The new regulation extends the existing price-control framework for 95-octane petrol, diesel, and heating oil for an additional six months, replacing the previous system that was due to expire on 15 June. Authorities stated that the measure is aimed at preserving market stability and ensuring greater predictability for consumers regarding fuel costs.

Under the updated rules, fuel prices will continue to be determined using a formula that tracks movements in international oil markets and fluctuations in the euro–dollar exchange rate. The calculation will remain on a weekly basis, a mechanism introduced earlier this year to better reflect short-term market changes. At the same time, the government has adjusted the methodology for calculating biofuel-related costs in diesel and revised transport cost assumptions.

Alongside these changes, the government has increased the maximum permitted margins for fuel retailers. From Tuesday, distributors will be allowed to charge up to €0.115 per liter for petrol, diesel, and heating oil, replacing previous caps that were mostly below €0.10 per liter.

According to government estimates, the revised pricing model is expected to raise the retail price of gasoline by around 2 eurocents per liter, while diesel prices are projected to increase by 6 to 7 eurocents per liter. Heating oil is expected to become roughly 4 eurocents per liter more expensive.

The regulation will continue to apply only to fuel sold outside the motorway network, while prices at petrol stations located on highways and expressways will remain fully market-driven.

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According to information released by the Romanian Government, the project is currently undergoing an inter-ministerial assessment that evaluates its economic viability, environmental impact, and potential effects on Romania’s electricity system. Officials have stated that the country remains generally supportive of the initiative, although no final decision has yet been made as the review process continues.

The renewed attention surrounding HPP Đerdap 3 follows shortly after the US Embassy in Belgrade launched a call for expressions of interest aimed at attracting international participation in the project. This marks another step forward for a scheme that has been discussed for decades but has not yet entered the construction phase.

Planned as a large-scale pumped-storage facility on the Danube River, the project would have an installed capacity of approximately 2,400 MW, with the possibility of integrating an additional 400 MW of renewable energy sources, including wind and solar power. Current estimates place the investment value at around €2.6 billion, with full completion targeted for 2038.

The project is based on cooperation between Serbia and Romania and has generated significant debate on both sides of the border. Discussions have focused not only on its role in supporting future energy storage and grid balancing needs, but also on its potential environmental consequences.

Romanian institutions are paying particular attention to how the new facility could affect the operation of the existing Iron Gates I and Iron Gates II hydropower plants, which have been jointly managed by Serbia and Romania for decades. Any impact on these strategically important assets is considered a key factor in the ongoing assessment.

Several major international companies have shown interest in the project over the years, including Bechtel, which participated in preparatory technical studies and early development activities. As regional electricity systems increasingly require large-scale energy storage solutions to integrate growing renewable capacity, Đerdap 3 is being viewed as a potentially transformative infrastructure project.

However, due to its technical complexity, environmental sensitivity, and cross-border coordination requirements, the final decision-making process is expected to remain lengthy and highly detailed.

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According to government data published in 2024, the state is currently involved in ten court proceedings initiated by concession holders whose contracts were either terminated or allowed to expire. Most of the lawsuits seek not only reimbursement of already completed investments but also compensation for lost future profits, which investors argue they would have earned over concession periods extending up to three decades.

The majority of cases stem from decisions taken after the change of government in 2020–2021, when authorities unilaterally terminated several concession agreements. Only one dispute relates to a previously negotiated termination involving the Dekar-Hidro project.

The first court rulings have already begun to emerge. In the case involving BB Hidro, the court awarded compensation for part of the claimed direct damages but rejected a request for more than €1.4 million in lost profit compensation.

Government records show that the disputes involve projects located on numerous watercourses, including the Bukovica, Đurička, Komaraca, Bistrica, Muriška, Ljeviška, Trepačka, Slatina, Reževića rivers, as well as the Crnja river. The lawsuits are distributed across several investor groups rather than concentrated within a single network.

Publicly available information suggests that at least three major investor clusters are involved. These include companies connected to Florin Krasniqi and Triangle General Contractors, another group involving Plava Hydro Power and associated partners, and a third network linked to Hydra MNE, Igma Energy, and several domestic investors.

The legal proceedings are unfolding against a backdrop of long-standing public criticism of the small hydropower sector. Critics have argued that economic benefits were largely captured by concession holders, while local communities saw limited gains despite the environmental impact of the projects.

Because most lawsuits rely heavily on claims for lost profits rather than only reimbursement of invested capital, analysts believe the potential financial exposure for the state could be substantial. As the cases progress through the courts, they are increasingly seen as one of the most significant legal and financial challenges arising from Montenegro’s decision to reverse its earlier small hydropower development policy.

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Under the revised agreement, Atlantic-SEE will double the volume of liquefied natural gas it purchases from Venture Global. Starting in 2030, the Greek joint venture is expected to receive at least 1 million tons of LNG annually over a 20-year contract period, strengthening long-term supply visibility.

The expanded arrangement supports Atlantic-SEE’s broader strategy to import LNG into Greece and distribute it across Central and Eastern Europe. The company, formed by Aktor Group and DEPA Trade, plans to rely heavily on the Vertical Gas Corridor, an expanding infrastructure network designed to diversify regional gas routes and reduce dependence on traditional suppliers.

The deal reflects a wider European shift toward long-term LNG contracting, as energy companies respond to ongoing market volatility and geopolitical uncertainty. Securing fixed volumes has become a key priority for buyers seeking protection from fluctuations in the spot gas market.

A central role in this supply chain will be played by the Alexandroupoli LNG terminal in northern Greece. Venture Global already controls around 25% of the regasification capacity, giving it a strategic position in delivering US LNG into Southeast European markets.

The strengthened partnership highlights Greece’s growing importance as an energy gateway for the wider region and reinforces efforts to develop alternative supply corridors linking global LNG producers with consumers across Europe.

As infrastructure investment and interconnections continue to expand, the additional LNG volumes are expected to enhance supply flexibility, improve energy security, and strengthen long-term resilience across Central and Eastern Europe.

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The planned pipeline is considered one of the country’s most important energy infrastructure developments, as it would enable access to natural gas supplies arriving via Croatia’s LNG terminal on Krk Island. By creating an alternative import route, Bosnia and Herzegovina would reduce its dependence on Russian gas and improve the resilience of its energy system.

Flynn explained that AAFS does not intend to finance the project alone. Instead, the company is focused on assembling a consortium of banks, investment funds, and strategic partners capable of supporting infrastructure of this scale. With an estimated value of around €1.5 billion, the project requires broad financial participation, consistent with standard models used for large international energy developments.

According to Flynn, the main benefit of the Southern Interconnection is not necessarily lower gas prices, but improved energy security. The additional supply route would allow Bosnia and Herzegovina to access gas from multiple sources, reducing exposure to geopolitical disruptions and creating a more stable investment environment.

He also noted that the project has received interest and political support from the United States, as energy diversification in partner countries is seen as a strategic priority. A more interconnected and flexible regional gas market, he argued, would contribute to both stability and long-term economic development.

While greater competition among suppliers could put some downward pressure on prices, Flynn cautioned that no developer can guarantee cheaper gas in the future. Global market dynamics, geopolitical risks, and demand fluctuations remain highly uncertain, meaning the project’s core value lies in supply diversification rather than price predictability.

Despite ongoing efforts to secure financing, AAFS remains confident that the Southern Gas Interconnection will eventually be realized and will become a key element of Bosnia and Herzegovina’s future energy infrastructure.

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The auction, scheduled for 6 July, will offer annual gas transport capacity at the Sidirokastro interconnection point between Greece and Bulgaria for deliveries starting in October, marking the beginning of the new European gas year. According to DESFA, more than 30% of the nearly 100 GWh of available capacity could be booked in the first round.

Following an estimated 50% reduction in transit fees along the route, a booking rate above 30% would translate into annual volumes exceeding 1 billion cubic meters, according to market estimates. Total flows are expected to be higher overall, as a significant share of gas is likely to continue moving through short-term contracts alongside annual bookings.

Market interest is expected primarily from buyers in Bulgaria, Romania, and Hungary, while Ukraine is currently not seen as a major destination for corridor volumes. Further planned reductions in fees on the Romanian section are expected to enhance the competitiveness of the route and strengthen regional utilization.

Attention is also focused on Venture Global, which controls around 25% of the regasification capacity at the Alexandroupoli LNG terminal. Any decision by the US LNG supplier to channel cargoes through the corridor could significantly increase throughput and improve long-term utilization rates.

At the same time, infrastructure expansion continues. Transport capacity between Greece and Bulgaria is set to increase from 2.4 to 3.1 billion cubic meters per year starting 1 July, with a further expansion to 3.6 billion cubic meters already planned for the near future.

Despite positive expectations ahead of the winter season, uncertainty remains due to intensifying competition between European and Asian buyers for US LNG cargoes, a dynamic that continues to support elevated spot gas prices across global markets.

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The demand signal was the main driver. Regional consumption rose to 28.944 GW, up 3.337 GW day on day, while total net imports fell to 1.652 GW, down 1.325 GW from Sunday. That combination means Monday’s higher load was partly absorbed by stronger internal generation and stronger solar output rather than by a proportional import increase. Core imports from Austria and Slovakia into HU/SI still remained large at 2.970 GW, but were lower by 1.159 GW, while the region exported 1.055 GW toward Italy, reflecting Italy’s much higher clearing price.  

Solar remained the decisive intraday shaping factor. The regional solar forecast jumped to 7.296 GW, up 2.812 GW day on day, while wind was only 1.160 GW, up just 77 MW. That mix explains the strong midday price compression and evening scarcity profile. On HUPX, the daily minimum came around the solar-heavy midday period, while the maximum moved into the evening, with Hungary’s spot profile showing a sharp rise after the daytime trough. This is no longer a simple baseload market: the price risk is increasingly concentrated in the ramp from solar surplus into evening residual demand.  

Cross-border balances confirm the same structure. The HU+SEE region was still a net importer by 1.652 GW, but the burden was not evenly distributed. Croatia was the largest importer at -1.141 GW, followed by Romania at -904 MW, Serbia at -418 MW and Hungary at -269 MW. On the export side, Bulgaria exported 489 MW and Greece 264 MW, with Albania also positive in the detailed country data. This matters for trading because the physical balance does not fully match the price map: Serbia was deeply discounted but still import-dependent, pointing to congestion, local bidding structure and limited market coupling effects rather than a fully efficient regional price signal.  

Serbia remains the most interesting dislocation. SEEPEX at €53.40/MWh was far below HUPX, Romania, Croatia, Slovenia, Bulgaria and Greece, yet Serbia’s system balance showed 3.276 GW of consumption, 2.858 GW of generation and -418 MW of net exports, meaning a net import position. The Serbian generation stack remains coal-heavy, with the latest disclosed mix showing coal around 71%, hydro around 23%, wind around 5% and gas around 1%. For traders, this is a congestion and optionality signal: cheap Serbian day-ahead prices do not automatically mean available export capacity or monetisable spread capture into Hungary, Croatia or Romania.  

Bulgaria was the regional balancing support. Its consumption reached 3.807 GW, generation 4.296 GW and exports 489 MW, while flows turned strongly toward Romania and Serbia in the detailed border data. Greece also moved back to a net export position of 264 MW, with generation at 6.072 GW against consumption of 5.808 GW. Croatia, by contrast, stayed structurally short: consumption was 1.939 GW, generation only 798 MW, and net imports 1.141 GW, making it one of the clearest buyers of regional flexibility.  

The forward market tells a different story from spot. The Monday day-ahead rally did not translate into a bullish forward repricing. Hungarian power forwards softened, with Week 25 at €107.50/MWh, Week 26 at €120/MWh, July 2026 at €119/MWh and Cal-26 at €113/MWh, all lower except the nearest HU-DE spread line. Gas forwards and coal also moved down, while EUA held flat at €77.17/t. That says the spot move was driven by load recovery, daily shape and congestion rather than a broader fuel-cost shock.  

The near-term bias is firmer but volatile. Weather forecasts show regional temperatures rising through the week, especially in Hungary, Serbia and Croatia, while Greece remains warm. If solar stays strong, midday prices should remain compressed, but evening prices should retain premium risk, particularly where imports from CORE and Italy-facing flows tighten available capacity. The key trading watchpoints are therefore HUPX evening hours, Serbia-Hungary and Serbia-Croatia spread monetisation, Croatia’s import dependence, Bulgaria-Romania flows, and Italy’s persistent premium over the SEE core.

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The base-case outlook for 2026–2028 is not simply “high prices” or “low prices.” It is continued volatility.

Average wholesale prices may remain below the extreme levels seen during the energy-crisis years, but the shape of prices will matter more. Midday prices are likely to weaken as solar grows. Evening prices are likely to remain exposed to scarcity when demand is high and flexible capacity is limited. ACER’s analysis of the 2024 price spikes and the persistent 2025–early 2026 SEE–Central Europe price gap supports this view.  

The first major investment signal is storage. Batteries are moving from optional enhancement to core infrastructure. Bulgaria’s RESTORE-backed storage push, including official support for 3,000 MWh of usable capacity and wider project approvals around 9.7 GWh, shows how quickly the region is moving toward flexibility investment.  

The second signal is grid value. Transmission capacity, interconnectors, congestion management and cross-border allocation will be decisive. ACER has recommended better use of available network capacity, implementation of the 70% cross-zonal capacity requirement, expanded flow-based capacity calculation and extension of market coupling to non-EU neighbors.  

The third signal is market sophistication. The EU’s shift to 15-minute day-ahead trading reflects a system where electricity value changes quickly within the day. South East Europe will need trading, forecasting and balancing capabilities that match this more granular market reality.  

The fourth signal is carbon exposure. CBAM is already affecting the commercial relationship between the EU and Western Balkans. The Energy Community reported a 25% fall in commercially scheduled exchanges between the EU and Western Balkans in Q1 2026, while day-ahead prices in Contracting Parties were on average €30/MWh lower than neighboring EU markets.  

This creates a clear map of likely winners.

The first winners are flexible assets: batteries, pumped hydro, flexible hydro operation, demand response and fast-ramping plants. These assets benefit from price spreads and system stress.

The second winners are sophisticated traders and optimizers. As markets move toward negative prices, 15-minute products and more volatile intraday conditions, value shifts toward forecasting and flexibility management.

The third winners are renewable projects with storage, hybrid profiles or strong offtake structures. Standalone merchant solar will still be built, but its risk profile is becoming more challenging.

The fourth winners are industrial buyers with flexible demand. Companies able to shift consumption into low-price hours can turn volatility into savings.

The fifth winners are grid and infrastructure investors. Transmission reinforcement, substations, digital grid technologies and interconnectors will be central to market integration.

The likely losers are also clear.

Unhedged consumers will remain exposed to price spikes. Standalone solar projects without storage or shape protection may face declining capture prices. Aging coal assets will face rising carbon, pollution and financing pressure. Utilities that delay transition planning may lose export revenue and market position. Policymakers that slow market coupling may leave consumers paying for inefficient fragmentation.

The upside case for South East Europe is attractive. Faster storage deployment, stronger grids, market coupling, better balancing markets and industrial demand response could reduce scarcity events and improve renewable integration. In that scenario, the region becomes a competitive clean-power corridor linking the EU and Western Balkans.

The downside case is equally plausible. A hot and dry summer, weak hydro output, gas-price volatility, grid outages and CBAM-related trade friction could combine to produce another period of severe price stress.

The strategic conclusion is simple: South East Europe is not short of energy potential. It is short of flexibility, integration and investable market design.

The next two years will reward those who understand that electricity is no longer a simple commodity sold by volume. It is a time-specific, location-specific and carbon-sensitive product.

That is the new electricity market in South East Europe.

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The first change is that average prices no longer tell the full story. A buyer can secure an apparently attractive annual price and still face major exposure if consumption is concentrated in expensive evening hours. Conversely, a buyer with flexible operations may benefit from low or negative midday prices.

This is why industrial procurement should move from a baseload mindset to a shape-risk mindset.

The broader European context is mixed. Eurostat reported that EU non-household electricity prices fell by 5.4% in the second half of 2025 compared with the same period in 2024, and by 3.5% from the first half of 2025. But national outcomes varied, and electricity bills still depend heavily on taxes, network charges, levies and contract structures.  

For South East Europe, the key risk is volatility rather than only price level. ACER’s work on the region showed that the 2024 price spikes were concentrated in evening hours and linked to limited flexibility and constrained cross-border capacity.  

Industrial buyers should draw five practical conclusions.

First, a solar PPA is not the same as a full electricity hedge. Solar generation is concentrated in daylight hours. If a factory consumes heavily in the evening or overnight, a solar PPA may leave significant residual exposure. Buyers should compare the hourly production profile of the PPA with their actual load profile.

Second, buyers should ask who carries negative-price risk. As negative prices spread into markets such as Serbia’s SEEPEX, contract language becomes more important. A PPA that does not clearly define treatment of negative prices, curtailment and imbalance costs can create unexpected liabilities. SEEPEX introduced negative prices in May 2026, aligning Serbia’s organized market with EU-style pricing signals.  

