Developments in the Middle East conflict continued to influence Brent futures during the first week of April. Supply disruption concerns through the Red Sea pushed prices higher at the end of March. However, expectations of a possible end to the conflict led to a sharp decline on April 1. Later, renewed concerns over potential US military actions in the region supported a price recovery by the end of the week.

TTF gas futures on the ICE market for the Front Month reached their weekly maximum settlement price of €54.81/MWh on Monday, March 30. Prices then declined until April 1, when they hit a weekly low of €47.51/MWh, the lowest level since March 11, according to AleaSoft Energy Forecasting. Prices recovered slightly to €50.04/MWh on April 2, although this remained 7.6% lower than the previous Friday.

Supply concerns and low European storage levels continued to support gas prices early in the week. However, geopolitical developments and expectations of higher temperatures and increased renewable generation contributed to downward pressure, pushing prices below €50/MWh on April 1.

CO2 emission allowance futures in the EEX market for the December 2026 contract remained above €70/t throughout the first week of April. These futures reached a weekly high of €74.65/t on April 1, the highest level since February 12, according to AleaSoft Energy Forecasting. After a 4.0% drop, prices fell to their weekly minimum of €71.70/t on April 2, remaining close to the levels seen in the previous week, AleaSoft reports.

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In the week of March 30, weekly averages stayed below €85/MWh in most European electricity markets. The Dutch and Italian markets were exceptions, averaging €88.83/MWh and €136.15/MWh, respectively. Spain and Portugal recorded the lowest weekly averages, at €12.44/MWh and €12.62/MWh, respectively. In the other markets analyzed by AleaSoft Energy Forecasting, prices ranged from €61.97/MWh in the Nordic market to €84.95/MWh in the British market.

Regarding daily prices, Iberian markets stayed below €25/MWh during the first week of April. However, Germany recorded the lowest daily average of the week among the analyzed markets, at €16.34/MWh on Sunday, April 5, marking the lowest price since July 3, 2023 in that market. On April 5, France and Belgium reached their lowest daily prices since May 12, 2025, at €3.56/MWh and €0.05/MWh, respectively. That same Sunday, the British, Nordic and Dutch markets registered their lowest daily averages since October 2025, at €6.84/MWh, €7.61/MWh and €14.46/MWh.

By contrast, daily prices in the Italian market remained above €100/MWh throughout the first week of April and exceeded €150/MWh during the first three days. The German, Belgian, British, French, Dutch and Nordic markets also recorded prices above €100/MWh during at least one session that week. On April 1, the Italian market reached the highest daily average of the week, at €159.99/MWh, while the French market registered €134.70/MWh, its highest level since February 18, 2025.

In the week of March 30, lower gas prices compared to the previous week and reduced demand pushed European electricity prices downward. Higher solar energy production in the Iberian Peninsula and Germany also contributed to this decline.

AleaSoft Energy Forecasting’s price forecasts suggest that during the second week of April, prices could continue falling in markets such as Germany, where wind and solar production are expected to increase. However, gas price trends will continue to strongly influence electricity prices across Europe. Meanwhile, demand recovery, lower wind production in the Iberian Peninsula, and reduced solar production in Spain could push prices higher in the Spanish and Portuguese markets, AleaSoft reports.

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Higher average temperatures supported this trend, rising between 1.6 °C and 2.0 °C and reducing heating needs. The Easter holiday calendar also contributed to lower demand.

For the second week of April, AleaSoft Energy Forecasting’s demand forecasts point to mixed trends across Europe, while average temperatures will continue rising in all analyzed markets. France, Italy and Belgium are expected to register the largest temperature increases. Under these conditions, demand will fall in France, Great Britain, the Netherlands, Belgium and Italy, while Germany, Spain and Portugal could see demand recovery. Overall, in addition to the effect of temperatures, the different distribution of Easter holidays will continue to influence week-on-week demand comparisons, AleaSoft reports.

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AleaSoft Energy Forecasting’s solar energy forecasts for the second week of April point to uneven performance for this technology. Germany and Italy, where production remained relatively moderate the previous week, are expected to see significant increases in photovoltaic energy production. By contrast, the Iberian markets, which registered high values during the first week of the month, could experience downward corrections.

Regarding wind energy production, all analyzed European markets registered declines in the first week of April compared to the previous week. Portugal showed one of the sharpest drops, at 28%, followed by Italy with a decline of 10%. Forecasts from AleaSoft Energy Forecasting for the second week of April indicate further declines in Italy and France, while Portugal is expected to see a significant rebound after the previous week’s sharp drop, AleaSoft reports.

