to undertake the engineering design and construction package. The utility submitted its application to the spatial-planning ministry in November, but construction remains dependent on receiving the necessary approval.

Repeated setbacks

The project has encountered repeated setbacks since EPCG concluded a concession agreement with the Montenegrin government in 2022. Difficulties in appointing a contractor led to extensions of the implementation timetable, delaying the planned addition of hydroelectric capacity.

Part of a broader strategy

Otilovići is modest in size compared with large utility-scale renewable developments, but it forms part of EPCG’s strategy to broaden its generation mix. The permit decision and execution of the design-build contract will determine whether the project can move beyond its prolonged development phase as Montenegro evaluates its longer-term dependence on coal-fired electricity.

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The project is expected to enter commercial service in the second half of 2028. Its 11 Nordex turbines are forecast to produce about 244 GWh annually, equivalent to the electricity needs of approximately 71,000 households, according to the development estimates.

Project development and output

Scatec acquired Urleasca 2 from Swedish developer OX2 in July 2026. OX2 will remain involved in overseeing construction through commissioning, despite transferring ownership to the Norwegian group. CJR Renewables is handling construction, EnergoBit is responsible for the grid connection and Nordex will supply turbines.

The wind farm has a long-term contract for difference awarded during the development phase that covers approximately 57% of expected electricity output. That arrangement should improve revenue visibility, while the remaining production will have different market exposure.

Financing and wider portfolio

Bank debt is expected to finance around 60% of the investment, with Erste Group and Banca Comercială Română acting as lead arrangers and underwriters. Scatec is also pursuing the Dobrun and Sadova solar projects, together totalling 190 MW, and an 88 MW/176 MWh battery development in Romania.

The combination of a contracted generation share, bank financing and established engineering partners illustrates how renewable developers are assembling bankable projects in Romania’s expanding electricity market.

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Contracte și finanțare

Construction responsibilities have been divided into separate packages. CHINT Green Energy, CMC Europe and Solarpro will each undertake engineering, procurement and construction work; EnergoBit and Siemens Energy will provide high-voltage infrastructure; and Tongwei and Astronergy will supply solar modules.

The contractor selections follow a financing arrangement announced in September 2026 worth up to €561 million and involving 14 lenders, including the European Investment Bank. The size of the financing package highlights the capital required to build utility-scale renewable generation and the role of multiple institutions in funding projects of this scale.

Venituri și conservare

Dama Solar has secured revenue support for part of its expected output. Contracts for difference awarded in August 2025 cover 520 MW of capacity. Rezolv has also signed a ten-year virtual power purchase agreement with retailer Ahold Delhaize, which will draw on electricity associated with Dama and the company’s 300 MW Dunărea East wind project.

The developer has set aside 82 hectares for habitat restoration and conservation rather than placing panels across the entire available site. Backed by Actis and Mubadala, Rezolv reports a renewable-energy portfolio of around 2.8 GW across Romania and Bulgaria.

Dama’s next milestones will be construction progress, grid integration and delivery against its planned 2028 commissioning schedule.

The post Rezolv awards contracts for 1.36 GW Dama Solar project in western Romania appeared first on Serbia SEE Energy Mining News.

Production at risk

Local reporting indicates that throughput has been scaled back and that a complete suspension could become necessary if crude shipments do not resume before early December. Refinery operator NIS, however, has not confirmed that production will cease or announced a shutdown date, and the potential interruption should not be treated as a firm decision.

Pipeline damage and repairs

The supply problem followed damage to the Sisak-Slavonski Brod section of the JANAF network on November 6, when construction equipment reportedly struck the pipeline and an estimated 500,000 litres of crude escaped. JANAF said on November 9 that the leaked oil had been recovered and transported by road to its terminals before being returned to the pipeline system.

Repair work and environmental cleanup were still continuing, with no confirmed date given for the restart of crude deliveries. NIS said it was adjusting refinery operations in response to information from the pipeline operator and relevant authorities.

Fuel stocks support sales

The company also stated that its retail network remained supplied and that existing fuel stocks were sufficient to sustain ordinary petrol-station sales. The immediate operational risk is therefore concentrated at the refinery, while the broader market impact will depend on the duration of the pipeline outage and the ability of available inventories to bridge the interruption.

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Study details

The agreement was signed by Turkish state nuclear company TUNAS and Candu Energy, an AtkinsRéalis subsidiary, during the COP31 conference in Antalya. The study will examine the use of Canadian CANDU technology, prospective sites, technical requirements, capital costs and possible financing structures. No final construction decision has been taken.

The feasibility review is scheduled to finish by the end of 2027, with some preliminary engineering work potentially continuing into 2028. The partners also plan to assess opportunities for Turkish manufacturers, construction companies and workers to participate in any future programme.

Broader nuclear plans

Turkey is already developing the 4.8 GW Akkuyu nuclear power plant with Russia’s Rosatom and has examined additional sites at Sinop and in Thrace. It has also held discussions with several international partners about technology and development options.

Ankara aims for 10 GW of nuclear capacity and an 11% share of electricity consumption by 2040. The Canadian option remains subject to feasibility findings, financing and a future investment decision.

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Investment framework

The framework envisages about 7 GW of new wind and solar projects together with storage assets and transmission facilities with roughly 4 GW of transfer capacity. Individual project sites, capital commitments and financing structures have yet to be finalised, making the announced amount an investment ambition rather than a portfolio of fully approved construction projects.

The arrangement was concluded during the COP31 conference in Antalya and also places emphasis on technology transfer. Turkish officials want closer cooperation with Chinese manufacturers in wind-turbine components and other renewable-energy equipment, with domestic industrial participation forming part of the proposed investment programme.

Energy targets and delivery

The initiative is aligned with Turkey’s National Energy 2040 strategy, under which the government is targeting 175 GW of combined solar and wind capacity by 2040. The same policy framework envisages renewable sources accounting for about 77% of installed generation capacity, compared with approximately 63% at present.

More storage and stronger transmission links would be needed to absorb additional variable output and move it to consumers. The key commercial test will be whether the two countries convert their broad agreement into financed projects, executable equipment contracts and a deliverable grid-development schedule.

The post Turkey and China outline $15 billion renewable-energy investment programme appeared first on Serbia SEE Energy Mining News.

Regional prices retreat

The decline reversed Montenegro’s daily price premium over northern Italy and substantially reduced procurement costs across the Balkans, although transmission restrictions continued to limit opportunities to move cheaper electricity between markets.

Prepared on 13 November 2026 at 09:05 CET, this article compares cleared day-ahead prices for 00:00–24:00 CET on 13 November with the equivalent delivery period on 12 November. Generation and demand comparisons cover completed operating days; Friday’s forecasts remain provisional.

Albania’s ALPEX average fell to €162.51/MWh from €282.91/MWh, the largest percentage decline among the reviewed SEE markets. Serbia’s SEEPEX dropped 32.8% to €191.68/MWh, while Montenegro’s BELEN declined 34.1% to €197.24/MWh.

The retreat extended across the region. Hungary’s HUPX fell 31.1% to €200.40/MWh, Romania’s OPCOM declined 32.5% to €199.32/MWh, and Bulgaria’s IBEX lost 33.1% to €193.84/MWh.

Croatia’s CROPEX dropped 26.9% to €203.36/MWh, Slovenia’s BSP/ADEX fell 25.2% to €205.12/MWh, and North Macedonia’s MEMO declined 30.9% to €211.11/MWh. Greece’s HEnEx remained cheaper at €144.83/MWh, down 35.7%.

Both comparison days are weekdays, making a weekend demand transition an insufficient explanation for the decline. Serbia’s daily average was approximately 47% below Tuesday’s, while Hungary’s had almost halved, extending the retreat from early-week scarcity pricing.

Spreads and transmission constraints

The sharpest change in cross-border relative value involved Montenegro and Italy. Northern Italy’s day-ahead average eased only 4.4% to €236.42/MWh, leaving Montenegro €39.18/MWh cheaper, compared with a €51.81/MWh premium on Thursday.

That €90.99/MWh swing changes the indicative direction of the trading opportunity. Executable returns nevertheless depend on hourly prices, the relevant Italian landing zone, available transmission rights, losses and transaction costs. Austria also remained above the central Balkan markets at €218.37/MWh, despite an 18.8% decline.

Within the Balkans, Montenegro’s premium over Serbia narrowed to €5.56/MWh from €14.12/MWh. Hungary’s premium over Serbia widened to €8.72/MWh from €5.87/MWh, showing that falling outright prices did not eliminate differences between neighbouring markets.

A persistent constraint continued to separate Greece from Italy. IPTO’s 29 October notice forecast the Greece–Italy direct-current link would remain unavailable until 15 November, with zero net transfer capacity in both directions and curtailment of previously allocated long-term rights. Restoration had not been confirmed at preparation time.

Auction volumes diverged. SEEPEX traded 11,344.7 MWh for Friday delivery, down 24.9% from Thursday’s 15,114.9 MWh. MEMO volume increased 10.5% to 6,734.9 MWh, demonstrating that the regional price decline did not coincide with a uniform contraction in exchange activity.

Supply shifts and renewable output

Completed operating figures for 12 November, compared with 11 November, showed several sources of supply relief. Serbia’s average net imports fell to approximately 362 MW from 574 MW, while wind generation increased to 239 MW from 133 MW and coal output rose modestly.

Bosnia and Herzegovina increased average net exports to approximately 291 MW from 212 MW, despite lower reservoir-hydro generation. A comparable Bosnian exchange-price benchmark was not verified.

Romania’s average nuclear generation rose to approximately 433 MW from 192 MW, consistent with the recovery following Nuclearelectrica’s Cernavodă Unit 2 reconnection. Higher wind output also helped reduce average net imports to 1,525 MW from 1,660 MW, despite increased demand.

The latest verified company timetable forecast Cernavodă Unit 1 reconnection on 13 November, followed by nominal output on 14 November. An achieved Friday restart had not been confirmed.

Hungary remained exposed to external supply. Average net imports increased to approximately 2,180 MW from 1,965 MW, while domestic gas generation declined. Its lower auction price therefore coincided with greater import dependence.

Greek wind generation rose approximately 23% to 3,089 MW on Thursday, while gas-fired output fell approximately 24% to 2,284 MW and demand eased. German onshore and offshore wind generation together increased from roughly 6,065 MW to 19,999 MW, providing a broader European backdrop of stronger renewable supply.

