The upgrade covered the hydropower plants in Dravograd, Vuzenica, and Mariborski otok, where key secondary systems were fully modernized over a three-year implementation period. Through the introduction of advanced process equipment and digital technologies, the company expects the plants to operate efficiently for at least another 20 years.

A major component of the project was the integration of modern data management systems, enabling real-time operational monitoring and predictive maintenance capabilities. In parallel, improvements were made in cybersecurity, while the lifespan of primary equipment has effectively been extended into the later stages of its operational cycle.

One of the most notable outcomes of the modernization is the deployment of a newly developed digital turbine control system, designed in-house by DEM’s engineering team. This innovation represents an important step toward greater technological independence and improved optimization of hydropower plant performance.

Overall, the project marks a significant milestone in the digital transformation of DEM’s hydropower fleet, strengthening both operational resilience and long-term system sustainability.

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For comparison, in March of the previous year, the plant generated 520,951 MWh, which was also above the planned level by 0.91%, indicating consistently stable operational performance.

The plant operated within all required technical specifications, with all safety systems fully functional throughout the reporting period. Both the availability factor and the capacity factor reached 100%, reflecting uninterrupted operation and high reliability.

No technical issues were reported during the month, confirming the continued stable and efficient performance of the facility under normal operating conditions.

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The newly operational Pecineaga wind farm, located in Constanța County, has an installed capacity of 48 MW and represents an investment of approximately €90 million. The project is equipped with eight Siemens Gamesa SG 6.6-170 turbines, featuring 135-meter towers and 85-meter blades, reaching a total height of around 220 meters, and introducing some of the most advanced wind technology currently in use in Romania.

According to Adrian Dobre, Country Manager for Romania, the project further strengthens Eurowind Energy’s position in one of its core European markets. Romania is among the company’s four strategic priority countries, alongside Poland, Germany, and Denmark. With the addition of Pecineaga, Eurowind’s operational capacity in Romania has reached 124 MW, while energy storage projects totaling 120 MWh are already under construction.

The wind farm is expected to generate approximately 176,000 MWh of electricity annually, enough to supply around 48,000 households. This production will contribute to increasing the share of renewable energy in Romania’s electricity mix and improving overall system sustainability.

Eurowind Energy, active in Romania since 2011, continues to expand its presence in the market, with a development pipeline of approximately 7.5 GW across wind, solar, and storage projects. The company’s current portfolio includes several solar parks and a battery storage project under development in Teiuș.

Looking ahead, Eurowind plans to invest around €300 million annually in Romania through 2030, aiming to build a diversified portfolio of up to 1 GW across wind, solar, and energy storage technologies.

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The planned HPP Kruševo is expected to have an installed capacity of 82 MW and an annual electricity production of around 170 GWh. Ongoing geological investigations, initiated in late 2025, are forming the basis for the next development phase. These studies follow a contract signed in November 2024 with the Jaroslav Černi Institute for Water Management, covering both project design and detailed field research.

According to EPCG, the current focus is on determining the most suitable technical concept for the plant. One of the key options under consideration is upgrading the project into a pumped-storage hydropower facility, which would significantly enhance system flexibility and grid balancing capabilities.

Once the optimal technical solution is defined, the next steps will include preparation of full technical documentation and the launch of procedures leading to the signing of an EPC (Engineering, Procurement and Construction) contract.

Cooperation with French utility EDF is based on a memorandum of understanding that outlines a potential broader role for the partner, including possible involvement in design, financing, and operational aspects, particularly related to the Krusevo project.

Although another hydropower project, HPP Komarnica, remains under evaluation, EPCG has indicated that HPP Kruševo currently holds development priority. Further decisions regarding Komarnica will depend on ongoing assessments and future planning outcomes.

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The court rejected Croatia’s objections and confirmed the validity of the earlier arbitration award. The case originates from a previous arbitration ruling that had already been contested without success.

Over time, the financial obligation has steadily increased due to accumulated interest and arbitration-related costs. Initially set at approximately $183.9 million in 2022, the amount rose progressively to around $200 million, then $236 million, and has now reached approximately $286 million.

Croatia previously attempted to overturn the decision, but its appeal was dismissed in 2025 by the same court. With all legal avenues in the United States judicial system now exhausted, the ruling has been definitively upheld.

Authorities in Zagreb have previously stated that the payment will be covered from the state budget following the conclusion of the legal process.

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The proposed project, located in Topusko, is designed as an integrated facility combining advanced data infrastructure with clean electricity generation. It includes a planned 500 MW solar power plant and a large-scale battery storage system with a capacity of 2,000 MW and 8,000 MWh, which will directly supply electricity to the campus. Portugal-based company Greenvolt International Power has already signed a letter of intent to support the development of on-site energy solutions.

In addition to the core campus, the project includes significant upgrades to the regional power network. Plans involve the construction of four 400 kV transmission lines, which would enable the integration of up to 5.2 GW of additional renewable capacity into Croatia’s electricity system, substantially increasing the country’s ability to absorb and distribute clean energy.

The main data center complex is expected to reach 1 GW of installed capacity, with around 800 MW dedicated to artificial intelligence computing workloads. The site will initially cover more than 125 hectares, with the possibility of expansion to approximately 180 hectares depending on future demand.

Construction of the first phase, valued at around €12 billion, is scheduled to begin in early 2027, with commissioning planned for early 2029. Over the long term, total investment could exceed €50 billion, as additional hyperscale tenants expand their operations within the facility.

The project is also expected to generate a significant economic impact. Approximately 3,000 jobs are anticipated during the construction phase, followed by around 1,500 permanent positions once the campus becomes operational. Local authorities in Sisak-Moslavina County have already expressed support through a formal cooperation agreement aimed at facilitating project development.

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Despite the decrease in net earnings, the company posted a stable overall performance, generating total revenue of 35 million euros and a gross profit of nearly 16 million euros. Core operations, mainly crude oil transport and storage of oil and petroleum products, contributed approximately 33 million euros to total revenue.

International business remained the dominant source of income. Around 72% of revenue from core activities, or close to 24 million euros, was generated from foreign clients, while the domestic market accounted for just over 9 million euros.

Management highlighted that geopolitical tensions and broader energy market uncertainty significantly shaped operating conditions in early 2026. Nevertheless, the company emphasized that its financial performance remains above the national average, enabling continued investment in strategic development projects.

These initiatives include the expansion of storage capacities, diversification into renewable energy, and the pursuit of international opportunities, including planned activities in Kazakhstan.

JANAF aims to further strengthen its position as a key regional energy logistics hub, while gradually transitioning toward a more diversified and integrated energy business model designed to enhance long-term resilience in a volatile market environment.

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The company has opened a tender for a single LNG cargo with a volume of 1,000,000 MWh, to be delivered to a terminal in Turkey. Participation in the tender has been restricted to a group of pre-approved international traders and producers, with a total of 37 companies invited to submit bids. Offers will be evaluated based on several criteria, including price competitiveness, delivery terms, and payment conditions.

This initiative forms part of broader efforts to manage both short-term supply security and medium-term storage requirements. Bulgargaz has also indicated that, following the completion of maintenance works at the Alexandroupoli LNG terminal in Greece, it plans to procure an additional LNG cargo. That shipment is expected to be directed toward the Chiren gas storage facility, supporting the build-up of reserves ahead of the 2026–2027 winter season. The Alexandroupoli terminal has been temporarily offline since early April due to scheduled maintenance.

Through this dual strategy of immediate procurement and seasonal storage optimization, Bulgargaz aims to reinforce supply reliability and mitigate risks associated with volatile regional gas market conditions.

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Natural gas consumption also decreased in February 2026, falling by 13.4% to 311 million cubic meters, while domestic production remained unchanged at 1 million cubic meters. Compared to February 2025, electricity production dropped by 16.9%, while consumption decreased by 3.7%. Over the same annual period, natural gas consumption increased slightly by 1%.

In the oil products segment, production of unleaded petrol declined by 5% to 115,000 tons, while consumption decreased by 2.6% to 37,000 tons. Diesel production rose by 1.3% to 230,000 tons, while consumption fell significantly by 13.3% to 183,000 tons.

Consumption of liquefied petroleum gas (LPG) increased by 3%, reaching 34,000 tons, while production rose sharply by 33.3% to 4,000 tons.

In the solid fuels segment, production dropped sharply by 40.4% to 1,337 thousand tons, while consumption also declined by 39.7% to 1,386 thousand tons, indicating a strong contraction in coal-related energy activity during the period.

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A central component of the agreement is the long-delayed Vlore gas-fired power plant. The government plans to convert the facility—originally designed for oil—to run on natural gas supplied under the new LNG arrangement. This conversion is expected to give new life to a project that has remained inactive since its completion.

Once operational, the Vlore facility is expected to provide approximately 350 MW of installed capacity. The plant itself was constructed in 2011 with support from international financial institutions, including the World Bank, the European Bank for Reconstruction and Development (EBRD), and the European Investment Bank (EIB). Despite this backing, the plant has never entered commercial operation.

Previous attempts to establish LNG infrastructure in Vlore faced multiple setbacks. A 2021 agreement involving Excelerate Energy and ExxonMobil LNG Market Development envisioned the development of an LNG import terminal, conversion of the power plant, and a broader regional distribution network. However, the project ultimately stalled after a planned floating LNG unit was redirected to Germany in 2022.

The new agreement marks a renewed effort to position Albania as a regional energy hub, with LNG imports expected to support both domestic demand and wider Balkan energy needs.

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Of the total volume, 111.4 GWh was traded for the Kosovo bidding zone, while 104.5 GWh was allocated to the Albania bidding zone. The average price across ALPEX stood at €96.89/MWh, recorded uniformly for both bidding zones.

The total transaction value on ALPEX in March amounted to approximately €15.1 million, marking a strong 48% increase year-on-year.

ALPEX was established in October 2020 by the Albanian Transmission System Operator (OST) and its Kosovo counterpart (KOSTT). The first auction on the Albanian market was held in April 2023. Today, the exchange has a total of 36 members operating across the Albania and Kosovo bidding zones.

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The trading signal is a classic solar-midday compression versus evening scarcity spread. Across several markets, hourly curves show weak or negative midday prices but strong evening peaks around H20–H21. Hungary’s 7-day table shows a 30 April base of €89.8/MWh, but the minimum fell to -€28.2/MWh, while the maximum reached €248.5/MWh. Serbia showed a cleaner scarcity profile, with SEEPEX base at €91.8/MWh, peak at €75.8/MWh, off-peak at €107.8/MWh, minimum €30/MWh and maximum €165/MWh. This means Serbia avoided the deepest negative-price stress seen in Hungary, Slovenia, Austria and Croatia, but still priced above several neighbouring SEE markets.  

System fundamentals were not bearish on demand. Regional consumption rose to 30,297 MW, up 1,115 MW day on day, while total generation fell by 715 MW to 27,408 MW. Imports remained structurally important at 1,583 MW, although down 190 MW from the previous day. The supply mix was led by hydro at 6,638 MW, nuclear at 5,428 MW, coal at 5,190 MW, solar at 4,868 MW, gas at 3,224 MW, wind at only 1,233 MW, and other generation at 828 MW. The most important short-term change was solar: output fell 821 MW day on day, while gas rose 252 MW, confirming that thermal flexibility was again needed to cover ramps.  

Cross-border flows show the region remained a net importer. The SEE balance recorded -1,583 MW average net import, with Hungary at -518 MW, Serbia at -553 MW, Bulgaria at -314 MW, Romania at -393 MW, Croatia at -213 MW, while Greece was a net exporter at +130 MW. This import dependence supported evening prices despite weaker daily averages. Core imports from Austria and Slovakia into Hungary/Slovenia were still high at 3,196 MW, while the HU-DE spread narrowed sharply to €17.75/MWh, down almost €30/MWh day on day.  

Forward markets were firmer despite weaker spot pricing. Hungarian power forwards rose, with Week 19 at €102/MWh, Week 20 at €96/MWh, May-26 at €96.5/MWh, and Cal-26 at €113/MWh. Gas also strengthened, with CEGH at €47.03/MWh and Greece gas around €47/MWh. Coal forwards moved higher, with May-26 API2 at $110.5/t and Q3-26 at $119.5/t, while EUA softened to €73.2/t. The forward curve therefore points to traders still pricing fuel-risk and summer reserve risk, even as the spot market was pulled lower by intraday renewable effects.  

The key signal is not the daily average but the widening shape value: midday remains vulnerable to solar-driven price collapse, while evening hours retain scarcity premium. Batteries, pumped hydro, flexible gas, hydro dispatch and intraday optimisation continue to gain value. Serbia and Albania showed relative price strength, Hungary remained the regional reference hub, while Slovenia, Croatia, Montenegro and Austria were weaker because of stronger exposure to Central European solar-price compression.

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For years, the Western Balkans functioned as a critical transit zone within the broader Southeast European grid. Electricity did not simply flow into or out of these markets; it passed through them, linking EU systems in a chain of arbitrage-driven transactions. Routes such as Hungary–Serbia–Bulgaria or Croatia–Serbia–Romania were not incidental—they were central to the way traders optimised flows across price differentials. The region’s interconnectors were valued not only for bilateral trade but for their role in multi-leg arbitrage strategies that spanned several markets.

This model has begun to fragment. In Q1 2026, commercially scheduled cross-border exchanges between the Western Balkans and the EU declined by approximately 25% compared to the same period in 2025. The contraction was not symmetrical. Flows from the EU into the Western Balkans fell sharply—by −40.7%—while flows in the opposite direction declined more modestly. This imbalance resulted in a shift in the region’s net trade position, with the Western Balkans moving from a net importer to a net exporter of electricity by approximately 1.35 TWh. However, this shift was driven less by increased export activity and more by the collapse of imports from the EU.

The reduction in EU-to-WB6 flows is closely linked to the disruption of transit-based trading strategies. Under CBAM, uncertainty regarding the treatment of electricity passing through non-EU countries has made such routes less attractive. Traders face the risk that electricity transiting through the Western Balkans could be subject to carbon costs, even if it originates and is consumed within the EU. This regulatory ambiguity has been sufficient to discourage the use of WB6 corridors for intra-EU trade, leading to a reconfiguration of flows towards routes that remain entirely within EU jurisdiction or involve low-carbon systems.

As a result, the role of the Western Balkans as a transit hub is diminishing. Electricity that would previously have flowed through Serbia or Bosnia and Herzegovina is increasingly rerouted through alternative corridors. These include direct EU-to-EU interconnections, as well as pathways that incorporate low-emission systems capable of avoiding CBAM costs. The emergence of these “CBAM-efficient” routes represents a fundamental change in how the regional grid is utilised.

One of the most notable beneficiaries of this shift is Albania. With a hydro-dominated generation mix and a default emission factor effectively equal to zero, Albania occupies a unique position in the CBAM framework. It can export electricity into the EU without incurring carbon costs, making it an attractive source of supply in a carbon-constrained trading environment. In Q1 2026, Albania significantly increased its scheduled exports across all borders, including flows to Greece, Kosovo, and Montenegro. The net effect was a redistribution of approximately 1.2 TWh of electricity compared to the same period in 2025.

This Albanian surplus did not remain confined to immediate neighbours. It was transmitted through Greece and onward into EU markets such as Bulgaria and Italy. Greece itself, benefiting from a substantial increase in hydro generation, became a key intermediary in this process. Flows from Albania to Greece increased markedly, and from there, electricity moved northward and westward into the broader EU system. This south-to-north corridor, anchored by low-carbon generation, has gained prominence as an alternative to traditional transit routes through coal-heavy systems.

The rise of such corridors highlights a broader trend: the optimisation of trade routes based on carbon exposure rather than purely economic or physical considerations. Traders are increasingly selecting pathways that minimise CBAM costs, even if those routes are longer or less direct. This behaviour introduces a new dimension to grid utilisation, where the shortest or most efficient path is not necessarily the most economically viable once carbon pricing is taken into account.