Third, shaped PPAs will become more valuable. A flat green PPA may not be enough. Buyers may need solar-plus-storage PPAs, sleeved structures, hybrid wind-solar products or supplier-shaped contracts that better match consumption. These products may cost more than raw solar output, but they reduce shape risk.

Fourth, flexibility is a procurement asset. Industrial facilities that can shift production, pre-cool, store heat, pump water, charge batteries or adjust non-critical processes can monetize low-price hours. In a market with wider intraday spreads, flexible demand becomes a hedge.

Fifth, procurement teams need closer coordination with operations and finance. Energy buying is no longer just a contract exercise. It is an operational strategy. The CFO, plant manager, sustainability team and procurement department should all understand the company’s hourly load, peak exposure, imbalance risk and decarbonization targets.

A practical buyer checklist should include:

1. Map hourly consumption, not just annual demand.
2. Compare load shape with PPA generation shape.
3. Stress-test exposure to evening peak prices.
4. Define negative-price and curtailment treatment in contracts.
5. Evaluate battery or demand-response options.
6. Separate energy price, network charges, taxes and imbalance costs.
7. Use a portfolio of contract types instead of one single hedge.
8. Review cross-border and regulatory exposure if operating in multiple SEE markets.

The best industrial buyers in South East Europe will not simply buy cheaper electricity. They will buy smarter electricity. That means matching contracts to operations, using flexibility where possible and treating volatility as a manageable risk rather than an unavoidable cost.

In the next phase of the SEE power market, procurement advantage will come from understanding time.

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Hydropower is central to the Western Balkan electricity balance. Albania is the clearest example: its electricity system is overwhelmingly hydro-based, while Bosnia and Herzegovina, Montenegro, Serbia and North Macedonia also rely on hydro to varying degrees. Bruegel research notes that Western Balkan electricity generation is significantly reliant on hydropower, with Albania producing close to all of its electricity from hydro.  

Hydro gives the region important advantages. It can provide low-carbon electricity, flexibility, storage and fast ramping. In wet years, hydro-heavy systems can export electricity and reduce regional prices. In dry years, the same systems can become import-dependent and contribute to price stress.

That makes hydrology one of the most important market risks in South East Europe.

The 2025 drought conditions offered a reminder. AP reported that a severe drought and heatwave affected the Western Balkans, reducing hydropower output in Albania and forcing the government to spend around €60 million on energy imports.  

This is the hydro paradox. Hydro is flexible, but water inflows are not controllable. Reservoirs can shift energy across hours, days or seasons, but only if there is water to store. During prolonged drought, hydro loses both energy and flexibility value.

Climate volatility makes this issue more important. Hot, dry summers can increase electricity demand through air conditioning while reducing hydro availability. That is a dangerous combination. At the same time, solar output may be strong during heatwaves, but solar does not cover evening demand unless paired with storage or demand shifting.

Hydro also interacts with cross-border trade. Albania may be an exporter in wet periods and an importer in dry periods. Montenegro and Bosnia and Herzegovina can also swing with hydrological conditions. These shifts affect neighboring markets because South East Europe is a connected regional system. A dry Balkan hydro season can increase imports from EU markets, raise prices and intensify competition for cross-border capacity.

For traders, hydro forecasting is therefore essential. Rainfall, snowpack, reservoir levels, river flows and seasonal temperature outlooks can be as important as fuel prices. A market model that ignores hydrology will miss major balance swings.

For renewable developers, hydro can be a complement. Solar and hydro often fit well together. Solar produces during the day, allowing hydro reservoirs to conserve water for evening or peak periods. In theory, hydro can act as a natural battery for solar-heavy systems. But that strategy depends on reservoir management, market rules and water availability.

For policymakers, hydro risk argues for diversification. A hydro-heavy system may be low-carbon, but it is not automatically secure. Albania’s experience shows that dependence on one weather-sensitive source can create import risk. Solar, wind, storage, interconnectors and demand response can reduce that exposure.

For investors, hydro modernization may be an overlooked opportunity. Existing hydro assets can often be upgraded with better turbines, digital controls, improved reservoir management and environmental safeguards. Pumped hydro may also play a role where geography and permitting allow.

But hydro development must be handled carefully. New projects can face environmental, biodiversity and social concerns, especially on sensitive river systems. The region needs better hydro flexibility, but not at any ecological cost.

The broader lesson is simple: South East Europe’s power market is not only a fuel market. It is a weather market. Sun, heat, rainfall, snow and wind increasingly determine prices.

Hydro will remain one of the region’s strategic assets. But it should be treated as a flexible resource with weather risk, not as guaranteed firm supply. The countries that manage that risk well will have a major advantage in the next phase of the electricity transition.

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In several Western Balkan systems, coal provides domestic electricity, employment, system inertia, dispatchable capacity and political security. It is embedded not only in the power system but in regional economies and social structures. That is why the coal transition is not simply a technology substitution. It is a political economy challenge.

The region’s exposure is significant. Research on the Western Balkan energy sector has shown that Kosovo, Serbia, Bosnia and Herzegovina, North Macedonia and Montenegro have relied heavily on coal for electricity generation, while Albania is the major exception because of its hydropower-based system.  

This creates a reliability dilemma. Coal plants are aging, often inefficient and emissions-intensive, but they still provide firm generation when hydro output is weak, imports are expensive or solar is unavailable. Closing coal capacity without replacing its system role would create security-of-supply risk.

At the same time, the economics of coal are weakening. CBAM exposes carbon-intensive electricity exports to additional costs when sold into the EU. Reuters reported that electricity from coal-reliant Western Balkan producers is likely to become more expensive for EU importers under CBAM, reducing competitiveness in EU markets.  

That matters because exports have historically helped support utility revenues in some countries. If coal-based exports become less attractive, domestic coal plants lose part of their commercial buffer. They may still be needed for local supply, but they become harder to finance, modernize and justify.

Pollution rules add another pressure. Many coal assets in the region require investment to meet environmental standards. At the same time, lenders are increasingly reluctant to finance coal. Even where coal remains technically available, its cost of capital and compliance burden are rising.

The transition challenge is therefore not whether coal faces pressure. It clearly does. The real question is what replaces coal’s firm capacity function.

Solar alone cannot do it. Wind alone cannot do it. Hydro helps, but hydrology is uncertain. Gas can provide flexibility, but it introduces fuel-price and import-dependence risks. Batteries are essential for short-duration flexibility, but they do not fully replace multi-day firm capacity. Demand response can reduce peaks, but it requires market design and consumer participation.

A realistic transition pathway will need a portfolio: renewables, storage, grid upgrades, regional market integration, flexible hydro, limited flexible thermal backup, demand response, energy efficiency and targeted support for coal regions. It also needs domestic carbon-pricing discussions, because paying carbon costs at the EU border is less useful than recycling revenues into local transition.

The social dimension cannot be ignored. Coal regions need investment before closures, not after them. Workers need retraining, municipalities need alternative tax bases, and utilities need credible investment plans. A disorderly transition would increase political resistance and threaten security of supply.

For investors, coal-transition risk should be treated as both downside and opportunity. The downside is obvious: stranded assets, rising compliance costs and export-market erosion. The opportunity lies in replacement infrastructure: renewables, batteries, transmission, district heating modernization, mine-land repurposing and flexible capacity.

For governments, the worst strategy is delay without preparation. Aging coal assets do not become more reliable with time, and CBAM does not disappear because domestic politics are difficult. Waiting simply compresses the transition into a shorter and more expensive period.

Coal may remain part of the Western Balkan power mix for some time. But its strategic position is weakening. The future system will still need reliability, but reliability will increasingly come from flexibility portfolios rather than single-fuel dependence.

Coal’s last stronghold is not generation volume. It is firm capacity. That is the role the region must replace.

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In electricity markets, price differences are often the visible symptom of invisible constraints. If cheap power cannot reach a high-price area, prices separate. If interconnectors are congested or cross-zonal capacity is limited, regional stress cannot be relieved efficiently. That is exactly what South East Europe has experienced.

ACER found that more efficient use of available network capacity between South East Europe and the rest of the EU could have helped ease regional system stress during the 2024 price spikes. The agency also found that the price gap between Southeast and Central Europe persisted through 2025 and into early 2026, pointing to deeper structural challenges.  

This is a critical point. Price spikes are not always caused by a lack of total generation. They can also be caused by the inability to move electricity across borders at the right time. A region can be surrounded by lower-cost power and still experience scarcity pricing if grid capacity is not available.

This is why cross-border capacity allocation has become a central market issue. ACER has recommended finalizing the implementation of the EU’s minimum 70% cross-zonal capacity requirement across Central and Southeast Europe, extending market coupling to non-EU neighbors, and expanding flow-based capacity calculation and allocation in the region.  

The 70% rule matters because it aims to ensure that transmission capacity is made available for cross-border electricity trade instead of being excessively reserved for internal grid constraints. In a region like South East Europe, where demand, renewable output and hydro conditions can shift quickly, cross-border access is essential for price convergence.

Market coupling is the second part of the problem. EU member states participate in increasingly integrated day-ahead and intraday markets, while Western Balkan markets are still moving toward full integration. The Energy Community’s Electricity Integration Package is designed to enable Contracting Parties to integrate into the single European electricity market.  

Until that integration is complete, liquidity remains fragmented. Traders face more friction. Cross-border flows may not respond efficiently to price spreads. Renewable exporters face more complexity. Consumers ultimately pay for the inefficiency.

The EU’s move to 15-minute day-ahead trading from 30 September 2025 adds another layer. More granular pricing helps reflect actual system conditions more accurately, especially with variable renewables. But for South East Europe, the benefit of granular pricing depends on the ability to move electricity across time and space. Fifteen-minute prices help reveal the problem; they do not solve grid congestion by themselves.  

The grid bottleneck also affects renewable development. Solar and wind projects may be quick to build, but transmission upgrades are slower. If generation connects faster than the grid expands, the system faces curtailment, congestion and lower capture prices. Developers then face the risk that a technically strong project becomes commercially weak because it cannot deliver power when and where it is valuable.

This is why grid investment should be treated as energy-transition investment. Transmission lines, substations, digital control systems, dynamic line rating, phase-shifting transformers and better outage coordination are not secondary infrastructure. They are what allow renewable electricity to become useful electricity.

For investors, the lesson is clear: study the grid before studying only the resource map. The best solar irradiation or wind speed is not enough if the connection point is constrained. The best PPA is not enough if curtailment risk is poorly allocated. The best trading strategy is not enough if cross-border capacity is unavailable.

For policymakers, the message is equally clear. South East Europe cannot solve volatility with generation investment alone. It needs transmission reinforcement, market coupling, better capacity calculation, storage and demand flexibility.

The grid is the market. When the grid is constrained, prices diverge. When prices diverge, consumers pay, investors hesitate and system stress rises.

South East Europe’s next electricity-market reform must therefore be physical and institutional at the same time: build more grid and make better use of the grid that already exists.

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CBAM changes the economics of exporting electricity into the EU from countries without equivalent carbon pricing. For the Western Balkans, where coal remains a major part of the power mix in several countries, this is a major structural shock.

The first signs are already visible. The Energy Community Secretariat reported that, in the first quarter of 2026, commercially scheduled electricity exchanges between the EU and the Western Balkans fell by 25% across borders with EU member states. It also reported that day-ahead prices in the Contracting Parties were on average €30/MWh lower than in neighboring EU markets.  

That is unusual. In a well-integrated market, lower prices on one side of a border would normally encourage exports to higher-price neighboring markets. If the Western Balkans are cheaper while exports fall, something else is interfering with normal trade signals. CBAM is one of the main candidates.

The mechanism makes carbon intensity a commercial variable. Electricity exported from coal-heavy systems into the EU becomes less competitive because importers must account for embedded emissions. Reuters reported that the EU’s CBAM applies from 1 January 2026 to imports including electricity, and that electricity from coal-reliant Western Balkan producers is likely to become more expensive for EU importers.  

For utilities, this changes the value of export markets. A coal generator in Bosnia and Herzegovina, Serbia, Montenegro or North Macedonia may still be able to produce power, but its access to EU demand becomes less attractive if carbon costs reduce the netback price. For countries that historically relied on exports during favorable conditions, this can reduce revenue and liquidity.

For policymakers, CBAM creates a strategic choice. Western Balkan governments can treat it as an external penalty, or they can use it as a catalyst for domestic carbon pricing, renewable investment and power-sector reform. The second path is harder but more productive. If carbon revenues are collected domestically rather than paid at the EU border, they can potentially be used to fund transition, grid upgrades, social protection and coal-region diversification.

For renewable exporters, CBAM also raises technical questions. Clean power should theoretically benefit in a carbon-constrained market. But in practice, exporters need credible certification, guarantees of origin, metering, carbon-intensity accounting and market-coupling arrangements. Without those systems, even low-carbon electricity can face commercial friction.

This is why CBAM is not just a coal issue. It is also a market-integration issue. The Western Balkans need better tracking of electricity origin, stronger regulatory alignment, more transparent exchanges, and faster integration with EU electricity markets. Without these tools, the region risks lower export revenues, weaker investment signals and fragmented liquidity.

The impact will vary by country. Albania, with its hydro-dominated system, is less exposed to coal-carbon costs but highly exposed to hydrology and import/export swings. Bosnia and Herzegovina, Serbia, Montenegro, North Macedonia and Kosovo face larger coal-transition challenges. EU neighbors such as Croatia, Hungary, Romania, Bulgaria and Greece will feel the trade effects because they are connected to Western Balkan flows.

CBAM will not close coal plants overnight. Coal remains important for domestic security of supply in several Western Balkan systems. But it changes the economics around the edges, especially for exports, investment finance and long-term planning.

The direction is clear: carbon is becoming embedded in electricity trade. The Western Balkans can either adapt early or watch market access become more difficult.

CBAM is a border mechanism, but its impact will be domestic. It will influence dispatch, investment, export strategy, coal economics and the pace of market reform across the region.

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That is why batteries are becoming a strategic asset.

South East Europe’s electricity markets are increasingly shaped by a mismatch between solar output and demand. Solar pushes prices down during the day, especially around midday. Evening demand then rises as solar output disappears. ACER identified this lack of flexible resources to replace solar generation after sunset as one of the key drivers of the region’s 2024 summer price spikes.  

Batteries directly address that problem. They can charge during low-price or negative-price hours and discharge during evening peaks. They can provide balancing services, reduce curtailment, support grid stability and improve the shape of renewable PPAs. In markets with increasing intraday volatility, that flexibility becomes valuable.

Bulgaria is becoming the clearest regional test case. The EU’s Recovery and Resilience-backed RESTORE investment supports the installation and commissioning of grid-scale electricity storage facilities with 3,000 MWh of usable energy capacity, backed by a €603 million contribution and scheduled for completion by 30 June 2026.  

The scale of market interest has been even larger. Bulgaria approved support for 82 standalone battery energy storage projects with around 9.71 GWh of capacity and roughly €587 million in subsidies, according to regional energy reporting.  

This is not just a Bulgarian story. It is a regional signal. South East Europe has the ingredients that make storage valuable: strong solar growth, grid constraints, evening price spikes, hydro variability and market integration gaps. Batteries are not a luxury add-on in that context. They are part of the new market architecture.

The revenue model for batteries is also broader than simple arbitrage. A battery can earn money by buying low and selling high, but that is only one layer. Depending on market rules, it may also provide balancing services, frequency response, congestion management, reserve capacity, PPA firming and imbalance-risk reduction.

For renewable developers, batteries can protect project economics. A solar-plus-storage project can shift part of its output from weak midday hours into stronger evening hours. It can reduce exposure to negative prices. It can also offer corporate buyers a more valuable product: not just green electricity, but shaped green electricity.

For industrial consumers, behind-the-meter or contracted storage can reduce peak exposure and improve hedging. In a market where hourly spreads are widening, storage can be used not only as an energy asset but as a procurement tool.

For system operators, batteries can reduce stress. They can respond faster than thermal plants, absorb surplus renewable output and provide flexibility without fuel costs. But this value depends on regulation. If grid fees, licensing rules, balancing-market access or double-charging structures are poorly designed, battery economics can be weakened.

That is the key policy challenge. South East Europe does not only need battery subsidies. It needs market rules that allow batteries to compete fairly. Storage should be able to charge, discharge, provide services and participate in multiple markets without being treated as both a final consumer and a generator in ways that penalize its function.

The next investment cycle in South East Europe will not be won by capacity alone. It will be won by flexibility. Batteries are one of the most direct ways to monetize that shift.

The region’s solar boom created the need. Price volatility created the signal. Bulgaria’s storage push shows the direction. The question now is which markets will build the rules, grids and revenue structures fast enough to turn batteries into bankable infrastructure.

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Across the EU, 2025 marked a structural milestone. Ember reported that wind and solar generated 30% of EU electricity, overtaking fossil fuels at 29% for the first time. Solar alone supplied 13% of EU electricity and grew by more than 20% year-on-year for the fourth consecutive year.  