For Friday’s Greek operating day, IPTO forecast average renewable generation of approximately 5,581 MW and system load of 5,368 MW. These forecasts cover the Greek local day and do not establish realised export availability. Reservoir filling stood at 35.73% at midnight Greek time, little changed from 35.70% a day earlier. Thursday’s operating records also showed net exports of approximately 3,275 MWh to Turkey.

Greece’s cheapest Friday day-ahead intervals reached €0/MWh, without turning negative. No negative intervals were identified in the reviewed Serbian, Montenegrin, Hungarian, Bulgarian, Croatian or Slovenian series, unchanged from Thursday.

Investment and market outlook

A material investment milestone came from Rezolv Energy, backed by Actis and Mubadala, which announced construction-partner appointments on 12 November for its 1,360 MWp Dama Solar project in Romania.

CHINT Green Energy, CMC Europe and Solarpro will undertake construction packages, EnergoBit and Siemens Energy will deliver high-voltage infrastructure, and Tongwei and Astronergy will supply modules. The appointments follow financing of up to €561 million, signed in September through West Power Investments with 14 lenders, anchored by the European Investment Bank. Commercial operation is forecast for the second half of 2028.

Comparable current intraday prices, balancing costs and final imbalance settlement charges remained unverified across the region. SEEPEX’s latest populated intraday display covered 11 November, showing €331.29/MWh on 350 MWh. A comparable Turkish day-ahead price with a verified currency conversion was also unavailable.

For buyers, Friday’s auctions deliver substantial relief from early-week costs. For traders, changing spreads increase the importance of hourly transmission availability and imbalance exposure. For investors, the combination of zero-price Greek intervals, continuing import dependence and expanding renewable capacity strengthens the case for assessing capture prices, flexibility and connection constraints alongside headline electricity prices.

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Growing price gaps

The driver is the growing gap between cheap and expensive hours. The region has added gigawatts of solar capacity in a short time, which floods the market at midday and pushes prices down, sometimes below zero. In the evening, when solar fades, prices are set by gas plants, imports and hydropower, and can climb steeply. BloombergNEF estimated that Romania’s average two-hour day-ahead price spread reached €151 per megawatt-hour in 2025, among the highest in Europe. ENTSO-E has identified Southeast Europe as one of the most valuable regions on the continent for storage investment.

Several factors point to even wider spreads in 2027. Solar growth continues in Romania, Bulgaria and Greece. Market analysts expect midday curtailment in Greece to become a regular feature rather than an exception, and windy days are already causing midday price collapses in Romania. At the same time, gas prices in the first half of 2027 are forecast to stay high, keeping evening prices elevated. Forward markets are reflecting this, with peak contracts carrying growing premiums over baseload.

Investors build storage

Investors are responding. Romania has dozens of large battery projects in development, supported by a €150 million subsidy scheme. Greece’s PPC and Metlen are developing up to 3 gigawatt-hours of storage across the region. Montenegro, Croatia, Albania and Serbia are all adding batteries to solar parks or launching their first standalone systems, and Albania’s next solar auction will include storage. At EU level, a leaked plan points to a target of 200 gigawatts of storage by 2030.

Beyond batteries

Batteries are not the only option. Pumped hydro projects, such as the Đerdap 3 scheme agreed between Serbia and Romania and new plans in Croatia, offer longer-duration storage. Flexible gas plants designed to ramp up quickly in the evening are also part of the mix, especially in Greece. Germany’s first capacity auction, which awarded all 5.16 gigawatts to gas plants, is a reminder that policy design still favours gas in some markets.

Risks and returns

The risks deserve attention. Battery revenues depend on volatility, and as more storage connects, price spreads will narrow. Early projects will likely earn the highest returns. Supply chains are another concern, as possible EU restrictions on Chinese inverters and components could raise costs. Grid connection queues, particularly in Serbia, can delay projects for years.

The strongest business cases will combine several income streams: daily price arbitrage, balancing services for grid operators, and support for co-located solar or wind plants. Companies that can trade these assets actively, rather than relying on fixed contracts, are likely to perform best.

In 2027, volatility will be a defining feature of Southeast Europe’s power market. For consumers it is a cost, but for owners of flexible assets it is the foundation of a growing and increasingly mature investment market.

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Rising carbon costs

The first pressure point is the EU’s Carbon Border Adjustment Mechanism. Since January 2026, electricity exported from the Western Balkans to the EU has carried a carbon charge. The impact is already clear: Western Balkan power exports to the EU fell 17 percent year-on-year in the third quarter of 2026, as carbon costs outweighed the price advantage of coal-fired generation. Because CBAM uses default emission factors, even renewable electricity can be charged as if it came from lignite, unless producers can document otherwise.

The second pressure point is the carbon price itself. Analysts surveyed by Reuters in the spring expected EU allowances to average around €93 per tonne in 2027, lower than earlier forecasts because of proposed market reforms. Since then, views have diverged: some analysts now expect prices up to €20 higher, others a modest decline. Either way, CBAM costs for coal-heavy exports are likely to rise next year rather than fall.

A delayed route to relief

The way out for Western Balkan countries is to align their own carbon pricing with the EU’s and to integrate fully into the single electricity market, which would qualify them for an exemption. That process is taking longer than hoped. Market coupling between the EU and the Western Balkans, originally pencilled in for 2027, is now expected around 2028 or 2029, according to Anže Predovnik, head of the ADEX Group and BSP Southpool. Governments in the region have asked Brussels for an earlier exemption for electricity, but no decision has been made.

Some in the region hoped for breathing room from the EU’s second emissions trading system, covering buildings and road transport. Its launch has been pushed back from 2027 to 2028. That delay matters little for the power sector, however, which faces CBAM directly.

Utilities and clean alternatives

For state utilities such as Serbia’s EPS, Bosnia’s Elektroprivreda companies and North Macedonia’s ESM, the implications are significant. EPS has adopted a decarbonisation action plan and committed, under its agreement with the IMF, to begin workforce optimisation by early 2027. These are steps in the right direction, but the scale of the challenge is large: coal plants that once earned money from exports will increasingly be used only for domestic supply.

There is a commercial upside for those who move quickly. Renewable projects in the region that can prove their output is clean stand to benefit when exemptions or verification rules improve. Utilities that add solar, wind and storage alongside existing hydro will be better placed to export to the EU without carbon penalties.

From cost to opportunity

The message for 2027 is that the Western Balkans can no longer compete on cheap coal power in the EU market. The faster the region builds clean capacity and completes the regulatory work needed for full market integration, the sooner it can turn carbon pricing from a cost into an opportunity.

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Hungary sets the regional benchmark

The reason is geography and grid structure. Most of the electricity that flows into Southeast Europe from the continent’s large central markets passes through Austria and Slovakia into Hungary before spreading across interconnectors towards Romania, Serbia and Croatia. When German prices rise, Hungary imports that pressure and passes it south. Market analysts at Electricity.Trade conclude that Hungary has effectively taken over from Italy as the main reference market for price formation in the region.

The effect is visible on the busiest days. On 11 November, Hungary and Romania recorded the highest average day-ahead prices in the region, at around €354 and €352 per megawatt-hour respectively, with most neighbouring markets just a few euros behind. Only Greece, at €279, was noticeably cheaper.

Forward prices tell a similar story. According to energy analyst Mervar, the price of Hungarian power for 2027 delivery had already risen by more than 26 percent between mid-February and early April, as the Middle East conflict pushed up gas and oil costs. Contracts for 2028 and 2029 also rose, though by smaller amounts, suggesting that the market expects some stabilisation later in the decade.

Hedging risks for buyers

For buyers in the Western Balkans, the HUPX benchmark creates a specific problem. Because liquid forward markets are concentrated in Hungary, a Serbian utility or industrial consumer that wants to hedge future exposure often has to do so with Hungarian contracts. Yet Serbia’s own spot prices on SEEPEX can be much lower: on one recent day, Serbian spot power cleared at about €54/MWh while Hungarian forward contracts traded between €95 and €100. That mismatch, known as basis risk, can make a hedge expensive or ineffective.

The shape of prices is also changing. As solar output grows in Romania, Bulgaria and Greece, midday prices are falling, sometimes below zero, while evening prices climb as solar fades and thermal plants ramp up. Forward markets are starting to price this in, with peak-hour contracts carrying larger premiums over baseload. Analysts expect that gap to widen further in 2027, especially in summer.

What could change the market

Two developments could reduce Hungary’s dominance. New interconnectors between Romania, Bulgaria and Greece would allow surplus power to move more freely, narrowing regional price gaps. And full coupling of the Western Balkan markets with the EU, now expected around 2028 or 2029, would deepen liquidity on local exchanges.

Until then, companies across Southeast Europe need to treat HUPX as the region’s real benchmark. That means building hedging strategies around regional price spreads and the daily price curve, rather than relying on a single annual price. In a more volatile market, the companies that understand how prices move between countries and between hours will manage their costs best.

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Near-term price risks

The near-term risk is clear. Benchmark Dutch TTF futures rose above €100 per megawatt-hour at the end of October for the first time since the 2022 crisis, before easing to the low €80s. Goldman Sachs has raised its forecast for the first quarter of 2027 to €74/MWh from €44, and its average for the full year to €51 from €32. The bank assigns a 45 percent probability to a winter in which Middle Eastern LNG exports stay low, and warns that a cold winter combined with weak Gulf supply could push prices much higher. Rabobank is more moderate, with a base case of around €42/MWh for 2027 but a range of €50 to €60 if damage to Gulf export infrastructure persists.

The longer view is very different. Goldman expects TTF to fall to around €19/MWh in 2028 and €16/MWh in 2029, provided the Strait of Hormuz is fully open, as new liquefaction capacity in the United States, Qatar and elsewhere comes online. Other analysts share the view that the late 2020s will be a buyer’s market, even if they differ on timing.

A regional transition

For Southeast Europe, the timing matters as much as the price. Russian LNG imports into the EU must stop by the end of 2026, and pipeline gas by autumn 2027. Bulgaria, Greece, Romania and Croatia are already largely diversified, but Serbia, Bosnia and Herzegovina and North Macedonia still depend heavily on Russian volumes delivered through TurkStream. The transition will happen during the tightest part of the cycle, before the expected glut arrives.