At the same time, intra-regional trading within the Western Balkans has intensified. As cross-border exchanges with the EU become more constrained, markets within the region are turning inward, increasing trade among themselves. This shift reflects both the availability of surplus generation—particularly hydro—and the reduced attractiveness of exporting to the EU under CBAM conditions. The result is a more interconnected intra-WB6 market, albeit one that is less integrated with the EU.

This inward shift has implications for price formation and market liquidity. Increased intra-regional trading can support liquidity and enhance price discovery within the Western Balkans, but it does not fully compensate for the loss of access to higher-priced EU markets. The net effect is a redistribution of trading activity rather than an expansion, with potential consequences for revenue generation and market depth.

The reconfiguration of trade corridors is also evident in the performance of specific interconnectors. The Montenegro–Italy submarine cable provides a particularly striking example. Despite offering a direct link between a lower-priced WB6 market and a higher-priced EU market, utilisation of this interconnector declined in Q1 2026. Scheduled flows from Montenegro to Italy fell by over 2,100 MWh per day, while physical flows decreased by approximately 1,400 MWh per day. This occurred even as the price spread between the two markets widened significantly. The explanation lies in CBAM costs, which effectively erased the economic advantage of exporting across this corridor.

This pattern underscores a key point: the value of interconnectors is no longer determined solely by price differentials and capacity constraints. It is increasingly influenced by the regulatory environment, particularly the carbon costs associated with cross-border trade. Interconnectors that link low-carbon systems to the EU retain or even increase their value, while those connecting high-emission systems face declining utilisation and reduced economic relevance.

The divergence between commercial schedules and physical flows adds another layer of complexity to this reconfiguration. While traders adjust their schedules to minimise CBAM exposure, electricity continues to flow according to the physical characteristics of the grid. This has led to situations where increased scheduled exports along certain corridors are not matched by corresponding changes in physical flows. For example, increased commercial exports from Albania to Greece were not fully reflected in physical flows along that route, as electricity continued to move through Montenegro and Bosnia and Herzegovina towards EU markets.

This mismatch between commercial intent and physical reality introduces inefficiencies into the system. Transmission system operators must manage flows that do not align with scheduled transactions, increasing the risk of congestion, loop flows, and operational instability. The reconfiguration of trade corridors, therefore, has implications not only for market participants but also for the technical operation of the grid.

From an investment perspective, the changing geography of trade raises important questions about the future of infrastructure development. Projects that were conceived under the assumption of stable arbitrage flows may need to be reassessed in light of CBAM-induced changes. Interconnectors that once promised strong congestion revenues may see reduced utilisation, while new opportunities may emerge in corridors that connect low-carbon systems or bypass high-emission regions.

The broader strategic implication is that Southeast Europe’s electricity network is evolving from a system optimised for economic efficiency to one increasingly shaped by carbon policy. The traditional logic of trade—buy low, sell high, and move electricity along the most efficient path—is being supplemented, and in some cases overridden, by the need to manage carbon exposure. This shift does not eliminate the role of market forces, but it alters the framework within which they operate.

Looking ahead, the persistence of these trends will depend on several factors. Greater clarity on the treatment of transit flows under CBAM could restore some of the attractiveness of WB6 corridors for intra-EU trade. Adjustments to emission factor methodologies could reduce the disparity between systems and mitigate some of the distortions currently observed. At the same time, the development of carbon pricing mechanisms within the Western Balkans could align incentives and reduce the asymmetry between EU and non-EU markets.

However, even with such adjustments, the underlying direction of change is unlikely to reverse entirely. Carbon pricing is now a central component of electricity market design, and its influence on trade patterns will continue to grow. The reconfiguration observed in Q1 2026 is therefore best understood not as a temporary anomaly but as the early stage of a longer-term transformation.

For market participants, adapting to this new geography of trade will require a reassessment of strategies, from route optimisation and portfolio management to infrastructure investment and risk assessment. For policymakers, the challenge will be to ensure that the pursuit of decarbonisation does not come at the expense of market efficiency and system stability. The balance between these objectives will shape the future of Southeast Europe’s electricity markets, as the region navigates the intersection of energy integration and climate policy.

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At the core of this divergence lies the application of default emission factors, which determine the carbon cost applied to electricity imports into the European Union. These factors, expressed in tonnes of CO₂ per megawatt-hour, are intended to approximate the carbon intensity of exporting systems. In practice, they create a simplified and, in some cases, blunt representation of complex generation mixes. The resulting cost differentials are substantial. In Q1 2026, Albania faced a CBAM cost of €0/MWh, reflecting its hydro-dominated system, while Serbia incurred approximately €78.45/MWh, Bosnia and Herzegovina €86.5/MWh, and Montenegro around €73.8/MWh. These figures are not marginal adjustments; they are of a magnitude that can completely redefine the economics of cross-border trade.

The immediate effect is a bifurcation of regional competitiveness. Low-carbon systems—particularly those dominated by hydro—gain a structural advantage that extends beyond their already low marginal generation costs. They are able to export electricity into EU markets without incurring additional carbon charges, effectively positioning them as preferred suppliers in a CBAM-regulated environment. Coal-heavy systems, by contrast, face a dual penalty: higher emission intensity and the imposition of a carbon cost that often exceeds the underlying price differential between markets. This dynamic transforms what was once a relatively level playing field into a stratified market where access to cross-border trade is determined as much by carbon intensity as by production cost.

The contrast between Albania and Montenegro illustrates this divergence in stark terms. Both systems benefited from strong hydro output in Q1 2026, contributing to lower domestic prices. However, their export performance diverged significantly. Albania increased its exports across multiple borders, leveraging both its surplus generation and its zero emission factor. Montenegro, despite facing favourable price spreads—most notably with Italy, where the differential reached approximately €43/MWh—saw a decline in exports. The explanation lies in the CBAM cost applied to Montenegrin electricity, which effectively absorbed the price advantage and rendered exports economically unattractive. This outcome underscores the extent to which CBAM can override traditional market signals.

The implications for coal-dependent systems are profound. Serbia, Bosnia and Herzegovina, and Montenegro have historically relied on their thermal generation fleets to provide both domestic supply and export capacity. These assets, often fully depreciated and capable of producing electricity at relatively low operating costs, formed the backbone of regional trade. CBAM challenges this model by attaching a cost that reflects carbon intensity rather than operational efficiency. In doing so, it reduces the competitiveness of existing assets and introduces uncertainty into their future utilisation.

This shift is not merely a matter of reduced export volumes. It affects the entire economic lifecycle of coal-based generation. Revenues decline as access to higher-priced markets is constrained, while costs increase due to the need to account for carbon pricing in cross-border transactions. Over time, this could lead to lower capacity utilisation, reduced cash flow, and a reassessment of asset value. For utilities and investors, the question is no longer whether these assets can compete on cost alone, but whether they can remain viable in a market where carbon intensity is a primary determinant of competitiveness.

The divergence also extends to investment signals. In theory, CBAM is designed to incentivise decarbonisation by making carbon-intensive production less competitive. In practice, the signals it sends are uneven. Low-carbon systems receive a clear and immediate advantage, reinforcing the attractiveness of investments in hydro, wind, and solar generation. Coal-heavy systems, however, face a more complex set of incentives. While CBAM increases the cost of carbon-intensive generation, it does not necessarily provide a clear pathway for transition, particularly in regions where access to capital, regulatory frameworks, and grid infrastructure may be less developed.

This asymmetry can lead to unintended consequences. Rather than accelerating investment in new renewable capacity, the structural disadvantage imposed on coal-based systems may result in reduced overall investment, as market participants adopt a wait-and-see approach. The uncertainty surrounding future carbon costs, regulatory adjustments, and market integration can deter long-term commitments, particularly for large-scale projects that require stable revenue expectations. In this sense, CBAM may create a transitional gap where existing assets are penalised, but replacement investments are not yet fully mobilised.

Another dimension of this divergence is its impact on regional market integration. The Western Balkans have long been in the process of aligning their energy markets with those of the European Union, with cross-border trade serving as a key mechanism for integration. CBAM introduces a friction into this process by creating differential treatment based on carbon intensity. Markets that are structurally aligned with low-carbon generation are effectively drawn closer to the EU, while those reliant on coal are pushed further away. This divergence risks fragmenting the region into distinct sub-markets with differing levels of integration and competitiveness.

The effect is particularly evident in the reconfiguration of trade flows. As traders seek to minimise exposure to CBAM costs, they increasingly favour routes and sources that offer lower emission intensity. This has led to a shift towards “CBAM-efficient” corridors, where electricity can be sourced or routed through low-carbon systems. Albania’s role as a transit and export hub has expanded as a result, while traditional transit routes through coal-heavy systems have become less attractive. The net effect is a redistribution of trade activity that reflects carbon intensity as much as geography or infrastructure.

From a pricing perspective, the divergence introduces a new layer of complexity. Prices in low-carbon systems are influenced primarily by supply conditions, particularly hydrology and renewable output. Prices in coal-heavy systems, while still affected by these factors, are increasingly constrained by their limited ability to export and arbitrage. This can lead to situations where low-carbon systems enjoy both low domestic prices and access to higher-priced export markets, while coal-based systems experience suppressed domestic prices without the ability to monetise them externally. The result is a widening gap in revenue potential across different markets.

The interaction between CBAM and the EU ETS further amplifies this divergence. Because CBAM costs are directly linked to carbon prices, any increase in EU ETS allowances will disproportionately affect coal-heavy exporters. In Q1 2026, the carbon price of €75.36/tCO₂ already imposed significant costs. Should prices rise further—as many long-term projections suggest—the gap between low-carbon and high-carbon systems will widen accordingly. This introduces a dynamic element to competitiveness, where relative positions can shift with movements in the carbon market.

The use of default emission factors adds another layer of rigidity to the system. These factors are applied uniformly at the country level, without accounting for variations in generation mix over time. As a result, even if a coal-heavy system temporarily relies on low-carbon generation—such as during periods of high hydro output—it still faces the same CBAM cost. This disconnect between actual emissions and applied costs can discourage efficient dispatch and distort investment decisions. Systems may be penalised for emissions they are not currently producing, while others benefit from structural classifications that may not fully reflect their operational reality.

For policymakers, the challenge is to reconcile the objectives of decarbonisation and market integration. CBAM is a powerful tool for aligning carbon costs across borders, but its current implementation highlights the difficulty of applying a uniform mechanism to diverse energy systems. Adjustments that allow for more granular recognition of actual emissions—such as plant-level reporting or certification of low-carbon generation—could mitigate some of the distortions observed. At the same time, efforts to align carbon pricing frameworks across the Western Balkans with the EU ETS could reduce the asymmetry that currently drives divergence.

Looking ahead, the structural divide between low-carbon and coal-based systems is likely to deepen unless significant changes occur in either market design or generation portfolios. The economics of electricity trade will increasingly favour systems that can demonstrate low emission intensity, whether through renewable generation, nuclear capacity, or carbon capture technologies. Coal-based systems will need to adapt, either by reducing their carbon footprint or by focusing on domestic markets where CBAM does not apply.

The first quarter of 2026 has made one point unmistakably clear: competitiveness in Southeast Europe’s electricity markets is no longer determined solely by cost efficiency or resource availability. It is now fundamentally linked to carbon intensity and the regulatory frameworks that govern it. CBAM has introduced a new hierarchy into the market, one that rewards low-carbon systems and penalises high-emission ones in a direct and measurable way.

This transformation is still in its early stages, and its long-term trajectory will depend on a range of factors, including carbon price developments, regulatory refinements, and investment responses. What is already evident, however, is that the region’s electricity markets are entering a new phase—one defined not just by the integration of physical infrastructure, but by the alignment of carbon economics. In this emerging landscape, the distinction between low-carbon and coal-based systems will continue to shape trade flows, price formation, and investment decisions, establishing a new competitive order across Southeast Europe.

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Regional hydro generation increased from 16.7 TWh in Q1 2025 to 22.18 TWh in Q1 2026, representing a rise of 5.48 TWh, or +33%. This expansion was broad-based, affecting nearly all observed markets. Greece contributed the largest absolute increase, adding +1.86 TWh, followed by Romania with +1.04 TWh, Bulgaria with +0.87 TWh, and Croatia with +0.36 TWh. Among the Western Balkans, Bosnia and Herzegovina added +0.64 TWh, Serbia +0.53 TWh, Montenegro +0.36 TWh, and North Macedonia +0.23 TWh. Albania, a hydro-dominated system, increased production by +1.34 TWh, a rise of approximately 70%, with particularly strong output concentrated in January and February.

This surge in hydro output effectively flooded regional markets with low marginal cost electricity. Hydropower, once installed, operates with near-zero fuel cost, meaning that in periods of abundant water inflow it becomes the dominant price-setting resource. As a result, day-ahead electricity prices in the Western Balkans fell significantly during Q1 2026. Serbia averaged €94.7/MWh, Montenegro €85.8/MWh, and North Macedonia €96.7/MWh, all well below neighbouring EU benchmarks, which remained clustered around €120–130/MWh.

Under typical market conditions, such a differential would lead to strong export flows from the Western Balkans to higher-priced EU markets. However, the interaction between hydro-driven price suppression and CBAM-related costs created a more complex outcome. While hydro reduced production costs and lowered prices, CBAM imposed additional costs on exports from carbon-intensive systems, limiting their ability to capitalise on these favourable conditions. The result was a market where low prices did not translate into proportionally higher exports, and where price spreads persisted despite the availability of surplus generation.

The role of hydro in shaping these dynamics extends beyond simple price suppression. It also alters the merit order within individual markets. Coal-fired generation, which typically provides baseload supply in several Western Balkan systems, was displaced by hydro during the quarter. Regional coal generation declined from 18.81 TWh to 15.79 TWh, a reduction of 3.02 TWh, or −16%. Serbia, the largest coal producer in the region, reduced output from 6.08 TWh to 5.47 TWh, while Bosnia and Herzegovina declined from 2.09 TWh to 1.62 TWh. North Macedonia recorded the sharpest relative reduction at −37%, reflecting both lower demand for thermal generation and the dominance of hydro in the dispatch order.

This displacement of coal has two important implications. First, it reduces the average carbon intensity of electricity production in the region, albeit temporarily. Second, it creates a disconnect between actual generation emissions and the default emission factors used under CBAM. While hydro generation may dominate in a given period, exporters from coal-heavy systems are still subject to carbon costs based on their structural emission profiles. This mismatch amplifies the distortion in price signals, as the cost applied to exports does not reflect the real-time composition of generation.

Hydro dominance also reshapes cross-border flow patterns. Albania provides a clear example of this effect. With a zero default emission factor and a significant increase in hydro output, Albania became a major exporter during Q1 2026. Scheduled exports increased across all its borders, including flows to Greece, Kosovo, and Montenegro. The net effect was a swing of approximately 1.2 TWh in Albania’s trade position compared to the same period in 2025. This surplus was then redistributed across the region, often moving through Greece into EU markets such as Bulgaria and Italy.

Greece itself experienced a substantial increase in hydro production, rising from 0.67 TWh to 2.53 TWh, a gain of +275%. This contributed to lower prices in the Greek market, which averaged €94.6/MWh, closely aligning with Western Balkan price levels. The convergence between Greece and WB6 markets stands in contrast to the divergence observed with other EU markets, highlighting the role of hydro in shaping regional price clusters.

However, the influence of hydro is not uniform across all markets. Italy, despite being the largest hydro producer in absolute terms at 6.03 TWh, recorded a decline in output of −0.42 TWh compared to Q1 2025. As a result, Italian prices remained elevated, driven primarily by gas-fired generation. This divergence between hydro-rich and gas-dependent systems contributed to the widening of price spreads across the region.

The temporal distribution of hydro output also played a role in market dynamics. The strongest generation occurred in January and February, leading to an initial sharp drop in prices in the Western Balkans. As the quarter progressed and hydrological conditions began to normalise, prices recovered somewhat, contributing to a partial restoration of price correlations. However, the overall spread remained wide, suggesting that while hydro influenced the magnitude of price divergence, it was not the sole driver of the structural decoupling observed.