For South East Europe, this trend is especially important. The region has strong solar irradiation, rising air-conditioning demand, growing renewable pipelines and still-limited storage penetration. Greece, Bulgaria, Romania, Hungary and Serbia are all exposed to a new daily price shape: low or negative prices during sunny midday hours, followed by higher prices in the evening.

This is the classic “duck curve” problem. Solar output rises quickly during the morning and reaches its peak around midday. At that moment, wholesale prices can fall sharply because the system has a high volume of low-marginal-cost electricity. But as the sun sets, solar generation drops. If demand remains high and flexible resources are limited, prices can rise quickly.

That pattern is already visible in South East Europe. ACER identified the lack of flexible resources to replace solar generation in the evening as a key driver of the region’s 2024 summer price spikes. The agency also found that limited cross-border capacity made it harder for South East Europe to import lower-priced electricity from elsewhere during stress periods.  

This matters for solar project economics. A solar plant does not earn the annual baseload price. It earns the price available during the hours when it produces. As more solar enters the system, solar plants increasingly compete with one another during the same hours. That pushes down the solar capture price.

This is why solar cannibalization is becoming a central issue. The first wave of solar benefits from high daytime prices. Later waves reduce the value of those same daytime hours. The result is a paradox: more solar is good for decarbonization and consumer prices during sunny hours, but it can weaken the merchant business case for standalone solar projects.

SolarPower Europe has already warned that negative prices and curtailment are eroding business cases in the EU solar sector. The group reported that the EU installed 65.1 GW of new solar PV in 2025, slightly below the 65.6 GW installed in 2024, marking the first annual decline since 2016.  

South East Europe should read that warning carefully. The region is not “finished” with solar. Far from it. Solar will remain one of the fastest and cheapest sources of new electricity. But the commercial model must evolve.

Standalone solar exposed entirely to merchant prices will become riskier as negative-price hours increase. Solar projects with batteries, flexible offtake, corporate PPAs, curtailment protection or intraday optimization will be better positioned. Industrial consumers that can shift load into midday hours may also benefit from lower daytime prices.

There is also a grid dimension. Solar growth can happen faster than transmission reinforcement. When grid capacity is limited, renewable output can become trapped in specific areas. That creates local congestion, curtailment and price separation. In South East Europe, where interconnection and internal grid constraints are already major issues, solar deployment must be matched with network investment.

The political message is equally important. Policymakers should not interpret negative prices as proof that too much renewable energy has been built. Negative prices are proof that the system lacks enough flexibility to absorb renewable output efficiently. The solution is not to stop solar. The solution is to build storage, demand response, grid capacity and more granular market signals.

Solar is rewriting the rules of South East European power markets. The winners will not simply be the companies that build the most capacity. The winners will be those that understand when their electricity is valuable, when it is not, and how to move value from surplus hours to scarcity hours.

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For years, the main question in South East Europe was whether the region had enough electricity. Today, the more important question is whether the system has the right kind of electricity at the right hour. That distinction is becoming central to prices, investment decisions and security of supply.

The clearest signal came from the summer 2024 price spikes. ACER found that most Southeast European bidding zones experienced significant price increases during that period, particularly in the evening hours, with prices reaching up to €1,000/MWh in some cases. ACER’s conclusion was important: the spikes were not simply a fuel-price event. They were linked to a lack of flexible resources able to replace solar generation after sunset, combined with limited cross-border capacity to import cheaper power from other regions.  

That finding changes how the market should be read. South East Europe has strong renewable-resource potential, especially solar. It also has legacy hydro, coal and gas assets that can provide firm supply under certain conditions. But the system is increasingly exposed to the gap between daytime renewable output and evening demand. In other words, the problem is not always total annual generation. It is hourly balance.

This is why average baseload prices are becoming less useful as a market indicator. A market can look adequately supplied on an annual basis and still experience severe price stress in a few evening hours. It can also experience very low or negative midday prices during high solar output, while scarcity pricing appears just a few hours later. For utilities, traders, renewable developers and industrial consumers, the value of electricity is moving from the megawatt-hour alone to the timestamp attached to it.

The price gap between South East Europe and Central Europe reinforces the point. ACER reported that, although prices in 2025 did not reach the extreme levels seen in summer 2024, the price gap between Southeast and Central Europe persisted throughout 2025 and into early 2026. That suggests the region’s volatility is structural, not accidental.  

Three factors explain this structural volatility.

First, solar is growing faster than system flexibility. Solar lowers prices during daylight hours, especially at midday, but it does not solve evening peak demand. Without batteries, pumped hydro, flexible gas, demand response or stronger interconnectors, the system becomes long during the day and tight after sunset.

Second, grid constraints matter as much as generation mix. If lower-cost electricity cannot move into the region when needed, local prices separate. This is why cross-border capacity, market coupling and transmission investment are now core market issues, not technical side topics.

Third, the region is unevenly integrated. EU member states in South East Europe operate inside the EU electricity-market framework, while Western Balkan markets are still progressing toward full integration. Serbia’s market is moving closer to EU practice, but wider Western Balkan market coupling remains unfinished.

The move to 15-minute day-ahead trading in the EU from 30 September 2025 is part of the same transition. The European Commission says the shift from hourly to 15-minute pricing helps markets reflect expected generation and demand more accurately. That matters in systems with high wind and solar shares, because imbalances can appear within much shorter time intervals than traditional hourly markets captured.  

For South East Europe, this creates a new hierarchy of value. Pure generation remains important, but flexible generation is more valuable. Solar remains attractive, but solar with storage or flexible offtake is more valuable. Hydro remains strategic, but hydro availability depends on weather. Coal remains relevant for security of supply, but its economics are weakening under carbon and pollution pressure. Grid capacity, once treated as background infrastructure, is now a price-setting asset.

The investment implications are clear. The next wave of value creation in South East Europe will likely come from batteries, pumped hydro, grid upgrades, balancing-market participation, demand response, shaped PPAs and smarter trading capabilities. The region does not just need more megawatts. It needs more controllable megawatts.

This is the central thesis for South East Europe’s electricity markets in 2026–2028: the crisis has changed shape. It is no longer only about shortage. It is about flexibility scarcity.

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Between June 8, 2026 and June 14, 2026, 79 articles were published.

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The European Commission’s technical study on indirect emissions in CBAM should be read as a turning point. The study, published through DG TAXUD on 8 June 2026, frames three policy questions: how operational default emission factors for indirect emissions should be determined; when declarants should be allowed to claim actual indirect emissions, including through direct technical links, PPAs and verification; and whether indirect-emissions coverage should be extended to additional CBAM sectors.  

CBAM is becoming an engineering problem.
The new indirect-emissions study does not only affect carbon accounting, legal reporting or importer paperwork. It changes the physical readiness question for exporters: can the plant’s electrical architecture prove the electricity claim behind the CBAM number?

For exporters, the message is simple: electricity is no longer background energy consumption. It is becoming a compliance object.

Until now, many CBAM discussions have focused on direct emissions: fuel combustion, process emissions, calcination, reduction agents, furnace routes, hydrogen pathways and precursor emissions. Those remain essential. But the Commission’s new work on indirect emissions brings a second layer into the foreground: the electricity consumed in producing CBAM goods, the emissions factor applied to that electricity and the evidence needed to support any claim that the electricity was low-carbon.

This is where CBAM stops being only an emissions calculation and becomes an engineering due-diligence exercise.

The new CBAM question: Can the plant prove its electricity?

Indirect emissions are determined by multiplying the electricity consumed during production by the applicable electricity emission factor. The Commission FAQ also states that the electricity emission factor may be based on the grid supplying the electricity or, where CBAM rules allow, an actual electricity emission factor.  

That formula looks simple. In practice, it creates a complex evidence chain.

A plant must be able to answer:

What electricity was consumed?
Not only at the site gate, but by installation, production process, product route, auxiliary system and, where possible, CBAM product category.

When was it consumed?
Monthly data may not be enough where PPA matching, onsite generation, settlement periods or verifier sampling require stronger time resolution.

Where did it come from?
Grid import, onsite generation, behind-the-meter renewable assets, direct technical links, PPAs, supplier contracts and certificate systems may each create different evidence requirements.

How was it allocated?
If one plant produces multiple products, serves EU and non-EU markets, uses shared auxiliaries or operates several production routes, the electricity allocation method becomes a technical risk point.

Can it survive verification?
Supplier statements and green certificates alone may not be enough if the underlying metering, contractual and operational evidence is weak.

This is the reason CBAM readiness now requires electrical metering architecture.

Why defaults are a commercial risk

The definitive-period CBAM regime already includes default values. The Commission’s CBAM legislation and guidance page states that default values have been published and that the legally binding values are set out in Commission Implementing Regulation (EU) 2025/2621.  

The Commission FAQ also explains that authorised CBAM declarants may use default values for CBAM goods other than electricity where verified actual embedded-emissions data are not available, and that default values are country- and year-specific.  

For exporters, this creates a clear business risk. Weak electricity data can push the importer toward default values. Defaults may be administratively easier, but they are not necessarily commercially optimal. For a producer in a carbon-intensive grid, the difference between a default factor and a verified actual electricity claim may become a price, margin and market-access issue.

The practical implication is direct: a producer that cannot prove electricity consumption and electricity origin may lose the ability to defend a lower embedded-emissions figure.

The PPA opportunity — and the PPA trap

The study’s second policy question is especially important because it focuses on actual indirect-emissions claims, including direct technical links, PPAs and verification.  

This creates a major opportunity for renewable developers, industrial exporters and EU buyers. A well-structured renewable PPA can become more than an energy procurement contract. It can become part of a CBAM value strategy.

But there is a trap: not every green PPA will be CBAM-ready.

A generic green electricity contract may create a sustainability claim, but CBAM requires a stronger evidentiary logic. The Commission’s earlier transitional-period default-values document allowed actual electricity emission factors where there is either a direct technical link between the production installation and the electricity generation source, or a PPA between the consumer and producer for an equivalent amount of electricity.  

That means a CBAM-relevant PPA should be engineered around evidence, not only price. The contract should be supported by metering points, generation data, delivery shape, settlement records, guarantees of origin or equivalent certificate controls, matching methodology, balancing treatment and verifier access.

The new commercial product is not simply “green electricity.”
It is CBAM-verifiable electricity.

Why this matters for Serbia and Southeast Europe

For Serbia, the Western Balkans and Southeast Europe, this is strategically important. Many industrial exporters sell steel, aluminium, cement, fertilisers, hydrogen-related products, components or precursors into the EU market. Many also operate in power systems where grid-emission intensity, renewable procurement structures and metering maturity vary significantly.

The current CBAM FAQ states that CBAM scope is limited to direct emissions for iron/steel, aluminium and hydrogen, while cement, fertilisers and agglomerated iron ore must declare both direct and indirect emissions. It also states that indirect emissions are taken into account only for the CBAM goods for which indirect emissions fall within scope.  

That current scope should not create complacency. The Commission’s study expressly examines whether and how indirect-emissions coverage could be extended to additional CBAM sectors.  

For aluminium, electric arc furnace steel, rolling mills, ferroalloys, cement grinding, fertilisers, hydrogen and power-intensive processing, the strategic direction is clear: electricity evidence will become a competitive variable.

The missing layer: Engineering before verification

Many companies approach CBAM through legal, tax, customs or ESG reporting channels. That is necessary, but incomplete.

Before a verifier can verify, someone must establish whether the physical and digital plant evidence exists. That is an engineering task.

A CBAM electricity-evidence review should examine:

1. the plant single-line diagram;
2. grid import and export interfaces;
3. transformer and substation metering;
4. process-level and line-level meters;
5. SCADA, EMS and meter-data systems;
6. onsite generation metering;
7. PPA settlement data;
8. guarantees of origin or equivalent certificate controls;
9. production-process boundaries;
10. electricity allocation by CN code, product route and EU export volume;
11. reconciliation between MWh consumed and tonnes produced;
12. evidence gaps that could force default-value use.

This is closer to Owner’s Engineer work than classic reporting support. The question is not only whether the emissions calculation is mathematically correct. The question is whether the plant architecture can support the claim.

The Clarion.Engineer service thesis

Clarion.Engineer positions CBAM readiness as a technical infrastructure problem.

The service model is built around four layers.

1. CBAM electrical metering architecture review

Clarion.Engineer maps the physical electricity system behind the CBAM claim: grid connection, substations, transformers, main meters, process meters, auxiliary loads, self-generation, direct links, PPA interfaces and excluded loads.

The output is a CBAM meter hierarchy showing which meters support which production processes and where evidence gaps exist.

2. Product-level electricity allocation model

CBAM does not need only site-level MWh. It needs electricity allocation that can be linked to production boundaries and product categories.

Clarion.Engineer develops the allocation logic for complex plants: shared equipment, multiple production routes, auxiliaries, EU and non-EU production, precursors and downstream processing.

The output is a product-level electricity allocation model that can be reviewed by importers, auditors and verifiers.

3. PPA and low-carbon electricity evidence pack

A PPA should not sit separately from the CBAM file. It should be translated into an engineering evidence package.

Clarion.Engineer reviews whether the PPA claim is supported by generation evidence, metering, settlement data, delivery periods, matching logic, certificate treatment and verification access.

The output is a CBAM-ready PPA evidence file.

4. Importer and verifier data room

EU importers are legally responsible for CBAM declarations. The Commission FAQ states that importers must be authorised CBAM declarants from 1 January 2026, and that the first annual CBAM declaration for the 2026 import year is due by 30 September 2027, together with certificate surrender.  

That means importers will increasingly demand structured evidence from non-EU suppliers.

Clarion.Engineer prepares the technical data room: meter registry, monthly readings, SCADA extracts, PPA records, certificates, production allocation, emission-factor assumptions, reconciliation checks and gap-closing actions.

The output is a verifier-facing CBAM electricity evidence dashboard.

The winners

The companies that win under CBAM will not be the ones with the best sustainability slogans. They will be the ones with the best evidence.

In the indirect-emissions era, CBAM readiness means being able to prove electricity consumption, electricity origin, allocation logic and low-carbon claims with engineering-grade documentation.

For exporters, this is a warning. Weak metering may become expensive.

For renewable developers, this is an opportunity. A renewable PPA that can reduce CBAM exposure is more valuable than a generic green contract.

For EU importers, this is a due-diligence requirement. Supplier declarations need technical review before they become CBAM declarations.

For industrial plants, this is the practical conclusion:

CBAM readiness now starts at the meter.

Engineering services by Clarion.Engineer

CBAM electrical metering architecture | PPA evidence packs | product-level electricity allocation | verifier-ready data rooms

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That market is now changing.

The European Commission’s latest technical work on indirect emissions under the Carbon Border Adjustment Mechanism points to a future in which electricity used by industrial producers is not merely purchased, consumed and settled. It must be proven. It must be documented in a way that EU importers can use inside CBAM declarations. It must be credible enough for verification. And where a producer wants to claim actual low-carbon electricity rather than a default grid factor, the supporting evidence may become as important as the physical power itself.

This is the new energy-market angle in CBAM: electricity is becoming a carbon passport for traded industrial goods.

The issue moved into sharper focus on 8 June 2026, when DG TAXUD published its technical study on indirect emissions in CBAM. The study is organised around three questions: how to determine operational default emission factors for indirect emissions; when declarants should be allowed to claim actual indirect emissions, including requirements for direct technical links, power purchase agreements and verification; and whether indirect-emissions coverage could be extended to additional CBAM sectors.  

For power producers and traders, that is a commercial signal. The buyers most exposed to CBAM will no longer be satisfied with a standard electricity supply contract, a generic green tariff or an annual certificate statement. They will need electricity products that can be linked to production, metering, embedded-emissions calculations and audit trails.

That is a very different market.

From green electricity to CBAM-verifiable electricity

The key distinction is between green electricity as a marketing claim and low-carbon electricity as a CBAM evidence file.

A renewable PPA may help an industrial company decarbonise, hedge electricity costs and strengthen its ESG profile. But under CBAM, the question becomes more technical: can the electricity claim be used to calculate actual indirect emissions for goods entering the EU? Can the importer or authorised CBAM declarant rely on it? Can the claim be checked by a verifier? Can the power consumption be allocated to the specific installation, process and product line producing CBAM goods?

That is why DG TAXUD’s focus on direct technical links, PPAs and verification matters. It implies that not every green electricity arrangement will have the same CBAM value. A behind-the-meter renewable asset with clear metering and a direct technical link to the industrial installation may carry stronger evidentiary weight than an ordinary supply contract. A PPA with robust settlement data, certificate cancellation, production matching and verifier access may be more valuable than a generic renewable certificate procured after the fact.

For producers and traders, the product has to evolve. The industrial buyer will increasingly ask not only: “What is the price?” but also: “Can this electricity reduce my CBAM exposure, and can I prove it?”

Why traders are central to the new framework

Traders are often treated as intermediaries in power markets. Under this emerging CBAM-linked electricity framework, they become data and evidence managers.