The infrastructure to replace Russian gas is taking shape. Croatia’s Krk terminal has expanded its capacity to 6.1 billion cubic metres a year. The Vertical Gas Corridor will carry LNG from Greek terminals north through Bulgaria and Romania, with a new branch planned towards North Macedonia and Serbia. Albania has signed a 20-year US LNG deal, and Bosnia and Croatia have agreed to build the Southern Interconnection.

A difficult buying decision

This creates a difficult decision for regional buyers. Signing long-term LNG contracts now means locking in supply at prices set during a crisis. Waiting for the glut risks exposure to winter shortages and to the 2027 deadline for Russian gas. The most sensible approach for most utilities and industrial users is likely to be layered: securing enough contracted volume to cover the next two winters, while leaving room to take advantage of cheaper spot cargoes later in the decade.

Building regional leverage

Governments have a role too. Joint purchasing, coordinated storage and regional capacity booking on the new corridors could give smaller markets more bargaining power than they would have alone.

Gas will remain the price-setting fuel for electricity across much of the region in 2027. The countries and companies that get through this winter, and lock in flexible access to LNG on reasonable terms, will be in the strongest position when the market turns in their favour.

The post Gas in 2027: An Expensive Winter, Then the Big LNG Glut appeared first on Serbia SEE Energy Mining News.

Oil and gas outlook

$79 per barrel. That is the World Bank’s forecast for average Brent crude in 2027, down from about $91 this year. Other forecasters are slightly higher, at $84 to $87. Fuel costs should ease, but not to the low levels of 2025.

$105 per barrel. This is the World Bank’s estimate for Brent in 2027 if the Middle East conflict escalates further. It is the main downside risk to every energy budget in the region.

€74 per megawatt-hour. Goldman Sachs’ forecast for European gas in the first quarter of 2027 shows that winter will remain expensive. The bank’s average for the full year is €51.

€16 to €19 per megawatt-hour. This is where Goldman expects gas prices to fall in 2028 and 2029 as new LNG supply arrives. Companies signing long-term contracts now should keep this future glut in mind.

Regional supply routes

Autumn 2027. This is the EU deadline for ending Russian pipeline gas imports. Serbia, Bosnia and Herzegovina and North Macedonia face the biggest adjustment, relying on new routes through Greece and Croatia.

6.1 billion cubic metres. That is the expanded annual capacity of Croatia’s Krk LNG terminal, a key entry point for American and other non-Russian gas into the region.

Power and carbon costs

26 percent. That is how much the price of Hungarian power for 2027 delivery rose in just a few weeks this spring. Because Hungary’s HUPX exchange sets the reference price for much of the region, this matters to buyers far beyond Hungary.

€93 per tonne. That was the average analyst forecast for EU carbon allowances in 2027 in this spring’s Reuters survey. Carbon costs feed directly into electricity prices in the EU and into CBAM charges for Western Balkan exporters.

Trade and demand

17 percent. That is how much Western Balkan power exports to the EU fell year-on-year in the third quarter of 2026, as CBAM made coal-based exports less competitive. Full market coupling with the EU, which would ease the pressure, is now expected only around 2028 or 2029.

3.2 percent. That is the World Bank’s growth forecast for the six Western Balkan economies in 2027. Steady growth means steadily rising energy demand, and higher bills for those without secure supply.

Taken together, these numbers point to a year of transition. The first months of 2027 will be costly, particularly for gas and electricity. As Gulf supply recovers and new LNG arrives, prices should ease through the year, but carbon costs and regulatory change will keep pressure on traditional business models. The companies best placed for 2027 will hedge sensibly, invest in flexibility and treat the energy transition as a strategic priority rather than a compliance exercise.

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Forecasts diverge

The World Bank’s latest Commodity Markets Outlook expects Brent to average about $91 a barrel this year and fall to around $79 in 2027, assuming no further escalation in the Middle East. The US Energy Information Administration’s October outlook was more cautious, putting 2027 at roughly $84 after an expensive final quarter of 2026. The Oxford Institute for Energy Studies sees $87, and S&P Global expects prices to stay mostly in an $80 to $100 range through next year. The common thread is a gradual recovery in Gulf output and exports, which should allow inventories to rebuild after this year’s heavy drawdowns.

The downside scenario is equally clear. The World Bank estimates that if the conflict intensifies, Brent could average $105 next year. For a region that imports most of its crude and refined products, that gap between $79 and $105 is the difference between relief and another year of emergency measures.

What lower prices mean for consumers

For consumers, lower crude prices will not show up at the pump straight away. Governments across the Balkans cut excise duties, capped margins or froze prices this year to soften the shock. As crude falls, finance ministries will be tempted to restore those revenues before retail prices fully adjust. Diesel is a particular concern: global distillate markets have been tight, and refining margins are expected to stay elevated well into 2027.

Refiners face uncertainty

Refiners face a mixed picture. Wide margins have supported profitability, but the region’s refining sector is also caught up in geopolitics. Serbia’s only refinery at Pančevo, operated by NIS, has spent more than a year under US sanctions targeting its Russian majority owners. A sale of the Russian stake to Hungary’s MOL was agreed in principle in January, but the transaction has moved slowly through repeated licence extensions. Until it closes, the refinery’s crude supply depends on decisions taken in Washington and Moscow. Elsewhere, the sale of Lukoil’s international assets, including Bulgaria’s Burgas refinery and retail networks across the region, is still being worked out.

Managing the risk

For businesses, 2027 offers an opportunity rather than certainty. Transport operators, airlines and energy-intensive manufacturers that hedge part of their fuel exposure at current forward prices can lock in some of the expected decline while protecting themselves against the escalation scenario. Those who wait for the full drop risk being caught out if Gulf supply disappoints again.

The broader lesson of 2026 is that the region’s exposure to oil shocks is structural. Limited refining capacity, dependence on imports and slow progress on electrifying transport mean that every disruption in the Strait of Hormuz is felt quickly in Belgrade, Sarajevo and Skopje. Cheaper oil in 2027 would be welcome, but it would not change that underlying vulnerability. Real resilience will come from settling the ownership of key refineries, building strategic reserves and moving transport away from imported fuel.

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Gas and winter pressure

The short answer is that the first quarter will remain tight, and any meaningful relief depends on gas.

Since the conflict in the Persian Gulf disrupted LNG flows at the end of February, gas has become the single most important driver of power prices in the region. Gas-fired plants set the price in most evening hours, and with wind and solar output weak during much of November, they have been setting it for long stretches of the day as well. The Dutch TTF benchmark rose above €100 per megawatt-hour in late October before easing to around €82, still more than double its pre-conflict level.

The forecasts for early 2027 offer limited comfort. Goldman Sachs expects TTF to average about €74 in the first quarter and €51 for the year as a whole, and puts the probability of a winter with persistently weak Middle Eastern LNG supply at 45 percent. Rabobank is more optimistic, with a base case near €42 for 2027, but it sees prices staying in the €50 to €60 range if damage to Gulf export facilities lingers. Both banks expect a wave of new LNG supply to push prices sharply lower later in the decade. The problem is that the relief arrives after the winter that matters most.

That winter starts from a weak position. EU gas storage peaked at just under 75 percent at the end of October, about eight points below last year, and Germany entered the heating season with its lowest stocks on record. On historical withdrawal patterns, European storage would end March at around a quarter full. The International Energy Agency has warned that a cold winter combined with further supply disruption could push it below 10 percent. In that environment, every cold spell or delayed LNG cargo can move power prices quickly, and Southeast Europe tends to feel it first.

A fragile regional supply mix

Gas is not the only constraint. The region’s supply fleet is weaker than usual going into winter. Romania’s Cernavodă nuclear plant, which covers around a fifth of the country’s electricity needs, spent much of the autumn offline after low Danube levels left it without enough cooling water, and its return has been bumpy. Hungary’s Paks plant had to cut output sharply during the summer heat for the same reason. Reservoirs and rivers across the Balkans are low, reducing the hydropower that normally cushions evening peaks. Ageing lignite plants in Serbia, Bosnia and Herzegovina and North Macedonia are running with lower availability and more imported coal.

The result is a region that increasingly depends on imports. Serbia covered around a quarter of its October demand from abroad, at a cost estimated at €8 to €9 million a day. Hungary is a structural net importer, which is why price pressure from Germany and Central Europe passes so quickly through Hungarian interconnectors into Romania, Serbia and Croatia. When gas is expensive, nuclear and hydro output is low, and import capacity is stretched, all at the same time, Southeast Europe moves to the top of Europe’s price table, as it did in early November.

For the first quarter of 2027, three paths look plausible. In the base case, LNG exports from the Gulf recover gradually towards around 83 percent of normal by February, temperatures stay close to average and Romanian nuclear capacity returns reliably. Prices would then hold close to current levels in January before easing through March, although evening peaks would remain high. In a tight scenario, with weak Gulf supply, a cold January and February and further nuclear or hydro setbacks, gas could climb well above €100 and regional power prices could exceed the highs of this autumn. In a milder scenario, with faster LNG recovery and windier weather, gas could fall towards €50, bringing significantly lower power prices and wider gaps between regional markets.

The forward market is already signalling which risk it fears most. Across Europe, winter contracts have risen faster than full-year 2027 contracts, showing that traders are pricing a specific winter scarcity premium rather than a permanent shift. That is consistent with the broader outlook: a difficult first quarter, followed by gradual relief as the year goes on.

Structural shifts beyond winter

Beyond the winter, three structural trends will shape the region’s power market through 2027.

The first is volatility in daily prices. Solar capacity in Hungary, Romania, Bulgaria, Greece and Serbia continues to grow, pushing midday prices down, sometimes below zero, while evening prices are set by gas and imports. The gap between the cheapest and most expensive hours of the day is widening, and forward markets are starting to price peak-hour power at a growing premium. This is the strongest argument yet for battery storage, pumped hydro and flexible gas plants, and investors are responding with a growing pipeline of projects from Romania to Montenegro.