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The planned battery energy storage system (BESS) will have a capacity of 60 MW and 120 MWh and is part of a broader strategy to strengthen grid stability and improve the predictability of renewable generation. The total investment is estimated at around 26.1 million euros, with approximately 2.9 million euros expected to be financed through the EU-backed Modernization Fund.

This is the third storage project announced by PPC Renewables Romania, signaling a faster rollout of battery systems as the company works toward nearly 2 GW of renewable capacity in the Romanian market.

The system will be installed at the Zephyr 1 wind farm located in the Nicolae Bălcescu area in southeastern Romania. The site currently includes 52 wind turbines with a total installed capacity of 120 MW. In the wider area, the Zephyr 1 and Zephyr 2 projects together consist of 78 turbines and a combined capacity of 180 MW, making it one of the company’s key wind energy hubs in the country.

The company states that the project is part of a broader effort to combine renewable generation with storage, aiming to enhance system flexibility, improve resilience, and support the continued integration of clean energy into Romania’s electricity sector.

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Traded volume on the day-ahead market reached 1.36 million MWh in March, marking a slight increase of 0.68% compared to the same period last year, while remaining 8.08% lower than in February. The average traded volume was 1,824.9 MWh per hour, reflecting steady market activity.

The total value of transactions amounted to 148.1 million euros, which is 2.96% higher than in March last year, but 1.43% lower compared to the previous month. The share of the day-ahead market in forecasted net consumption reached 29.89%, indicating a solid level of market participation.

On the intraday market, a total of 158,095.2 MWh was traded in March, which is 22.35% less than in March 2025, but 18.36% higher than in February. The average intraday price stood at 88.02 euros/MWh, reflecting a decline of 7.29% year-on-year and 5.13% compared to the previous month.

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TPP Pljevlja is set to go offline on 15 April for approximately one month, during which a series of technical works and system upgrades will be carried out. The downtime is also intended to support the final phase of the plant’s environmental refurbishment.

EPCG stated that key components installed under the ecological upgrade project, including the boiler and newly implemented systems, have already undergone successful testing in recent months. The upcoming shutdown will now allow for further adjustments and fine-tuning.

Maintenance activities will focus on critical segments of the facility, including mechanical systems, coal and water preparation units, as well as electrical equipment. Additional efforts will be directed toward improving emission control systems and enhancing overall operational reliability.

The company also said that coordination with the coalmine operator has ensured adequate stock management, allowing the planned outage to proceed without disruption to supply planning.

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Under the reported arrangement, Hungarian energy group MOL Group is set to purchase 500,000 tons of oil worth around 500 million dollars. Further details of the transaction have not yet been disclosed.

In recent years, MOL has increased its purchases of Russian crude after securing sanctions exemptions from both the United States and the European Union. The planned agreement with the United States would therefore represent a notable addition to Hungary’s energy sourcing strategy, further diversifying its supply portfolio.

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Only a few years ago, the country was heavily dependent on imports, but recent developments have reversed that trend. The shift is largely driven by increased output from wind energy, which has enabled Greece to supply electricity to neighboring markets and improve its overall energy balance.

Alongside its export performance, Greece also recorded comparatively lower wholesale electricity prices than countries in Central and Southeastern Europe during the same period. In the natural gas market, prices have remained within a relatively stable band, fluctuating between 45 and 50 euros/MWh. These levels are similar to those seen during the winter of 2024–2025 and remain far below the extreme highs experienced during the peak of the energy crisis, when prices reached around 250 euros/MWh.

Tsafos explained that one of the key reasons gas prices have not returned to crisis levels is the absence of strong competition from Asian buyers for liquefied natural gas (LNG) shipments. Instead, many Asian economies have relied more heavily on coal, easing pressure on global LNG demand and helping stabilize prices for Europe.

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The 80 MW facility is planned for an area covering the municipality of Dicmo and the town of Trilj. According to current plans, the project will include 11 wind turbines and is positioned as a step toward strengthening Croatia’s domestic energy production and reducing reliance on imported electricity.

Representatives from VSB stated that Croatia needs a broader mix of renewable energy sources to improve energy security and reduce dependence on imports. While rooftop solar systems play an important role, they emphasized that larger projects such as wind farms are essential to meet national demand and ensure stable supply throughout the year.

In addition to energy generation, the project is expected to bring financial benefits to the local area. Estimates from the developer suggest the wind farm could generate more than 300,000 euros annually for municipal and town budgets, supporting investments in infrastructure, public services, and other development priorities.