Industrial buyers will need power products that combine several layers:

1. physical or financially settled electricity supply;
2. renewable or low-carbon attribution;
3. metered consumption records;
4. production-period alignment;
5. certificate or guarantee-of-origin control;
6. balancing and residual supply treatment;
7. audit access;
8. documentation that can be transferred into the importer’s CBAM file.

This is where traders can create value. A trader that can assemble power from multiple producers, manage balancing, document certificate flows, reconcile metered consumption and provide a CBAM-ready data package will become more valuable than a trader offering only price execution.

The trader’s role becomes similar to a structured-products desk. It must package energy, certificates, shape, balancing, traceability and verification support into one industrial supply solution.

That is especially important in Southeast Europe, where power-market volatility is already intense. In Week 23 of 2026, SEE electricity demand rose 8.2% week on week to 15.15 TWh, variable renewable output fell 8.9%, wind dropped 15.5%, solar declined 5.1%, hydro rose 10.1%, and thermal generation jumped 24.5%. Net imports rose 9.1% to 1.22 TWh, showing how strongly the region still depends on cross-border balancing.  

That volatility matters because industrial buyers cannot build CBAM strategies on annual averages alone. They need electricity contracts that address hourly shape, residual supply, balancing exposure and the carbon character of power actually consumed during production.

The default-factor risk

The first DG TAXUD study question — operational default emission factors — is crucial for energy markets.

A default factor is not just a technical fallback. It can become a commercial penalty for poor evidence. If an industrial exporter cannot prove actual low-carbon electricity use, the EU importer may have to rely on a default emissions factor. For producers in carbon-intensive grids, that could make exported cement, fertiliser, steel derivatives, aluminium products or other affected goods less competitive.

This creates a powerful incentive for industrial buyers to procure electricity differently. They will want power contracts that reduce the risk of falling back on defaults.

For electricity suppliers, that means the sales pitch changes. It is no longer enough to say: “We can supply renewable power.” The more valuable claim is: “We can supply electricity with the data architecture needed to support an actual indirect-emissions claim.”

That architecture includes metering, settlement records, generation certificates, PPA documentation, grid connection evidence, time-matching logic and a clear approach to residual consumption. In practical terms, power suppliers will need to provide a compliance appendix alongside the commercial contract.

The direct technical link premium

A direct technical link is likely to become one of the strongest forms of evidence for industrial buyers seeking low-carbon electricity recognition.

For renewable developers, this opens a premium segment: dedicated solar, wind, hydro, biomass or hybrid plants serving CBAM-exposed industrial sites. The value of such projects will not be limited to the electricity price. They may also help buyers reduce embedded-emissions exposure, protect EU market access and strengthen supply-chain credibility.

That can improve PPA bankability.

A cement producer, fertiliser plant, metals processor or hydrogen producer that faces CBAM-related electricity scrutiny may be willing to pay for a more robust direct-supply structure. The renewable developer receives a stronger offtaker. The lender sees a more strategic contract. The industrial buyer receives not only energy, but an emissions-evidence asset.

This is where battery storage also becomes important. A solar PPA may not match an industrial load curve. A battery can help shift renewable output into higher-value or more relevant consumption periods, reduce residual grid draw and strengthen the credibility of the supply profile. In a CBAM context, BESS is not only a flexibility asset. It can become part of the evidence strategy.

PPAs must be redesigned for verification

The standard PPA will not be enough.

A CBAM-ready PPA should include clauses on data ownership, access rights, metering hierarchy, certificate transfer or cancellation, settlement-period matching, residual electricity treatment, curtailment, outages, replacement power, balancing responsibility and verifier access. It should define exactly what the buyer can claim, what the seller guarantees, and what documentation will be delivered.

This is not only legal drafting. It is engineering and market design.

The PPA must be compatible with the plant’s electrical system, the production process and the buyer’s CBAM reporting boundaries. A contract that looks green on paper may fail if the production line cannot allocate electricity consumption to the CBAM good, or if the power supplier cannot provide the necessary audit trail.

That means power producers and traders should prepare standardised CBAM electricity data packs for industrial buyers. These should include:

• generation asset identity and location;
• installed capacity and technology;
• grid connection status;
• direct-line or grid-supply structure;
• PPA delivery period and settlement granularity;
• metered generation and consumption data;
• certificate issuance and cancellation evidence;
• balancing and replacement power treatment;
• residual mix disclosure;
• third-party verification rights;
• monthly and annual reconciliation templates.

The market will reward suppliers that can make this easy for buyers.

Why this matters beyond cement and fertilisers

The Commission’s CBAM page states that the definitive regime started on 1 January 2026, and that EU importers or indirect customs representatives importing more than the single mass-based threshold of 50 tonnes of CBAM goods must apply for authorised CBAM declarant status. It also says CBAM certificate prices are calculated from EU ETS allowance auction prices, quarterly in 2026 and weekly from 2027.  

The current definitive-period treatment of indirect emissions is narrower than the transitional reporting experience. The Publications Office summary for Task 2 notes that CBAM covers direct production emissions and, for cement and fertiliser goods, indirect emissions from electricity consumed to produce CBAM goods; during the transitional period, indirect emissions were to be reported for all CBAM goods except electricity.  

But DG TAXUD’s third study question is whether and how indirect-emissions coverage could be extended to additional CBAM sectors. That is the forward-looking market trigger.  

Steel, aluminium, hydrogen and downstream processing chains should therefore not ignore electricity data simply because some indirect emissions are not yet chargeable in the same way. The direction of travel is clear: electricity is becoming a strategic variable in CBAM policy design.

The Task 3 publication also places the issue inside the wider EU carbon-leakage framework, including the EU ETS Directive, free allocation, auctioning revenues and indirect cost compensation for electro-intensive industries.   That matters because any extension of CBAM indirect-emissions coverage has to interact with how EU producers are treated for carbon costs passed through electricity prices.

For traders, this means future-proofing products now. The buyer that asks for CBAM-grade electricity today may be a cement or fertiliser producer. Tomorrow it may be an aluminium processor, steel product exporter, hydrogen supplier or complex industrial group responding to buyer pressure even before the regulation formally expands.

Power-market volatility makes the framework commercially urgent

CBAM electricity evidence would be important even in stable power markets. But in SEE and wider Europe, volatility makes it urgent.

The market Week 23 trends showed SEE prices diverging sharply. Italy averaged €128.09/MWh, Bulgaria €100.83/MWh, Hungary €103.15/MWh, Greece €89.25/MWh, Serbia €99.63/MWh, Croatia €99.29/MWh, and Türkiye only €22.53/MWh, showing significant fragmentation across the region.  

Gas risk adds another layer. TTF gas futures averaged €48.56/MWh during the first week of June, while the one-month forward contract was trading near €49.335/MWh. The report also warned that European gas markets remain vulnerable to LNG disruption, storage risk and competition for cargoes.  

For industrial buyers, this means electricity procurement now has three linked purposes: price hedging, decarbonisation and CBAM evidence. A buyer that fixes price but cannot prove low-carbon supply has solved only one problem. A buyer that procures certificates but remains exposed to volatile spot residual supply has solved only part of the problem. A buyer that signs a PPA without metering and verification rights may still fail the evidence test.

That is why producers and traders need to build integrated products.

What producers must prepare

Power producers should prepare for a buyer base that asks for documentation as intensively as it asks for price.

Renewable producers should be ready to provide asset-level generation data, metering records, certificate issuance and cancellation evidence, curtailment logs, outage reports and clear contractual linkage to the industrial buyer. Where possible, they should design direct technical link projects or behind-the-meter solutions for CBAM-exposed sites.

Hydro producers should prepare to document generation origin, dispatch periods and certificate treatment. Hydro can be highly valuable for industrial buyers because it can better match non-solar load profiles, but only if its low-carbon attributes are traceable and not double-counted.

Thermal producers face a different market. They may continue supplying reliability and balancing power, but they will need to understand that CBAM-exposed buyers may treat fossil-based residual supply as a liability unless it is explicitly separated, priced and disclosed.

Storage operators should position batteries as compliance-supporting flexibility assets. A BESS can help renewable supply match industrial demand, reduce exposure to fossil-heavy evening power and improve the delivery shape of a PPA.

What traders must prepare

Traders should prepare for a world in which the best industrial electricity contract is not the cheapest contract, but the most defensible one.

They need systems that can reconcile generation, consumption, certificates, schedules and imbalances. They need to provide monthly evidence packs that industrial buyers can pass to EU importers. They need to manage residual electricity transparently. They need to avoid double-counting renewable attributes. They need to understand which parts of a supply structure are physical, which are contractual, and which are only financial.

A CBAM-ready trader will offer:

• structured renewable PPAs;
• sleeving services;
• balancing and shaping;
• storage optimisation;
• certificate management;
• residual mix disclosure;
• hourly or settlement-period reporting;
• importer-facing documentation;
• verifier cooperation;
• audit-ready data rooms.

This is a higher-margin service than commodity trading, but it requires stronger controls.

What industrial buyers will demand

Industrial buyers will increasingly demand electricity contracts that answer five questions.

First, what electricity did the plant consume during production of CBAM goods?

Second, what was the emissions factor attached to that electricity?

Third, is the claim based on a default factor, an actual factor, a PPA, a direct technical link or a blended method?

Fourth, can the electricity evidence be reconciled with production volumes and product-level allocation?

Fifth, can the EU importer or authorised CBAM declarant use the evidence safely in the CBAM declaration?

Any producer or trader that cannot answer those questions will be selling a weaker product.

The winners

The DG TAXUD technical study should be read by energy-market participants as the beginning of a new commercial category. It is not just a compliance document for importers. It is a signal to the power sector that electricity contracts are becoming embedded-emissions instruments.

For industrial buyers, the objective is clear: reduce CBAM exposure and protect EU market access.

For power producers, the opportunity is to turn low-carbon generation into a premium industrial supply product.

For traders, the opportunity is to become the infrastructure layer between volatile power markets and verifiable carbon documentation.

The winners will be those who can sell megawatt-hours plus proof. In the CBAM era, electricity without evidence will increasingly be just power. Electricity with evidence will become a market-access asset.

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For years, electricity transactions in the region have been structured around the familiar pillars of price, delivery period, balancing responsibility, guarantees of origin, credit support and settlement. That will no longer be enough for industrial companies exporting steel, aluminium, cement, fertilisers, hydrogen, chemicals, precursors or processed materials into the EU. Under the new direction of DG TAXUD’s technical framework, the industrial buyer will increasingly need electricity that can be defended inside a CBAM file.

The Commission’s technical study on indirect emissions, published in June 2026, focuses on three questions: how operational default emission factors should be determined, under what conditions declarants may claim actual indirect emissions, including through direct technical links, PPAs and verification, and whether indirect emissions should be extended to more CBAM sectors. This is a technical study, not a final regulation by itself, but it is already a market signal. It tells producers and traders that the value of electricity for industrial offtakers will increasingly depend on the quality of the evidence attached to it.

That is a major change for the power market. A megawatt-hour sold to a household, a commercial supplier or a pure trader is one product. A megawatt-hour sold to a CBAM-exposed industrial exporter is becoming another. The second product must carry a data trail: source, metering point, delivery shape, contractual link, certificate logic, balancing treatment, grid boundary, allocation method and audit access. In effect, CBAM is creating a new segment of power trading: CBAM-verifiable electricity.

This matters especially in Southeast Europe because industrial exporters often operate in power systems where carbon intensity varies widely by hour, season and country. A plant may buy electricity at a competitive price but still face a weak CBAM position if the electricity cannot be documented as actual low-carbon supply. Conversely, a renewable producer or trader able to deliver verified, well-documented electricity may command a premium from industrial buyers whose EU customers and authorised declarants are demanding stronger evidence.

The old green electricity product was often built around annual guarantees of origin. That approach may remain useful, but it is unlikely to be sufficient on its own for higher-quality CBAM claims. DG TAXUD’s focus on direct technical links, PPAs and verification indicates that the EU is concerned not only with whether a certificate exists, but with whether the electricity claim reflects a credible production and consumption relationship. This moves the market away from generic “green supply” language and toward detailed contractual and technical architecture.

For power producers, the first preparation step is metering. Renewable generators selling to CBAM-exposed industry must be able to provide generation data that is time-stamped, auditable and linked to defined delivery periods. Wind and solar producers will need clear metering at the grid connection point, SCADA-backed output data, settlement reconciliation and certificate issuance or retirement evidence. Hydro producers will need equivalent documentation, especially where reservoir dispatch is used to firm supply. If a producer cannot prove when and how electricity was generated, its power may be less valuable to industrial buyers seeking actual indirect-emissions claims.

For traders and suppliers, the challenge is more complex. A trader may source electricity from a portfolio of generators, exchanges, bilateral contracts and balancing positions. That portfolio logic is normal in power markets, but CBAM pushes the supplier to distinguish between commodity electricity and attributed electricity. Industrial buyers will ask whether the delivered volume is backed by a specific PPA, a defined generation asset, a direct technical link, a portfolio of renewable assets, or a residual mix. They will also ask how imbalances, shortfalls and replacement volumes are treated.

That creates a new documentation burden. Traders will need CBAM-ready electricity packs attached to industrial supply contracts. These packs should include the generator identity, technology type, location, installed capacity, grid connection details, metering hierarchy, contractual delivery period, volume allocation logic, certificate treatment, balancing rules, replacement electricity rules, settlement evidence and audit rights. The contract itself will need to say what happens if renewable generation is below forecast and the supplier covers the shortfall from the market. Without that clause, the buyer may not know whether it can claim actual indirect emissions or must fall back on a default factor.

The default-factor issue is commercially critical. The Commission’s study explicitly examines how operational default emission factors for indirect emissions should be determined. That means weak electricity evidence may push exporters toward default factors, which could be more conservative than actual plant-level electricity emissions. For a CBAM-exposed industrial buyer, the difference between default and actual values can become a direct cost issue. For a producer or trader, the ability to help the buyer avoid default treatment can become a pricing premium.

This is where electricity becomes a compliance hedge. Industrial companies already buy power to manage cost volatility. Under CBAM, they will also buy power to manage carbon-documentation risk. A well-structured renewable PPA can reduce price exposure, support decarbonisation claims and improve the embedded-emissions profile of exported goods. But a poorly documented PPA may fail to deliver the compliance benefit even if the electricity is genuinely renewable.

The highest-quality structure will usually be a direct technical link. That could mean behind-the-meter renewable generation, a dedicated line, on-site solar, captive wind or a clearly traceable physical connection between generator and industrial installation. Such arrangements are easier to defend because the relationship between production and consumption is physically visible. But they are not always practical, especially for large industrial loads or where renewable resources are located far from the plant.

The next tier is a structured PPA with robust evidence. This requires more than a commercial contract. It needs asset-level generation data, delivery reconciliation, certificate matching, balancing treatment and independent verification access. For hourly or sub-hourly matching, the data burden rises further. If the EU framework moves toward stricter temporal matching, traders and suppliers that already have digital metering and portfolio allocation systems will be better positioned.

A generic supplier contract with annual guarantees of origin will be the weaker tier. It may still support a corporate renewable claim, but it may not satisfy the stricter logic implied by actual indirect-emissions verification. The risk is resource shuffling: clean electricity is assigned on paper to the CBAM exporter while the wider system remains unchanged and other consumers receive more carbon-intensive residual supply. The Commission’s technical framing shows that this risk is already on the policy radar.

For Southeast European traders, this creates both risk and opportunity. The risk is that industrial customers will no longer accept undifferentiated electricity products. The opportunity is that traders can build higher-margin services around CBAM-ready supply. A trader that can aggregate renewable generation, manage balancing, retire certificates, produce audit files and reconcile delivery data to factory consumption can become a strategic partner to industrial exporters.

This also changes the role of batteries. Storage is not only an arbitrage asset; it can become a compliance-enabling asset. A solar PPA may produce heavily at midday, while an industrial plant consumes across a wider profile. A battery can shift renewable electricity into evening production hours, reduce reliance on fossil-heavy residual grid power and improve the credibility of matching between renewable supply and industrial load. For CBAM-exposed buyers, battery-backed renewable supply may carry more value than a flat annual green certificate.

Wind and hydro have different roles. Wind can provide non-solar-hour renewable generation, but it needs stronger forecasting and imbalance management. Hydro can provide flexible low-carbon electricity where documentation and sustainability requirements are met. A supplier that combines solar, wind, hydro and BESS can offer a more credible industrial electricity product than a supplier selling single-technology renewable power without shape management.

The energy-market timing is important. SEE power prices remain volatile. In Week 23 of 2026, regional demand rose 8.2%, variable renewable generation fell 8.9%, thermal generation increased 24.5%, and net imports rose 9.1%. Gas prices were also elevated, with TTF futures near €49/MWh. This is the market environment in which industrial buyers are being asked to manage both electricity-price risk and CBAM documentation risk. A buyer exposed to spot prices and default indirect-emissions factors faces a double vulnerability: high power cost and weak carbon evidence.