The second is carbon. The EU’s Carbon Border Adjustment Mechanism has already cut Western Balkan electricity exports to the EU by 17 percent year-on-year in the third quarter of 2026, while trading within the region has grown strongly. EU carbon prices are expected to remain around €90 a tonne in 2027, and the EU has committed to completing reform of its emissions trading system early in the year. With full market coupling between the EU and the Western Balkans now expected only around 2028 or 2029, coal-heavy producers in the region will continue to face a carbon cost at the border throughout 2027.

The third is the end of Russian gas. The EU ban on Russian LNG takes effect at the start of 2027, and pipeline imports must stop by autumn. New routes through Croatia’s Krk terminal and the Vertical Gas Corridor from Greece are taking shape, but much of the capacity will mature only after the winter. For Serbia, Bosnia and Herzegovina and North Macedonia, securing alternative supply at a reasonable price will be one of the defining energy challenges of the year.

What businesses should do

For businesses, the practical lessons are clear. Companies exposed to the spot market should hedge at least part of their winter consumption rather than wait for prices to fall. Hedging strategies need to account for differences between countries and between hours of the day, not just a single annual price. And investments in flexibility, from on-site storage to demand response, are likely to pay back faster in this market than at any time in the past decade.

Southeast Europe’s power market in 2027 will be defined by an expensive start and a gradual, uncertain easing. Gas will decide how fast prices fall, weather will decide how painful the winter is, and carbon and grid integration will shape who wins and loses over the rest of the year. The companies that plan for volatility, rather than hoping it disappears, will be best placed to come through it.

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Exports to the EU fall

According to the Energy Community Secretariat’s third quarterly report on CBAM’s impact, electricity exports from the Western Balkans to the EU fell 17 percent year-on-year in the third quarter of 2026. The reason is straightforward: for coal-heavy systems, the carbon charge now attached to each exported megawatt-hour has outweighed the price advantage that cheap lignite once offered. Gross scheduled exchanges between the six Western Balkan economies and the EU stayed below last year’s levels, and the region remained a net importer on a scheduled basis.

Regional trading expands

The more surprising story is what happened inside the region. Day-ahead trading on the four Western Balkan power exchanges, ALPEX in Albania, MEMO in Montenegro, MEPX in North Macedonia and SEEPEX in Serbia, reached around 2.97 terawatt-hours in the third quarter. That is up about 10 percent on the previous quarter and nearly 27 percent on a year earlier. Lower trade with the EU has not meant less market activity. Instead, more power is being bought and sold within the region.

The secretariat is careful not to overstate the case. Its report notes that prices and flows were also shaped by hydrology, demand and available capacity, and that a wider price gap with EU markets did not automatically translate into more exports. Earlier in the year, an exceptionally wet first quarter flooded the region with cheap hydropower, and surplus electricity increasingly found buyers in Ukraine and Moldova, often transiting through Hungary and Romania.

Prices and renewable power

Prices tell a similar story. In the first quarter, day-ahead prices in Energy Community markets averaged about EUR 30 per megawatt-hour below neighbouring EU zones. Over the first half of the year, Italy was the most expensive neighbouring market at around EUR 125 per megawatt-hour, while Albania was the cheapest at about EUR 86. The gap has attracted a new wave of power traders into Balkan markets to exploit the spreads.

The biggest frustration for the region is that renewable electricity is treated the same as coal power at the border. Because CBAM applies default emission factors, a megawatt-hour from a Serbian wind farm or an Albanian hydropower plant can carry the same carbon cost as lignite-fired generation. Investors at this year’s Belgrade Energy Forum said they hope future amendments will exempt verified renewable imports, a change that would significantly improve the business case for clean energy projects aimed at EU buyers.

A path to exemption

The longer-term way out is for Western Balkan countries to introduce carbon pricing that matches the EU’s and to integrate fully into the single electricity market, which would qualify them for an exemption. The Energy Community’s own readiness tracking suggests that goal is still some distance away.

For now, CBAM is doing what it was designed to do: making carbon-intensive power less competitive in Europe. It is also pushing the Western Balkans to develop deeper regional markets, look for new buyers to the east and build a stronger case for renewables. The region is adapting to the mechanism faster than many expected, and the pressure to decarbonise is rising with it.

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Turkey sets the pace

Turkey is setting the pace. The country has awarded 2.3 gigawatts of capacity in its annual round of wind and solar auctions, part of a broader push by Energy Minister Alparslan Bayraktar to accelerate the build-out of renewables. Ahead of the UN climate conference in Antalya, Bayraktar also unveiled Turkey’s National Energy 2040 plan, a long-term roadmap that will guide investment decisions in one of the region’s largest and fastest-growing power markets. Turkey has also announced plans to launch a carbon market, a move that will influence its industrial exporters as EU carbon rules tighten.

Serbia keeps nuclear option open

Serbia, meanwhile, is keeping its nuclear option open. France’s EDF will carry out four additional studies on nuclear energy for the country, building on earlier cooperation between Belgrade and Paris. Nuclear power remains a long-term prospect, given that Serbia still has a legal moratorium to unwind and decades of planning ahead, but the studies signal that the government sees nuclear as a possible replacement for its ageing lignite fleet. Serbia is also advancing wind projects such as Alibunar in the north-east, where SANY Renewable Energy has broken ground.

Hydrogen partnerships take shape

Hydrogen is moving from strategy documents to early partnerships. Romania’s gas transmission operator Transgaz has signed a memorandum with Japan’s Kawasaki Heavy Industries to develop hydrogen projects, with a project agreement as the next step. North Macedonia has completed its first national hydrogen study. Across Europe, electrolyser capacity is nearing 1 gigawatt, according to Hydrogen Europe, with a pathway towards 4 gigawatts by 2030, still well short of earlier ambitions but showing real progress.

Market rules and larger projects

Market infrastructure is developing alongside new generation. North Macedonia held its first auction for guarantees of origin, giving renewable producers a new revenue stream and buyers a way to prove the source of their electricity. Albania has allowed negative power prices and started trading guarantees of origin, bringing its market rules closer to EU practice. These changes are less visible than new power plants, but they matter to the corporate buyers and lenders who finance projects.

Scale is also increasing. Romania’s Dama Solar project, at 1.3 gigawatts, is set to become the largest photovoltaic plant in Europe outside Turkey, and Montenegro’s state utility EPCG is developing a 639 megawatt portfolio of solar, wind, battery and hydropower projects. Projects of this size were rare in the region only a few years ago.

Challenges remain, including grid congestion, slow permitting and uneven regulation from one country to the next. Serbia has delayed parts of its renewables connection process until 2029, and investors across Central and Eastern Europe continue to cite regulatory uncertainty as a key risk.

Taken together, these developments point to a region that is no longer just adding solar capacity but building a more diverse energy system. Wind, storage, nuclear and hydrogen are all part of the planning now, and countries that offer clear, stable rules will attract most of the capital needed to deliver them.

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What is driving prices

The causes are familiar. Gas prices have been climbing since the spring, when the conflict in the Middle East pushed up oil and LNG costs, and a stretch of weak wind across the continent has left gas-fired plants setting the marginal price for more hours of the day. In a region where hydropower, lignite and imports have to fill the gaps left by intermittent solar, any squeeze on gas quickly shows up in power bills.

Brussels is sounding the alarm. EU Energy Commissioner Dan Jørgensen warned at the end of October that Europe could be heading into another energy crisis and a difficult winter for households and industry alike. Days later, ministers from EU member states and Energy Community contracting parties gathered in Zagreb for the Central and South-East European Energy Connectivity (CESEC) high-level group, and the message coming out of the meeting was blunt: regional cooperation on security of supply is no longer optional, it is urgent.

Governments face pressure

Romania offers a clear picture of what is at stake. The country recorded the steepest rise in household electricity prices anywhere in the EU in the first half of 2026, after the removal of earlier price caps. Its new prime minister, Luca Niculescu, and energy minister, Dumitru Chisăliță, have both publicly flagged security-of-supply risks for the coming months. For a government that has just taken office, energy affordability has quickly become a political test as well as an economic one.

Elsewhere, governments are reaching for familiar tools. Serbia has repeatedly extended its cap on electricity prices for businesses, and several Balkan states moved earlier this year to cushion the jump in fuel prices. These measures buy time, but they also shift costs onto state utilities and budgets that are already stretched, and they blunt the price signals that should be attracting investment in new capacity.

A more volatile power system

What makes this winter different from 2022 is the shape of the system. Southeast Europe now has far more solar capacity, a fast-growing fleet of batteries and better-coupled markets. Those assets help in the middle of the day, but they do little on cold, still evenings when demand peaks. The result is a market with deeper price swings: cheap, sometimes negative prices at noon and expensive evenings. Croatia, for example, has seen the number of hours with negative prices rise sharply, even as evening peaks climb.

Managing market exposure

For businesses, the practical lesson is that exposure to the spot market has become a strategic risk rather than a procurement detail. Industrial consumers that locked in long-term contracts or invested in on-site generation are better placed than those buying day to day. Utilities with flexible assets, from pumped hydro to batteries, stand to capture significant value from volatility.

The coming months will show whether the region’s investments in interconnection and flexibility have made it more resilient than four years ago. The early signs are mixed. Southeast Europe is better equipped than it was in 2022, but it is still heavily exposed to gas prices it cannot control, and this winter will test whether governments can coordinate before the next price spike rather than after it.

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EU ban sets the deadline

The deadline driving the change is fixed in EU law. The bloc has adopted a legally binding ban on Russian gas, with Russian LNG imports set to end by the close of 2026 and pipeline supplies by autumn 2027. For EU members such as Bulgaria, Greece, Croatia and Romania, the question is no longer whether to switch suppliers but how fast the infrastructure can be ready. For Energy Community countries outside the EU, the pressure is less formal but just as real.

US LNG deals take shape

Washington has moved quickly to fill the gap. In February, twelve countries from Central and Eastern Europe and the Balkans agreed with the United States to expand access to American LNG and to remove regulatory barriers to gas imports. That framework has since produced concrete deals. Albania’s Albgaz signed a 20-year supply agreement with Aktor LNG USA, with gas initially routed via Greece’s Revithoussa terminal and the Trans Adriatic Pipeline. Croatia and Bosnia and Herzegovina agreed to build the long-discussed Southern Interconnection, a roughly 160-kilometre pipeline that would link Bosnia to the LNG terminal on the island of Krk, whose capacity has already been expanded to 6.1 billion cubic metres a year.