At this stage, the Cemernica project remains in the preparatory phase. Current work focuses on data collection, including wind measurements and the preparation of an environmental impact study. After this phase, the project will enter public consultation and permitting procedures, followed by final decisions on turbine placement and the start of construction.

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The association highlights that strong potential in solar and hydropower could serve as a solid foundation for sector growth, increased exports, and new investments. Despite this, producers are facing growing difficulties in selling electricity under sustainable market conditions.

One of the key issues in recent months has been a sharp decline in electricity purchase prices, particularly during periods of high solar generation. Additional concerns include the lack of stable long-term agreements such as PPAs (power purchase agreements), an underdeveloped electricity market, the absence of a fully functional electricity exchange, and limited balancing and storage capacities.

These challenges are not only reducing the economic viability of existing renewable energy projects but are also discouraging new investments at a time when the sector should be expanding rapidly.

The association stresses that the most urgent priority is the establishment of a transparent and well-structured electricity market, including the launch of a functional exchange platform. It also calls for the introduction of long-term contracting mechanisms to ensure more predictable revenue streams for renewable energy producers.

Furthermore, the development of energy storage solutions, particularly battery systems, is seen as essential for absorbing excess generation and mitigating the impact of oversupply during peak renewable output.

The group also urges regulators and institutions to take a more active role in protecting domestic investments and creating a more predictable and stable business environment for project developers.

Without progress in these areas, Bosnia and Herzegovina risks leaving much of its renewable potential untapped and missing the opportunity to establish itself as a regional leader in clean energy.

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Hungary’s HUPX cleared at EUR 103.01/MWh, up EUR 8.6/MWh day on day, restoring a clear premium over the rest of SEE. Romania followed at EUR 100.03/MWh, while Bulgaria and Greece clustered near EUR 94–95/MWh, with Croatia and Slovenia slightly lower. Serbia, at EUR 88.33/MWh, remained one of the cheapest organized markets in the region, trading at a discount of roughly EUR 14–15/MWh to Hungary, a spread wide enough to sustain cross-border export incentives into the HU node during peak hours.  

That pricing structure reflects a system that temporarily shifted back into import dependence. Regional consumption rose to 31,284 MW, up 1,066 MW day on day, while net imports swung to +1,405 MW, compared to a net export position previously. Core inflows, particularly via the AT+SK → HU+SI corridor, increased sharply to 3,434 MW, underlining that Hungary remained the gateway through which higher-priced Central European power was transmitted into the SEE system.  

The generation mix provides the clearest explanation for the intraday shape. Total output increased to 30,486 MW, but composition shifted in a way that reinforced volatility rather than suppressing it. Wind output surged to 3,753 MW, up 1.8 GW day on day, while hydro edged higher to 7,679 MW. However, solar generation dropped materially to 4,496 MW, down 671 MW, tightening the system precisely during the late-afternoon and evening hours when demand remained elevated. This divergence between strong wind and weaker solar created a classic spring “duck curve” effect, where midday oversupply transitions rapidly into evening scarcity.  

Hourly price profiles across the region confirm that dynamic. Hungary recorded a daily minimum of –EUR 3.1/MWh, reflecting midday renewable saturation, before rising sharply to a peak of EUR 215.1/MWh in the evening hours. Romania followed a similar pattern with a peak of EUR 202/MWh, while Slovenia and Bulgaria exhibited slightly dampened but still pronounced evening spikes. This level of intraday amplitude continues to define trading strategy in SEE, where value is increasingly concentrated in flexible positioning rather than flat baseload exposure.  

Serbia’s relative discount deserves closer attention in this context. At EUR 88.33/MWh, SEEPEX remained below both Hungary and Romania, suggesting that domestic balancing conditions or adjacent lower-priced inflows provided temporary insulation from the broader regional tightening. However, the persistence of a double-digit spread to Hungary implies continued monetization potential for cross-border capacity, particularly in the evening peak when Hungarian prices pull upward and regional convergence strengthens.  

The forward and fuel complex does not point to a structural tightening trend, which reinforces the view that current price strength is largely shape-driven. CEGH gas traded at EUR 46.91/MWh, while EUA carbon stood at EUR 71.67/t, both broadly stable to softer day on day. Hungarian forward power declined across the curve, with Week 16 at EUR 110/MWh, Week 17 at EUR 101/MWh, May-26 at EUR 93/MWh, and Cal-26 at EUR 110/MWh, indicating that the market does not price sustained upward pressure beyond short-term balancing conditions.  