For producers and traders, the product response should be immediate. Industrial electricity offers should be redesigned around three layers: physical delivery, financial hedge and CBAM evidence. Physical delivery defines how the electricity is supplied. The financial hedge defines price risk and indexation. The CBAM evidence layer defines what the buyer can show to an EU importer, authorised declarant or verifier. Without the third layer, the product is incomplete for CBAM-exposed customers.

Contract language must also change. PPAs and supply agreements should include clauses on emission-factor representation, metering evidence, certificate ownership, certificate retirement, data delivery deadlines, audit rights, replacement power, force majeure, balancing responsibility, curtailment, grid constraints and changes in CBAM law. The buyer will need protection if the electricity product fails to qualify for actual indirect-emissions treatment. The supplier will need clear limits on liability where regulatory rules remain evolving.

The strongest commercial offers will include a monthly CBAM electricity statement. This should show contracted volume, metered generation, delivered volume, consumption allocation, certificate status, residual supply, imbalance volume, replacement source and estimated electricity-related emissions factor. For exporters producing multiple products, the statement should be compatible with plant-level allocation rules so electricity can be assigned to product lines or batches.

This opens a new business line for energy traders: CBAM electricity data management. The trader becomes not just a seller of power but an evidence manager. That requires IT systems, data pipelines, metering integration, legal templates, registry access and verification workflows. Traders that invest early will be able to sell a premium product. Those that do not may be pushed back into commodity supply.

Industrial buyers will also need to prepare. They cannot simply ask for “green power” and assume it solves CBAM. They must define the electricity boundary of the plant, map metering points, reconcile electricity use with production volumes, decide allocation rules, and align the supplier’s evidence with the CBAM declarant’s reporting needs. The buyer’s procurement team, energy manager, finance department, production manager and CBAM compliance officer will need to work from the same data.

For banks and project financiers, the new framework changes renewable PPA bankability. A renewable project selling CBAM-verifiable electricity to a steel, aluminium or fertiliser exporter may have a stronger offtake story than a merchant project exposed only to spot prices. The PPA is no longer just a price hedge; it is part of the buyer’s market-access infrastructure. That could improve contract durability and credit quality, especially where the buyer’s EU customers require low-carbon documentation.

But this only works if the PPA is technically credible. Lenders should review the metering design, certificate regime, delivery profile, balancing obligations, curtailment risk, grid connection, buyer consumption profile and CBAM evidence obligations. A PPA that looks attractive commercially may still be weak if it cannot support the buyer’s actual indirect-emissions claim.

There is also a regional policy angle. Serbia, Montenegro, Bosnia and Herzegovina, North Macedonia and Albania can turn renewable electricity into an export-competitiveness tool if they build credible certificate systems, grid data transparency, renewable registries and industrial PPA frameworks. Without that infrastructure, exporters may face higher default factors and weaker EU customer confidence, even where renewable generation exists.

For SEE power exchanges and system operators, the framework points toward more granular data. Hourly market prices, generation technology data, residual mix factors, grid emission factors and cross-border flow transparency will become more valuable. Industrial buyers and their EU declarants will need more than annual national averages. They will need auditable electricity data that can support product-level embedded-emissions reporting.

The commercial vocabulary of electricity is therefore changing. Producers will talk not only about MWh and price, but about traceability. Traders will talk not only about baseload and peakload, but about allocation and verification. Buyers will compare not only fixed and indexed supply, but default-factor exposure versus actual-emissions eligibility. Banks will ask not only for PPA tenor, but for CBAM defensibility.

The market is moving toward a two-tier electricity product. The first tier is ordinary electricity, priced mainly by market conditions. The second tier is compliance-grade electricity, priced by market conditions plus evidence value. CBAM is likely to accelerate the premium for the second tier because industrial buyers exporting to the EU will need to defend their emissions data under increasing scrutiny.

The most prepared producers and traders will start building that product now. They will identify industrial buyers with CBAM exposure, map their load profiles, match them with renewable assets, design PPAs with evidence clauses, integrate metering data, structure certificate retirement and provide monthly audit files. They will not wait for the final legal detail to arrive because the technical direction is already visible.

The energy-market conclusion is direct: CBAM is turning electricity into a documented industrial input. For power producers and traders, the next competitive advantage will be the ability to sell not only electrons, but verified low-carbon electricity evidence. For industrial buyers, the next procurement decision will not be only which supplier offers the best price. It will be which supplier can keep their EU market access defensible.

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The Commission frames the study around three policy questions: how to determine operational default emission factors for indirect emissions, under what conditions declarants should be allowed to claim actual indirect emissions, including rules for direct technical links, PPAs and verification, and whether indirect emissions should be extended to additional CBAM sectors. This means the study is not only technical; it is a design paper for the definitive CBAM period, especially for exporters that use electricity-intensive processes. (Taxation and Customs Union)

The broader final report says the analysis combines methodological assessment, review of existing CBAM rules, scenario testing and stakeholder input. It weighs environmental integrity, carbon-leakage prevention, administrative feasibility, even-handed treatment between EU and non-EU producers, and risks such as resource shuffling, weak data, verification complexity and overlap with EU indirect cost compensation. (Publications Office of the EU)

The main policy signal

The main signal is that electricity is becoming a core CBAM compliance variable. Until now, many exporters have treated CBAM mainly as a question of plant-level process emissions: fuel combustion, calcination, process chemistry, reduction agents, furnace emissions and other direct sources. The Commission’s new study makes clear that the electricity side is moving closer to formal compliance architecture.

This matters most for aluminium, steel, fertilisers, cement, hydrogen and electricity-intensive processing chains, especially in countries outside the EU where grid electricity can have a higher carbon intensity than the EU average. For the Western Balkans, Türkiye, Ukraine, North Africa, the Gulf and parts of Asia, the study points toward a future where exporters will need much stronger evidence of electricity origin, metering, consumption boundaries and contractual power supply.

Task 1: Default emission factors

The first policy area is the design of default emission factors for indirect emissions. In practical terms, this means deciding which emissions factor should be used when an exporter or declarant cannot prove actual electricity-related emissions with sufficient quality.

The commercial importance is substantial. A default factor can become the baseline penalty for weak data. If an exporter cannot document actual electricity consumption and supply, the CBAM declarant may have to rely on a conservative default value. For countries with carbon-intensive grids, this could raise the embedded-emissions figure and increase the CBAM certificate exposure once the definitive system is fully operational.

For exporters, the operational lesson is clear: weak electricity data may become expensive. Plants will need to show not only total electricity consumption, but consumption by installation, production line, product route, batch or process boundary. For aluminium, steel rolling, ferroalloys, cement grinding, ammonia, hydrogen or precursor production, this pushes CBAM readiness into electrical metering architecture, not only environmental reporting.

Task 2: Actual indirect emissions, PPAs and verification

The second policy area is the most important for exporters and industrial buyers. The study examines when declarants should be allowed to claim actual indirect emissions, including requirements for direct technical links, power purchase agreements and verification. The Commission’s publication explicitly identifies PPAs and technical links as central design conditions. (Taxation and Customs Union)

This is a major signal for green electricity procurement. It means that an exporter’s claim that it uses renewable or low-carbon electricity will likely need to be supported by more than a simple certificate or supplier statement. The study points toward a framework where the credibility of actual indirect-emissions claims depends on physical, contractual and verification evidence.

A direct technical link would likely be the strongest form of proof: for example, a dedicated renewable generation asset connected to the production installation or a clearly traceable behind-the-meter arrangement. PPAs may also be relevant, but the key issue will be whether the PPA proves genuine low-carbon electricity consumption or merely reallocates clean electricity on paper while the physical grid remains carbon-intensive.

This is where resource shuffling becomes central. The final report metadata highlights resource-shuffling risk as one of the study’s key concerns. Resource shuffling occurs when clean electricity is contractually assigned to CBAM-export production while dirtier electricity is left for other users, without reducing total system emissions. The Commission is clearly concerned that actual-emissions claims must not become a paper exercise that undermines environmental integrity. (Publications Office of the EU)

For Serbian and SEE exporters, this creates a practical due-diligence agenda. A green PPA will not be enough unless it is supported by a credible data package: power meter readings, hourly or sub-hourly consumption records where relevant, generation proof, grid connection documentation, GO or equivalent certificate controls, matching logic, settlement records, and independent verification. This turns electricity procurement into a CBAM engineering task.

Task 3: Extension to additional sectors

The third policy area is whether and how indirect-emissions coverage could be extended to more CBAM sectors. Under the definitive CBAM framework, indirect emissions are currently covered for cement and fertilisers, while during the transitional period indirect emissions are reported for all CBAM goods except electricity, according to the Publications Office summary for Task 2. (Publications Office of the EU)

The Task 3 summary places this question inside the broader EU carbon leakage framework, including the EU ETS Directive, free allocation, indirect cost compensation and the CBAM Regulation. It also notes that state-aid rules for indirect cost compensation define how Member States may compensate electricity-intensive industries for indirect carbon costs passed through power prices. (Publications Office of the EU)

This is politically sensitive. If the EU extends CBAM indirect-emissions coverage too widely, non-EU exporters could face a higher compliance and cost burden. But if the EU does not extend it, EU producers that pay indirect carbon costs through electricity prices may argue that imports are not facing an equivalent carbon constraint. The study is therefore trying to balance environmental integrity, WTO/legal robustness, administrative feasibility and competitive neutrality.

For energy-intensive sectors, this is the start of a larger debate. Aluminium is the obvious candidate because electricity is central to primary aluminium emissions and cost structure. Steel can also be affected, especially electric arc furnace routes, rolling, downstream processing and hydrogen-based pathways. Fertilisers already have strong relevance because electricity can influence ammonia, hydrogen and related production routes. Cement is affected through grinding and electricity consumption, even though process emissions remain dominant.

Implications for exporters

The exporter implication is direct: CBAM readiness must now include an electricity evidence system. Exporters should not wait for final legal wording before building the data architecture. The minimum credible package should include plant electricity balance, production-process boundary maps, product-level electricity allocation rules, metering hierarchy, electricity supplier contracts, PPA documentation, guarantees of origin or equivalent instruments, grid-emission-factor assumptions, and an audit trail linking electricity use to exported goods.

For a Serbian steel, aluminium, cement, fertiliser or precursor producer, the key question becomes: can the plant prove what electricity was consumed, when it was consumed, where it came from, how it was allocated to the exported product, and whether the claim can survive importer and verifier review?

This also changes the role of the EU importer. The importer or authorised CBAM declarant cannot simply accept supplier declarations at face value. The importer will need a mirror-verification protocol: supplier data request, plausibility check, electricity contract review, metering evidence, production volume reconciliation, embedded-emissions calculation review, and escalation rules if data quality is weak.

Implications for PPAs and renewable developers

The study creates a new commercial opportunity for renewable developers outside the EU. A PPA with an exporter may become more valuable if it helps reduce CBAM indirect-emissions exposure. This can improve offtaker credit quality and strengthen the bankability of renewable projects serving industrial customers.

However, PPA value will depend on compliance credibility. A generic green electricity contract will be weaker than a structured CBAM-ready PPA with clear metering, generation matching, certificate retirement, grid connection evidence, delivery shape, balancing responsibility and verification access. Renewable developers, banks and exporters should therefore treat CBAM as a new bankability layer in industrial PPAs.

For SEE renewable markets, this is particularly important. Serbia, Montenegro, Bosnia and Herzegovina, North Macedonia and Albania have industrial exporters that could benefit from documented low-carbon power. The strongest commercial model is not just “green electricity”; it is CBAM-verifiable electricity.

Implications for verification and Owner’s Engineer-type support

The study reinforces the need for third-party technical support before formal verification. Exporters will need technical consultants who understand production processes, electricity systems, metering, SCADA, PPAs, guarantees of origin, emission-factor logic and audit trails. This is closer to Owner’s Engineer / technical due diligence than classic accounting support.

A practical CBAM indirect-emissions readiness review should cover the plant’s electrical single-line diagram, grid and self-generation interfaces, metering points, transformer and substation records, SCADA logs, production-line consumption, production allocation rules, PPA settlement data, certificate registry evidence, and reconciliation between production volumes and electricity consumption. Without that technical basis, a legal or accounting declaration will remain exposed.

View on three core takeaways

First, the Commission is preparing the ground for operational indirect-emissions rules in CBAM. The study is not a final regulation by itself, but it is a policy evidence base for the definitive period and future design decisions. (Publications Office of the EU)

Second, actual indirect-emissions claims will likely require robust evidence. The study explicitly focuses on direct technical links, PPAs and verification, which means that electricity procurement, metering and contractual proof will become central to CBAM compliance. (Taxation and Customs Union)

Third, extension of indirect-emissions coverage to more sectors could become one of the next major CBAM policy moves. This would raise the strategic importance of green electricity for exporters and could reshape industrial PPAs, renewable project bankability and supply-chain due diligence for EU-bound products. (Publications Office of the EU)

Practical action list for exporters

Exporters should immediately map electricity consumption by product and process, identify all metering gaps, collect electricity supplier and PPA documentation, establish a guarantee-of-origin or equivalent certificate-control process, build a product-level electricity allocation methodology, prepare a default-versus-actual-emissions comparison, and create a verification file that an EU importer can review before CBAM costs become financially material.

The strategic conclusion is simple: CBAM is moving from emissions reporting into electricity documentation. For exporters in carbon-intensive grids, the ability to prove low-carbon electricity use may become a competitive advantage, while weak data may translate directly into higher CBAM exposure.

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Week 23 captured the transition. Regional demand rose 8.2%, variable renewables fell 8.9%, wind dropped 15.5%, thermal generation increased 24.5%, hydro rose 10.1%, and imports climbed 9.1%. This was not a simple supply shortage or a renewable success story. It was a flexibility stress test.

The region passed the test through a combination of hydro, thermal generation and cross-border flows. But this balancing model is not enough for a decarbonising system. Thermal generation carries carbon and fuel risk. Hydro depends on hydrology. Imports depend on neighbouring availability and interconnector capacity. That leaves a clear investment gap.

Batteries are the most immediate opportunity. The evening price ramp creates a commercial case for storage that can charge during lower-price solar hours and discharge during peaks. Two-hour and four-hour systems can support arbitrage, balancing and ancillary services. Co-located BESS can improve solar and wind project bankability.

Pumped storage offers the long-duration layer. SEE’s hydro geography gives the region natural potential, but projects require long development timelines, permitting, grid coordination and public-private financing structures. As solar penetration rises, long-duration storage will become more valuable.

Interconnectors are another investment theme. Persistent spreads between Italy, Greece, Hungary, Romania, Serbia, Bulgaria and Croatia show that transmission constraints still limit market efficiency. More cross-border capacity can reduce price fragmentation, improve security and monetise regional surplus.

Digital infrastructure also matters. Forecasting systems, SCADA integration, intraday trading platforms and balancing-market optimisation will become essential. Flexibility is not only physical; it is informational. The ability to forecast wind, solar, demand and congestion has direct financial value.

For investors, this creates a broader opportunity than generation alone. The next energy assets in SEE will include storage portfolios, flexibility platforms, grid equipment, forecasting services, balancing aggregators and hybrid renewable projects. Utilities and developers that move early can capture premium margins.

Week 23 showed the region’s future in compressed form. Demand volatility, renewable volatility and fuel-price risk are all increasing the value of flexibility. The next SEE investment cycle will be built around assets that can respond, shift, store and optimise power, not only produce it.

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TTF gas futures averaged €48.56/MWh, while the one-month forward contract was near €49.335/MWh. At the same time, SEE power prices ranged from €89.25/MWh in Greece to €128.09/MWh in Italy, with several markets clustered around €100/MWh. This is not a low-risk procurement environment.

The volatility was driven by fundamentals. Demand rose 8.2%, variable renewables fell 8.9%, hydro rose 10.1%, thermal generation increased 24.5%, and net imports climbed 9.1%. Each of these variables can affect price shape. Together, they create a market where weekly and hourly outcomes can shift quickly.

For industrial companies, the issue is budget protection. Electricity can be a major operating cost, especially in metals, chemicals, cement, fertilisers, food processing and data centres. A poorly hedged energy position can erode margins even when production volumes remain stable.

For generators, hedging protects revenue. Merchant renewables face capture-price risk and imbalance exposure. Thermal plants face fuel-cost risk. Hydro operators face water-value timing risk. Batteries face spread-risk assumptions. Each asset class needs a different hedge design.

For lenders, hedging affects debt service. A project with unmanaged merchant exposure may not support the same leverage as a project with contracted revenues, storage-backed flexibility or a balanced hedge book. Energy volatility therefore feeds directly into DSCR, equity IRR and covenant design.

Corporate PPAs are part of the solution, but not the full answer. Buyers and sellers need to define volume shape, balancing responsibility, price indexation, curtailment treatment, guarantee-of-origin delivery and termination risk. A weakly structured PPA can simply move risk from one side to the other.