The other key route runs north from Greece. The Vertical Gas Corridor, designed to carry gas from Greek terminals through Bulgaria and Romania towards Ukraine and Central Europe, is gaining a second branch. In September, North Macedonia and Serbia signed a memorandum to join an extension that would bring US LNG into the Western Balkans, and Bulgaria expects key sections of its part of the corridor to be completed by the end of this year.

Serbia’s difficult position

Serbia remains the most complicated piece of the puzzle. Its oil company NIS, majority-owned by Gazprom Neft and Gazprom, has operated under US sanctions for more than a year. A sale of the Russian stake to Hungary’s MOL was agreed in principle in January, but the deal has dragged on through repeated licence extensions. At the end of October, Serbian officials said they would travel to both Washington and Moscow for talks on gas supply and NIS, acknowledging that the country’s crude and gas security depends on short-term decisions made in both capitals.

Costs and climate concerns

The shift is not without critics. The European Commission and environmental groups such as CEE Bankwatch have questioned whether new pipelines in the Western Balkans risk locking the region into decades of gas dependence just as the EU plans to reduce fossil fuel use. There are also commercial questions. Bosnia consumes only about 250 million cubic metres of gas a year, while the Southern Interconnection is designed for around 1.5 billion, and officials in the region have noted that LNG often costs more than gas delivered through TurkStream.

For investors and energy companies, the direction is nonetheless clear. Terminal capacity in Greece and Croatia, interconnectors linking national grids and gas-to-power projects designed to back up renewables are where the near-term capital is flowing. The companies that secure long-term capacity on these routes will shape regional trade for years.

The Balkan gas market is ending its reliance on one dominant supplier and moving to a model built on LNG, interconnection and new commercial relationships. Whether that brings lower prices as well as greater security will depend on how quickly the infrastructure is built and how firmly the region holds to its longer-term climate commitments.

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Why storage is taking off

The economics are simple. The region has some of the best solar resources in Europe and has added gigawatts of photovoltaic capacity in a short time. That solar fleet floods the market at midday, pushing prices down and sometimes below zero, while evening demand still depends on hydropower, gas and imports. The gap between cheap afternoon power and expensive evening power is exactly what batteries are built to capture. BloombergNEF estimated that Romania’s average two-hour day-ahead price spread reached EUR 151 per megawatt-hour in 2025, and ENTSO-E has identified Southeast Europe as one of the most valuable places on the continent to invest in storage.

The flow of projects reflects those returns. In recent weeks, Sunrise Europe secured a building permit in Montenegro for its Dubrovsko solar plant paired with a 400 megawatt-hour battery. NextGrid Energy installed Croatia’s first standalone battery energy storage system, a milestone for a market that is still finalising its regulatory framework for storage. Albania’s energy minister has confirmed that the next solar auction, expected by early 2027, will include battery storage as part of the offer.

Romania remains the regional leader. Premier Energy is building a 200 megawatt, 400 megawatt-hour system in the east of the country, Jantzen Renewables has a permit for a 360 megawatt battery, and the government has set aside EUR 150 million to support standalone storage. Greece’s PPC and Metlen have joined forces to develop up to 3 gigawatt-hours of storage across the region, while Bulgaria’s rapid battery build-out has helped turn the country into a much larger net exporter of power.

Policy and market design

Policy is moving in the same direction. A leaked European Commission plan points to an EU-wide target of 200 gigawatts of energy storage by 2030, a goal that would make storage central to grid planning rather than an add-on. Not every market is following that logic yet. Germany’s first capacity auction, completed this week, awarded all 5.16 gigawatts to gas-fired plants, with batteries effectively excluded until a later phase. The result is a reminder that market design, not technology, often decides which assets get built.

Risks for investors

The risks are real. Battery revenues depend heavily on price volatility, and as more storage connects, the spreads that make early projects so profitable will narrow. Investors have also raised concerns about potential EU restrictions on Chinese inverters and components, which dominate the supply chain. Grid connection queues, already long in countries such as Serbia, could slow projects that look attractive on paper.

What comes next

Even so, the direction is unlikely to change. Every new solar park in the region increases the value of storage, and governments that once saw batteries as experimental now include them in auctions and subsidy schemes. Early movers that secure grid connections and sites now are positioning themselves for a market that could look very different by the end of the decade.

Southeast Europe’s energy transition began with solar panels. Its next phase will be built around batteries, and the companies that understand how to trade flexibility, not just generate electricity, are likely to come out ahead.

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Revenue and costs

Total income rose 13.5% to €28.6 million from €25.2 million, while expenditure increased to €25.4 million from €24 million. The difference lifted earnings despite a higher overall cost base.

The company employed 636 people at the end of September, compared with 654 a year earlier. The results indicate an improved operating margin during the first three quarters, although the reported figures do not establish how much of the gain came from production volumes, prices or other revenue components.

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Renewable energy rules

The complaints concern implementation of the EU Renewable Energy Directive, under which relevant national frameworks were due by June 30, 2021. In Croatia, ClientEarth argues that restrictive rules and inadequate support have undermined the commercial viability of energy communities. Three have been registered, but one reportedly ceased operating and the other two have struggled to develop sustainable business models.

In Bulgaria, the criticism focuses on lengthy administrative procedures. The Burgas Energy Community, whose approximately 130 members financed solar panels serving a public swimming pool, illustrates the potential of collective investment but also the regulatory burden faced by participants. ClientEarth previously initiated comparable action involving Poland and Hungary, bringing the number of targeted countries to four.

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Rising grid costs

Grid operators also spent €5.4 billion on redispatching, more than 25% above the previous year. These interventions, which change generation schedules to relieve overloaded lines, affected approximately 70 TWh of electricity. Without sufficient network investment, annual redispatch expenditure could exceed €100 billion by 2040, according to the regulatory projections described in the report.

The burden is increasingly visible in consumer bills. Average network-related charges rose from €60/MWh in 2019 to €84/MWh in 2025, accounting for approximately 28% of the average European household electricity bill. Congestion revenues remain below the almost €20 billion recorded during the 2022 energy crisis, but the continuing growth in grid-management costs points to a structural infrastructure challenge rather than a temporary price shock.

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Project design and funding

The project would connect a new reservoir at Yadenitsa with the existing Chaira reservoir through a reversible pressure tunnel and additional hydraulic infrastructure. Greater water storage could allow longer pumping and generation periods, strengthening the system’s ability to balance variable renewable production. Interested contractors include groups from Bulgaria, Turkey, Greece, Austria and Spain.

State-owned utility NEK will prequalify applicants before negotiations and contractor selection. Funding remains unresolved. The development has EU Project of Common Interest status and may qualify for Connecting Europe Facility support of up to 50% of eligible construction costs. NEK submitted a financing application in September, with a decision expected in the second quarter of 2027. Bulgaria has separately approved state guarantees of up to €228 million.

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The reform is particularly important for wind and solar producers, whose actual output can differ from forecasts prepared a day earlier. Intraday trading can improve balancing decisions, create additional opportunities to trade surplus electricity and help participants manage short-term portfolio risk.

Integration with Italy

The country is also preparing electricity market coupling with Italy as part of wider integration with European wholesale markets. The government has reaffirmed its support for both initiatives, but has not specified a launch date for coupling with Italy. Implementation will therefore depend on completing the relevant market and operational arrangements.

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Restructuring and funding

The proposal would allow state-guaranteed working-capital loans through December 2029. EC Oltenia faces substantial carbon-compliance costs: expenses and provisions linked to emissions exceeded €390 million in 2025, close to 60% of annual turnover. The company surrendered 4.63 million CO2 allowances by the September 30 deadline, including about 1.1 million borrowed from a Trafigura subsidiary.

The Senate approved an additional €81 million allocation for allowances, while legislation also envisages a €180 million ministry capital contribution in the first half of 2027 and guarantees for loans of up to €195.8 million. Some financing measures remain unsettled, and the revised restructuring plan submitted in 2025 has not yet received European Commission approval.

Financial outlook

Oltenia forecasts its 2026 net loss narrowing to €109 million from €211 million, mainly through cost reductions. Revenue is expected to decline 23.3% to €630 million and expenses 27.7% to €735 million. Average employment is projected to fall from 7,950 to 6,509 as the company attempts to sustain operations while replacement generation capacity is delayed.

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Revising the project

The companies have established a joint project vehicle and plan to review capacity, configuration and construction costs rather than automatically retain the original design. Earlier proposals envisaged approximately 1,000 MW of installed capacity and expenditure exceeding €1 billion, but those estimates are more than 15 years old.

Financing remains a central challenge. Hidroelectrica has begun preliminary discussions with Romania’s Energy Ministry about possible support, including state aid for large-scale storage. The project could provide flexibility as wind and solar generation expands, pumping water when electricity is abundant and generating during tighter periods. Hidroelectrica is also examining another pumped-storage scheme and developing battery storage projects alongside modernization of existing hydropower assets.

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Deliveries begin for the project

The order covers Tongwei TNC 3.0 modules for the proposed 1.36 GW project. Deliveries have begun, with an initial shipment dispatched from the manufacturer’s Nantong facility in China. Once operational, the solar park is expected to generate approximately 1.8 TWh annually.

Rezolv is backed by investment firm Actis. The contract extends cooperation among the developer, its investor and Tongwei while highlighting the importance of overseas utility-scale orders for Chinese photovoltaic suppliers facing intense domestic competition and manufacturing overcapacity.

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Temporary tax flexibility

The authorization, approved by EU finance ministers under Article 19 of the Energy Taxation Directive, will be available for six months following formal notification. It would permit petrol duty to fall to €0.1395 per litre from €0.41759, and diesel duty to €0.105 per litre from €0.33.

The government does not plan to implement the cuts immediately. Instead, the exemption provides flexibility to respond if international oil prices rise sharply. Any future activation could moderate the impact of fuel-price increases on households, transport companies and other businesses.

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Wind and storage plans

The agreement, announced during the COP31 conference in Antalya, adds wind farms, battery storage and high-voltage direct-current transmission infrastructure to a partnership that began with 2 GW of solar projects. Saudi developer ACWA Power is preparing the initial solar investments in Sivas and the Taşeli area of Karaman province.