From a system perspective, the surge in hydro generation introduced both opportunities and challenges. On the one hand, increased low-cost supply enhanced security of supply and reduced reliance on fossil fuels. On the other hand, the sudden influx of generation created congestion risks on key transmission corridors, particularly along the south-north axis from Greece through Albania and Montenegro to Bosnia and Herzegovina. These corridors, already critical to regional flows, experienced increased loading as surplus hydro was transmitted towards EU markets.

The interaction between hydro-driven physical flows and CBAM-affected commercial flows further complicated system operation. In several instances, increased scheduled exports did not correspond to proportional increases in physical flows, as electricity followed the path of least electrical resistance rather than the commercially designated route. This divergence between scheduled and actual flows reduces predictability for transmission system operators and increases the risk of unscheduled loop flows, which can strain network stability.

From a market perspective, hydro dominance also influenced liquidity patterns across power exchanges. Exchanges in hydro-rich systems saw increased trading activity, reflecting the availability of surplus generation and the need to allocate it efficiently. Albania’s ALPEX, for example, experienced a significant increase in traded volumes, while Montenegro’s MEPX also recorded strong growth. By contrast, markets more dependent on transit trading, such as Serbia’s SEEPEX, saw reduced activity, as CBAM dampened the attractiveness of cross-border arbitrage.

The temporary nature of hydro-driven dynamics is a critical consideration. Hydrological conditions are inherently variable, and the exceptional levels observed in Q1 2026 are unlikely to persist throughout the year. In the second half of the year, when water inflows typically decline, the Western Balkans often shift from net exporters to net importers of electricity. This seasonal reversal will interact with CBAM in different ways, potentially altering the balance of trade and the direction of price convergence.

At the same time, the increasing penetration of solar generation across the region introduces a new layer of complexity. Spring and summer months are expected to see rising solar output, which could partially offset the decline in hydro generation and create new periods of surplus supply. The interaction between solar, hydro, and CBAM-adjusted trade flows will be a key determinant of market behaviour in the coming quarters.

For investors, the hydro-driven market conditions of Q1 2026 highlight both opportunities and risks. On the positive side, low marginal cost generation can enhance profitability during periods of high output, particularly for systems with favourable emission profiles. On the risk side, reliance on hydrology introduces variability in revenue streams, as output and prices are highly sensitive to weather conditions. The addition of CBAM further complicates this picture, as it affects the ability to export surplus generation and monetise it in higher-priced markets.

The broader implication is that hydro dominance, while beneficial in the short term, does not provide a stable foundation for long-term market integration. The distortion observed in Q1 2026 is the result of an exceptional alignment of factors: high water inflows, low marginal costs, and the introduction of a new carbon pricing mechanism. As these conditions evolve, the market will need to adjust to a new equilibrium where hydro remains important but is no longer the dominant force shaping prices and flows.

In this context, Q1 2026 can be seen as both an outlier and a preview. It is an outlier in terms of hydrological conditions, but a preview of how CBAM interacts with supply-side shocks to produce complex and sometimes counterintuitive market outcomes. The challenge for market participants is to disentangle these effects, identifying which dynamics are temporary and which represent lasting structural changes.

What is already evident is that hydro, long considered a stabilising force in Southeast European electricity markets, can also act as a source of volatility when combined with new regulatory frameworks. Its ability to depress prices, alter trade flows, and reshape system dynamics is amplified under CBAM conditions, creating a market environment that is both more dynamic and more uncertain. As the region moves into subsequent quarters, the interplay between hydrology, carbon pricing, and market integration will remain a defining feature of its evolving electricity landscape.

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At the centre of this transformation is the linkage between CBAM and the EU Emissions Trading System. In Q1 2026, the relevant carbon benchmark for electricity imports was set at a quarterly weighted average of €75.36 per tonne of CO₂, effectively anchoring the cost of imported electricity to the EU’s carbon market. This linkage is not theoretical; it is directly translated into per-megawatt-hour costs applied to imports from non-EU systems. For coal-heavy exporters in the Western Balkans, default emission factors resulted in CBAM costs ranging between €70 and €86/MWh, while low-carbon systems such as Albania faced no additional cost due to a zero emission factor.

This cost layer fundamentally alters the structure of price formation in interconnected markets. In a conventional marginal pricing framework, the price of electricity in a given market is determined by the marginal generator—the last unit required to meet demand. In much of the EU, this marginal unit is often gas-fired generation, particularly during periods of moderate demand. In the Western Balkans, by contrast, marginal pricing has historically been influenced by coal and hydro, depending on seasonal conditions. CBAM introduces a new dimension: the marginal cost of imported electricity is no longer defined solely by the exporting system’s generation mix but by the carbon-adjusted cost imposed at the border.

The implications become evident when examining price differentials between markets. In Q1 2026, EU markets such as Hungary and Italy maintained price levels in the range of €120–130/MWh, reflecting a combination of gas prices and carbon costs embedded within the EU ETS. At the same time, Western Balkan markets, benefiting from strong hydro output, recorded significantly lower prices, with Serbia averaging €94.7/MWh and Montenegro €85.8/MWh. Under traditional market conditions, these lower-cost systems would have exported electricity to the EU, contributing to price convergence. However, when CBAM costs of €70–80/MWh are added to these exports, the effective cost of imported electricity rises to levels that often exceed EU domestic prices, eliminating the economic incentive to trade.

This dynamic illustrates a key shift in marginal pricing logic. The marginal cost of supply in EU markets is no longer influenced by the actual cost of generation in neighbouring systems but by the carbon-adjusted cost imposed on imports. In effect, CBAM acts as a price floor for imported electricity, ensuring that it cannot undercut EU domestic generation by more than the carbon differential. This mechanism supports the policy objective of preventing carbon leakage but does so by reshaping the competitive landscape of electricity markets.

The pass-through of carbon costs is not uniform across all systems. It is determined by default emission factors assigned at the country level, which serve as proxies for the carbon intensity of exported electricity. These factors introduce a degree of approximation into the pricing mechanism, as they do not necessarily reflect the actual generation mix at the time of export. For example, a country with a mixed generation portfolio that includes both hydro and coal may still face a high default emission factor, resulting in CBAM costs that exceed the true carbon intensity of the exported electricity. This creates a distortion in price signals, as the cost applied at the border does not align perfectly with the underlying emissions.

From a market perspective, this distortion has several consequences. First, it reduces the efficiency of price signals by decoupling them from actual production costs. Traders and utilities must base their decisions not on the marginal cost of generation but on a regulatory construct that may not reflect real-time conditions. Second, it introduces uncertainty into price formation, as changes in EU ETS prices directly affect the cost of imports. In Q1 2026, carbon prices exhibited notable volatility, declining sharply between mid-January and the end of March amid discussions on potential reforms. This volatility feeds directly into electricity prices, adding a layer of financial risk that market participants must manage.

The integration of carbon cost pass-through into electricity pricing also affects bidding behaviour in day-ahead markets. Generators and traders must now anticipate not only the supply-demand balance and fuel costs but also the impact of CBAM on cross-border trades. In practice, this has led to more cautious bidding strategies, particularly for exports into the EU. The uncertainty surrounding the final cost of CBAM certificates—combined with the lag between trading decisions and the actual surrender of certificates—creates an additional risk premium that is reflected in bids. As a result, price formation becomes less responsive to pure market fundamentals and more influenced by regulatory considerations.

Another important dimension of carbon cost pass-through is its impact on the relative competitiveness of different generation technologies. Within the EU, carbon pricing has already shifted the merit order in favour of lower-emission sources such as renewables and nuclear, while penalising coal and, to a lesser extent, gas. CBAM extends this logic to imports, effectively exporting the EU’s carbon price signal to neighbouring markets. However, the use of default emission factors amplifies this effect in ways that may not fully align with actual emissions. Systems with high default factors face significant cost penalties, regardless of their current generation mix, while low-carbon systems gain a disproportionate advantage.

This dynamic is particularly evident in the contrast between Albania and Montenegro. Albania’s electricity system, dominated by hydro, is assigned a zero emission factor, allowing it to export electricity into the EU without incurring CBAM costs. Montenegro, by contrast, with a substantial share of coal generation, faces CBAM costs of approximately €73–74/MWh. In Q1 2026, this difference translated into divergent trading outcomes. Albania increased its exports, benefiting from both low generation costs and the absence of carbon charges, while Montenegro saw a decline in exports despite favourable price spreads. The implication is clear: carbon cost pass-through is not merely an adjustment mechanism but a determinant of market access.

The influence of CBAM on price formation also extends to forward markets and long-term contracting. Power purchase agreements and hedging strategies rely on expectations of future price dynamics, including the relationship between different markets. When carbon costs become a central component of pricing, these expectations must incorporate projections of EU ETS prices, regulatory developments, and potential changes in emission factor methodologies. This increases the complexity of contract structuring and risk management, as participants must account for a wider range of variables.

For investors, the integration of carbon cost pass-through into electricity markets has significant implications. Projects that depend on cross-border exports—particularly those in coal-heavy systems—face increased revenue uncertainty, as their competitiveness is contingent on carbon pricing dynamics. Conversely, low-carbon projects, especially in hydro and renewable generation, benefit from a structural advantage, as their output can be exported without incurring additional costs. This creates a divergence in investment signals, favouring certain technologies and locations over others.

At the system level, the incorporation of carbon costs into price formation contributes to the broader objective of decarbonisation but may also introduce transitional inefficiencies. By altering the relative prices of electricity across borders, CBAM affects the allocation of generation and the utilisation of transmission capacity. In some cases, this may lead to suboptimal dispatch decisions, where higher-cost domestic generation is used instead of lower-cost imports due to carbon adjustments. While this outcome aligns with climate policy objectives, it raises questions about the trade-off between efficiency and decarbonisation.

Looking forward, the evolution of carbon cost pass-through will depend on several factors. The trajectory of EU ETS prices will remain a key driver, as higher carbon prices increase the cost of imports and reinforce the effects observed in Q1 2026. Regulatory refinements to CBAM, particularly in the treatment of emission factors and the recognition of actual generation characteristics, could mitigate some of the distortions currently observed. Additionally, the potential introduction of carbon pricing mechanisms within the Western Balkans could reduce the asymmetry between EU and non-EU markets, aligning price signals and restoring some degree of integration.

The first quarter of 2026 demonstrates that carbon cost pass-through is no longer a peripheral consideration in electricity markets; it is a central determinant of price formation. By embedding carbon costs directly into cross-border transactions, CBAM has extended the reach of the EU ETS beyond its borders, reshaping the economics of trade and the structure of pricing across Southeast Europe. The resulting system is more complex, more policy-driven, and more closely tied to carbon market dynamics than ever before. For market participants, understanding and navigating this new landscape will be essential as the region moves deeper into the CBAM era.

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That model has begun to unravel. The introduction of the Carbon Border Adjustment Mechanism (CBAM) in its definitive phase at the start of 2026 has altered the economics of cross-border electricity trade in a way that fundamentally challenges the viability of arbitrage-based strategies. The first quarter of the year provides the clearest evidence yet that the traditional trading architecture of Southeast Europe is no longer intact.

The mechanics of this shift are straightforward in principle but far-reaching in effect. CBAM imposes a carbon cost on electricity imports into the EU, calculated on the basis of default emission factors and linked directly to the EU Emissions Trading System. In Q1 2026, the relevant carbon price averaged €75.36 per tonne of CO₂, translating into effective import costs of approximately €70–86/MWh for electricity originating from coal-dominated systems in the Western Balkans. This additional cost layer does not merely compress margins; in many cases, it eliminates them entirely.

The consequences are visible in the relationship between price spreads and physical flows. In a functioning arbitrage environment, a widening spread between two markets should trigger increased cross-border trade until the spread narrows. In Q1 2026, the opposite occurred. Price differentials between Western Balkan markets and neighbouring EU zones widened to levels rarely observed in recent years—often exceeding €30/MWh, and in some corridors reaching over €40/MWh—yet cross-border flows declined. This disconnect between price signals and trading behaviour is the defining feature of the new market reality.

The Montenegro–Italy corridor offers a particularly illustrative example. Southern Italy recorded some of the highest day-ahead prices in the region, averaging above €130/MWh, while Montenegro’s prices hovered closer to €85/MWh. Under traditional market conditions, a spread of roughly €43/MWh would have supported strong export flows from Montenegro to Italy via the submarine interconnector. Instead, both scheduled and physical flows on this route declined. The reason is not a lack of capacity or demand but the absorption of the price differential by CBAM-related costs. With Montenegro’s default emission factor implying a carbon cost of approximately €73–74/MWh, the apparent arbitrage opportunity is effectively neutralised.

This pattern is not confined to a single corridor. Across the region, similar dynamics are evident. The Serbia–Hungary border, historically one of the most active trading interfaces in Southeast Europe, exhibited a spread of approximately €31/MWh in Q1 2026. Yet this differential failed to generate the expected increase in export flows from Serbia to Hungary. The explanation lies in the same mechanism: CBAM costs, combined with regulatory uncertainty regarding compliance and reporting, have reduced the economic attractiveness of cross-border trades.

The impact of this shift extends beyond spot market activity into the structure of trading strategies themselves. Arbitrage, as traditionally practiced, relies on the ability to capture predictable spreads between markets. When those spreads are subject to policy-driven cost adjustments that can vary with carbon prices, the risk profile changes fundamentally. Traders are no longer dealing with purely market-based variables such as fuel costs, demand patterns, or weather conditions. They must now incorporate regulatory risk, carbon price volatility, and the specifics of CBAM implementation into their decision-making.

This increased complexity has led to more cautious trading behaviour. Evidence from cross-border capacity auctions suggests that market participants reduced their exposure to forward commitments even before CBAM entered into force. Yearly auction prices for interconnection capacity declined by as much as 24–67% on key corridors, reflecting lower expectations of future arbitrage profitability. Daily allocation rates remained high—often above 95%—indicating that capacity continues to be booked, but the value attributed to that capacity has diminished. In effect, interconnectors are still used, but not in the same way or for the same economic purpose.

The transformation is also visible in the performance of regional power exchanges. Total traded volumes across the Western Balkans increased modestly, rising from 2.16 TWh to 2.39 TWh year-on-year, but this aggregate figure masks a significant divergence at the exchange level. Markets with strong domestic generation—particularly hydro-rich systems—experienced substantial growth. Albania’s ALPEX saw volumes roughly double, while Montenegro’s MEPX recorded a 49% increase. By contrast, Serbia’s SEEPEX, which has historically functioned as a hub for transit-based trading, saw volumes decline by 11%. This divergence reflects a broader shift away from arbitrage-driven liquidity towards generation-driven activity.

The decline of transit trading is particularly significant. Prior to 2026, the Western Balkans often served as a corridor for electricity flows between EU markets. For example, power might move from Hungary through Serbia and into Bulgaria, exploiting price differentials along the way. CBAM has disrupted this model by introducing uncertainty regarding the treatment of transit flows. If electricity passing through a non-EU country is subject to carbon costs, even if it originates and is consumed within the EU, the economics of such routes become less attractive. As a result, traders have begun to avoid transit paths involving the Western Balkans, favouring alternative routes that remain entirely within the EU or involve low-emission systems.

This rerouting behaviour has broader implications for the geography of electricity trade. Instead of a network optimised for economic efficiency, flows are increasingly shaped by regulatory considerations. Routes that minimise exposure to CBAM costs become more attractive, even if they are not the shortest or most direct paths. This introduces inefficiencies into the system, as electricity may travel longer distances or through less optimal corridors to avoid carbon charges. Over time, such patterns could alter the utilisation of interconnectors, the development of new infrastructure, and the strategic positioning of different markets within the regional grid.

The erosion of arbitrage also affects the role of interconnectors as financial assets. In liberalised electricity markets, interconnectors are not merely physical links but also instruments for capturing price differentials. Their value is often reflected in the prices paid for capacity rights in auctions. When arbitrage opportunities diminish, so does the willingness of market participants to pay for those rights. The decline in forward auction prices observed at the end of 2025 suggests that investors and traders had already begun to reassess the revenue potential of interconnectors under CBAM conditions. This has implications for future investment decisions, particularly in projects that rely on congestion rents or merchant revenue models.