Cross-border flow patterns further highlight Hungary’s central role. The HU-DE spread widened to EUR 21.38/MWh, supporting increased imports from the core and reinforcing Hungary as the regional clearing hub. At the same time, commercial flow data across the SEE network shows persistent directional movements from Bulgaria, Romania, and Hungary toward deficit nodes, with Serbia positioned in a more balanced, occasionally export-capable role depending on intraday conditions.  

The broader implication for market participants is that SEE remains firmly in a high-volatility, flexibility-driven regime. Renewable penetration continues to deepen midday price compression, but insufficient storage and limited flexible capacity ensure that evening ramps remain structurally expensive. This creates a widening spread between low and high hours, with significant monetization potential for assets capable of shifting generation or consumption across the curve.

Battery storage, in particular, sits at the center of this evolving structure. The magnitude of intraday spreads—moving from negative pricing to above EUR 200/MWh within the same day—creates arbitrage windows that are already approaching levels required to justify standalone storage economics in parts of the region. Similarly, hydro operators and gas peakers benefit from increasingly valuable dispatch optionality, especially in systems like Serbia and Romania where balancing capacity still plays a critical role.

From a trading perspective, the current setup favors short-term positioning strategies that exploit cross-border spreads, intraday volatility, and renewable-driven price shape, rather than directional bets on outright price levels. Hungary’s continued role as the price setter ensures that monitoring HU-DE spreads, core inflows, and Austrian/German price signals remains essential for anticipating movements across the SEE complex.

The market is not signaling scarcity in the classical sense. Instead, it is signaling a system in transition, where structural oversupply during certain hours coexists with localized scarcity during others. That duality continues to redefine value creation across South-East Europe’s power markets, with flexibility, interconnection access, and execution speed increasingly determining trading outcomes.

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The operational data from early April 2026 already reflects these constraints. Despite total regional generation of 26,197 MW, the system required ~1,002 MW of net imports to meet demand. At the same time, periods of excess solar generation pushed prices into negative territory, indicating that available generation could not be fully absorbed or redistributed. This combination of simultaneous scarcity and surplus is the hallmark of a grid-constrained system.

At a structural level, the SEE transmission network was not designed for the current generation profile. Historically, electricity systems in the region were built around centralized, dispatchable assets—coal plants, hydro stations and, in Hungary, nuclear capacity. Power flows were relatively predictable, moving from large generation centers to demand hubs along established corridors. Renewable generation, by contrast, is geographically dispersed and temporally variable, requiring a fundamentally different network architecture.

Solar expansion has been particularly disruptive in this regard. With installed capacity rising rapidly in Romania and Hungary, generation is increasingly concentrated in areas that were not originally designed to export large volumes of electricity. During peak production hours, local networks can become saturated, limiting the ability to transmit surplus energy to other regions or across borders. This leads to localized oversupply, forcing prices downward and, in extreme cases, resulting in curtailment.

Curtailment—the forced reduction of generation due to network constraints—is emerging as a critical economic factor. For developers, it represents a direct loss of revenue, reducing effective capacity factors and undermining project economics. As renewable penetration increases, the frequency and magnitude of curtailment events are likely to grow, particularly in areas with limited grid capacity.

The broader European context underscores the scale of the challenge. Across the EU, more than 120 GW of renewable capacity is at risk of curtailment due to grid constraints, a figure that highlights the systemic nature of the issue. In SEE, while absolute numbers are smaller, the relative impact is significant, given the region’s reliance on a limited number of transmission corridors.

Key bottlenecks are concentrated along major north–south and east–west axes. The Austria–Hungary–Romania corridor serves as a primary conduit for imports and exports, linking SEE markets to Central Europe. Similarly, the Romania–Bulgaria–Greece axis facilitates flows toward the Eastern Mediterranean, while the Croatia–Slovenia–Italy corridor connects the region to Western European markets. These corridors are increasingly operating near capacity during periods of high renewable output, restricting the system’s ability to balance itself through cross-border trade.

Congestion on these corridors has direct implications for price formation. When transmission capacity is available, price differences between markets are minimized as electricity flows from lower-priced to higher-priced regions. When capacity is constrained, these price signals cannot be fully transmitted, leading to divergence. This divergence creates localized price distortions, with surplus regions experiencing depressed prices and deficit regions facing elevated costs.

From a trading perspective, congestion introduces both complexity and opportunity. Price spreads between markets can widen significantly when interconnectors are saturated, creating arbitrage potential for those with access to transmission capacity. However, this also increases risk, as congestion patterns can change rapidly in response to generation and demand fluctuations.