The proposed wind capacity would amount to roughly one-fifth of Turkey’s existing installed wind fleet. Storage and HVDC connections are intended to improve the integration and transport of variable generation. The wind projects remain at an early stage, however, and their locations, financing structures and construction timetables have not yet been disclosed.

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Coordinating clean energy investment

The Renewable Energy Acceleration and Clean Transition Platform, known as REACT, was introduced at COP31 in Antalya. It is not a standalone $300 billion fund; instead, it will coordinate investment opportunities across solar and wind generation, power networks, batteries, industrial electrification and domestic energy technology manufacturing.

Turkey is targeting 175 GW of combined wind and solar capacity by 2040, requiring major investment in generation and grid infrastructure. REACT brings together the Turkish Energy Ministry, EBRD and other development institutions, including the European Union, World Bank, International Finance Corporation, KfW and Climate Investment Funds. The EBRD says it has already invested more than €26 billion in Turkey, largely through private-sector operations.

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The company disclosed the project on 11 November and indicated a potential operating start between 2028 and early 2029. The announced amount is an estimated development investment, not evidence that financing has closed or that construction contracts have been signed. A final permitting, equipment-procurement and grid-connection timetable was not established in the disclosure.

Albania seeks a broader energy mix

The project comes as Albania seeks a broader mix of generation to reduce dependence on hydrological conditions. A larger share of wind and solar capacity could help diversify domestic production, although output from either technology remains weather-dependent and may not coincide with periods of peak demand.

At an indicative €36 million for 20 MW, the proposal represents a capital-intensive investment that will require careful assessment of turbine productivity, site access, construction logistics and the cost of connecting to the electricity network. The estimate should not be interpreted as an awarded contract value or a guaranteed final budget.

Potential effects on the market

For electricity market participants, additional wind supply could eventually change the timing of domestic generation and demand for balancing or short-term imports. Actual effects will depend on how the project is scheduled, whether it secures a long-term electricity sales arrangement and the flexibility available from Albania’s hydroelectric fleet.

Equipment manufacturers, civil contractors, grid engineers and environmental consultants could benefit if the project progresses through financial close and procurement. Lenders will need evidence of wind-resource quality, land rights, environmental permissions and bankable revenue arrangements before treating projected output as dependable cash flow.

Projects at different stages

The proposal is separate from the previously announced Spille project backed by Austria’s VERBUND, for which Nordex disclosed an 84 MW turbine order. The two projects are at different commercial stages and should not be combined when assessing committed capacity or capital spending in Albania.

EU Green Energy’s next major milestones are confirmation of permits, grid terms, the financing structure and an executable construction schedule. The plan demonstrates growing developer interest in Albania’s wind resources, while its contribution to electricity supply remains contingent on completing those steps.

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The agreement was signed in Antalya during COP31 by the energy ministers of Azerbaijan, Turkey and Bulgaria and Georgia’s deputy prime minister and economy minister. It builds on earlier cooperation but represents a new government-level commitment to develop the Azerbaijan–Georgia–Turkey–Bulgaria route.

What the agreement covers

The framework addresses electricity transmission and supply, cross-border infrastructure, commercial and regulatory coordination and supporting fibre-optic communications. The partners also envisage designating transmission system operators to participate in a joint development structure. Those steps are preparatory: they do not amount to construction approval, a binding electricity-supply contract or the commissioning of additional transfer capacity.

For Bulgaria, the proposed route could eventually diversify the origins and directions of electricity imports and strengthen its role in regional transmission. For Turkey, it would reinforce the country’s position between the Caucasus and European power markets. Azerbaijan and Georgia would gain a potential new route to sell renewable electricity to buyers farther west.

Commercial prospects and requirements

The commercial proposition depends on more than constructing lines. Traders require compatible market rules, transparent capacity allocation, balancing arrangements, reliable scheduling and contracts defining who bears congestion and delivery risks. Buyers would also need to establish how electricity attributes and contractual evidence are recognised across jurisdictions.

The project could create demand for transmission engineering, power-system studies, substations, cable and line equipment, communications infrastructure and project-finance advisory services. It may also offer a future route for industrial companies seeking diversified electricity procurement. None of those commercial benefits should yet be treated as secured revenue.

Uncertainties and next steps

Important uncertainties remain over the investment budget, the precise route, permissible transfer capacity, ownership allocation and the financing of new infrastructure. The agreement itself did not establish an operational date or confirm an awarded construction package, and geopolitical and regulatory coordination will be material to delivery.

The next meaningful milestones will be transmission-operator mandates, feasibility and financing decisions, and the publication of a credible implementation timetable. Until then, the agreement is a strategic market-opening step rather than a new source of electricity already available to Southeast European buyers.

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Unit 2 returns to the grid

The operator expected Unit 2 to reach nominal output on 12 November. It also said that repair work on Unit 1 had been completed and scheduled the reactor’s reconnection for 12 November, with nominal power targeted for 13 November. Those output milestones remained forecasts when the company issued its 11 November statement, rather than confirmation that both reactors were operating at full capacity.

Unit 1 had disconnected on the evening of 9 November because of a technical problem in the conventional, non-nuclear part of the plant, only days after reconnecting on 6 November. Unit 2’s restart followed recovery of the river water level needed for safe operation. Nuclearelectrica said the work was conducted under established nuclear-safety procedures, with no impact on personnel or the environment.

Capacity and market impact

Cernavodă’s two units provide roughly 1,400 MW of installed capacity and normally supply around one-fifth of Romanian electricity demand. When both reactors are unavailable, suppliers must rely more heavily on replacement generation, imports or portfolio adjustments. The effect depends on the prevailing load, weather and availability of hydroelectric and thermal plants.

The recovery is significant for Romania’s trading relationships with Hungary, Bulgaria and Serbia. Interconnected markets can transmit changing generation expectations through wholesale prices, cross-border flows and balancing demand. Yet a reactor’s return cannot by itself explain movements in any single day-ahead auction, which also reflect consumption, renewable output, network congestion and fuel costs.

Reliability and outlook

For Nuclearelectrica, the sequence has implications for lost production, operational reliability and investor forecasts. For utilities and electricity-intensive industrial buyers, it highlights the distinction between contracted supplies and the physical assets expected to deliver the electricity. Short-term traders also face the risk of changing availability estimates as units move through synchronisation and power ramp-up.

The next test is sustained operation at nominal output, not grid reconnection alone. Until both units are confirmed stable, generation forecasts and the cost of replacement electricity will remain important variables for Romania and neighbouring power markets.

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Consumer protections and contracts

The legislation transposes provisions of Directive (EU) 2024/1711 and adds requirements intended to give customers clearer contracts and greater protection against sudden price changes. Parliamentary passage is a legislative milestone; publication of the final law and the timing of individual measures must be checked separately before provisions are treated as operational.

Under the reform, suppliers would be required to offer fixed-price electricity contracts of at least one year‘s duration alongside dynamic-price options, subject to the applicable conditions. The framework also strengthens supplier hedging and risk-management requirements, aiming to reduce the likelihood that wholesale price shocks are passed through abruptly or undermine retail providers’ ability to serve customers.

The bill introduces further safeguards for customers disputing electricity bills, including protection from disconnection while specified complaint-resolution procedures are pending. Public explanations of the measure refer to limited complaint periods of up to 90 days, rather than an unrestricted suspension of payment or disconnection rights. The treatment of vulnerable households remains subject to existing protections.

Another provision extends the period for which customers may be served by a supplier of last resort, from three months to at least six months. The reform also addresses renewable electricity sharing, allowing eligible households, smaller businesses and public bodies to participate in arrangements involving self-generated energy, within the framework’s technical and contractual conditions.

Impact on suppliers and customers

For suppliers, the new obligations could raise compliance, hedging and customer-service costs while increasing incentives to manage wholesale exposure through forward contracts. For independent retailers, the balance between consumer protection and the cost of capital will be important, particularly when prices are volatile and collateral demands rise.

For customers and industrial buyers, a broader choice of fixed and market-linked contracts can improve procurement planning, but the economics still depend on contract terms, consumption profiles and creditworthiness. Energy-sharing rules may eventually create opportunities for community operators, metering service providers and aggregators, subject to implementing regulations.

Implementation and market impact

The bill’s commercial impact will depend on the final published text, secondary regulation and enforcement by Greek authorities. Its importance lies in shifting risk management and consumer protection closer to the core design of the retail electricity market, rather than in changing the wholesale price on the day of passage.

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Hungarian portfolio details

The purchase was made through PPC Hungary Holding and includes five operating solar parks with a combined capacity of 82 MW. The rest of the portfolio is at different stages of development, meaning the headline capacity should not be confused with generation already in service. PPC also acquired the local project development team, gaining expertise in Hungarian permitting, commercial arrangements and grid-access procedures.

The completion is a material step beyond the strategic agreement announced on 7 August. That earlier agreement covered ABO Energy subsidiaries in both Hungary and Poland, with a combined portfolio exceeding 2 GW. Hungary’s contribution is the up-to-1.1 GW figure; the larger total does not describe Hungarian assets alone. PPC said completion of the Hungarian transaction finalised the broader acquisition process.

Strategic value and market risks

For PPC, the transaction is both an asset purchase and an investment in a development platform. Operating solar farms provide an existing generation base, while development rights and local personnel can help the utility evaluate future wind, solar and storage opportunities more quickly than building an organisation entirely from scratch.

Hungary’s electricity market offers exposure to industrial demand and trading links with neighbouring Central European and Balkan bidding zones. However, the value of a mixed renewable pipeline will depend heavily on which projects obtain final permits, economical grid connections, financing and viable sale arrangements. Delays in network reinforcement or changes in market-price forecasts could alter development priorities.

The acquisition also illustrates how utilities are using cross-border mergers and acquisitions to diversify generation portfolios and secure access to projects that may be difficult to originate independently. For engineering suppliers, lenders and contractors, the deal creates a larger prospective pipeline but not a commitment to build every asset.

Price and next steps

PPC did not disclose a transaction price in its completion announcement, making it impossible to infer the value paid per megawatt from the stated capacity. Investors should therefore distinguish the existing 82 MW operating base from prospective projects before calculating returns or regional market share.

The next indicators will be project-by-project investment approvals, grid access and commissioning timetables. The acquisition gives PPC a stronger position in Hungary, but construction execution and electricity-market economics will determine the portfolio’s eventual contribution to earnings.