From a system perspective, the decline in arbitrage-based trading introduces new challenges. Cross-border flows have historically contributed to balancing supply and demand across regions, smoothing price volatility and enhancing security of supply. When these flows are constrained by economic factors rather than physical limitations, the system loses a degree of flexibility. Markets become more reliant on domestic generation, which may not always be the most efficient or cost-effective option. In the longer term, this could lead to higher overall system costs and reduced resilience to shocks.

The interaction between CBAM and EU ETS adds another layer of complexity. Because CBAM costs are directly linked to carbon prices, the economics of arbitrage are now sensitive to developments in the emissions market. In Q1 2026, EU ETS prices declined sharply after an initial increase, reflecting political discussions around potential reforms. This volatility feeds directly into electricity trading decisions, as the cost of importing power from non-EU countries fluctuates with carbon prices. Traders must therefore manage not only power price risk but also carbon price risk, effectively integrating two markets that were previously more loosely connected.

For coal-dependent systems in the Western Balkans, the implications are particularly stark. These markets have traditionally relied on their cost advantage to remain competitive in regional trade. CBAM erodes that advantage by attaching a carbon cost that reflects their higher emission intensity. While this aligns with the broader objective of decarbonisation, it also creates a transitional challenge. Investments in cleaner generation or emissions reduction technologies take time, while the impact of CBAM is immediate. In the interim, these systems may find themselves excluded from cross-border trade, with limited opportunities to monetise their existing generation assets.

At the same time, low-carbon systems—particularly those dominated by hydro—gain a relative advantage. Albania, with a default emission factor effectively equal to zero, can export electricity into the EU without incurring CBAM costs. This creates a strong incentive for traders to source power from such systems, reinforcing their role in regional markets. However, this advantage is contingent on hydrological conditions, which can vary significantly from year to year. The sustainability of this competitive position is therefore uncertain.

Looking ahead, the future of cross-border power trading in Southeast Europe will depend on how market participants adapt to the new environment and how policymakers refine the CBAM framework. Greater clarity on the treatment of transit flows, potential adjustments to default emission factors, and mechanisms for recognising actual generation characteristics could all influence the evolution of trading strategies. At the same time, the development of regional carbon pricing mechanisms aligned with the EU ETS could reduce the asymmetry between EU and non-EU markets, restoring some of the conditions necessary for efficient arbitrage.

What is already evident is that the era of straightforward cross-border arbitrage is coming to an end. The combination of carbon pricing, regulatory uncertainty, and shifting market fundamentals has transformed the landscape in which traders operate. Arbitrage has not disappeared entirely, but it has become more complex, more conditional, and more tightly linked to policy dynamics. For a region that has relied heavily on cross-border trading to drive integration and efficiency, this represents a profound change—one that will continue to shape market behaviour in the years to come.

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At the centre of this shift lies a fundamental change in how cross-border electricity trade is priced. Electricity imports into the EU from non-member states are now subject to a carbon cost aligned with the EU Emissions Trading System (EU ETS). In principle, this creates a level playing field between EU and non-EU producers. In practice, it introduces a non-market cost layer that disrupts the traditional mechanics of arbitrage and price convergence. The immediate effect has been visible in day-ahead market outcomes. Average prices in core EU benchmark markets such as Hungary and Italy remained anchored at €120–130/MWh in Q1 2026, broadly consistent with 2025 levels. By contrast, prices in key WB6 markets dropped significantly, with Serbia averaging €94.7/MWh, Montenegro €85.8/MWh, and North Macedonia €96.7/MWh. The resulting spread—exceeding €30/MWh—is not only materially wider than historical norms but also persistent across the quarter.

The scale of this divergence is best understood in the context of previous years. Throughout 2025, price spreads between Hungary and the Western Balkans typically fluctuated within a €5–15/MWh range, with strong correlation coefficients often exceeding 0.90. Such conditions reflected a functioning arbitrage mechanism: electricity flowed from lower-priced zones to higher-priced ones until price convergence was restored. In Q1 2026, this mechanism weakened. Correlations collapsed sharply in January, with some relationships briefly approaching zero or turning negative. Although partial recovery was observed towards the end of the quarter, correlations remained below historical levels, indicating that the underlying integration mechanism had been impaired.

The immediate question is whether this decoupling is cyclical or structural. A superficial reading might attribute the divergence to the exceptional hydrological conditions that characterised the quarter. Hydro generation across the region increased by 33%, rising from 16.7 TWh to 22.18 TWh, flooding WB6 markets with low-cost electricity and pushing prices downward. This effect was particularly pronounced in Albania, Serbia, and Bosnia and Herzegovina, while Greece also saw a significant increase in hydro output, partially explaining its closer alignment with WB6 price levels. Hydro-driven price suppression is not new; similar dynamics have been observed in previous wet years. What is new, however, is the persistence of wide spreads despite available cross-border capacity and strong economic incentives to trade.

Under normal conditions, a €30–40/MWh spread between neighbouring markets would trigger substantial exports from the lower-priced region. Yet in Q1 2026, arbitrage flows were muted. Cross-border capacity allocation rates remained high—often above 95%—suggesting that physical infrastructure was not the constraint. Instead, the limiting factor was economic. CBAM-related costs, derived from default emission factors and EU ETS prices averaging €75.36/tCO₂, added between €70 and €86/MWh to electricity imports from coal-intensive WB6 systems. This effectively neutralised the price advantage of cheaper generation, compressing or eliminating arbitrage margins.

The result is a paradox: markets that appear disconnected in price terms remain physically interconnected, yet economically segmented. Electricity continues to flow according to the physical properties of the grid, but commercial incentives no longer align with those flows. This decoupling of economic and physical signals represents a departure from the foundational principles of market integration in Europe, where price signals are expected to guide both trading and dispatch decisions.

The implications for price formation are significant. In an integrated market, prices in neighbouring zones reflect a shared marginal cost, adjusted for transmission constraints. In a fragmented system, prices become increasingly localised, reflecting domestic supply conditions rather than regional equilibrium. In Q1 2026, WB6 prices were driven primarily by hydro availability, while EU prices remained tied to gas-fired generation and carbon costs. The absence of effective arbitrage allowed these divergent cost structures to persist, resulting in a bifurcated pricing landscape.

This bifurcation has consequences beyond spot market dynamics. Forward markets, which rely on expectations of future price convergence, become less reliable in a decoupled environment. Traders and utilities face increased uncertainty when pricing contracts, hedging exposures, or structuring power purchase agreements. The decline in forward capacity auction prices—by 24–67% on key corridors—suggests that market participants anticipated reduced arbitrage opportunities even before CBAM took full effect. This forward-looking adjustment reinforces the notion that decoupling is not merely a short-term anomaly but a structural shift in market expectations.

Liquidity patterns across regional power exchanges further illustrate this divergence. While total traded volumes in the Western Balkans increased by 11% year-on-year, the distribution of that growth was uneven. Exchanges benefiting from hydro-driven supply, such as Albania’s ALPEX and Montenegro’s MEPX, recorded substantial increases in activity. By contrast, Serbia’s SEEPEX—historically a hub for transit-based trading—experienced a decline of 11%. This divergence reflects a broader transition from arbitrage-driven liquidity to generation-driven liquidity. Markets that rely on their own low-cost production gain prominence, while those dependent on cross-border trading lose relevance.

The decoupling also raises questions about the future of market coupling initiatives in Southeast Europe. The EU’s long-term objective has been to integrate neighbouring markets into a single electricity market, enabling efficient allocation of resources and enhancing security of supply. CBAM, while designed as a climate policy tool, introduces frictions that run counter to this objective. By imposing uniform carbon costs on imports—regardless of the actual generation source—it distorts the price signals that underpin market coupling. The result is a system where regulatory design overrides market logic, at least in the short term.

For policymakers, the challenge lies in balancing decarbonisation objectives with market integration goals. CBAM aims to prevent carbon leakage and ensure fair competition, but its current design—particularly the reliance on default emission factors—creates blunt cost signals that do not reflect the diversity of generation mixes within exporting countries. Hydro-dominated systems such as Albania benefit disproportionately, while coal-heavy systems face significant penalties. This asymmetry amplifies price divergence and reinforces structural imbalances across the region.

Looking ahead, the trajectory of price decoupling will depend on several factors. Hydrological conditions are likely to normalise in the second half of the year, reducing the supply-driven price advantage in the WB6. At the same time, increased solar generation during the summer months may introduce new volatility patterns, potentially creating periods of surplus in both EU and non-EU markets. The evolution of EU ETS prices will also play a critical role, as CBAM costs are directly linked to carbon market dynamics. Finally, regulatory clarity—particularly regarding the treatment of transit flows and the potential refinement of emission factor methodologies—will influence how market participants adapt to the new environment.

What is already clear is that Q1 2026 represents more than a transitional phase. The observed breakdown in price correlation, the persistence of wide spreads, and the weakening of arbitrage mechanisms collectively point to a structural redefinition of Southeast Europe’s electricity market. The region is no longer operating as a loosely integrated extension of the EU market but is beginning to exhibit characteristics of a segmented system, where cross-border trade is constrained not by physical limitations but by policy-induced cost barriers.

For investors, traders, and system operators, this shift demands a recalibration of strategies. Price signals can no longer be assumed to converge, arbitrage opportunities are conditional on carbon cost dynamics, and market risk is increasingly shaped by regulatory factors rather than purely economic ones. The integration narrative that has defined Southeast Europe’s energy markets over the past decade is entering a new phase—one where decarbonisation policy and market design intersect in ways that fundamentally alter the rules of engagement.

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Day-ahead prices across the region posted double-digit declines, with the steepest corrections seen in Croatia and Hungary, where weekly averages fell to €72.92/MWh (-30.3%) and €80.31/MWh (-27.3%), respectively. Romania and Bulgaria followed with prices easing to €86.99/MWh (-17.5%) and €81.82/MWh (-16.8%), while Greece dropped to €78.61/MWh (-16.2%). Serbia saw a more moderate decline to €80.41/MWh (-11.6%), reflecting comparatively tighter system conditions. Italy remained the regional premium market at €109.12/MWh, despite a softer week-on-week trend.

The correction mirrored developments in core European markets, where prices fell more aggressively, led by Germany, the Czech Republic and Slovakia with declines exceeding 40%, while France collapsed to €7.62/MWh (-89.3%), indicating extreme oversupply conditions tied to high nuclear and renewable output. The Iberian markets remained broadly stable around €50/MWh, highlighting continued regional decoupling within Europe.

Despite the weekly downturn, early indications for Week 18 point to renewed upward pressure. Day-ahead prices on April 28 rebounded across SEE, ranging between €97.01/MWh in Greece and €112.66/MWh in Hungary, underlining persistent volatility and the absence of a stable downside in current market conditions.

On the demand side, electricity consumption across SEE declined by -2.6% week-on-week, reversing the previous week’s growth. Italy and Türkiye led the downturn with contractions of -4.1% and -3.9%, respectively, while Hungary also posted a -4.1% decline. In contrast, Romania and Greece recorded increases of +6.5% and +3.2%, suggesting localized demand recovery linked to weather patterns and short-term economic activity.

Supply dynamics were dominated by a sharp drop in wind generation. Total variable renewable output across SEE fell by -11.3%, driven by a -29.3% collapse in wind production, while solar output increased by +8.8%, partially offsetting the decline. The largest reductions in wind were recorded in Türkiye (-40.4%), Croatia (-22.9%) and Greece (-16.3%), reinforcing the system’s exposure to weather-driven volatility.

Hydropower output remained broadly stable at -1.5%, although national trends diverged significantly. Croatia posted a sharp increase of +145.2%, while Serbia, Bulgaria and Romania recorded declines of -23.4%, -27.4% and -9.8%, respectively. Thermal generation decreased by -6.4%, led by a -14.3% drop in gas-fired output, while coal generation rose modestly by +3.3%, highlighting continued fuel switching in response to gas price dynamics.

Cross-border flows expanded notably during the week, with the region’s net import position rising by +39.7%. Greece and Romania both shifted from net export to net import positions, while Serbia also moved deeper into import territory. Italy remained the dominant net importer, while Croatia strengthened its export position and Hungary’s surplus narrowed.

Market liquidity remained highly concentrated. Weekly traded volumes reached 20,340 GWh in Italy, significantly outpacing other markets, followed by 3,560 GWh in Greece, 2,450 GWh in Bulgaria, and 2,260 GWh in Hungary. Serbia continued to show limited liquidity with just 110 GWh traded over the week, underscoring structural constraints in regional price formation.

In gas markets, TTF front-month futures extended gains early in the week before stabilizing. Prices rose from €40.29/MWh to a peak of €44.86/MWh, with a weekly average of €43.03/MWh, marking a +1.3% week-on-week increase. By April 27, prices eased slightly to €44.65/MWh, suggesting consolidation near the mid-€40/MWh range.

The upward pressure was driven by renewed geopolitical uncertainty linked to stalled US-Iran negotiations and escalating tensions around the Strait of Hormuz. Disruptions to LNG flows have already altered the global gas balance, with estimates pointing to a cumulative loss of around 120 bcm of LNG supply between 2026 and 2030, equivalent to roughly 15% of expected global supply growth. This has delayed the anticipated market loosening by up to two years and reinforced the role of gas as a key price-setting component in European power markets.

LNG flows into Europe showed mixed signals. Greece recorded a +22% increase in LNG inflows to 663.83 GWh, while Italy maintained its position as the dominant entry point with 4,334.7 GWh. In contrast, Croatia saw a sharp decline of -60.8%, highlighting the volatility of regional LNG infrastructure utilization.

The interplay between weakening renewable output, shifting cross-border flows and firming gas prices suggests that while short-term price corrections remain likely, the broader market structure continues to support elevated price levels and high volatility across SEE power markets.

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The main driver was the regional balance tightening. SEE consumption increased to 29,312 MW, up 1,234 MW versus the previous day, while total net imports jumped to 1,752 MW, an increase of 1,509 MW. Core imports from Austria and Slovakia into the HU/SEE perimeter rose to 3,336 MW, showing that Central European supply was again needed to cover regional shortness. At the same time, solar output fell by 1,424 MW and wind by 243 MW, removing cheap midday supply and lifting the whole daily curve.  

The spread structure confirms the tightening. The HU-DE spot spread widened to €47.31/MWh, up €14.7/MWh, showing that Hungary and SEE were priced materially above Germany. The HU-GR spread narrowed to €15.65/MWh, meaning Greece was closer to the regional price stack but still below HUPX. The import signal was therefore strongest from the northwest, while southern SEE markets remained less expensive than Hungary.  

Serbia traded in line with the regional core rather than the lower Balkan fringe. SEEPEX reached €107.06/MWh, up €10.3/MWh, leaving Serbia €5.60/MWh below HUPX but above Greece, Bulgaria, Montenegro, Albania and North Macedonia. This points to Serbia being pulled by Hungary-Croatia-Slovenia pricing rather than by the cheaper southern markets.

The intraday shape remained highly volatile. HUPX showed a deep midday trough, with the daily minimum around hour 15, and a strong evening ramp, with the maximum around hour 21. This confirms the dominant April pattern: solar depresses midday pricing, but once solar fades, residual demand and imports drive steep evening scarcity premiums.

Forward indicators were mixed. CEGH gas stayed around €46.05/MWh, Greek gas eased to €45.9/MWh, EUA moved slightly higher to €75.11/t, while Hungarian forward power showed week-19 at €99.50/MWh, week-20 at €91.00/MWh, May-26 at €93.50/MWh and Cal-26 at €111.50/MWh. Coal forwards remained around $104.5–114.5/t, keeping thermal marginal costs firm but not the sole driver of spot pricing.