The economic value of transmission capacity itself is rising. Access to interconnectors is becoming a strategic asset, enabling participation in cross-border arbitrage and enhancing portfolio flexibility. This has implications for market design, including the allocation of capacity and the development of financial instruments that allow market participants to hedge congestion risk.

The investment requirements to address these constraints are substantial. Grid expansion and modernization across SEE are likely to require multi-billion-euro CAPEX programs over the next decade, encompassing both transmission and distribution networks. This includes not only the construction of new lines but also the upgrading of existing infrastructure, deployment of advanced control systems and integration of digital technologies to enhance grid management.

One of the key challenges in this process is the alignment of generation and grid investment timelines. Renewable projects can be developed relatively quickly, often within a few years, while grid infrastructure typically requires longer planning, permitting and construction periods. This mismatch creates a lag in which generation capacity comes online before the network is capable of supporting it, exacerbating congestion and curtailment.

Regulatory frameworks play a critical role in addressing this imbalance. Coordinated planning between transmission system operators, regulators and developers is essential to ensure that grid expansion keeps pace with generation growth. This includes the identification of priority corridors, streamlined permitting processes and mechanisms to allocate costs and benefits among stakeholders.

The integration of digital technologies offers additional opportunities to enhance grid efficiency. Advanced forecasting tools, real-time monitoring and automated control systems can improve the utilization of existing infrastructure, reducing the need for physical expansion in some cases. However, these solutions are not a substitute for investment; they complement rather than replace the need for new capacity.

Energy storage is also closely linked to grid constraints. By absorbing excess generation and releasing it during periods of high demand, storage can reduce the burden on transmission networks. Strategically located storage assets can alleviate congestion, improve price stability and enhance overall system flexibility. This creates a strong synergy between storage investment and grid development, with each reinforcing the value of the other.

The implications for renewable developers are significant. Project viability increasingly depends not only on resource quality and technology costs but also on grid access and congestion risk. Securing connection agreements and understanding network constraints are becoming critical components of project development. In some cases, developers may need to invest in grid infrastructure themselves or co-locate projects with storage to mitigate risks.

For policymakers, the challenge is to balance the rapid expansion of renewable capacity with the need for a resilient and efficient grid. This requires a shift in focus from generation targets alone to a more holistic approach that encompasses infrastructure, flexibility and market design. Failure to address grid constraints risks undermining the economic and environmental benefits of renewable investment.

The SEE region is at a pivotal moment in this transition. The pace of renewable deployment is accelerating, driven by both market forces and policy objectives. At the same time, the limitations of existing infrastructure are becoming increasingly apparent. How these challenges are addressed will determine the trajectory of the region’s energy system over the coming decades.

Grid congestion is not merely a technical issue; it is a structural constraint that shapes the entire market. It influences prices, investment decisions and the integration of renewable energy. As such, it must be treated as a central element of the energy transition, requiring coordinated action and sustained investment.

In this evolving landscape, the grid is no longer a passive conduit for electricity. It is an active component of the system, determining how energy is distributed, how prices are formed and how value is captured. Understanding and addressing grid constraints is therefore essential for all market participants, from developers and investors to policymakers and system operators.

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This relatively low penetration is not merely a function of resource availability. The SEE region possesses substantial wind potential, particularly along coastal corridors in Croatia and Montenegro, as well as inland zones in Serbia and Romania. Instead, the constrained role of wind reflects a combination of structural, regulatory and infrastructural factors that have limited its deployment relative to solar.

The contrast with solar expansion is striking. Solar capacity has scaled rapidly across the region, driven by shorter development timelines, lower capital intensity and fewer permitting barriers. Projects can often be brought online within 12–24 months, compared to 3–5 years or more for wind, particularly when grid connection and environmental approvals are factored in. This difference in execution speed has allowed solar to dominate recent capacity additions, reshaping the generation mix in a relatively short period.

Wind projects, by contrast, face a more complex development pathway. Site selection must account for wind resource quality, environmental constraints and proximity to grid infrastructure. Permitting processes are often lengthy and subject to local opposition, particularly in areas with ecological sensitivity or tourism value. Grid connection, in particular, has emerged as a critical bottleneck, with available capacity in high-resource areas frequently limited.

These constraints are reflected in the current generation profile. On the observed day, wind output declined by approximately 299 MW compared to the previous period, highlighting its inherent variability. Unlike solar, which follows a predictable diurnal pattern, wind generation is driven by meteorological conditions that can change rapidly and are often poorly correlated with demand peaks. This unpredictability reduces its effectiveness as a balancing resource, increasing the burden on hydro and thermal generation.