The gas market adds another layer. LNG supply risk, storage levels around 38%, limited US export spare capacity and TurkStream maintenance all feed into regional power-price expectations. Even companies buying electricity rather than gas are exposed when gas-fired generation sets marginal prices.

Week 23 showed that energy hedging is no longer a technical treasury exercise. It is strategic. Companies that understand their hourly consumption, fuel exposure, contract structure and carbon obligations will have a competitive advantage. In SEE, energy risk has moved from the trading desk to the boardroom.

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Net imports across SEE increased 9.1% week on week to 1.22 TWh. The largest increase came from Hungary, where net imports rose 64.7% to 179.75 GWh. Romania increased imports 34.0%, while Croatia raised imports 18.5%. Italyremained the region’s largest importer with 950.91 GWh, despite reducing imports 14.1%.

The flow shifts came during a week of strong regional stress. Demand rose 8.2%, variable renewables fell 8.9%, wind output dropped 15.5%, and thermal generation increased 24.5%. In this environment, interconnectors became balancing tools.

Price spreads remained wide enough to support trading. Italy averaged €128.09/MWh, while Greece was at €89.25/MWh and several Balkan markets clustered around €100/MWh. These differences create opportunities, but only for market participants with access to capacity, forecasting tools and scheduling capability.

The new trading market is not only day-ahead arbitrage. It includes intraday adjustments, congestion management, transmission rights, balancing positions and portfolio optimisation. As renewables grow, forecast errors and hourly price shifts become more valuable to manage.

Greece and Türkiye remained net exporters, although exports fell. Their positions matter because lower-priced export supply can influence neighbouring markets when capacity allows. But persistent price divergence shows that physical constraints and market rules still prevent full convergence.

For traders, the core asset is optionality. The ability to move power from a lower-priced node to a higher-priced market, or to adjust positions intraday when wind or solar forecasts change, can generate value. For generators, export optionality improves realised revenue. For industrial buyers, cross-border procurement can reduce cost exposure.

This creates a strategic role for data, forecasting and trading systems. Market participants need accurate renewable forecasts, demand models, interconnector capacity monitoring and price-spread analytics. In a volatile SEE market, information speed becomes financial value.

Week 23 confirmed that cross-border trading is no longer a secondary function. It is becoming part of the region’s core market architecture. As demand rises, renewables fluctuate and price spreads persist, flow volatility will create both risk and opportunity.

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The market data explain why. SEE demand rose 8.2% week on week, variable renewables fell 8.9%, thermal generation increased 24.5%, hydro rose 10.1%, and net imports climbed 9.1%. Prices diverged sharply across the region, from €128.09/MWh in Italy to €89.25/MWh in Greece and €99–103/MWh across much of Central SEE. This was a flexibility market.

Hydro-rich systems had a clear advantage where water availability improved. Serbia increased hydro output 30.8% and saw prices fall 5.8%. Croatia lifted hydro generation 73.6%. Türkiye increased hydro output 15.4% and still managed to remain a net exporter despite a 31.0% demand surge. Flexible hydro allowed systems to respond to price shape and residual demand.

Thermal flexibility also retained value, despite carbon and fuel risks. Türkiye more than doubled thermal generation, while Greece increased lignite output 66.2%. These assets are politically and environmentally exposed, but during tight weeks they remain commercially relevant. The market pays for availability when renewables underperform and demand rises.

Battery storage is the next flexibility layer. Utilities that move early into BESS can capture evening spreads, support renewables, provide ancillary services and reduce imbalance exposure. As solar penetration rises, storage will increasingly separate higher-quality renewable portfolios from simple megawatt pipelines.

Interconnector access is another valuation driver. Italy’s premium price of €128.09/MWh and its net imports of 950.91 GWh show that export optionality has value. Utilities with access to constrained corridors, trading desks and regional optimisation capabilities can monetise spreads more effectively than purely domestic generators.

This changes how investors should read SEE utilities. A company’s value should not be assessed only by installed capacity, annual generation or regulated tariffs. The key questions are: how flexible is its portfolio, how exposed is it to fuel costs, how much storage or hydro does it control, how strong is its grid position, and can it trade across borders?

The energy transition increases this flexibility premium. More solar and wind mean more volatility. More volatility means more value for assets that can shift, store, balance or trade electricity. Week 23 was a practical demonstration of that shift.

SEE utilities with flexible assets should attract a different valuation logic. The market is moving from megawatt volume to dispatch value.

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The weekly price spread was substantial. Italy averaged €128.09/MWh, while Greece stood at €89.25/MWh, Serbia at €99.63/MWh, Croatia at €99.29/MWh, Bulgaria at €100.83/MWh, Romania at €102.23/MWh and Hungary at €103.15/MWh. Türkiye remained structurally cheap at €22.53/MWh, but largely outside the normal SEE price range.

For industrial buyers, the risk is not only high prices. It is unpredictable price formation. Demand rose 8.2%, variable renewables fell 8.9%, thermal generation increased 24.5%, and gas prices remained close to €50/MWh. This combination can change procurement costs quickly, especially during evening peaks and low-renewable periods.

Traditional fixed-price contracts may protect budgets but can become expensive if suppliers price in volatility. Pure spot exposure preserves flexibility but leaves companies vulnerable to spikes. Indexed contracts can reduce supplier premiums but transfer market risk to the buyer. The right structure increasingly depends on load shape, production flexibility, carbon exposure and risk appetite.

Corporate PPAs are becoming more important, but they are not simple solutions. A solar PPA may reduce average cost and support green claims, but it may not match industrial consumption during evening or night shifts. A wind PPA may provide better non-solar-hour output but carries forecast risk. Hybrid PPAs with storage may offer stronger value but require more complex structuring.

For CBAM-exposed exporters, procurement strategy also has a compliance dimension. Green electricity documentation, guarantees of origin, hourly matching and audit-ready metering can affect the credibility of low-carbon claims. Electricity procurement is therefore linked to customer retention, export competitiveness and regulatory risk.

Hedging also needs to become more granular. Industrial buyers should consider layered procurement: fixed baseload volumes, indexed market exposure, PPA-backed renewable blocks, intraday optimisation, demand response and financial hedges where available. Large users with flexible production schedules may also monetise price volatility by shifting consumption away from peak hours.

Week 23 confirmed that SEE power markets are becoming more sophisticated and more demanding. The old procurement model — buy annual volume, accept supplier price, manage invoices — is no longer enough. Industrial buyers need portfolio strategies.

The companies best positioned will be those that understand their hourly load, carbon exposure, flexibility potential and contract risks. In SEE’s new power market, electricity procurement is becoming a financial discipline.

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The weekly price range was wide. Italy averaged €128.09/MWh, Hungary €103.15/MWh, Romania €102.23/MWh, Bulgaria €100.83/MWh, Serbia €99.63/MWh, Croatia €99.29/MWh, Greece €89.25/MWh and Türkiye €22.53/MWh. Such divergence affects industrial competitiveness directly, especially for electricity-intensive producers.

At the same time, the generation mix shifted toward dispatchable conventional output. Thermal generation rose 24.5% week on week, while variable renewable generation fell 8.9%. In Türkiye, gas-fired generation jumped 278.1%, while Greece increased lignite output 66.2%. This matters for embedded emissions because electricity sourced from systems with higher fossil dispatch can carry a different carbon profile than electricity backed by renewable PPAs or documented green supply.

CBAM will increase the importance of credible electricity documentation. Exporters selling into the EU will need to understand not only their direct emissions, but also the electricity basis used in their embedded-emissions calculations where applicable. Annual procurement claims will not be enough if buyers, declarants or verifiers require stronger evidence of renewable sourcing, hourly matching or contract credibility.

This creates a new role for green PPAs. A renewable PPA can reduce price exposure, support decarbonisation claims and improve buyer confidence. But it must be structured carefully. The industrial buyer needs evidence of generation source, grid connection, metering, guarantees of origin or equivalent certificates, balancing responsibility and delivery profile.

Battery-backed renewable procurement can become more attractive. Storage can improve the match between renewable generation and industrial consumption, reduce reliance on fossil-heavy evening power and strengthen the credibility of green electricity claims. For large exporters, this may become part of a wider CBAM-ready procurement strategy.

Week 23 also showed why relying only on the spot market is risky. Industrial buyers exposed to volatile day-ahead prices may face sudden cost increases when gas prices rise, renewables fall or imports tighten. A structured procurement portfolio — combining PPAs, hedges, guarantees of origin and flexible consumption — can reduce both price and carbon risk.

For SEE exporters, electricity strategy is becoming part of market access. Buyers in the EU will increasingly ask how electricity was sourced, how emissions were calculated and whether low-carbon claims are auditable. Power-market volatility therefore feeds directly into CBAM readiness.

The industrial winners will be those that treat electricity procurement as a compliance architecture, not only a purchasing function. In a volatile SEE market, green electricity is becoming both a cost hedge and a carbon-risk control.

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Variable renewable output fell 8.9% week on week, with wind down 15.5% and solar down 5.1%. At the same time, regional electricity demand rose 8.2% to 15.15 TWh. Thermal generation increased 24.5%, while net imports rose 9.1%. Prices moved differently across the region, with Bulgaria and Italy rising while Serbia, Hungary, Croatia and Romania softened.

This is exactly the kind of market that exposes weak revenue modelling. A solar project may face low midday prices even when weekly averages are high. A wind project may have strong annual output but high imbalance costs during volatile weeks. A merchant project may look attractive under average market prices but lose value if its generation profile is poorly matched with high-price hours.

Bankable RES projects now need layered revenue stacks. Day-ahead market income is only one component. Developers must consider intraday optimisation, balancing-market participation, ancillary services, corporate PPAs, guarantees of origin, battery co-location and curtailment management. The stronger the revenue stack, the more resilient the project.

This is especially important in Greece, Romania, Bulgaria, Croatia, Serbia and Hungary, where renewable pipelines are growing and grid constraints are becoming more visible. In these markets, lenders should ask not only how much energy a project produces, but when it produces, where it is connected, who takes imbalance risk and how curtailment is allocated.

Corporate PPAs can improve bankability, but only if structured properly. Fixed-price PPAs reduce merchant exposure, but may transfer shape and balancing risk to the generator. Indexed PPAs can preserve market upside, but leave offtakers exposed to volatility. Hybrid PPAs with storage, guarantees of origin and delivery-shape clauses may become more common.

Batteries are increasingly part of the bankability solution. They can shift output, reduce imbalance costs, capture evening spreads and improve firmness. For solar projects, BESS can protect against price cannibalisation. For wind projects, it can smooth forecast deviations and support balancing strategies.

Week 23 showed that SEE renewables are no longer operating in a simple growth market. They are entering a complex power-market environment where volatility, flexibility and grid access decide returns. The next bankable renewable projects will be those designed for this complexity from the start.

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The movement was broad. Hungary increased net imports 64.7% to 179.75 GWh, Romania raised imports 34.0%, and Croatia increased imports 18.5%. Italy remained the largest net importer, with 950.91 GWh, even though its imports fell 14.1% from the previous week. Greece and Türkiye remained net exporters, although both reduced export volumes.

These flows matter because SEE prices remained fragmented. Italy averaged €128.09/MWh, while Greece averaged €89.25/MWh, Serbia €99.63/MWh, Bulgaria €100.83/MWh, Romania €102.23/MWh, Hungary €103.15/MWh and Croatia €99.29/MWh. Wide spreads create theoretical arbitrage value, but actual value depends on interconnector availability, congestion and scheduling rules.

This makes transmission capacity a financial asset. The ability to move power between price zones can be as valuable as generation itself. Traders who secure capacity across constrained borders can capture spreads. Generators with access to export routes can improve realised prices. Industrial buyers can reduce procurement costs if they can structure cross-border supply.

Italy’s position is the clearest example. It remained the highest-priced SEE market and the largest net importer. Lower-cost Balkan power has value if it can reach Italian or Central European demand centres. But persistent price differences show that interconnection is not sufficient to fully equalise markets.

Hungary’s import increase is also strategically important. As a Central SEE hub linked to Austria, Slovakia, Croatia, Serbia and Romania, Hungary can transmit price signals across several borders. Its €103.15/MWh weekly average kept it in the upper regional cluster, supporting import demand and cross-border trading interest.

Interconnectors also become more important as renewables grow. Wind and solar variability can quickly change a country’s net position. A market with surplus solar at midday may need imports in the evening. A wind-heavy system can move from export to import depending on weather. Cross-border capacity is therefore a flexibility tool, not only a trading instrument.

For TSOs and regulators, Week 23 reinforces the case for grid reinforcement, market coupling, intraday liquidity and transparent capacity allocation. For investors, it shows that generation projects should be assessed together with grid access and export optionality. A project in a constrained node may have lower value than a similar asset with access to liquid cross-border routes.

SEE is not yet one integrated price zone, but it is increasingly one interconnected balancing region. Interconnectors are where that tension becomes visible. As imports rise and price spreads persist, transmission capacity will carry more strategic and financial value.

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The immediate issue is Qatari LNG. Qatar is a major supplier to Asia, and any disruption would force Asian buyers to secure alternative cargoes. Europe’s direct dependence on Qatari LNG has declined to around 8% of total imports, but that does not eliminate risk. LNG is a global market. If Asian buyers bid more aggressively for cargoes, Europe must pay more to attract supply.

The report notes that European benchmark gas prices may need to rise 40–50% from current levels to secure sufficient LNG if disruptions to Qatari exports persist. With TTF already averaging €48.56/MWh during Week 23 and the one-month forward near €49.335/MWh, such an increase would be material for power pricing.

US LNG cannot easily fill the gap. Export facilities were operating at approximately 94% utilisation, leaving limited spare capacity. This means the adjustment mechanism would be price, not immediate additional supply. Europe would have to compete for available cargoes, pushing TTF higher.

For SEE, the link comes through several channels. Italy, Greece and Croatia all have LNG import infrastructure that affects regional gas balance. During Week 23, LNG inflows to Greece recovered to 860.32 GWh, Italy received 2,836.03 GWh, and Croatia received 645.30 GWh. These terminals are not peripheral assets; they are part of the region’s supply-security architecture.

Higher LNG prices would feed into gas-fired power generation. That matters most during evening peaks, low-wind periods and high-demand weeks. In Week 23, Turkish gas-fired power generation jumped 278.1%, while thermal generation across SEE rose 24.5%. If gas prices rise sharply, the cost of this balancing response rises with them.

A Hormuz shock would also affect industrial electricity buyers. Even companies without direct gas exposure can face higher power prices if gas-fired generation sets marginal prices. Steel, aluminium, cement, fertiliser, chemicals and data centres would all feel the effect through electricity costs, hedging needs and procurement risk.

The impact would not be uniform. Markets with stronger hydro or lignite availability may be less immediately exposed than gas-heavy systems. But because SEE markets are interconnected, higher prices in Italy, Greece or Hungary can influence flows and spreads across the Balkans.

The key lesson is that SEE energy security is now linked to global maritime chokepoints. The region’s gas exposure is no longer only about Russian pipeline routes or local storage. It is also about LNG cargo competition between Europe and Asia. A disruption in the Strait of Hormuz would not need to land directly in the Balkans to reprice Balkan electricity.

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Gas matters because it often sets or influences marginal power pricing during tight hours, especially in markets such as Italy, Greece, Türkiye, Hungary and Romania. Even where gas does not dominate total generation, it can define the price of flexibility during evening ramps, low-wind periods and high-demand conditions.

Week 23 showed this clearly. Regional electricity demand rose 8.2%, variable renewables fell 8.9%, and thermal generation increased 24.5%. Türkiye’s gas-fired power generation jumped 278.1%, while Romania also increased thermal output with stronger gas-fired contribution. Gas became part of the balancing response, not just a fuel-market issue.

For investors, this changes project economics. A renewable project’s revenue may rise during gas-driven price spikes, but its balancing costs and PPA structures may also become more complex. A gas-fired plant may benefit from scarcity pricing, but its fuel-cost exposure can erode margins unless hedged. An industrial offtaker may face higher electricity prices even if it does not buy gas directly.

The gas-price risk is being driven by more than normal seasonal storage dynamics. The report highlights geopolitical uncertainty, US-Iran tensions, risk around Persian Gulf energy flows and concerns over LNG supply. European storage was around 38% full, while US LNG export facilities were operating at approximately 94% utilisation, limiting short-term supply flexibility.

The LNG risk is especially relevant. Around 20% of global LNG trade passes through the Strait of Hormuz, and disruption to Qatari exports could force Asian buyers to compete aggressively for Atlantic Basin cargoes. Analysts cited in the report suggested European gas prices may need to rise 40–50% from current levels to attract enough LNG if disruptions persist.

For SEE power finance, this means gas-price stress cases need to be updated. Lenders should test merchant power revenues, PPA indexation, balancing-market costs and industrial offtaker creditworthiness against higher fuel-price scenarios. A project that looks bankable at €45–50/MWh gas may behave differently if TTF moves materially higher.