The trading conclusion is straightforward: 29 April was not a fuel-cost rally, but a balance-driven repricing. Lower RES, colder weather, stronger demand and higher imports tightened SEE-Hungary supply, widened the HU-DE spread and lifted Serbia, Croatia, Slovenia and Romania into the €107–111/MWh band. Midday downside remains visible, but the evening ramp is now the key risk window for traders.

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In March, production from thermal power plants fell by 7% year-on-year to 361 GWh. Output from hydropower plants dropped significantly by 36%, reaching 265 GWh, while the Krško nuclear power plant maintained stable production at approximately 521 GWh. In contrast, generation from wind and solar sources increased by 45%, reaching 146 GWh, highlighting continued growth in renewables.

On the trade side, Slovenia imported 768 GWh of electricity, which is 7% more than in March 2024, while exports amounted to 836 GWh, representing a 14% decrease. This indicates a slightly reduced export surplus compared to the previous year.

Final consumption trends showed mixed movement. Household electricity consumption stood at 303 GWh, down 3% compared to the previous month, while commercial consumption increased by 6%, reaching 609 GWh, reflecting stronger business activity.

In terms of energy commodities, supply trends were generally positive in March, with increases across most categories. However, declines were recorded in kerosene (-6%), natural gas (-5%), LPG (-5%), and coke (-3%). On the other hand, strong monthly growth was observed in other petroleum products (+188%), followed by increases in hard coal (+44%), diesel (+13%), petrol (+13%), and lignite and brown coal (+9%).

Year-on-year comparisons also showed broad increases in energy supply. The supply of other petroleum products rose by 120%, kerosene by 41%, petrol by 9%, natural gas by 5%, and hard coal by 3%, indicating overall stronger energy market activity compared to March 2025.

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The project, named Maruntei–Vest and located in Olt County, will include 61 MW of solar capacity together with a 100 MWh battery energy storage system (BESS). Construction is already underway, with engineering and construction works being carried out jointly by ENEVO Group and Vertex Energy.

As part of the financing structure, Vertex Energy has entered the project as a minority shareholder, acquiring a 49% stake, while Kraftfeld Energy retains majority ownership. In parallel, the Austrian developer secured €50.4 million in project financing arranged by Kommunalkredit.

The Olt-based development represents Kraftfeld Energy’s second major investment move in Romania within a short period. It follows the earlier financing of the Gârla Mare 2 solar project, which has an installed capacity of 126 MW.

Together, the two projects are expected to add nearly 190 MW of solar capacity and around 300 MWh of storage to Romania’s power system, strengthening the country’s renewable generation base and flexibility in grid operations.

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This marks the third amendment to the original concession agreement concluded in 2022. Project progress accelerated earlier this year after EPCG appointed Vigoris Ecotech to handle both design and construction works, following several unsuccessful tender procedures.

Under the revised timeline, the project is expected to obtain a construction permit by late September 2026, which would formally complete the preparatory phase. Originally, EPCG was required to finalize technical documentation and secure all necessary permits within 18 months, but repeated delays led to successive extensions of the deadline.

Once the first phase is completed, the second stage will focus on construction and commissioning, with a planned duration of two years as defined in the concession agreement. The facility will include two horizontal Francis turbine units with a total installed capacity of approximately 3.2 MW.

Upon completion, the small hydropower plant is expected to generate around 11 GWh of electricity annually, supplying energy equivalent to the consumption of roughly 1,800 households, contributing to Montenegro’s broader renewable energy expansion goals.

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The Zabok–Lučko section was connected at the Lučko gas hub, while the Kozarac–Sisak line was tied into the existing Zagreb East–Kutina pipeline near the Kozarac node. The operation was overseen by system operator Plinacro, with works carried out by Monter and other contractors.

During the shutdown, extensive safety and environmental procedures were implemented. Natural gas was first evacuated from the system in line with strict methane emission regulations, after which the infrastructure was filled with nitrogen to ensure safe working conditions. Once the connections were completed, the system was gradually recommissioned, with nitrogen replaced by natural gas and pressure restored to normal operating levels.

Executing the works simultaneously at two separate locations required complex system coordination but helped avoid additional service interruptions. During the maintenance period, gas inflows from the LNG terminal on Krk were temporarily halted, while the southern part of the network relied entirely on domestic production from the northern Adriatic. At the same time, nearly 90 kilometers of pipeline were isolated from the system.

Despite the scale and complexity of the operation, the project was completed without unexpected disruptions, marking an important step in strengthening the resilience and flexibility of Croatia’s gas transmission infrastructure.

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HROTE sold 258,578 GOs from wind power plants for electricity produced in Q1 2026 at a price of 1.32 €/GO, alongside 30,483 GOs from biomass power plants for the same production period at 1.26 €/GO. These volumes represented the largest share of the auction activity, driven primarily by wind generation assets.

ENNA Next sold several smaller but diversified batches of guarantees of origin. This included 15,026 GOs from Croatian wind power plants (production in January and February 2026) at 1.30 €/GO, as well as 8,082 GOs from German wind power plants (Q1 2026 production) at a higher price of 1.45 €/GO, reflecting stronger valuation for imported renewable certificates.

Additional volumes included 360 GOs from biogas plants, 296 GOs from solar plants, and 337 GOs from biomass plants, all produced between December 2025 and February 2026, and all sold at 1.22 €/GO.

Overall, the auction results highlight steady demand for renewable-backed certificates, with wind energy guarantees dominating trading volumes, while price differentiation across technologies and geographies reflects varying market perceptions of renewable origin value.

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BNRA Chairman Tsanko Bachiyski confirmed that the transition is proceeding in line with approved technical documentation. Two batches of new fuel assemblies have already been inserted into the reactor core, and early monitoring indicates stable and expected performance levels.

The unit is scheduled for a planned shutdown on May 9, when another set of fuel assemblies will be introduced during a maintenance outage expected to last around 40 days. Continuous monitoring will remain in place, with the full fuel transition targeted for completion in 2027, while a final assessment of long-term performance is expected in 2028.

The regulator highlighted that the fuel diversification effort represents a notable milestone within the European Union, as Bulgaria becomes the first EU member state to successfully implement such a transition for a VVER-1000 reactor. This achievement was also recognized during the latest review under the Convention on Nuclear Safety.

At the same time, the operator of the Kozloduy plant has submitted a request to introduce test assemblies of the new fuel into Unit 6. However, the application has been returned for revision due to incomplete documentation, with the plant given two months to correct the issues before the review process continues.

Bachiyski emphasized that regulatory approval will depend entirely on compliance with strict safety standards. He also noted that evaluating the performance of test assemblies in Unit 6 will require several years of operational data, meaning any final decision on broader fuel replacement will only be made after sufficient evidence is collected.

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The project is expected to significantly improve supply diversification for Bosnia and Herzegovina (BiH) by enabling access to alternative gas sources, including liquefied natural gas (LNG) delivered via the Krk terminal in Croatia. Officials emphasized that the initiative will strengthen energy security at a time of continued global uncertainty.

Prior to the signing ceremony, the agreement had already passed key institutional approvals, first from the Council of Ministers and subsequently from the Presidency of Bosnia and Herzegovina, paving the way for formal adoption in the presence of international representatives.

Government officials from both sides described the pipeline as a strategic regional infrastructure project with long-term importance. According to statements from the Bosnian side, the initiative represents a turning point in efforts to diversify energy supply routes and reduce dependence on limited sources.

Bosnian energy sector representatives also highlighted the broader economic and industrial impact of the project. Federal Energy Minister Vedran Lakić pointed to years of preparatory work leading to this stage, while Energoinvest CEO Mirza Ustamujić emphasized its importance for strengthening energy independence and integrating domestic companies into major regional developments.

Despite earlier concerns about potential disagreements among international stakeholders, both European and US officials confirmed that the project will fully comply with EU energy market regulations. These rules require open access to infrastructure and prohibit preferential treatment for individual companies, ensuring equal access for all potential gas suppliers.

Initial proposals from external investors have been aligned with European regulatory frameworks, particularly the EU Third Energy Package, which mandates the separation of infrastructure operators from gas suppliers in order to ensure fair competition.

Once completed, the Southern Gas Interconnection is expected to become a key pillar of regional energy cooperation, contributing to a more resilient and diversified gas supply system across Southeastern Europe.

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The rise in oil prices was primarily driven by escalating geopolitical tensions, particularly the closure of the Strait of Hormuz and the lack of progress in negotiations between the United States and Iran. These developments heightened supply risk perceptions and reinforced bullish momentum in global oil markets.

TTF natural gas futures on the ICE market also moved higher during the same period. The front-month contract registered its weekly low at €40.29/MWh on Monday, April 20, before steadily increasing throughout the week. By Friday, April 24, prices reached a weekly high of €44.86/MWh, representing a 16% increase compared to the previous week’s final session, according to AleaSoft Energy Forecasting.

Gas prices were similarly influenced by geopolitical developments. Rising tensions between the United States and Iran, combined with disruptions linked to restricted maritime flows through the Strait of Hormuz, raised concerns over global LNG supply security. The resulting risk premium supported higher prices across European gas benchmarks.

In contrast, EU carbon emission allowance futures (EUA) for the December 2026 contract on the EEX market showed a weaker performance. Prices opened the week at their high of €76.15/t on Monday, already down 1.7% from the previous Friday, and then declined further midweek. The weekly low was reached on Wednesday, April 22, at €74.42/t. Although a slight recovery followed in the final two sessions, prices remained below €75/t, closing on Friday, April 24 at €74.91/t, which was 3.3% lower week-on-week, according to AleaSoft Energy Forecasting.

Overall, the week was defined by strong upward momentum in both oil and gas markets driven by geopolitical risk, while carbon prices moved in the opposite direction, reflecting weaker sentiment and a modest corrective phase in emissions trading, AleaSoft reports.

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During the week of April 20, weekly average prices stayed below 70 €/MWh in most European electricity markets. The United Kingdom and Italy were exceptions, with averages of 108.54 €/MWh and 109.12 €/MWh, respectively. At the lower end, France recorded the weakest weekly average at just 7.62 €/MWh, while other markets ranged from 39.75 €/MWh in the Nordics to 67.36 €/MWh in the Netherlands.

On a daily basis, France recorded the lowest average price of the week among the analyzed markets, reaching 40.83 €/MWh on Sunday, April 26, which also marked its lowest level since June 17, 2013. On the same day, the Dutch market posted a daily price of 12.95 €/MWh, its lowest since October 6, 2025.

At the other end of the spectrum, Italy and the United Kingdom consistently recorded daily prices above 100 €/MWh throughout most of the week. Belgium and the Netherlands also briefly exceeded this level on April 20. The Italian market reached the highest daily average of the week on April 22, at 120.07 €/MWh, among all analyzed markets.

Overall, during the week of April 20, lower electricity demand combined with higher wind and solar generation across most markets pushed prices downward across Europe. However, reduced wind and solar output in Spain contributed to a slight upward pressure on prices in that market. According to forecasts from AleaSoft Energy Forecasting, electricity prices in Europe could rise in the final week of April, driven primarily by lower wind generation, while gas price movements are also expected to play a key role in shaping market direction, AleaSoft reports.

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Average temperatures generally rose across most of the region during the same period. Portugal and Spain experienced the strongest increases, at 2.1°C and 1.7°C, respectively. The United Kingdom recorded the smallest rise of 0.1°C, while France saw temperatures increase by 1.4°C. In contrast, several other markets experienced cooling, with declines ranging from 0.8°C in Belgium to 2.5°C in Germany, highlighting uneven weather patterns across Europe.

According to AleaSoft Energy Forecasting, demand forecasts for the week of April 27 suggest a further decline in electricity consumption in France, Belgium, Germany, Italy, Spain, and Portugal, largely due to the impact of the May 1 International Workers’ Day holiday observed across much of continental Europe. In contrast, the British market is expected to see an increase in demand, setting it apart from the broader European trend, AleaSoft reports.

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During the same period, several markets reached new solar production records for April. France achieved its highest ever April solar output on April 20, reaching 149 GWh. Germany followed with a new April daily peak of 444 GWh on April 22, highlighting the strength of spring irradiance conditions. Italy set an all-time solar record on April 24 with 163 GWh, while Portugal also reached its highest April level on the same day, producing 28 GWh. These records underscore the growing role of solar energy in shaping short-term electricity supply dynamics across Europe.

According to AleaSoft Energy Forecasting, solar generation is expected to increase further during the week of April 27 in key markets such as Italy, Germany, and Spain, suggesting continued volatility driven by weather conditions and seasonal effects.

Wind energy production also showed strong movement during the week of April 20, increasing in most major European markets compared to the previous week. Germany and France experienced the most significant surges, with wind generation rising by 127% and 115%, respectively, fully reversing three consecutive weeks of declines. Portugal saw a more moderate increase of 42%, reflecting steadier but less extreme wind conditions.

However, Spain and Italy moved against the regional trend. Spain recorded a fourth consecutive weekly decline in wind generation, falling by 23%, while Italy saw a decrease of 20%, despite the rebound observed in the prior week. This divergence highlights the uneven nature of wind resource availability across Southern Europe.

Forecasts from AleaSoft Energy Forecasting indicate that during the week of April 27, wind energy production is expected to decline across all analyzed markets, suggesting a potential shift back toward tighter supply conditions and greater reliance on alternative generation sources, AleaSoft reports.

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Spot and forward gas prices surged early in the month as disruptions linked to the Middle East conflict constrained LNG transit flows, particularly through the Strait of Hormuz. During the first week of March, benchmark prices climbed rapidly, with average levels rising from around €31/MWh to €45/MWh, before front-month TTF futures peaked at €56.4/MWh on 9 March.  

The price spike reflected both immediate supply risk and a broader repricing of geopolitical exposure. Although prices briefly eased to around €47.4/MWh following signals of potential de-escalation, the market remained highly reactive to political developments, highlighting a structurally elevated volatility environment.

At the core of the tightening market is the disruption of LNG supply chains. Reduced availability of Qatari volumes and intensified competition for Atlantic Basin cargoes introduced a significant risk premium into European pricing. QatarEnergy warned that up to 17% of its LNG export capacity, equivalent to 12.8 mtpa, could remain offline for three to five years, reinforcing concerns over medium-term supply constraints.  

This has effectively doubled European gas prices compared with pre-conflict levels in February, pushing policymakers and market participants to reassess supply strategies and risk exposure. The situation has been compounded by continued structural tightness linked to the Russia-Ukraine war, which has already altered traditional pipeline flows and increased reliance on LNG imports.

European responses have so far been fragmented. Several countries introduced temporary measures to cushion the impact of higher prices, including excise tax reductions in Hungary, Italy and Slovenia, while Croatia and Slovakia implemented price controls. Italy also announced targeted financial support, allocating €100 million for 2026 to assist affected market participants.  

Despite these interventions, no coordinated EU-wide mechanism has emerged, leaving the market exposed to ongoing volatility and policy divergence.

Looking ahead, the outlook for the 2026 injection season is increasingly challenging. Europe enters the refill period with lower storage levels and higher uncertainty around LNG availability. Historically, EU gas demand during the April–October injection season has ranged between 140–145 bcm, typically met through a mix of pipeline imports.  

Maintaining comparable storage targets—around 83% capacity—will require significantly higher LNG inflows than in 2025, at a time when global competition for cargoes is intensifying. Any disruption to expected supply flows could therefore translate directly into higher prices and tighter market conditions.

Pipeline supply is expected to remain broadly stable, with Norway potentially increasing output to offset reduced Russian volumes. However, this stability does little to ease the central pressure point, which remains LNG availability. Additional uncertainty stems from Ukraine’s import requirements, which continue to fluctuate depending on infrastructure damage and repair cycles.

As a result, the European gas market enters the 2026 summer period under heightened stress, with price formation increasingly driven by global LNG dynamics rather than regional fundamentals alone. The combination of geopolitical risk, constrained supply flexibility and elevated demand for storage refilling points to a structurally tighter market, where volatility is likely to persist into the 2026–2027 winter cycle.