Capacity factor dynamics further illustrate the divergence between wind and solar in the region. While wind projects can achieve annual capacity factors of 30–40% in favorable locations, their output is distributed unevenly over time. Solar, despite lower capacity factors of 15–25%, delivers output during daylight hours that align more closely with daytime demand and market activity. This alignment, combined with lower development barriers, has made solar the preferred investment choice in recent years.

However, the limitations of solar are becoming increasingly apparent, particularly in the context of midday oversupply and negative pricing. This raises the question of whether wind could play a more significant role in balancing the system. In theory, wind generation profiles can complement solar, particularly if peak wind output occurs during evening or nighttime hours. In practice, the current scale of wind deployment in SEE is insufficient to provide this counterbalance.

The geographic distribution of wind resources also presents challenges. Coastal regions with strong wind potential are often distant from major demand centers, requiring significant investment in transmission infrastructure. Inland sites, while closer to load, may offer lower resource quality or face competing land use considerations. These factors complicate project economics and extend development timelines.

Romania represents one of the more advanced wind markets in the region, with established capacity and ongoing development activity. The Dobrogea region, in particular, hosts significant wind resources and existing infrastructure. However, even here, expansion is constrained by grid capacity and the need for system upgrades. Serbia, Croatia and Montenegro are at earlier stages of development, with project pipelines emerging but still limited relative to potential.

The interaction between wind and grid infrastructure is a critical determinant of future growth. Transmission networks in SEE were not designed to accommodate large-scale variable generation, particularly in remote or coastal areas. As a result, connecting new wind capacity often requires substantial grid reinforcement, increasing CAPEX and extending project timelines. This contrasts with solar, which can often be deployed closer to existing infrastructure or distributed across smaller sites.

Curtailment risk is another emerging issue. As renewable penetration increases, periods of oversupply can lead to forced reductions in output, particularly in areas with limited grid capacity. While this has been more pronounced for solar to date, wind projects are not immune. The risk of curtailment reduces effective capacity factors and introduces uncertainty into revenue projections, complicating financing.

From an investment perspective, these dynamics create a more complex risk-return profile for wind compared to solar. Higher CAPEX—typically in the range of €1.2–1.6 million per MW—combined with longer development timelines and regulatory uncertainty, requires stronger revenue visibility to justify investment. Power purchase agreements (PPAs) and other long-term contracts are therefore critical in securing financing, but their availability varies across the region.

Despite these challenges, the strategic role of wind should not be underestimated. As the system evolves and solar penetration increases further, the need for complementary generation profiles will become more pronounced. Wind, with its potential for nighttime and winter output, can help smooth seasonal and diurnal variability, reducing reliance on thermal generation.

The integration of wind with other technologies offers additional opportunities. Hybrid projects combining wind, solar and storage can optimize resource use and enhance revenue stability. By diversifying generation profiles and incorporating flexibility, such projects can mitigate some of the risks associated with standalone wind developments.

Policy frameworks will play a decisive role in shaping the future of wind in SEE. Streamlining permitting processes, enhancing grid planning and providing clear investment signals are essential to unlocking the region’s potential. Lessons from more mature European markets suggest that coordinated policy support can accelerate deployment and reduce costs over time.

At the same time, the broader European context is relevant. As the EU continues to prioritize wind as a key component of its energy transition, supply chain developments, technology improvements and financing mechanisms are likely to benefit SEE markets. Access to these resources can help overcome some of the current barriers to deployment.

The interplay between wind and other system components will define its future role. In a system dominated by solar and constrained by flexibility, wind has the potential to provide valuable diversification. However, realizing this potential requires addressing the structural challenges that have limited its growth to date.

The SEE power market is at a stage where choices made today will shape the generation mix for decades. The current dominance of solar reflects immediate economic and regulatory conditions, but a balanced system will require a broader portfolio of renewable resources. Wind, despite its current underrepresentation, remains a critical part of that portfolio.

The path forward is therefore not one of substitution, but of integration. Solar, wind, hydro and storage must be developed in a coordinated manner, supported by grid infrastructure and market design that enable efficient operation. In this context, wind’s role is likely to expand, but at a pace determined by the ability of the system to accommodate its unique characteristics.

For now, the data tells a clear story. Wind is present, but not yet central. Its variability influences the system, but its scale is insufficient to shape it. The challenge—and the opportunity—is to move from this peripheral role to one where wind becomes a meaningful contributor to both generation and flexibility in the SEE energy transition.