Gas also interacts with inflation and interest rates. Higher gas prices can lift electricity prices, industrial costs and consumer inflation. That can affect central-bank policy, financing costs and demand. In a region where many energy projects depend on long-tenor debt, fuel volatility can quickly become a financial-market issue.

The Week 23 signal is clear. Gas risk is back inside the power-finance model. SEE investors cannot treat TTF as a background variable. It is again one of the key drivers of merchant prices, hedging needs, industrial electricity costs and project stress cases.

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The project was delivered by Allview Energy, the renewable energy arm of Romanian technology company Visual Fan, on behalf of Teiuș Solar, a local subsidiary of Danish renewable developer Eurowind Energy.

Visual Fan executed the project under a turnkey engineering, procurement and construction (EPC) contract, overseeing all stages of development. This included system design, equipment procurement, construction works, installation, technical integration, testing, and final commissioning.

The completed battery system is among the more significant storage projects currently operating in Romania, reflecting the country’s growing focus on technologies that can balance intermittent renewable generation and improve overall grid stability and flexibility.

The project follows a contract awarded to Visual Fan in 2025, when the agreement for the development of the storage facility was valued at more than €16.6 million.

As Romania continues to expand its renewable energy capacity, large-scale battery systems are becoming increasingly important for storing surplus electricity, supporting grid reliability, and enabling a smoother transition toward a more decarbonized and flexible energy system.

The Teiuș solar power plant, with an installed capacity of 69 MW, was commissioned by Eurowind Energy in April 2025.

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The planned battery energy storage system (BESS) will have an installed power of 4.47 MW and a storage capacity of 8.94 MWh. The total investment is estimated at approximately €2.1 million, with around €385,000 expected to be financed through grants from the EU-backed Modernization Fund.

The storage system will be added to the Colibași solar power plant, a 15-hectare facility that has been operational since 2013. The site contains more than 39,000 photovoltaic panels and represents one of PPC Renewables’ established generation assets in Romania.

In addition to the battery installation, the project includes a wider set of infrastructure upgrades. These involve the construction of operation and maintenance facilities, improvements to internal roads and access infrastructure, enhanced perimeter security systems, lighting and monitoring equipment, as well as the development of logistics areas required for daily operations.

By integrating storage into an operational solar plant, PPC Renewables aims to increase the plant’s operational flexibility, enabling excess solar generation during peak production hours to be stored and later delivered when demand is higher or renewable output is lower.

Overall, the investment reflects a broader trend in Romania’s renewable energy sector, where developers are increasingly combining solar assets with battery storage systems to support a more stable, flexible, and modern electricity grid.

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The utility is seeking a contractor to carry out initial activities valued at approximately €1.72 million. Interested companies have until 10 July to submit their bids, while the selected contractor will be required to complete the works within a maximum period of 180 days.

This tender is part of a broader preparatory phase with a total estimated value of around €6.7 million. The works are intended to prepare the groundwork for the construction of one of Montenegro’s largest planned solar facilities.

The future solar park will be located near Lake Krupac in the Nikšić region and will cover approximately 118 hectares across three separate sites. Once operational, the 41.8 MW solar plant is expected to generate around 62 GWh of electricity annually.

Earlier this year, EPCG awarded a contract to the local engineering firm Greener to prepare the main project design documentation. This study will serve as the foundation for subsequent development phases and the eventual construction of the facility.

According to earlier estimates, the total investment in the Krupac solar power plant is expected to reach about €28 million. The project is part of EPCG’s broader strategy to expand renewable energy capacity in Montenegro and increase the share of solar power in the national electricity mix, supporting the country’s long-term energy transition goals.

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The installation consists of two battery storage units with a combined capacity of 99.8 MW. Its development was supported by more than €31 million in non-repayable European Union funding, making it one of the most significant energy storage investments in Hungary to date.

Government officials stated that the facility will improve the flexibility of the electricity system by helping to balance fluctuations between supply and demand. It is also expected to enhance market competition, reduce system balancing costs, and contribute to more stable electricity prices over the long term.

The Buj battery project was developed by Greenvolt Power, a subsidiary of the Greenvolt Group. Company representatives described it as their second investment in Hungary and indicated that another project in the country is already being prepared. Greenvolt operates exclusively in the renewable energy sector and is active across Europe, Asia, and North America as part of the investment portfolio of US-based KKR.

Each of the two installed battery systems has a rated power of 49.9 MW and an energy storage capacity of 144.3 MWh. The assets are operated through the project companies Buj Energy Storage and Buj Battery.

Overall, the project reinforces Hungary’s growing role in energy storage deployment in Central Europe, supporting grid stability and enabling higher penetration of renewable energy sources.

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New data from the Green Tank research organization show that LNG covered nearly two-thirds of Greece’s gas demand in the first five months of the year. Imports via the Revithoussa LNG terminal and the Alexandroupoli floating storage and regasification unit (FSRU) reached a record 18.9 TWh between January and May, accounting for 64.3% of total consumption.

At the same time, Russian pipeline gas has continued to lose market share. Deliveries through the Sidirokastro interconnection totaled 7.2 TWh, marking a decline of almost 40% compared with the same period in 2025. This reduced Russia’s share of the Greek gas market to 24.4%, down significantly from previous levels.

Azerbaijan also saw a slight reduction in its role. Gas flows through the Trans Adriatic Pipeline (TAP) entering Greece at Nea Mesimvria amounted to 4.3 TWh, giving it a 14.7% market share.

This shifting import structure supports Greece’s strategic goal of fully phasing out Russian gas imports by the end of 2027. However, the transition is not without challenges. Rising geopolitical tensions in the Middle East have contributed to higher LNG prices, increasing the overall cost of diversification.

Another emerging issue is Greece’s growing dependence on American LNG. In certain periods, shipments from the United States accounted for up to 80% of total LNG imports, raising concerns about supply concentration despite improved diversification away from Russia.

Beyond domestic consumption, Greece is increasingly strengthening its position as a regional gas hub. Gas exports surged during the first five months of the year to 8 TWh, four times higher than in the same period of 2025. Around 6.7 TWh of these exports were transported northward through the Sidirokastro pipeline to Balkan markets.

Despite these structural changes, total gas consumption remained stable at 29.35 TWh. The power generation sector remained the largest consumer, accounting for 63.1% of demand, followed by households and small businesses at 25.4%, while industrial users made up 11.6%.

Overall, the data highlight Greece’s dual transition: reducing reliance on Russian gas while expanding LNG infrastructure and reinforcing its role as a key energy gateway for Southeast Europe.

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NPP Kozloduy Director Ivan Andreev confirmed that revised documentation has been resubmitted to the Nuclear Regulatory Agency after an earlier application was returned due to technical deficiencies. According to both the operator and regulator, the identified issues have now been addressed, and the proposal is currently undergoing a substantive review process. Experimental fuel assemblies supplied by Westinghouse are planned for introduction into unit 6 as part of the qualification process before broader deployment of the new fuel type.

At the same time, NPP Kozloduy is expanding cooperation with other international suppliers. Representatives of French Framatome are expected to visit the plant later this month for discussions regarding future fuel deliveries for unit 6. Current schedules foresee the arrival of fuel shipments by November, while contractual provisions include penalties in case of delays.

Officials emphasized that the French fuel design is compatible with existing reactor requirements. Even if deliveries were postponed, the plant has sufficient fuel reserves to maintain operations well into the next decade, reducing immediate concerns about supply security. Diversification of nuclear fuel supply remains a broader strategic priority for the facility.

Andreev noted that transactions involving Russian suppliers have become increasingly complicated due to sanctions-related restrictions and concerns among financial institutions about secondary sanctions. These obstacles have slowed payment processing and complicated procurement procedures.

To address these risks, NPP Kozloduy has been expanding its network of alternative suppliers. A growing share of equipment, valves, and technical components is now sourced from Bulgarian manufacturers and companies across the European Union. The utility is also exploring substitute suppliers for specialized membrane systems and other critical equipment.

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The National Electricity Company (NEK) announced that the unit received its final operating permit following inspection by the state commission. The approval confirms that the rehabilitation works meet all technical, construction, and legal requirements, allowing the facility to return to regular service.

This certification marks the completion of the recovery process for unit 3 and represents another step toward the gradual restoration of HPP Chaira to full functionality. Inspectors confirmed that the refurbishment was executed according to approved engineering plans and in full compliance with applicable standards.

The HPP Chaira facility plays a crucial role in Bulgaria’s electricity system and the broader Balkan power market. As the largest pumped-storage hydropower plant in the region, it provides essential balancing and flexibility services that help stabilize increasingly dynamic electricity systems. The plant had been largely offline for several years following unsuccessful repair works that previously led to the shutdown of its generating units.

At the same time, NEK continues restoration activities across the remaining units. Work on unit 1 is currently being performed by Japan’s Toshiba Corporation under an agreed rehabilitation schedule, with completion expected in 2028.

Preparations are also underway for the recovery of unit 4, as the utility advances its broader program to fully restore this strategic energy storage and generation asset.

The return of additional capacity at Chaira is expected to significantly strengthen Bulgaria’s ability to balance renewable energy production, improve grid reliability, and enhance overall energy security across the region.

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The day-ahead market reflected a widening east-west divergence driven by stronger renewable production in the Balkans and increased imports from Central Europe into the regional system. Hungary’s HUPX surged to €111.89/MWh, Romania’s OPCOM reached €111.30/MWh, Bulgaria traded at €110.88/MWh, and Greece led the region at €116.43/MWh. Serbia’s SEEPEX stood out as the regional outlier at €74.33/MWh, while Albania and Montenegro cleared at €84.07/MWh and €89.44/MWh respectively.  

For traders, the most important signal was the return of a strong Hungary-Germany spread of €14.43/MWh, compared with a negative spread the previous day. This immediately increased the attractiveness of imports from Austria and Slovakia into the Hungarian and wider SEE market, with cross-border inflows from the CORE region rising to 1,182 MW.

From a fundamentals perspective, regional consumption eased slightly to 29.3 GW, while total generation slipped to 29.4 GW. Solar output declined sharply by 769 MW day-on-day to 6.27 GW, but this was largely offset by a significant recovery in wind generation, which rose by 442 MW to 1.56 GW. Hydro remained the dominant generation source at 6.67 GW, accounting for approximately 24% of the generation mix. Coal contributed 5.2 GW, gas 4.3 GW, and nuclear 4.1 GW.  

The regional power balance reveals a market that remains structurally long in renewable output despite the reduction in solar production. Net imports for the combined SEE-Hungary region were only 65 MW, indicating near self-sufficiency. However, internal regional flows remained substantial, with Hungary importing heavily from Austria and Slovakia while Greece continued to attract power from northern neighbors.  

A key trading development remains Greece’s persistent premium. At €116.43/MWh, HENEX traded nearly €42/MWh above Serbia and over €5/MWh above Hungary. The premium continues to reflect Greece’s structural dependence on gas-fired generation during evening peaks and its growing role as a regional gas hub.  

Forward markets offered a mixed signal. Hungarian Week-25 baseload strengthened to €109/MWh, while Week-26 rose to €123/MWh. German Week-25 power advanced to €114.50/MWh, indicating that traders continue to price tighter conditions into the second half of June despite improving renewable availability. Gas remained stable, with CEGH Austrian gas at €50.76/MWh, while EUA carbon allowances eased slightly to approximately €77/tCO₂.  

Several structural developments reported across the region are becoming increasingly relevant for medium-term market pricing. Hungary commissioned its largest battery project to date, a 99.8 MW / 288.6 MWh storage facility developed by Greenvolt near Buj. At the same time, Budapest unveiled a €1.5 billion grid-modernization package designed to unlock approximately 4.8 GW of additional renewable capacity. These developments reinforce Hungary’s position as one of the fastest-growing flexibility markets in Central Europe.  

Romania continued to accelerate storage deployment. PPC Renewables announced battery integration at its Colibasi solar facility, while Allview Energy completed a 120 MWh battery project at the 69 MW Teius solar plant. Combined with rapid smart-meter deployment by PPC’s distribution subsidiary, Romania is building the digital and physical infrastructure required for higher renewable penetration and future ancillary-service markets.  

For Serbia, the most significant strategic development remains the reported agreement between Serbian authorities and MOL regarding a potential acquisition of the majority stake in NIS currently held by GazpromNeft. Although the transaction still requires OFAC approval and agreement between the Russian and Hungarian parties, the proposal would increase Serbian state influence over the company and secure commitments regarding continued operation of the Pancevo refinery. From an energy-security perspective, the development reduces uncertainty around Serbia’s largest downstream energy asset.  

Looking ahead to the weekend, weather forecasts point to warmer conditions across most of SEE. Temperatures in Serbia are expected to rise from 17°C on Friday to around 22°C on Saturday before easing slightly. Greece remains above 24°C, while Montenegro and Albania continue to experience temperatures near 23–25°C. These conditions should support another strong solar generation weekend, potentially widening the discount of Western Balkan markets relative to Central Europe if interconnection capacity remains constrained.  

The dominant market theme remains the emergence of a two-speed regional electricity market. Hungary, Romania, Bulgaria and Greece continue to trade near or above €110/MWh, while Serbia, Albania and Montenegro are increasingly reflecting localized renewable surpluses. For traders, utilities and battery operators, the widening spreads between Central Europe and the Western Balkans are creating growing arbitrage opportunities, particularly as new storage assets enter service and cross-border flows become more valuable during periods of solar oversupply.  

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The spread was significant. Greece averaged €89.25/MWh, Serbia €99.63/MWh, Croatia €99.29/MWh, Bulgaria€100.83/MWh, Romania €102.23/MWh and Hungary €103.15/MWh. Italy therefore traded at a premium of nearly €39/MWh to Greece and around €27–29/MWh to several Balkan markets clustered around the €100/MWh level.

This premium matters because Italy remains a major destination for regional power flows where interconnector capacity allows. Even though Italy reduced net imports by 14.1% during the week, it still remained the largest net importer in the SEE region, with 950.91 GWh of net imports. That combination — lower imports but still the highest price — shows how structurally tight the Italian market remains.

For Balkan generators, Italy’s premium creates optionality. Hydro, lignite, gas, wind and solar assets located in neighbouring markets can capture value when export routes are available and congestion does not block flows. For traders, the Italy-Balkans spread creates opportunities in scheduling, hedging, transmission rights and congestion management.

The spread is not always fully tradable. Interconnector constraints, scheduled flow limits, internal bottlenecks and market coupling conditions decide how much price convergence can occur. The Week 23 flow map shows active regional exchanges, but persistent price differences prove that physical and commercial constraints still matter.

Italy’s price structure is also tied to fuel risk. The country remains exposed to gas-linked marginal pricing, even in weeks when gas-fired generation falls. With TTF prices near €49/MWh, Italian power retains a fuel-risk premium that can widen against markets with stronger hydro, lignite or cheaper domestic supply.

For Greece, Croatia, Slovenia and the Western Balkans, Italy’s high-price signal is strategically important. It can improve the economics of flexible generation and cross-border trading, but it also exposes import-dependent consumers to regional price volatility. The same spread that benefits exporters can raise costs for industrial offtakers if domestic markets converge upward.

Italy’s premium also strengthens the investment case for interconnectors and grid reinforcement. Where price spreads persist, transmission capacity has economic value. Projects that increase transfer capability between lower-cost Balkan zones and higher-priced Italian or Central European markets can unlock trading gains, improve security of supply and reduce price fragmentation.

Week 23 showed that Italy continues to function as the region’s high-price sink. For Balkan power markets, that keeps export optionality alive. For investors, it reinforces a simple point: generation value in SEE is increasingly linked not only to output, but to location, interconnector access and the ability to monetise spreads.

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The rise was driven mainly by Türkiye, where thermal output more than doubled, increasing 103.2% to 2.03 TWh. Turkish coal generation rose 55.7%, while gas-fired output jumped 278.1%. This was a direct response to a 31.0% surge in Turkish electricity demand. Even with stronger solar and hydro output, the system required a large conventional response.

Greece also increased thermal generation, with lignite output up 66.2%, while Serbia recorded higher thermal production as well. Romania increased thermal output by 5.2%, supported by stronger gas-fired generation. Italy moved in the opposite direction, with thermal generation down 16.7%, mainly because gas-fired production fell, but Italy still remained the region’s highest-priced market at €128.09/MWh.

The market message is clear. Renewable growth has not removed thermal generation from the SEE price stack. It has changed when thermal generation is needed. Coal, lignite and gas increasingly provide balancing during evening ramps, weak-wind periods, hydro shortfalls and high-demand weeks. That makes thermal assets less about baseload volume and more about system security and marginal pricing.

This has financial consequences. Gas prices near €50/MWh keep gas-fired power expensive. Lignite and coal remain important in several SEE systems, but they carry carbon and policy risks. Thermal units can earn value during tight hours, but their long-term role is exposed to decarbonisation, emissions costs, plant age and regulatory pressure.

The transition risk is therefore two-sided. Retiring thermal capacity too quickly can create security-of-supply problems and price spikes. Keeping it too long can increase carbon exposure, reduce investment in flexibility and weaken alignment with EU climate policy. SEE markets are still trying to manage that balance.