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Expanding in-house production

Announced on 11 November, the programme increases the company’s manufacturing footprint to 34,450 square metres and includes a new 28,000-square-metre metal-box manufacturing unit and a 1,250-square-metre plastic-container unit. Sunlight said the investment means it can now meet about 85% of its requirements for key battery components and structural elements internally.

The expansion centres on four additional precision-manufactured products used in industrial batteries, including structural cases, containers, seals and connectors. It is a factory-capacity investment, not an announcement of newly commissioned grid-scale battery storage or a project selling electricity to a power market.

Supply-chain strategy

For Sunlight, increasing vertical integration can reduce dependence on external component suppliers and improve control over delivery times, quality standards and product design. That matters in a battery industry exposed to volatile raw-material prices, international competition and shifts in industrial and storage demand.

The company said the Kilkis programme strengthens its European manufacturing base. A higher proportion of internally sourced components could support customer service and continuity of production, but it does not guarantee lower costs in every market condition. The economic benefit will depend on utilisation rates, productivity, energy expenses and the cost of imported inputs that the group still purchases.

Commercial and investment outlook

The investment is also commercially relevant beyond Greece. Regional engineering contractors and equipment suppliers may find opportunities in factory expansion and automation, while industrial battery buyers across Europe gain another example of manufacturers building local capacity rather than relying entirely on overseas component supply.

For investors, the announcement provides a completed capital-spending milestone and a measurable degree of internal supply-chain coverage. It does not by itself disclose the expected return on the investment, operating margins or utilisation at the new production lines. Those outcomes will determine how much of the spending ultimately translates into stronger profitability.

The Kilkis expansion illustrates a second layer of Europe’s energy transition: manufacturing the equipment and components behind electrification and storage, rather than only deploying generating or storage assets. Its long-term value will depend on whether regional production can remain competitive at scale.

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Regional price movements

BELEN fell 13.3% to €299.16/MWh, leaving Montenegro €14.12/MWh above Serbia, compared with a €0.96/MWh discount on Wednesday. Montenegro also moved to an €8.25/MWh premium over Hungary, reversing the previous day’s €9.30/MWh discount.

The regional decline broadened towards Central Europe. Austria fell 22.6% to €268.97/MWh, Slovenia’s BSP/ADEX dropped 19.9% to €274.12/MWh, Croatia’s CROPEX declined 19.1% to €278.28/MWh, and Hungary’s HUPX lost 17.9% to €290.91/MWh. Romania’s OPCOM fell 16.3% to €295.18/MWh, while Bulgaria’s IBEX declined 17.0% to €289.56/MWh.

Prepared on 12 November 2026 at 08:18 CET, this article compares cleared day-ahead prices for 00:00–24:00 CET on 12 November with the equivalent delivery period on 11 November. Thursday’s full-day operating and balancing outcomes remain incomplete. Wednesday was Serbia’s Armistice Day public holiday, making Serbian demand comparisons different from a normal working-day sequence.

Greece’s HEnEx fell another 19.6% to €225.09/MWh, while Albania’s ALPEX declined 15.5% to €282.91/MWh. North Macedonia’s MEMO dropped 12.7% to €305.58/MWh, remaining the most expensive market among the reviewed SEE exchanges.

MEMO’s lower price coincided with slightly higher auction activity. Traded day-ahead volume for 12 November delivery reached 6,093.5 MWh, up 1.2% from 6,018.5 MWh for Wednesday. That provides a verified volume comparison for North Macedonia; comparable daily volume figures were unavailable across the other exchanges.

The second consecutive regional decline substantially reduced procurement costs from Tuesday’s levels. Serbia was approximately 21% below its 10 November average, while Hungary was about 27% lower. Montenegro’s smaller cumulative decline left it comparatively expensive within the regional market.

Cross-border incentives changed accordingly. Hungary’s premium over Serbia narrowed to €5.87/MWh from €8.34/MWh, while its premium over Greece contracted to €65.82/MWh from €74.61/MWh. These daily averages indicate changing commercial incentives, but do not establish that transmission capacity was available in the relevant delivery intervals.

Italy’s IPEX North zone fell 13.3% to €247.35/MWh. Montenegro retained a €51.81/MWh premium over that benchmark, down from €59.92/MWh. The spread remains material, although executable returns across the Adriatic depend on the Italian landing-zone price, losses and transmission-rights costs.

Maximum prices also eased. Serbia’s highest quarter-hour fell to €343.01/MWh from €475/MWh, and Montenegro’s to €361.04/MWh from €475/MWh. Hungary and Romania retained higher maxima of €417.53/MWh and €421.27/MWh, respectively, leaving some delivery intervals substantially more expensive than the daily averages.

Nuclear availability

Romania recorded a concrete supply improvement when Nuclearelectrica confirmed Cernavodă Unit 2 reconnected on 11 November. The company expected nominal output on 12 November, but full-power operation had not been independently verified at preparation time. Reconnection therefore marks an achieved milestone, while completion of the ramp-up remains an operating assumption.

The outlook for Unit 1 changed twice on Wednesday. An initial disclosure forecast reconnection on Thursday, but a later filing published at 17:24 Romanian time on 11 November postponed it to 13 November, with nominal output expected on 14 November. The later timetable supersedes the earlier announcement and remains a forecast.

Romania’s reported net imports averaged approximately 1,661 MW on 11 November, down from about 1,983 MW on 10 November. Hungary’s imports declined to approximately 1,965 MW from 2,100 MW, while demand eased to 6,037 MW from 6,155 MW. These completed-day observations show some easing in external supply requirements, although they do not establish how Thursday’s balance will settle.

Regional supply and flows

Bosnia and Herzegovina’s reported net exports increased to approximately 212 MW from 193 MW. Serbia’s operating series remained incomplete, with 22 of 24 hourly observations available for Wednesday, preventing a reliable full-day comparison. Fresh comparable Montenegrin generation and demand figures were also unavailable.

Greece supplied a stronger renewable contribution. Reported wind generation more than doubled to approximately 2,515 MW on 11 November from 1,133 MW, while gas-fired output declined to 2,995 MW from 3,799 MW. Net exports increased to approximately 1,781 MW from 1,390 MW, despite higher domestic demand.

Greek physical-flow records for 11 November showed net exports of 16,267 MWh to Bulgaria, 14,853 MWh to North Macedonia, 7,848 MWh to Albania and 3,937 MWh to Turkey. Exports towards Bulgaria, North Macedonia and Albania increased from Tuesday, while the Turkish flow declined. Physical exchanges should be distinguished from commercial schedules and available transmission capacity.

For 12 November’s Greek local operating day, the latest renewable forecast averaged approximately 4,733 MW, against a separate demand forecast averaging 5,345 MW. These forecasts cover 00:00–24:00 EET, equivalent to 23:00 CET on 11 November through 23:00 CET on 12 November. The reported aggregate reservoir filling rate was 35.7% at midnight Greek time, compared with 35.5% a day earlier. These levels describe storage conditions, rather than guaranteeing a particular hydro dispatch.

Storage and market outlook

Storage development continued alongside the operating-market changes. An update published on 11 November reported MY Enerji’s 10.22 MWp Mihăești solar plant in commercial operation, with its associated 30 MWh battery on site and energisation targeted for late November, subject to testing and grid approvals. The battery should therefore remain outside operating-capacity assumptions until commissioning is confirmed.

No negative-price intervals were identified in the reviewed SEE day-ahead series for 12 November. Greece’s minimum nevertheless returned to €0.01/MWh, from €164.63/MWh on Wednesday. Verified comparable intraday volume-weighted prices, settled imbalance charges and balancing procurement costs remained unavailable. Specific border restrictions and congestion costs could not be quantified from the retrieved evidence.

For buyers, the latest auctions provide substantial relief from early-week prices. For traders, Montenegro’s move above Serbia and Hungary changes the relative value of local supply and cross-border positions. For investors, the combination of near-zero Greek intervals, expensive eastern peaks and staggered nuclear recovery reinforces the importance of dispatch flexibility, connection rights and realistic commissioning dates when assessing revenues.

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Regional prices and spreads

Hungary’s HUPX base price dropped €63.5/MWh to €290.91/MWh, while Serbia’s SEEPEX fell €61/MWh to €285.04/MWh. Romania declined to €295.18/MWh, Bulgaria to €289.56/MWh, Croatia to €278.28/MWh and Slovenia to €274.12/MWh. Montenegro remained relatively expensive at €299.16/MWh, while North Macedonia was the regional high at €305.58/MWh.

The more important trading signal came from Germany. German day-ahead power collapsed by €117.6/MWh to just €199.04/MWh, pushing the Hungary-Germany spread to €91.87/MWh, up more than €54/MWh in a single day. Greece was also substantially cheaper than the northern Balkan markets at €225.09/MWh, leaving Hungary at a premium of almost €66/MWh to Greece.

That divergence matters more than the headline fall in SEE prices. The region became cheaper compared with the previous session, but it remained significantly disconnected from lower-priced Germany. The result is a market in which outright prices can fall quickly while congestion value and cross-border spreads remain elevated.

Supply and demand ease

Regional fundamentals simultaneously became more comfortable. Combined Hungary and SEE consumption fell to 35,293 MW from 35,694 MW, while generation increased to 32,171 MW from 30,959 MW. Net imports consequently fell to 3,122 MW, down from 4,735 MW, while imports from the Austria-Slovakia core dropped to 2,258 MW from 3,721 MW.

Warmer temperatures contributed to the easing. The regional temperature indicator increased to around 14°C, while consumption fell by about 400 MW. The combination of softer demand and higher domestic generation reduced the need to pull expensive power into SEE from Central Europe, even as limited transmission capacity prevented the region from fully benefiting from the much lower German market.

National balances improve

Serbia’s balance also improved. Average consumption increased slightly to 4,179 MW, but generation recovered to 3,808 MW, cutting the country’s net import requirement to about 372 MW from 574 MW a day earlier. Serbia’s day-ahead price nevertheless remained at €285.04/MWh, almost €86/MWh above Germany.