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The observed trading day in early April 2026 provides a clear empirical illustration. During solar peak hours, wholesale prices fell as low as -€171/MWh in Hungary, while evening peak prices exceeded €200/MWh across several markets. This spread—approaching €350–400/MWh within a single day—is not simply a reflection of supply and demand fluctuations. It is the manifestation of a system where electricity has radically different values depending on the hour of delivery, driven by renewable intermittency and constrained flexibility.

At the core of this dynamic lies the rapid expansion of solar generation. With output reaching approximately 3,927 MW, solar now constitutes a meaningful share of system supply. However, its production profile is highly concentrated, creating a surge of generation during midday hours that the system is not yet equipped to absorb efficiently. Demand during these hours is insufficient to match supply, and without large-scale storage or flexible demand, excess electricity must be cleared at progressively lower prices.

Negative pricing emerges when generators are effectively willing to pay to remain online. This behavior is rational within the current market structure. Renewable generators, particularly those operating under support schemes or with low marginal costs, may continue producing even when prices fall below zero. Thermal units, which face costs associated with shutting down and restarting, may also remain online, further contributing to oversupply.

The result is a compression of prices toward zero and below, eroding revenue for generators and creating distortions in market signals. For solar assets, this translates into declining capture prices—the average price received for generated electricity—despite rising output. As solar penetration increases, this effect intensifies, reducing the economic value of additional capacity unless accompanied by flexibility solutions.

The evening peak presents the mirror image of this phenomenon. As solar output declines rapidly, the system must replace several gigawatts of generation within a short time frame. Demand, however, remains elevated, particularly during early evening hours. This creates a steep ramp in required supply, often referred to as the “duck curve.”

In the absence of sufficient storage, this ramp is met by dispatchable resources—primarily hydro and gas-fired generation. Hydro plants increase output where possible, but their capacity is limited by reservoir constraints and prior dispatch decisions. Gas plants, with higher marginal costs, fill the remaining gap, pushing prices upward. This transition from surplus to scarcity within a matter of hours drives the sharp price spikes observed in the market.

The magnitude of these spikes reflects both the cost of marginal generation and the scarcity of flexible capacity. When the system approaches its flexibility limits, prices can rise significantly above average levels, compensating generators for providing critical balancing services. These peaks are not anomalies; they are necessary signals within the market, indicating the value of flexibility.

This dual pricing regime—negative midday prices and elevated evening peaks—creates a fundamentally different economic landscape. Traditional baseload generation models, which rely on stable output and predictable prices, are increasingly challenged. Revenue streams become more volatile, and the timing of generation becomes as important as the volume.

For market participants, this volatility opens new avenues for value creation. Traders, in particular, are well positioned to exploit intraday price spreads. By purchasing electricity during low or negative price periods and selling during peak hours, they can capture arbitrage margins that were previously unavailable in more stable markets. This shift is driving increased activity in intraday and balancing markets, where price signals are most pronounced.

Battery energy storage systems are the most direct beneficiaries of this environment. Their operational model aligns perfectly with the observed price dynamics. By charging during periods of low or negative prices and discharging during peak demand, storage assets can capture the full extent of intraday spreads. The economics of such operations are increasingly compelling, particularly in markets where volatility is high and predictable.

Revenue models for storage are evolving accordingly. Rather than relying solely on capacity payments or ancillary services, storage operators are focusing on arbitrage as a primary revenue stream. In the SEE context, where daily spreads can exceed €200/MWh, the potential returns are substantial. Even accounting for efficiency losses and operational constraints, storage assets can generate significant value through active market participation.

However, the current system also exposes limitations. The scale of volatility indicates that existing flexibility is insufficient to balance renewable output effectively. As solar capacity continues to grow, the magnitude and frequency of negative pricing events are likely to increase, further compressing capture prices and amplifying the need for storage and demand-side solutions.

Demand response represents another potential avenue for addressing this imbalance. By shifting consumption to periods of high renewable output, industrial and commercial users can help absorb excess generation, reducing the incidence of negative prices. However, the deployment of demand response mechanisms in SEE remains limited, constrained by regulatory frameworks and market design.

Grid infrastructure plays a critical role in this context. The ability to export surplus energy to neighboring markets can mitigate local oversupply, reducing price pressure. However, as renewable penetration increases across Europe, the effectiveness of this mechanism diminishes. When multiple regions experience high solar output simultaneously, cross-border capacity becomes constrained, and the ability to export surplus energy is reduced.

This convergence of renewable generation patterns is an emerging challenge. Historically, geographic diversification allowed regions to balance each other’s variability. In a solar-dominated system, this diversification is less effective, as production profiles become more synchronized. This increases the importance of local flexibility solutions, particularly storage.