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Regional benchmarks shifted upward after a softer February, with average day-ahead prices clustering in the €95–€120/MWh range across core SEE hubs. Italy remained the most expensive market at €143.36/MWh, reinforcing its role as the region’s price anchor, while Hungary followed at €117.36/MWh and Croatia at €110.12/MWh. Romania and Bulgaria cleared at €105.15/MWh and €103.51/MWh respectively, with Greece and Serbia converging near €95/MWh. In contrast, Türkiye decoupled sharply, with prices dropping to €31.77/MWh, reflecting weaker demand and different market fundamentals.  

The upward correction in clearing prices was largely driven by higher gas input costs, as TTF futures moved above €50/MWh, feeding directly into thermal generation bids. Lower hydro output across much of the region and uneven renewable generation further tightened supply, increasing reliance on gas-fired units and amplifying price sensitivity.

Daily and hourly price formation pointed to growing intraday volatility. Midday prices were typically compressed by solar output, while evening peaks widened significantly, particularly in tighter systems such as Serbia, where balancing needs pushed prices sharply higher during ramping hours.  

On the volume side, liquidity remained highly concentrated. Italy dominated regional trading activity with approximately 24.2 TWh traded during the month, far exceeding all other markets. Greece followed with around 4.37 TWh, while Bulgaria and Hungary each recorded volumes close to 2.8 TWh. Romania traded roughly 1.35 TWh, Croatia 0.75 TWh, and Serbia remained structurally illiquid at just 0.46 TWh.  

Monthly volume movements diverged across the region. Greece recorded a +7.4% month-on-month increase in traded electricity, while Italy posted a modest +2.6% rise, suggesting stable demand and continued cross-border activity. Bulgaria also saw higher liquidity, with volumes up +5.6%, reflecting stronger market participation.

In contrast, Hungary and Romania saw declines in traded volumes of -7.8% and -10.0% respectively, indicating softer demand or reduced trading opportunities. Serbia’s volumes increased by +12.3% month-on-month, although absolute levels remained low, highlighting the limited depth of the SEEPEX exchange. Croatia posted a marginal +2.3% increase.  

Daily volume patterns confirmed a hub-and-spoke structure in regional trading. Italy consistently traded between 700–900 GWh/day, while Greece averaged 120–150 GWh/day and Bulgaria and Hungary ranged between 80–120 GWh/day. Serbia’s daily traded volumes remained below 20 GWh, underlining its exposure to sharper price movements due to limited liquidity.  

The relationship between clearing prices and volumes remained non-linear. High-liquidity markets such as Italy maintained elevated price levels due to their dependence on gas-fired generation, while smaller markets with lower liquidity, notably Serbia, exhibited stronger price volatility despite lower traded volumes. Markets with more diversified generation mixes, such as Bulgaria and Romania, recorded more moderate price increases alongside relatively stable liquidity.

March trading confirmed that SEE power markets remain structurally tied to gas price movements, with hydro variability and renewable output driving short-term divergences. Liquidity continues to be concentrated in a limited number of exchanges, while smaller markets show increased sensitivity to supply-demand imbalances, reinforcing volatility across the region.

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Net imports rose to 173 MW (+526 MW day-on-day), while core inflows from Austria and Slovakia reached 1,951 MW, underlining the region’s reliance on Central European supply.  

Electricity.Trade flow analytics show that these imports were concentrated along key corridors:

• AT/SK → Hungary → SEE
• Hungary → Serbia/Croatia
• Romania/Bulgaria → Greece

However, flows were unevenly distributed. Electricity.Trade congestion indicators confirm that Serbia and parts of Croatia experienced restricted access during peak hours, contributing to higher local prices.

The €32.6/MWh HU–DE spread acted as a primary driver for import arbitrage, but internal grid constraints limited transmission efficiency.   Electricity.Trade capacity utilisation data shows frequent saturation of key interconnectors during evening ramps.

System balancing requirements intensified these dynamics. Electricity.Trade real-time balancing data indicates that:

• Midday: reduced import demand due to solar surplus
• Evening: sharp increase in import needs exceeding +1 GW swing within hours

This created a feedback loop where flows directly influenced price formation, while price spreads in turn dictated flow direction.

April trading confirms that SEE markets are now fundamentally flow-driven systems, where pricing reflects the interaction between interconnection capacity, renewable variability and real-time balancing needs.

The structural implication is clear: control over flexibility and cross-border capacity has become the primary source of trading value in the region.

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Solar generation exceeded 5,174 MW, dominating midday supply and suppressing prices across multiple markets.  Electricity.Trade solar curves show sharp production peaks within a 4–5 hour window, followed by rapid decline.

Hydropower, at 6,252 MW, provided partial balancing support, but Electricity.Trade dispatch data indicates that hydro units increasingly shifted to peak-hour optimisation, reducing their availability for midday smoothing.

Wind generation remained limited at around 1,910 MW, offering insufficient counterbalance to solar variability.   Electricity.Trade wind tracking confirms low correlation with peak demand periods, reinforcing system imbalance.

This resulted in a structurally unstable generation profile:

• Midday surplus: up to +2–3 GW system oversupply
• Evening deficit: rapid drop requiring multi-GW ramp-up

Electricity.Trade system balance models show that flexibility gaps during ramp hours remain above 2 GW, forcing increased reliance on imports and thermal generation.

The imbalance also increased curtailment risk. Without sufficient storage or demand response, excess solar generation could not be fully absorbed, leading to negative pricing events and lost generation value.

April confirms that renewable expansion without parallel flexibility investment amplifies volatility rather than stabilising markets.

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Hungary exhibited the most pronounced volatility, with prices falling to -€500/MWh during solar peaks and rising above €275/MWh in evening hours.   Electricity.Trade hourly tracking shows price reversals exceeding €200–300/MWh within the same day, reflecting rapid system transitions.

Across Slovenia, Romania and Bulgaria, similar patterns emerged. Electricity.Trade negative pricing alerts indicate that midday oversupply events are becoming structurally embedded, particularly in high-solar penetration zones.

These events are driven by a combination of:

• Solar output exceeding 5 GW regionally
• Limited storage capacity (still below 100 MW aggregated utility-scale BESS in key markets)
• Inflexible thermal generation remaining online

As solar production declines after hour 16–17, Electricity.Trade balancing signals show sharp increases in import demand and thermal dispatch, triggering steep evening price spikes.

Serbia’s price profile diverged from this pattern. Electricity.Trade congestion analytics suggest that restricted import capacity during peak hours amplified price increases, pushing SEEPEX toward €96–100/MWh even as neighbouring markets softened.

The result is a structurally volatile market where intraday positioning dominates trading strategy, and where negative pricing is no longer an anomaly but a recurring feature.

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The first driver was renewable output concentration. Solar generation exceeded 5.1 GW, creating pronounced midday oversupply. Electricity.Trade intraday curves show that solar-driven price compression consistently emerged between hours 10–15, pushing several markets toward zero or negative pricing.

Hydropower contributed over 6.2 GW, acting as a stabilising force, but Electricity.Trade dispatch data indicates that hydro flexibility was increasingly reserved for evening ramp support, limiting its ability to smooth midday volatility.  

The second driver was cross-border flow intensity. Imports from Central Europe surged, with inflows from Austria and Slovakia reaching 1,951 MW (+1,242 MW). Electricity.Trade flow maps show these volumes concentrating through the AT–HU–SEE corridor, reinforcing Hungary’s role as the regional gateway.

The widening HU–DE spread to €32.6/MWh further incentivised imports, but Electricity.Trade congestion indicators confirm that internal SEE bottlenecks prevented full price convergence, particularly toward Serbia and the southern Balkans.  

Demand formed the third structural layer. With load above 28 GW, Electricity.Trade balancing signals show evening ramp requirements exceeding 3–4 GW across the region, tightening markets despite strong daytime generation.

These combined drivers produced a system where price formation is dictated by hourly imbalance rather than marginal fuel cost, marking a structural shift in SEE trading behaviour.

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Day-ahead baseload prices settled into two distinct corridors. Central markets such as Hungary, Croatia and Slovenia traded around €96–103/MWh, while south-eastern hubs including Greece, Bulgaria and Romania remained compressed at €75–85/MWh. Serbia stood out as a volatility node, rising sharply to €96.75/MWh (+14.3 €/MWh) despite broader regional softness.  

According to Electricity.Trade regional balancing dashboards, this divergence reflected localized congestion and uneven access to imports, particularly in the Serbia–Croatia corridor where cross-border allocation tightened during peak hours.

Demand remained structurally firm throughout April, with consumption reaching 28,328 MW (+1,058 MW day-on-day), confirming that load is now anchored in industrial and structural demand rather than temperature swings.  

On the supply side, total generation rose to 27,624 MW (+3,014 MW), led by hydro at 6,252 MW (+1,001 MW) and solar at 5,174 MW (+557 MW).   Electricity.Trade generation tracking indicates that midday solar penetration exceeded 20% of regional supply, intensifying intraday imbalances.

Despite strong generation, prices remained supported in constrained zones, confirming that system flexibility—not total supply—is now the binding factor in SEE markets.

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Day-ahead baseload on the Hungarian HUPX edged down to €103.26/MWh (-1.5 €/MWh), while Romania’s OPCOM dropped more sharply to €84.99/MWh (-8.4 €/MWh) and Bulgaria’s IBEX fell to €76.13/MWh (-4.5 €/MWh). Greece followed the same trend at €75.66/MWh (-4.4 €/MWh), pointing to a broadly softer south-eastern pricing zone.  

In contrast, Serbia’s SEEPEX jumped to €96.75/MWh (+14.3 €/MWh), marking the largest increase in the region, while Croatia’s CROPEX rose modestly to €100.32/MWh (+1.9 €/MWh).  

The divergence highlights a widening split between Central European-linked markets trading around €100/MWh and south-eastern hubs clustered closer to €75–85/MWh, with Serbia emerging as a local outlier on tightening fundamentals.

Rising consumption across the SEE region provided upward pressure on prices despite strong generation. Total demand reached 28,328 MW, up 1,058 MW day on day, signalling a firm underlying load profile not directly driven by weather conditions.  

At the same time, generation increased significantly to 27,624 MW (+3,014 MW), led by higher hydro and solar output. Hydropower climbed to 6,252 MW (+1,001 MW), while solar reached 5,174 MW (+557 MW), reinforcing the growing role of renewables in shaping intraday price dynamics.  

However, stronger renewable production failed to fully suppress prices, particularly in tighter markets such as Serbia, where balancing requirements and import constraints appear to have played a more decisive role.

Cross-border flows intensified, with total net imports rising to 173 MW (+526 MW) and core inflows from Austria and Slovakia into the region surging to 1,951 MW (+1,242 MW).  

The widening Hungary–Germany spread to €32.6/MWh (+26 €/MWh) underscored continued price tension between Western and Central European markets, encouraging higher import flows into the SEE region while exposing internal transmission bottlenecks.  

Intraday volatility remained elevated, particularly in Hungary, where prices ranged from deeply negative levels to strong evening peaks. Day-ahead data showed minimum prices falling as low as -€500/MWh, while peak hours exceeded €275/MWh, reflecting oversupply during solar hours followed by tighter evening conditions.  

Similar volatility patterns were observed across Slovenia, Romania and Bulgaria, confirming that the region is increasingly exposed to renewable-driven price swings rather than fuel-cost fundamentals.

On the fuels side, gas and carbon markets provided limited directional support. Austrian CEGH gas prices hovered around €46/MWh (+0.9 €/MWh), while EU carbon allowances eased slightly, suggesting that marginal power pricing is now being driven more by system balance than input costs.  

Market participants pointed to a growing structural shift in SEE power markets, where intermittent generation, cross-border congestion and balancing needs are overtaking traditional thermal price-setting mechanisms.

This trend is further supported by continued investment in flexibility assets across the region. Recent developments include new battery storage capacity in Hungary and a 52 MW storage project acquisition in Romania, reflecting a broader move toward capturing value from volatility rather than baseload generation.  

Outlook for the coming days suggests continued price dispersion, with renewable output and cross-border flows expected to remain the primary drivers, while structurally tighter markets such as Serbia and Croatia may continue to trade at a premium during periods of constrained imports or elevated demand.

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What is emerging is not simply a tighter linkage between EU and non-EU markets, but a layered system in which carbon costs propagate unevenly, creating new arbitrage opportunities while simultaneously increasing the complexity of managing exposure. For utilities, traders, and industrial consumers alike, hedging strategies are being redefined around this new reality.

The ETS remains the foundational pillar of European electricity pricing. By attaching a monetary value to CO₂ emissions, it directly influences the marginal cost of thermal generation, particularly gas and coal. In markets such as Hungary, Romania, and Bulgaria, wholesale electricity prices are effectively anchored to CO₂-inclusive production costs, meaning that even during periods of abundant renewable generation, the forward curve reflects expectations around emissions pricing.

In contrast, non-EU systems such as Serbia, Bosnia and Herzegovina, and Montenegro operate outside the ETS framework. Their generation mix—dominated by lignite and hydro—does not carry direct carbon costs. This creates an apparent structural advantage, with lower marginal production costs and, under normal circumstances, more competitive pricing.

Yet this advantage has become increasingly conditional. Whenever electricity flows from these systems into the EU, CBAM acts as a transmission mechanism for carbon pricing, imposing a border-adjusted cost that mirrors ETS exposure. In effect, CBAM extends the economic reach of ETS beyond EU borders, even if it does not formally integrate non-EU markets into the system.

The consequences of this interaction became particularly visible in early 2026. During the first quarter, exceptionally strong hydrology across SEE produced a surplus of low-cost electricity, pushing non-EU systems into export mode. Under normal conditions, this would have translated into strong cross-border flows toward EU markets.

Instead, CBAM introduced a significant friction. Exporting into the EU required absorbing a carbon-equivalent cost, eroding margins and creating a persistent price discount between SEE markets and EU benchmarks. In some instances, this discount reached 40–60 €/MWh relative to Hungarian prices, reflecting the combined effect of CBAM costs and limited export competitiveness.

This divergence revealed a key asymmetry. While EU markets incorporate ETS costs continuously, non-EU markets only face those costs conditionally. When exports are constrained, prices in SEE can decouple sharply from EU levels, exposing producers to sudden revenue compression.

Market participants responded quickly. Rather than absorbing CBAM costs, traders reconfigured flows, redirecting electricity toward Ukraine and Moldova, markets not subject to the mechanism. These flows often transited EU infrastructure but avoided carbon adjustments by maintaining non-EU destinations.

This adaptation highlighted a critical feature of the new system: hedging is no longer purely financial but increasingly physical. The ability to reroute electricity becomes a form of risk management, allowing participants to mitigate exposure to regulatory costs without relying solely on derivatives.

Despite its visibility, CBAM operates on top of a deeper and more persistent force—ETS pricing itself. For EU-based traders and utilities, managing carbon exposure remains central. The standard approach involves aligning forward power sales with EUA (European Union Allowance) purchases, ensuring that the cost of emissions is locked in alongside expected generation revenues.

In the SEE context, this logic extends beyond EU borders. Even non-EU participants must track EUA prices closely, as their export competitiveness depends on how their generation costs compare to ETS-adjusted EU prices. CBAM effectively converts EUA prices into a reference cost for cross-border trading, meaning that carbon markets now influence decisions across the entire region, regardless of formal participation.

The complexity arises from the conditional nature of CBAM. Unlike ETS, which applies continuously, CBAM is triggered only by specific trade flows. There is no liquid forward market for CBAM itself, forcing participants to construct synthetic hedges.

The most widely used approach involves cross-border spread trading, particularly between hubs such as HUPX (Hungary), SEEPEX (Serbia), and OPCOM (Romania). By positioning against these spreads, traders can capture the combined effects of carbon pricing, transmission constraints, and regulatory adjustments.

A widening spread between Hungarian and Serbian markets, for example, may reflect CBAM pressure, reduced export capacity, or rising ETS costs embedded in EU pricing. Hedging that spread becomes a proxy for managing all three factors simultaneously.