Montenegro showed an even stronger physical improvement. Average generation rose to about 407 MW against consumption of 403 MW, moving the system from a 62 MW net-import position on November 11 to a marginal 3 MW net export. Yet BELEN still cleared at €299.16/MWh, above both Serbia and Hungary. The combination suggests that Montenegro’s small market and its cross-border opportunity cost remain important price-setting factors even when the domestic physical balance is broadly neutral.

Forward risk remains

The forward market offered little evidence that the underlying regional risk premium has disappeared. Hungarian December power rose €5/MWh to €252/MWh, while Week 48 gained €6.5/MWh to €253.5/MWh. Austrian CEGH gas increased to €88.68/MWh, EU carbon allowances rose to €89.56/tonne, and December gas and coal contracts also advanced.

The November 12 session therefore looks more like a short-term correction from extremely elevated spot levels than a structural normalization of SEE electricity prices. Lower demand and stronger domestic output reduced imports and pulled regional prices down, but the nearly €92/MWh Hungary-Germany spread shows that available cross-border capacity remains the decisive constraint.

For Serbia and Montenegro, the immediate market signal is favorable on the physical side: import dependence eased materially. For traders and industrial buyers, however, the persistent premium to Germany means that congestion, interconnection availability and regional generation outages remain at least as important as the direction of European benchmark prices.

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Croatia’s rising import needs

Croatia’s net electricity imports rose 41.44% to 116 GWh in November 2-8 despite a substantial increase in variable renewable generation. Combined wind and solar output increased 44.6%, mainly on stronger wind production.

Hydropower generation also increased 24.22%, while thermal generation rose 10.04%. Nevertheless, Croatia’s electricity demand climbed 6.50% and its weekly day-ahead price advanced 5.76% to €286.53/MWh. The figures show simultaneous growth in several domestic supply sources and import requirements.

Romania’s high prices and imports

Romania recorded the highest weekly average day-ahead electricity price among the report’s core Southeast European markets in November 2-8, at €293.33/MWh. Its November 11 day-ahead price reached €352.56/MWh, the highest in the cited daily comparison.

Net imports increased 24.18% to 59.85 GWh, even as thermal production rose 7.95%, driven mainly by coal and lignite. Variable renewable generation also increased 33.4%, while hydro output slipped 4.15%.

Imports reflect a complex balance

Croatian net imports rose 41.44% to 116 GWh, while Romanian imports increased 24.18% to 59.85 GWh. Italy remained the largest net importer in the covered group, although its net purchases declined sharply to 369.71 GWh.

The report does not isolate plant outages, bilateral contract flows or hourly scheduling decisions. Those factors need to be tested before attributing higher imports to a single cause; the immediate story is the complexity of Croatia’s weekly supply balance.

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Power prices diverge from gas

Southeast European power prices rose in the first full week of November even as European benchmark gas futures retreated, highlighting the limits of using gas prices alone to forecast regional electricity costs. The report places the weekly TTF average at €90.16/MWh, down 8.8%, while the eight-market unweighted power average increased 3% to €256.16/MWh.

The power market was responding to a different combination of drivers: regional consumption increased 5.73%, solar output declined 1.7%, and hydro production weakened in most markets outside Türkiye. Gas-fired power output nevertheless climbed 18.41%, showing that plants can run harder even when the fuel benchmark declines.

Storage and shipping risks

European gas storage was reported at around 74% full in early November, leaving winter supply more sensitive to withdrawals, LNG arrivals and pipeline deliveries. At the same time, TTF futures retreated sharply during November 2-8.

The report places the weekly TTF average at €90.16/MWh, down 8.8%. It also identifies Middle East shipping risks and uncertainty surrounding the Strait of Hormuz as potential volatility drivers, rather than as verified interruptions to supply.

LNG flows shift across the region

LNG inflows into Croatia increased 58% week on week to 627.65 GWh during November 2-8, making the country the standout growth market among three LNG entry points detailed in the report.

Italy received 3,129.60 GWh, an increase of 2.60%, while Greek LNG inflows declined 7.3% to 252.94 GWh. The differences show how import patterns can shift substantially between neighbouring gas systems within a single week.

Resilience remains the priority

For Southeast European importers, the immediate issue is resilience: adequate physical delivery and flexibility may matter more than a single week’s price decline if temperatures fall or international cargo availability tightens.

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Wind and solar diverge

Wind production climbed 18% to 2.09 TWh, while solar slipped 1.7% to 1.09 TWh. Türkiye contributed the largest absolute increase in variable renewables; Greece, Romania, Bulgaria and Croatia also gained. Italy’s combined wind and solar output fell 25%, while Serbia’s reported variable renewable output declined 48.8%.

The divergence shows why regional aggregate renewable growth cannot by itself explain local clearing prices. Timing, geography, hydro conditions and the dispatchable generation needed to cover residual demand remain decisive.

Hydropower masks regional declines

Hydropower production was virtually unchanged across the report’s eight-market group in November 2-8, but that headline concealed a broad decline outside Türkiye. Output in the seven other markets fell about 12.2% combined.

Serbian hydro production dropped 21.70%, Greece fell 26.97%, Bulgaria declined 8.11% and Romania lost 4.15%. Italy registered the largest absolute decline, down 65.99 GWh. Türkiye’s 4.77% increase to 1.89 TWh largely offset the regional weakness.

Thermal generation rises

Thermal electricity generation in the report’s Southeast European coverage rose 13.15% to 8.22 TWh in November 2-8, outstripping the 5.73% increase in demand. Gas-fired output rose 18.41% to 5.14 TWh, while coal and lignite generation increased 5.37% to 3.09 TWh.

Italy accounted for the largest increase: thermal output rose 40.90% to 3.33 TWh, with gas generation adding 964.43 GWh. Hungary, Romania, Bulgaria, Croatia and Serbia also increased thermal generation, though their technology mixes differed. Türkiye moved in the opposite direction as gas-fired output declined.

Flexibility as winter load rises

The week is a snapshot rather than a long-term forecast. Still, it highlights the commercial importance of flexible thermal capacity, hydro management, storage and interconnection as winter load rises.

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Demand and generation

Electricity demand across the report’s eight-market group rose 5.73% to 16.91 TWh. Although wind and solar output increased 10.4%, hydro supply fell in most markets outside Türkiye and thermal plants were called on more heavily. Gas-fired generation rose 18.41%, lifting overall thermal production by 13.15%.

Prices converge

A cluster of Southeast European wholesale power markets moved closer together in the week of November 2-8, even as prices rose. Romania, Bulgaria, Serbia and Hungary all averaged between €290.98/MWh and €293.33/MWh, while Croatia traded at €286.53/MWh.

Across the seven markets excluding Türkiye, the difference between the highest and lowest weekly averages narrowed from €32.22/MWh to €22.66/MWh. Greece rose 6.13% and Croatia 5.76%, faster than the already more expensive central Balkan markets.

Trade flows shift

Greece increased net electricity exports by 10.79% to 230.87 GWh in November 2-8, even as demand rose and its wholesale price climbed to €270.67/MWh. Its position contrasted with Croatia and Romania, both of which increased net imports.

Croatian net imports rose 41.44% to 116 GWh, while Romanian imports increased 24.18% to 59.85 GWh. Italy remained the largest net importer in the covered group, although its net purchases declined sharply to 369.71 GWh.

Market outlook

Romania recorded the highest weekly average day-ahead electricity price among the report’s core Southeast European markets in November 2-8, at €293.33/MWh. Its November 11 day-ahead price reached €352.56/MWh, the highest in the cited daily comparison.

For market participants, cross-border opportunities increasingly require granular assessment of capacity auctions, congestion, hourly clearing prices and balancing exposures. A narrow weekly average is a signal to investigate, not proof of a permanently integrated price zone.

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Regional price signals

Wholesale electricity prices across several Southeast European markets approached €290-293/MWh during November 2-8, providing an important external price signal for Montenegro’s hydro-dependent electricity system. The underlying report does not publish Montenegro-specific generation, trading or day-ahead prices.

Regional hydro production outside Türkiye declined by about 12.2%, while demand and thermal output rose. In such conditions, dispatchable hydro can have significant commercial value when generation can be timed to expensive hours, subject to reservoir, environmental and system constraints.

Flexibility and investment

Southeast European electricity prices increased in November 2-8 despite an 8.8% decline in TTF gas futures. The divergence illustrates the importance of generation timing and flexibility for potential wind, solar and battery investments in Montenegro.

Wind and solar output increased regionally, but solar slipped overall and hydro weakened outside Türkiye. A battery may be able to shift low-price generation into higher-price hours, while wind and solar revenues depend on the hourly capture price rather than the weekly wholesale average.

Montenegro-specific data needed

For Montenegro, the investment and operating question is not whether regional prices are high in aggregate, but whether domestic hydro assets can capture peak-hour value without compromising water management or security of supply. That requires Montenegro-specific hourly generation and trade data.

The report provides no Montenegro-specific battery revenue, project cost or grid-connection data. Any bankability conclusion would therefore require local price curves, congestion forecasts, balancing rules and financing assumptions.

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Prices move closer together

A cluster of Southeast European wholesale power markets moved closer together in the week of November 2-8, even as prices rose. Romania, Bulgaria, Serbia and Hungary all averaged between €290.98/MWh and €293.33/MWh, while Croatia traded at €286.53/MWh.

Across the seven markets excluding Türkiye, the difference between the highest and lowest weekly averages narrowed from €32.22/MWh to €22.66/MWh. Greece rose 6.13% and Croatia 5.76%, faster than the already more expensive central Balkan markets.

Hourly average electricity price curves for November 2-8 show pronounced evening peaks in several Southeast European markets, with charted prices rising above roughly €330/MWh and, in some cases, approaching €350/MWh. Those peaks were materially higher than weekly averages around €270-293/MWh.

Hourly volatility drives opportunity

For battery energy storage systems, the relevant commercial opportunity lies in the difference between charging and discharging prices, after losses, fees and operational limits. The chart illustrates potential volatility, but does not provide a complete hourly revenue model or evidence of achievable battery returns.

Romania, Bulgaria, Hungary and Serbia clustered near €291-293/MWh, while Greece and Croatia recorded the strongest weekly price gains. This alignment changes the headline map of regional pricing but says less about the hourly differences that determine actual trading margins.

Test the investment case

Investors should test hourly spreads over longer periods, balancing market access, grid charges, degradation and capacity constraints before treating the November pattern as a bankable base case.

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