Week 23 is a warning against simplified transition narratives. Solar and wind are growing, but when wind falls 15.5% and demand rises 8.2%, conventional plants still carry the system. The investment question is not whether thermal disappears tomorrow. It is how quickly batteries, hydro flexibility, demand response and interconnectors can reduce the need for thermal ramping.

Until then, thermal generation remains the backstop. It sets the price floor in tight hours, supports reliability and exposes the region to fuel and carbon risk. SEE’s energy transition will be judged by how effectively it reduces this dependency without compromising system security.

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The largest contribution came from Türkiye, where hydro output rose 15.4%, or around 356 GWh, to 2.66 TWh. Croatia posted an even sharper percentage increase, with hydro generation up 73.6%, while Serbia recorded a strong 30.8% rise and Italy increased hydro output by 7.5%. These gains came at a critical moment. Regional demand was up 8.2%, while variable renewable output fell 8.9%.

Hydro’s value is not just in megawatt-hours. It is in timing, dispatchability and system control. Unlike solar, hydro can be scheduled around demand peaks. Unlike wind, it is less exposed to short-term meteorological volatility, although it depends heavily on hydrology and reservoir conditions. In a week with weaker wind and a visible evening price ramp, flexible hydro became a price-moderating asset.

Serbia’s market illustrates the point. Serbian day-ahead prices fell 5.8% week on week to €99.63/MWh, even as the broader SEE region saw stronger demand. Improved local hydro generation, combined with higher thermal output and a modest demand decline, helped reduce local price pressure. In this type of market, hydro availability can override broader regional bullish signals.

Croatia also benefited from a strong hydro rebound, although its prices still softened only modestly. In systems with hydro reservoirs, the commercial question is not simply how much water is available, but how it is dispatched. Water value rises when evening prices are high, imports are expensive and gas-linked generation sets the marginal price.

This strengthens the case for pumped storage and long-duration flexibility. SEE already has large hydro assets, but the next phase of renewable integration will require more sophisticated water management, pumped-storage investment, reservoir optimisation and coordination with solar and wind generation. Hydro can act as the region’s hidden battery, but only if operated and valued as a flexibility resource rather than only an energy source.

For investors, hydro-linked flexibility should command a premium. Assets that can shift generation into high-price hours, provide reserves, stabilise grids and support renewable integration are increasingly valuable. This also affects utility valuations: companies with flexible hydro portfolios should trade differently from generators exposed only to inflexible baseload or merchant solar output.

Week 23 showed that SEE’s flexibility transition is not starting from zero. The region already has a powerful balancing asset in hydro. The next market question is whether that flexibility can be expanded, modernised and priced properly.

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The core system numbers tell the story. SEE electricity demand increased 8.2% week on week to 15.15 TWh. Variable renewable output fell 8.9%, with wind down 15.5% and solar down 5.1%. Thermal generation jumped 24.5% to 4.22 TWh, while net imports rose 9.1% to 1.22 TWh. This is precisely the environment in which batteries create value.

The commercial logic is simple but powerful. Batteries can charge during lower-price daylight hours, especially when solar output depresses prices, and discharge during evening hours when solar fades, demand remains high and thermal units set the marginal price. The Week 23 hourly price profile showed this dynamic clearly, with prices climbing sharply into the evening peak across most SEE markets.

For solar developers, this changes the investment case. A standalone solar plant may face lower realised prices during its production window as more PV enters the system. A solar-plus-storage project can shift part of that generation into higher-value hours, reduce curtailment exposure and strengthen PPA delivery. For wind developers, batteries can help manage forecast errors, imbalance costs and short-duration output variability.

The strongest early BESS cases are likely to emerge in markets with growing solar penetration, volatile evening spreads and limited flexible capacity. Greece, Bulgaria, Romania, Hungary, Serbia and Croatia all fit parts of this profile. In these markets, two-hour and four-hour batteries can provide merchant arbitrage, ancillary services, congestion management and balancing support.

Batteries also improve bankability. Lenders increasingly need to see not only expected generation, but revenue resilience. A BESS can reduce exposure to low-price hours, improve shape risk, support firmed delivery and strengthen contracts with industrial offtakers. In merchant projects, it can create an additional revenue stack from day-ahead, intraday and balancing markets.

Week 23 also showed why batteries are system assets, not only project assets. The region responded to higher demand and weaker renewables by increasing thermal dispatch and imports. Storage can reduce the need for expensive evening thermal generation, limit import dependence and improve grid flexibility.

The investment conclusion is clear. SEE does not only need more renewable capacity. It needs flexibility that can follow the price curve. The evening ramp is becoming the region’s most important storage signal, and batteries are increasingly the asset class built for that spread.

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The steepest renewable-output declines were recorded in Romania, Croatia and Serbia, largely because of weaker wind generation. Greece also saw a clear drop, with wind output falling 16.5%, more than offsetting a modest 1.8% rise in solar generation. This matters because wind does not behave like solar. It has a different hourly pattern, different seasonal profile and different system value. It can support evening and night-time supply when available, but when it drops, the system often has to replace it with hydro, imports, lignite or gas.

That is why wind projects need to be modelled separately from solar in SEE project finance. Wind can carry higher capacity factors and stronger system value during non-solar hours, but its week-to-week volatility creates imbalance exposure. Lenders and investors should not rely only on annual P50 generation. They need P90 downside cases, imbalance-cost assumptions, curtailment sensitivity, capture-price modelling and realistic balancing-market exposure.

Week 23 showed the system effect clearly. Regional demand rose 8.2% to 15.15 TWh, while variable renewable output fell 8.9%. Thermal generation then increased 24.5% to 4.22 TWh, while net imports rose 9.1% to 1.22 TWh. In other words, weaker wind coincided with higher demand and forced the system to lean harder on dispatchable sources.

For wind developers in Serbia, Romania, Croatia, Greece and Bulgaria, the lesson is commercial as much as technical. Wind projects can still be attractive, especially where they produce outside solar-heavy hours. But bankability depends on the ability to manage volatility. Better forecasting, portfolio aggregation, hybridisation with batteries, flexible PPAs and access to balancing services will increasingly influence project returns.

This is particularly relevant for markets where transmission systems are already under pressure from new renewable connections. A wind farm located in a constrained node may face both imbalance risk and curtailment risk. A project with strong wind resources but weak grid access can quickly lose revenue quality.

Wind remains one of SEE’s most valuable renewable resources, but Week 23 showed why it cannot be treated as a simple annual-energy product. Its value lies in timing, flexibility and system contribution. The next generation of SEE wind projects will need stronger revenue models, not only stronger turbines.

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At 11:59 AM, solar installations generated 2,634 MW, according to data from transmission system operator Transelectrica. This exceeded the previous record of 2,580 MW, set on 29 May. With additional solar projects expected to become operational throughout the year, further records are likely before the winter period.

The strong solar output came during a period of relatively moderate overall electricity demand. Total national generation stood at around 6,000 MW, influenced by the temporary unavailability of one nuclear reactor, lower wind production, and reduced contributions from several other generation sources. Electricity consumption from the national grid was approximately 4,450 MW, partly lowered by increasing self-consumption from prosumers.

During the record period, solar power became the dominant generation source in Romania. Photovoltaic plants accounted for around 43% of total domestic electricity production and supplied nearly 60% of electricity consumed from the grid, excluding output from residential and commercial prosumers.

The rapid expansion of distributed generation continues to reshape the market. Romania now has more than 320,000 prosumers, with combined installed solar capacity exceeding 3,700 MW. In parallel, utility-scale solar plants have reached approximately 3,340 MW of installed capacity, according to data from the national energy regulator ANRE.

The abundance of solar generation also strengthened cross-border electricity flows. At the time of peak production, Romania was exporting around 1,600 MW of electricity to neighboring countries. The new record highlights the growing importance of solar energy in Romania’s electricity system and shows how rising renewable capacity is increasingly influencing market pricing dynamics and regional power exchanges.

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Prime Minister Hristijan Mickoski announced that the Government is seriously considering developing the 333 MW hydropower complex without a private concession partner, after numerous previous attempts to attract investors failed. The project, located on the Crna River, is estimated to require around €1.5 billion in investment.

To support the undertaking, authorities have opened discussions with international financial institutions regarding a potential syndicated financing package. According to Government estimates, the project’s strategic importance extends beyond North Macedonia, offering broader benefits for the Western Balkans region.

The planned hydropower project is designed to serve multiple functions. In addition to generating electricity, the future reservoirs would provide significant water storage capacity, helping to mitigate the increasing impacts of climate variability and drought conditions. The infrastructure is also expected to improve irrigation for approximately 60,000 hectares of agricultural land downstream from the existing Tikveš hydropower facility, an area known for its strong agricultural output, particularly vineyards and wine production.

The decision to pursue the project directly comes after a series of unsuccessful development attempts spanning several decades. Most recently, progress stalled after a consortium of Greek companies failed to meet the conditions required to finalize a concession agreement with the Government.

Officials believe the project could become one of the most important infrastructure investments in the country, combining renewable electricity generation, water resource management, and agricultural support within a single integrated system.

If financing arrangements are secured, the Cebren and Galište development would represent one of the largest energy projects ever undertaken in North Macedonia, with the potential to significantly strengthen both national energy security and regional resource resilience.

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The decision, adopted by the Council of Ministers, enables the country’s only nuclear power plant to sign a public procurement contract with a selected supplier and import specific iron and steel products needed for project execution. The exemption will remain in force for the duration of the relevant contractual arrangements.

Officials stressed that the measure is driven primarily by nuclear safety and operational stability. Continuous access to original components, spare parts, and specialized equipment is considered essential for the reliable functioning of NPP Kozloduy. Many of the plant’s systems were originally designed and manufactured in Russia, making alternative sourcing in some cases technically challenging.

The government emphasized that uninterrupted deliveries from original designers and manufacturers play a key role in ensuring nuclear safety standards, radiation protection, environmental compliance, and safe working conditions. For this reason, certain maintenance and operational contracts for units 5 and 6 must continue to involve Russian suppliers.

The Kozloduy Nuclear Power Plant is a central pillar of Bulgaria’s energy system, generating more than one-third of the country’s total electricity output. It is considered a cornerstone of national energy security and plays a vital role in maintaining the stability of the Bulgarian power grid.

By granting this derogation, authorities aim to ensure that essential maintenance and operational activities continue without interruption, safeguarding the continuous, safe, and efficient operation of the country’s largest electricity-producing facility.

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As part of the final preparations, representatives of key energy institutions met this week to coordinate the next steps before the launch of a public call for applications. The meeting brought together officials from the Renewable Energy and Efficient Cogeneration Operator (OIEiEK), the Energy Regulatory Commission of the Federation of BiH (FERK), the Federal Ministry of Energy, Mining and Industry, as well as the two power utilities EPBiH and EP HZHB.

The program is considered one of the most important support mechanisms for citizens in the renewable energy sector. Its objective is to enable households to receive financial assistance for installing solar power systems intended primarily for their own consumption.

Utility representatives reported progress in handling requests from future prosumers. EPBiH confirmed that procedures for issuing network connection approvals are already underway, while EP HZHB stated that it is currently processing dozens of submitted applications.

According to OIEiEK management, recent efforts have focused on removing barriers that previously slowed the development of renewable energy projects. Following measures aimed at improving conditions for investors, authorities are now shifting attention toward enabling households to play a more active role in the energy market.

The planned subsidy scheme is expected to become the first structured mechanism in FBiH that redirects part of the funds collected through renewable energy support charges back to citizens. The financial assistance will be used to encourage the installation of small-scale solar power plants for self-consumption.

Officials also highlighted strong public interest in the initiative, viewing it as evidence of growing demand among households to reduce energy costs and directly participate in renewable energy production.

To support implementation, a series of public information events will be organized in the coming months. These sessions will provide guidance on eligibility requirements, application procedures, and the documentation needed to apply for support.

Preparatory work is continuing, while the public call for applications is expected to be published within the next 90 days. Further details will be announced through official communication channels once the launch date is confirmed.

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The initiative was highlighted during discussions at the East Mediterranean Gas Forum (EMGF) in Washington, where Egyptian Petroleum and Mineral Resources Minister Karim Badawi emphasized the importance of strengthening energy links between the Eastern Mediterranean and Europe. Under the concept being promoted by Egypt, Greece would serve as a strategic transit hub, enabling LNG shipments to reach Central and Southeastern Europe through the region’s developing Vertical Corridor infrastructure.

Egypt’s renewed push comes as its gas sector shows signs of recovery after a difficult period marked by declining production, rising domestic consumption, and economic pressures that previously led to IMF-backed support measures in 2022. Those challenges temporarily turned Egypt from an LNG exporter into a net importer of liquefied gas.

Recent developments, however, have improved the outlook. New hydrocarbon discoveries, including projects led by Eni, alongside efforts to attract foreign investment, are expected to gradually increase domestic gas production. Cairo has also introduced policies allowing international energy companies to export part of their output as LNG in order to recover outstanding payments and sustain investment activity. One example is Energean, which received $125 million during the first quarter of 2026 as part of debt repayments.

The EMGF meeting also highlighted broader geopolitical energy dynamics in the region. The forum reconvened after a three-year hiatus and brought together representatives from Greece, Cyprus, Egypt, Israel, Jordan, Italy, France, the European Union, the United States, the World Bank, and the State of Palestine. It marked the first time since 2023 that Israeli and Palestinian representatives participated in the same forum discussions.

While no major agreements were announced, the gathering signaled renewed regional engagement on energy cooperation. Turkey remains outside the EMGF framework and continues to advocate for a greater role in approving regional energy projects, a stance that remains at odds with the forum’s existing cooperative structure.

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Serbia recorded the steepest decline among major exchanges, with SEEPEX falling by €37.4/MWh day on day to €78.37/MWh, the lowest price in the region. Slovenia’s BSP exchange dropped to €94.71/MWh, while Croatia’s CROPEX settled at €96.01/MWh. Hungary’s HUPX and Romania’s OPCOM both remained near the €100/MWh level despite declines exceeding €24/MWh. Montenegro stood out as the highest-priced market at €104.74/MWh, while Italy continued to trade at a significant premium of €127.23/MWh.  

The market correction came as temperatures retreated across much of Central and Southeast Europe. Regional average temperatures fell to 20.4°C, while Serbia experienced one of the sharpest drops, declining from 24.2°C to 18.3°C. Lower cooling demand reduced system stress at the same time that renewable generation remained elevated.  

Regional power generation rose to 29.1 GW, up almost 1 GW from the previous day. Hydro output increased by 190 MW, coal generation rose by 316 MW, and gas-fired generation climbed by 317 MW, while solar production remained exceptionally strong at 6.6 GW, accounting for approximately 23% of total generation. Hydro remained the largest single source at 24% of the generation mix.  

The stronger supply balance sharply reduced import requirements. Net regional imports fell to only 70 MW, compared with 235 MW a day earlier, demonstrating how domestic renewable generation is increasingly displacing imported electricity during daylight hours.  

Romania continued to emerge as one of the most influential markets in the region’s renewable transition. Solar generation reached a new all-time record of 2,634 MW, surpassing the previous national high set only days earlier. During peak production, solar represented roughly 43% of Romanian generation, enabling exports of approximately 1,600 MW into neighboring markets.  

The Romanian record follows broader structural changes occurring across the region. Hungary has now become the world’s most solar-intensive electricity system, with solar accounting for 27% of national electricity generation during 2025, according to figures cited in the report. The growing penetration of photovoltaics is increasingly reshaping market fundamentals, suppressing daytime prices while creating steeper evening ramps that favour flexible generation and storage assets.  

Cross-border flow patterns reflected these dynamics. Romania and Bulgaria remained major exporters, while Hungary, Greece, Croatia and Serbia continued to rely on imports during parts of the day. The spread between Serbia and Italy approached €49/MWh, creating attractive export economics for generators capable of accessing western European demand centres through regional interconnections.

Forward markets, however, remained considerably stronger than prompt prices. Hungarian Week 26 contracts traded at €117/MWh, July contracts at €121.5/MWh, while carbon allowances strengthened to €76.94/t and Austrian gas rose to €50.67/MWh. The resilience of forward curves suggests traders continue to price weather-related risks, hydro uncertainty and potential summer demand spikes despite current renewable abundance.  

For market participants, the latest trading session offered another indication that Southeast Europe is entering a new phase of power market behaviour. Solar output is increasingly setting daytime prices across Hungary, Romania, Bulgaria and Serbia, reducing thermal generation’s influence during midday hours. As photovoltaic capacity continues to expand and battery projects move toward commercial operation, the value of flexibility, balancing services and evening peak generation is likely to become more important than simple energy production volumes.

The resulting market structure is becoming increasingly familiar: depressed midday prices, strong evening recoveries, widening intraday spreads and growing opportunities for battery storage operators, hydro generators and traders able to arbitrage between renewable-rich Southeast Europe and structurally tighter western European markets.  

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