Transmission constraints add another layer of complexity. As highlighted by market behavior in 2026, electricity prices in the region are increasingly shaped by flow-based market coupling and grid limitations, rather than pure supply-demand fundamentals. A reduction in available transmission capacity can have a larger impact on prices than an equivalent change in generation availability.

This shifts the focus of hedging from commodities alone to the physical infrastructure of the system. Monitoring grid parameters such as Remaining Available Margin (RAM), cross-border capacities, and operator interventions becomes essential. In effect, traders are no longer just managing price risk—they are managing network risk.

For industrial consumers, particularly those integrated into EU value chains, the implications are equally significant. Electricity procurement strategies must now account for both direct and indirect carbon exposure. Even when sourcing power from non-EU markets at lower nominal prices, CBAM can reintroduce carbon costs through the value chain, affecting export competitiveness.

This has led to the emergence of shadow ETS hedging strategies, where companies align their energy procurement with financial positions linked to EU price benchmarks. The goal is not only to secure competitive electricity but to stabilize the embedded carbon cost of production.

Looking ahead, the distinction between ETS and non-ETS markets in SEE is likely to narrow further. As CBAM implementation becomes more robust and market coupling deepens, carbon pricing will be transmitted more consistently across borders. At the same time, the rapid expansion of renewable generation and battery storage is reshaping the temporal structure of price formation, concentrating volatility into fewer, more critical hours.

In this environment, ETS remains the baseline price anchor, while CBAM acts as a selective adjustment mechanism, and transmission constraints define the pathways through which value flows.

What is taking shape is a market where electricity trading is no longer defined by a single variable. Instead, it is governed by a multi-dimensional risk framework, where carbon pricing, regulatory mechanisms, and grid physics interact continuously.

Hedging strategies must evolve accordingly. Managing exposure now requires an integrated approach that combines CO₂ markets, power spreads, and physical flow optimization. Those able to navigate this complexity are not merely protecting margins—they are actively capturing the structural inefficiencies that define the new SEE electricity landscape.

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At its core, the EU ETS places a price on carbon emissions, forcing generators to internalize the cost of CO₂. For thermal power plants—particularly coal and gas—this translates directly into higher marginal production costs, which are then reflected in wholesale electricity prices.

In practical terms, the ETS establishes a floor for power prices in EU markets, especially in systems where fossil generation still plays a balancing role. Even when renewable output is high, the marginal unit during tight hours is often gas or coal, meaning CO₂ cost becomes embedded in forward curves and spot pricing.

The SEE region occupies a hybrid position in this framework. EU member states such as Hungary, Romania, Bulgaria, and Croatia are fully exposed to ETS pricing, while non-EU systems such as Serbia, Bosnia and Herzegovina, and Montenegro operate outside the ETS framework. This creates a structural divergence.

EU markets reflect:

• Full CO₂ cost pass-through
• Higher marginal cost of generation
• Elevated forward price expectations

Non-EU SEE markets, by contrast:

• Do not directly price CO₂
• Maintain lower marginal generation costs, particularly for lignite
• Appear structurally “cheaper” in pure generation terms

However, this apparent advantage is increasingly constrained—not by ETS directly, but by its interaction with cross-border mechanisms such as CBAM and market coupling.

The relationship between ETS and CBAM becomes critical in electricity markets. CBAM effectively attempts to mirror ETS costs at the border, translating carbon exposure into a trade adjustment. But unlike ETS, which operates continuously and predictably within EU markets, CBAM acts as a conditional overlay, activated only when exports occur.

This creates a layered pricing system:

• ETS defines internal EU price formation
• CBAM selectively transfers that cost to non-EU exporters

The consequence is that non-EU SEE markets are indirectly “pulled” toward ETS pricing levels during export periods, even though they are not formally part of the system.

In early 2026, this interaction became visible in a distorted way. During Q1, high hydrology in SEE combined with incomplete CBAM implementation created a temporary disconnect. Non-EU prices fell well below EU levels despite the ETS-driven cost base in neighboring markets.

But as market mechanisms normalized, the gravitational pull of ETS pricing reasserted itself. Even discounted SEE electricity—when exported—had to compete with EU power priced on CO₂-inclusive marginal cost, narrowing arbitrage opportunities.

From a generation perspective, ETS pricing plays a decisive role in fuel hierarchy. In EU markets, high CO₂ prices penalize lignite heavily, making gas or renewables more competitive. In non-EU SEE markets, lignite remains viable precisely because it avoids ETS costs.

Yet this advantage is increasingly fragile. Whenever electricity flows toward the EU, ETS pricing becomes unavoidable—either directly through market coupling or indirectly through CBAM adjustments. This creates a paradox:

• Lignite remains cheap domestically in non-EU SEE
• But loses competitiveness in cross-border trade

The result is a system where domestic dispatch and export economics diverge, complicating generation strategies for utilities such as EPS or Elektroprivreda BiH.

Another critical dimension is the influence of ETS on forward markets. Power futures in Hungary (HUPX) and across Central Europe are heavily anchored to CO₂ expectations, not just fuel prices. Traders price forward electricity based on anticipated:

• EUA (emissions allowance) prices
• Gas and coal spreads
• Regulatory tightening

This means that even when short-term spot prices are driven by grid constraints or hydrology, the forward curve reflects carbon pricing fundamentals.

The presentation highlights that absolute price levels are largely outside short-term forecasting control because they are driven by:

• CO₂ prices
• Regulatory shifts

Instead, traders focus on spreads (e.g. Hungary–Germany), but those spreads sit on top of an ETS-defined baseline.

The interaction between ETS and gas prices further amplifies its importance. When gas prices rise, the marginal cost of generation increases, but so does the CO₂ burden, since gas-fired plants still emit. This dual cost structure reinforces the role of ETS as a price multiplier, not just a standalone component.

In 2026, rising gas prices helped offset CBAM-induced distortions by lifting overall market prices, allowing even discounted SEE generation to remain economically viable. But the underlying driver remained ETS-linked cost structures in EU markets.

Looking forward, ETS is likely to become even more influential in SEE pricing dynamics, particularly as the region moves toward deeper integration with the European electricity market. Several trajectories are already visible.

First, the gradual alignment of non-EU countries with EU regulatory frameworks—whether through accession processes or market coupling—will increase indirect exposure to CO₂ pricing. Even without formal ETS participation, price convergence mechanisms will transmit carbon costs across borders.

Second, the expansion of renewable energy and battery storage will not eliminate ETS influence but reshape it. As solar and wind dominate daytime generation, the marginal unit—and therefore the CO₂ price signal—shifts into fewer, more volatile hours. This increases the price-setting intensity of ETS during scarcity periods, particularly in evening peaks.

Third, as CBAM becomes fully operational, the distinction between ETS and non-ETS markets will narrow further. CBAM effectively extends ETS logic beyond EU borders, meaning that over time, non-EU generators will face carbon-adjusted pricing indirectly in all export scenarios.

What becomes clear is that ETS is not just a regulatory instrument but the central economic anchor of European electricity markets. It determines the marginal cost of generation, shapes forward curves, and increasingly influences cross-border trade dynamics.

In contrast to CBAM—which acts as a visible but intermittent constraint—ETS operates continuously, embedding carbon cost into every megawatt-hour traded within the EU system. For SEE markets, the challenge is no longer whether they are exposed to ETS, but how deeply and through which channels that exposure materializes.

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What emerges from early 2026 market behavior is a system where CBAM’s influence is episodic, highly conditional, and rapidly arbitraged, rather than structurally transformative.

At its core, CBAM imposes a carbon-adjusted cost on electricity exports from non-EU countries into the European Union, directly affecting markets such as Serbia, Bosnia and Herzegovina, Montenegro, North Macedonia, and Albania. The cost is not determined by the physical origin of the electricity but by the entry point into the EU, meaning that the border through which power flows defines the carbon exposure.

This seemingly technical rule has profound implications. It effectively introduces a pricing wedge between EU and non-EU electricity markets, breaking the traditional arbitrage logic that had long governed cross-border flows in the region.

The most visible impact of CBAM unfolded during the first quarter of 2026, when an unusual convergence of factors amplified its effects. Exceptionally strong hydrological conditions across SEE, combined with unseasonably warm weather, led to a surge in low-cost hydro generation and subdued demand. At the same time, CBAM administrative systems—particularly those required to verify the carbon content and origin of electricity—were not fully operational.

The result was a sharp divergence in market outcomes. Non-EU SEE markets experienced significant price suppression, while EU markets registered marginally higher prices than would otherwise have been expected.

This divergence was not merely theoretical. It translated into persistent price discounts in markets such as Serbia and Bosnia, where electricity traded at levels materially below Hungarian or Romanian benchmarks, even when physical interconnection capacity remained available.

Crucially, the burden of CBAM has proven highly asymmetric. Non-EU systems, which rely on exports during periods of surplus, faced a direct loss of competitiveness. EU markets, by contrast, remained largely insulated due to their structural position as net importers or internally balanced systems. The result has been a downward pressure on non-EU prices without a commensurate tightening of EU supply, reinforcing the role of SEE as a price-taking periphery.

Yet this imbalance did not persist unchallenged. Market participants responded swiftly, identifying pathways to bypass CBAM exposure altogether. Electricity flows were increasingly redirected toward Ukraine and Moldova, markets that lie outside the CBAM regime. These transactions often transited through EU infrastructure—particularly Hungary and Romania—without triggering carbon costs, as long as the final destination remained outside the EU.

This rerouting had a dual effect. It allowed SEE exporters to recover part of their lost margin while simultaneously reducing demand on EU power exchanges, as Ukraine and Moldova sourced more electricity directly from SEE rather than from HUPX or OPCOM.

The intensity of CBAM’s impact has proven closely tied to hydrological conditions. During periods of high water inflows, SEE systems—traditionally hydro-heavy—shift into export mode, making them directly exposed to CBAM constraints. Under these conditions, prices in non-EU markets can collapse as surplus generation struggles to find competitive outlets.

When hydrology returns to normal or below-average levels, the situation reverses. SEE countries become net importers, drawing electricity from EU markets rather than exporting into them. In such scenarios, CBAM becomes effectively irrelevant, as there are no export flows subject to carbon adjustment.

This dynamic underscores a key structural limitation: CBAM only binds when SEE systems are long on energy. It does not influence the majority of operating hours, during which the region remains import-dependent.

One of the more immediate operational consequences of CBAM has been its impact on thermal generation, particularly lignite-fired plants. During the price depression of early 2026, operators across Serbia, Bosnia, and Montenegro faced a situation in which market prices fell below the marginal cost of lignite generation.

This triggered a temporary reduction in coal output, estimated at up to 500 MW during peak hydrological conditions.

However, this should not be mistaken for structural decarbonization. The reduction was driven purely by short-term economics. Lignite reserves were not depleted but rather conserved, with the expectation that they would be redeployed once market conditions improved. As hydrology normalized in March, coal generation recovered quickly, with output only 200–300 MW below historical averages, indicating that the CBAM effect on fuel switching is transient.

The interaction between CBAM and broader commodity markets further limits its long-term influence. Rising natural gas prices, observed from March 2026 onward, lifted wholesale electricity prices across the region. This increase restored the profitability of lignite plants even under discounted SEE pricing, effectively neutralizing CBAM’s suppressive effect on thermal generation.

In parallel, CBAM has begun to reshape trading behavior within SEE itself. As exports to the EU became less attractive, market participants increasingly turned inward, expanding cross-border trade among non-EU countries. This has the early characteristics of a regionalized SEE power market, partially decoupled from EU pricing dynamics during certain periods.

Despite its visible short-term impact, CBAM’s structural footprint remains limited. Historical data show that SEE countries are net exporters only in a minority of hours. In 2025, for example, exports exceeding 500 MW occurred in roughly 12% of total hours, underscoring the episodic nature of surplus conditions.

This means that CBAM affects marginal pricing periods rather than baseline system operation. Its role is to distort peak surplus conditions rather than redefine the overall market equilibrium.

Looking ahead through 2026 and into 2027, the influence of CBAM is expected to diminish further. As administrative frameworks mature and traders fully integrate CBAM costs into their strategies, the initial inefficiencies observed in early 2026 are likely to fade. At the same time, seasonal normalization of hydrology and sustained export channels toward Ukraine and Moldova will reduce the frequency of CBAM-constrained scenarios.

Under these conditions, CBAM becomes a situational constraint rather than a dominant pricing driver, shaping specific hours and flows but not the broader market trajectory.

The emerging picture is one of a mechanism that is economically significant but structurally bounded. CBAM introduces friction into cross-border electricity trade, redistributes value between EU and non-EU markets, and temporarily alters dispatch decisions. Yet it does not fundamentally change the region’s dependence on imports, nor does it enforce sustained decarbonization.

Instead, it reveals the adaptability of SEE electricity markets. Faced with new constraints, traders and utilities have demonstrated a capacity to reconfigure flows, preserve margins, and maintain system balance—often in ways that dilute the intended policy signal.

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In practice, CBAM has created a dual-market structure within SEE, sharply differentiating EU-integrated markets such as Hungary and Romania from non-EU systems including Serbia, Bosnia and Herzegovina, and Montenegro. Electricity exported from these non-EU countries into the EU is now subject to an implicit carbon cost, effectively acting as an export fee tied to the generation mix of the exporting system.

This has had an immediate impact on price formation at the start of 2026. During the first quarter, non-EU SEE markets experienced significant price suppression, while EU markets cleared at a relative premium. The divergence was particularly visible in January and February, when non-EU prices fell below levels justified by underlying supply-demand conditions, largely because export routes into the EU became economically constrained.

The effect was amplified by two temporary factors. First, administrative procedures required to certify the origin of electricity flows under CBAM were not fully operational at the beginning of the year. This created inefficiencies and uncertainty, further discouraging exports from non-EU markets into the EU. Second, exceptionally strong hydrological conditions across the Western Balkans generated surplus electricity precisely at a moment when export pathways were restricted, deepening the oversupply and reinforcing downward price pressure.

Yet CBAM’s influence on absolute price levels remained asymmetric. While EU markets did register higher prices relative to a no-CBAM scenario, the increase was modest. This reflects a structural reality: non-EU SEE countries are rarely sustained exporters of electricity, with export surpluses typically limited to periods of high hydro generation. As a result, the volume of electricity exposed to CBAM remains relatively small on an annual basis, constraining its ability to drive prices across the broader European market.

Where CBAM has proven far more consequential is in its impact on trading behaviour and physical flows. Faced with reduced profitability of exports into the EU, market participants rapidly adapted by redirecting electricity toward alternative destinations not subject to the mechanism. In early 2026, a significant portion of surplus power from the Western Balkans was rerouted toward Ukraine and Moldova, often transiting through Hungary and Romania.

This redirection effectively established a new eastward corridor for SEE electricity, partially neutralising CBAM’s intended effect. Instead of constraining exports outright, the mechanism reshaped the geography of trade, shifting volumes away from EU markets while maintaining overall system balance. At the same time, it reduced the reliance of Ukraine and Moldova on EU hubs such as HUPX and OPCOM, indirectly easing pressure on those markets.

Within non-EU systems themselves, CBAM triggered a notable change in generation behaviour. With domestic prices suppressed during the first quarter, operators of lignite-fired plants—particularly in Serbia and Bosnia—chose to reduce output rather than dispatch generation into a low-price environment. This resulted in a temporary decline in fossil generation, with estimates suggesting reductions of several hundred megawatts relative to previous years during peak hydrological conditions.

However, this should not be interpreted as structural decarbonisation. The analysis indicates that lignite output was effectively deferred rather than displaced. As hydrological conditions normalised and prices recovered, stored fuel would be redeployed in later periods, limiting any long-term emissions impact. CBAM, in this sense, has not yet driven a sustained shift in the generation mix across SEE’s non-EU markets.

The temporal dimension of CBAM’s impact is equally important. Its strongest effects were concentrated in Q1 2026, when high hydro output coincided with administrative inefficiencies and constrained export channels. As conditions evolved into March and beyond, the influence of CBAM began to diminish. With hydrology returning to average levels and fossil generation resuming, the price gap between EU and non-EU markets narrowed.

Looking forward, the mechanism is expected to have minimal impact during the summer months, when non-EU SEE countries are typically net importers. In these periods, electricity flows predominantly from EU markets into the Western Balkans, meaning CBAM is not triggered. Even in export periods, improved administrative processes and established trading routes are likely to reduce the magnitude of early-year distortions.

An additional moderating factor has been the broader energy price environment. The rise in natural gas prices from March 2026 increased wholesale electricity prices across Europe, restoring profitability for lignite-fired generation in non-EU markets despite CBAM-related discounts. This reduced the incentive to curtail output and further weakened CBAM’s impact on generation decisions.

Taken together, these dynamics suggest that CBAM’s role in SEE electricity markets is best understood as a short-term distortion mechanism layered onto a fundamentally unchanged structural system. It introduces friction at the EU–non-EU interface, alters the direction of flows, and temporarily suppresses prices in exporting systems, but it does not fundamentally alter the region’s position within the European power balance.

For market participants, the key implication is that CBAM should not be treated as a primary driver of long-term price levels. Its influence is episodic, peaking in periods of surplus generation and declining when the region reverts to its typical import-dependent position. Instead, its importance lies in its interaction with hydrology, trading behaviour and cross-border infrastructure, where it can amplify existing imbalances or accelerate shifts in flow patterns.

The experience of early 2026 highlights both the power and the limitations of the mechanism. CBAM has demonstrated an ability to reshape market behaviour almost immediately, redirecting flows and altering dispatch decisions across multiple countries. At the same time, it has underscored the resilience of underlying structural factors—hydrology, generation mix and regional demand—which ultimately determine whether these distortions persist or fade.

As implementation matures and administrative systems stabilise, CBAM is likely to become a more predictable element of the market landscape. Yet its core characteristic will remain unchanged: it is not a blunt instrument for raising prices, but a targeted intervention that reshapes incentives at the margins, with effects that are highly contingent on broader system conditions.

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The shift is subtle in regulatory language but profound in financial consequences. Transmission system operators are tightening grid access rules, formalising balancing responsibilities and introducing market mechanisms for ancillary services. Together, these changes are dismantling the legacy model under which renewable projects were assessed primarily on resource quality and capital cost. In its place, a new framework is taking shape, one in which grid positioning, system flexibility and operational responsiveness determine returns as much as installed capacity.

Nowhere is this transformation more visible than in Montenegro, where the draft transmission rules issued by Crnogorski elektroprenosni sistem provide a clear blueprint for the region’s direction of travel. The framework aligns the country with the operational standards of ENTSO-E, but more importantly it embeds the economic consequences of system constraints directly into project design. Renewable generators are required to provide voltage support, frequency response and real-time dispatchability, while assuming full balancing responsibility and accepting curtailment under defined system conditions.

This combination of obligations effectively transforms renewable energy from a passive generation business into an active system service. The implications for investors are immediate. Grid access is no longer a procedural step but a scarce asset, determined by detailed system studies and highly sensitive to location. In Montenegro’s relatively small and interconnected system, this scarcity is amplified by reliance on cross-border export capacity. Wind-rich northern regions and coastal solar corridors face structurally weaker nodes, while interconnection limits constrain the ability to export surplus generation. A project’s financial profile therefore depends less on irradiation or wind speeds than on the strength and timing of its connection to the transmission network.

The consequences are measurable. Delays in grid readiness of 12 to 18 months are becoming increasingly common, with direct implications for capital deployment and returns. Under typical project finance structures, such delays can compress equity internal rates of return by 2 to 4 percentage points, particularly where revenue assumptions are already under pressure from market volatility. At the same time, technical compliance requirements introduce an additional capital burden. Renewable plants must incorporate advanced inverter systems, reactive power compensation equipment and full integration with transmission operator control systems, adding between €50,000 and €150,000 per MW depending on technology. For a utility-scale project, this represents several million euros of incremental investment that cannot be ignored in financial modelling.

Curtailment risk further complicates the picture. While priority dispatch for renewables remains a formal principle, transmission operators across the region are increasingly empowered to reduce output in the interest of system stability. In Montenegro, where system balancing depends heavily on export capacity, this translates into a structurally embedded risk of production loss during periods of high generation and low demand. Base-case assumptions of 3 to 8 per cent curtailment are becoming standard, with stress scenarios reaching 10 to 20 per cent in constrained conditions. The effect is not simply a reduction in output but a redefinition of revenue stability, forcing lenders to adopt more conservative debt sizing and increasing the cost of capital.

Serbia, by contrast, benefits from a larger and more robust transmission system operated by Elektromreža Srbije, with a well-developed 400 kV backbone and expanding cross-border interconnections. This provides a degree of resilience that Montenegro lacks, allowing renewable projects to operate with lower immediate exposure to congestion. However, the direction of travel is similar. As renewable penetration increases, localised bottlenecks are emerging, particularly in wind-rich regions of eastern Serbia. Balancing responsibilities are being progressively tightened, and grid code enforcement is becoming more stringent. Curtailment remains moderate for now, typically in the range of 2 to 5 per cent, but the underlying trend is upward.

The Serbian market therefore offers a window of relative stability, but not immunity from structural change. Developers are increasingly aware that today’s conditions will not persist. As balancing costs rise and grid constraints intensify, the economics of standalone renewable projects are likely to converge with those already visible in Montenegro. Internal rates of return that currently sit in the 8 to 11 per cent range are expected to compress as additional costs are internalised and revenue volatility increases.

Bosnia and Herzegovina presents a different challenge. The transmission system, operated by Elektroprenos Bosne i Hercegovine, is structurally fragmented, reflecting the country’s complex institutional framework. Regulatory alignment with European standards is less advanced, and balancing mechanisms remain underdeveloped. On the surface, this creates a more permissive environment for renewable development, with lower immediate exposure to curtailment and balancing costs. However, this apparent advantage masks deeper structural risks.

Transmission corridors linking Bosnia with neighbouring systems are being expanded, but coordination between entities remains limited, and localised congestion is already emerging, particularly at distribution level where solar penetration is increasing rapidly. The absence of fully developed balancing markets effectively hides the true cost of system integration, but does not eliminate it. As regulatory convergence accelerates, these costs are likely to be internalised abruptly, creating a delayed but potentially sharper adjustment for project economics. Current return expectations of 8 to 12 per centtherefore carry a higher degree of uncertainty than in more mature markets.

North Macedonia occupies an intermediate position. The system operator MEPSO has implemented a relatively advanced regulatory framework, including detailed grid codes and formal balancing requirements. At the same time, the physical network remains constrained, with significant saturation at medium-voltage levels and sensitivity to voltage fluctuations at higher voltages. A major system disturbance in recent years, linked to overvoltage conditions, underscored the fragility of the network under stress.

For renewable developers, this creates a paradox. Regulatory clarity provides a degree of predictability, but physical constraints limit expansion and increase the likelihood of curtailment. Storage is already emerging as a technical necessity in certain regions, even in the absence of fully developed market incentives. Expected returns in the 7 to 10 per centrange are therefore subject to increasing volatility, particularly as renewable capacity continues to grow.

Across all four markets, a common pattern is emerging. Balancing responsibility, once a marginal consideration, is becoming a central cost driver. Renewable producers are required to forecast output, submit schedules and absorb the financial consequences of deviations. For solar projects, imbalance costs typically fall between €3 and €8 per MWh, while wind projects face higher exposure, often in the range of €5 to €12 per MWh. These costs are rising as systems become more saturated and less able to absorb variability without active intervention.

It is within this context that battery storage is moving from the margins to the centre of investment strategy. Across South-East Europe, storage is increasingly viewed not as an optional optimisation tool but as critical infrastructure for system stability. Its role is multifaceted. By absorbing excess generation, storage reduces curtailment losses. By smoothing output, it lowers imbalance costs. By providing fast-response services, it enables participation in ancillary service markets. Together, these functions create a new revenue stack that extends beyond energy sales.

The economics of storage remain challenging. Capital costs in the range of €300,000 to €600,000 per MWh represent a significant addition to project budgets. Yet when integrated into hybrid configurations, storage can materially improve risk-adjusted returns. A combined solar and battery system can stabilise cash flows, enhance dispatchability and access higher-value services, partially offsetting the impact of curtailment and balancing costs. In markets such as Montenegro, this is already becoming the default model for new developments. In Serbia, it is emerging as a strategic differentiator. In Bosnia and North Macedonia, it represents an inevitable next step as constraints intensify.

The broader implication is that renewable energy investment in South-East Europe is entering a new phase. The first wave of projects was defined by resource capture and capacity expansion. The next wave will be defined by system integration and operational flexibility. Transmission networks, once treated as passive infrastructure, are becoming active determinants of value. Ancillary service markets, once peripheral, are evolving into essential revenue streams. Storage, once optional, is becoming indispensable.

For investors and developers, this requires a fundamental reassessment of strategy. Project evaluation can no longer rely on simplified assumptions of load factors and power prices. It must incorporate grid availability, curtailment probability, balancing costs and the potential for multi-layer revenue generation. It must also account for regulatory convergence, as markets across the region align more closely with European standards and internalise costs that were previously externalised.

Those who adapt to this new reality—by securing strong grid positions, integrating storage and designing assets capable of operating across multiple market layers—will find opportunities in a system that increasingly rewards flexibility. Those who do not risk seeing returns eroded by constraints that are no longer temporary but structural.

South-East Europe’s renewable energy story is therefore no longer about how much capacity can be built. It is about how effectively that capacity can be integrated into a system under strain. In that transition, grid constraints and storage economics are not secondary considerations. They are the central forces reshaping the market.

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Once completed, the project could follow different strategic directions, including direct operation by Electro-Alfa or a potential sale to investors active in the energy sector. This flexibility reflects the growing value of storage assets in Romania’s evolving power market.

The move comes shortly after Electro-Alfa’s debut on the Bucharest Stock Exchange, where the company raised significant capital through an initial public offering earlier this year. The listing marked a new phase of expansion for the group, which has long-standing experience in electrical equipment manufacturing, engineering services, and energy efficiency solutions.

Operating as part of a broader industrial group, Electro-Alfa runs multiple production facilities and maintains in-house research and development capabilities, serving hundreds of domestic and international clients. The latest acquisition signals a clear strategic shift toward strengthening its position in the rapidly growing energy storage market.

At the same time, Romanian authorities are preparing stricter regulations to address bottlenecks in renewable energy development. The country’s energy regulator, ANRE, is preparing a public consultation on new rules designed to reduce speculative projects that occupy valuable grid capacity without real implementation plans.

The proposed framework would require developers to provide financial guarantees before accessing the electricity network. This includes an initial requirement of €20 per installed kW during allocation procedures, followed by additional commitments equal to 20% of connection costs after technical approval. The aim is to ensure that only serious investors proceed with grid access.

According to ANRE head George Niculescu, the measures are intended to eliminate inactive or speculative projects that slow down the energy transition. Authorities have identified cases where connection rights were being traded online, highlighting inefficiencies in the current system.

The initiative has political backing, with Prime Minister Ilie Bolojan confirming that a list of stalled projects has already been compiled. Some developers are believed to be holding permits without progressing construction, instead waiting for resale opportunities.

By tightening regulations and increasing scrutiny of inactive projects, the government aims to free up grid capacity, accelerate renewable energy deployment, and improve investor confidence. The reforms are seen as an important step toward stabilizing energy prices and aligning Romania’s energy sector with European climate goals.

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The contract, valued at up to approximately €12 million (excluding VAT), focuses on the delivery of prefabricated concrete transformer stations equipped with 24 kV medium-voltage systems. These “MINIBOX” units are fully integrated installations designed to speed up deployment, reduce on-site construction time, and improve operational safety once connected to the grid.

After installation, the substations will be integrated into the network’s remote monitoring and control system, supporting more efficient grid management. The initiative is part of a broader modernization strategy aimed at increasing network capacity, improving reliability, and enabling smoother integration of new energy sources, including decentralized generation.

The standardized and compact design of the units is also expected to optimize space usage at distribution points while strengthening resilience against climate-related disruptions. The procurement process is open for bids until 25 May, and the selected contractor will be responsible for deliveries over a four-year implementation period.

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Gross electricity production totaled 583,152 MWh, marking a 6.7% decrease compared to the same month last year. Thermal power plants generated 166,976 MWh (28.6%), but output dropped sharply by 43.7% year-on-year. In contrast, hydropower plants produced 178,448 MWh (30.6%), recording a strong 102.4% increase, reflecting improved water availability and hydro performance.

Combined heat and power (CHP) plants contributed 125,612 MWh (21.5%), down 13.9%, while wind farms generated 29,893 MWh (5.13%). Biogas plants produced 2,630 MWh, and solar power— including prosumers—accounted for 79,594 MWh, or 13.6% of total production, highlighting the growing role of distributed renewable generation.

Electricity imports decreased to 154,600 MWh from 206,024 MWh a year earlier, while exports fell significantly to 37,037 MWh compared to 84,092 MWh in February 2025. The overall data indicates a shift in production structure toward hydropower and solar, alongside reduced reliance on thermal generation and lower cross-border electricity trade activity.

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The project forms part of a wider investment cycle supported by Hungary’s Recovery and Resilience Plan, under which several Alteo subsidiaries secured funding for battery storage developments. One of them, Alteo-Therm, implemented the Győr facility with a total investment of approximately €7.4 million, including €2.4 million in non-repayable grants.

The storage system has been constructed next to a site housing multiple gas engines, allowing it to leverage existing operational infrastructure and optimize performance. In addition to supporting electricity supply and grid stability, the subsidiary also provides district heating services in several cities, contributing to a more resilient and diversified energy system.

With this latest addition, Alteo’s total aggregated storage capacity—managed through its centralized control system—has reached 90 MW. This expansion follows a series of recent developments, including a 50 MW system commissioned earlier this year in Győr and a 10 MW installation launched shortly afterward in Bana. Through continued investment in storage technologies, the company is positioning itself to enhance network reliability while supporting the integration of an increasing share of renewable energy.

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The GREGY project is seen as a strategic step toward improving energy security while accelerating the transition to low-carbon electricity. It is designed to deliver renewable energy generated in Egypt to European markets via Greece, offering a long-term alternative to fossil fuel imports. Its importance has grown amid ongoing geopolitical instability in the Middle East, which has once again exposed Europe’s vulnerability to supply disruptions.

The initiative is being developed by Elica, part of the Copelouzos Group, which is currently in discussions with multiple potential partners. The project focuses on building long-term collaborations with transmission operators and major industrial consumers, rather than relying solely on financial investors. Support has already been formalized through cooperation with ADMIE, while institutions such as the U.S. International Development Finance Corporation and the European Bank for Reconstruction and Development have also expressed interest.

Preparations are progressing across both technical and commercial fronts. Agreements have been signed with numerous companies in Greece and the Balkans to secure future electricity offtake, and demand is beginning to emerge in neighboring markets, including Bulgaria, with expectations that Serbia could follow.

Financing discussions are also advancing, with lenders indicating readiness to provide up to €10 billion in funding. If completed on schedule, the project could become operational around 2030–2031, delivering electricity at prices estimated to be up to €20/MWh lower than current wholesale levels, potentially reshaping regional energy markets.

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Net electricity production stood at 654 GWh, with 358 GWh generated by hydropower plants, 242 GWh by thermal power plants, and 54 GWh by wind farms. At the same time, electricity imports dropped sharply to 50 GWh from 172 GWh a year earlier, while exports increased to 125 GWh compared to 88 GWh in March 2025, indicating a stronger export position and reduced reliance on imports.

Coal production trends showed a continued decline. Brown coal output fell to 222,825 tons, representing a 23.7% decrease compared to March 2024, when production reached 292,008 tons. Lignite production also declined by 11.1%, totaling 104,201 tons compared to 117,201 tons a year earlier. Meanwhile, coke production in March 2026 was recorded at zero, following the permanent closure of the Lukavac coke plant, marking a significant structural shift in the region’s industrial and energy landscape.

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