The impact of these dynamics extends beyond the electricity market. Price volatility influences investment decisions across the energy sector, shaping the development of generation, storage and infrastructure. For renewable developers, declining capture prices necessitate new strategies, including co-location with storage or participation in hybrid projects that combine generation and flexibility.

For thermal generators, the implications are mixed. While peak prices provide opportunities for high-margin operation, declining utilization rates and regulatory pressure create uncertainty. The role of thermal assets is shifting from baseload providers to peaking and balancing resources, with corresponding changes in revenue models.

Policy frameworks are beginning to adapt to these changes. Market design reforms aimed at enhancing flexibility, such as improved balancing markets and incentives for storage, are gaining traction. However, the pace of regulatory change often lags behind market developments, creating a gap that must be bridged through investment and innovation.

The SEE market is not unique in experiencing these dynamics, but its characteristics—rapid solar growth, significant hydro capacity and limited storage—make it a particularly clear example. The patterns observed here are likely to intensify as renewable penetration increases, both within the region and across Europe.

The emergence of negative pricing and peak spikes should therefore be understood not as a sign of dysfunction, but as an indicator of transition. The system is evolving from one defined by scarcity and predictability to one characterized by abundance and variability. Managing this variability is the central challenge of the next phase.

In this context, price volatility is not merely a byproduct of change—it is a signal. It reflects the value of flexibility, the limitations of current infrastructure and the opportunities for innovation. For those able to interpret and respond to these signals, the evolving market offers significant potential.

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The dataset for early April 2026 captures this interdependence in quantifiable terms. Total system demand reached 29,759 MW, while internal generation stood at 26,197 MW, leaving a deficit covered through approximately 1,002 MW of net imports. This structural gap is not an anomaly. It reflects a persistent feature of the SEE market: even with rising renewable capacity, the region continues to rely on external supply to maintain equilibrium.

What has changed is not the existence of imports, but their role. In a system increasingly shaped by renewable intermittency, cross-border flows have become a dynamic balancing instrument, responding to intra-day fluctuations in generation and demand. Electricity is no longer simply traded across borders—it is actively redistributed in real time to manage volatility.

At the center of this system lies a set of well-defined transmission corridors that link SEE markets to Central Europe and beyond. The Austria–Slovakia–Hungary axis functions as the primary northern entry point, delivering baseload and flexible supply into the region. From Hungary, flows extend southward into Romania, Serbia and Croatia, forming a backbone that supports regional stability.

Romania occupies a particularly strategic position within this network. With a diversified generation mix that includes hydro, nuclear and increasingly solar, it can act as both an exporter and importer depending on conditions. During periods of strong hydro or solar output, Romania exports surplus energy into Hungary and Serbia. Conversely, when hydrological conditions weaken or demand rises, it draws on imports from Central Europe.

Bulgaria and Greece form the southeastern extension of the system, linking SEE markets to the Eastern Mediterranean. Flows through this corridor are influenced by both regional demand and external factors, including LNG-driven gas prices and interconnection with Turkey. Meanwhile, the western flank—Croatia and Slovenia—connects the region to Italy, where higher price levels often create a strong pull for exports.

This “Italy premium” is a recurring feature of the system. Italian power prices, frequently elevated due to structural supply constraints and high gas dependency, attract exports from Slovenia and Croatia, tightening supply in SEE markets. This dynamic introduces a layer of external price influence, where conditions in Western Europe can directly affect price formation in the Balkans.

The interplay of these corridors creates a complex web of flows that shift continuously throughout the day. During midday solar peaks, excess generation in Romania and Hungary may flow outward, reducing prices and relieving local congestion. In the evening, as solar output declines, the direction of flows reverses, with imports increasing to meet demand.

This constant reconfiguration is governed by price spreads between markets. Traders and system operators respond to these spreads, directing electricity from lower-priced regions to higher-priced ones. The result is a system that seeks equilibrium through arbitrage, with cross-border flows acting as the transmission mechanism for price signals.

However, this mechanism is increasingly constrained by physical infrastructure. Transmission lines have finite capacity, and as renewable penetration rises, these limits are being reached more frequently. Congestion on key interconnectors restricts the ability of the system to balance itself, leading to price divergence and localized stress.

The data already shows signs of this constraint. Day-on-day changes in imports, including a reduction of approximately 1,545 MW, indicate how quickly flows can adjust in response to market conditions. Yet when capacity limits are reached, further adjustment is not possible, forcing the system to rely on more expensive domestic generation.

Congestion has direct economic implications. When interconnectors are saturated, price spreads between markets widen, creating both risks and opportunities. For traders, these spreads represent arbitrage potential. For system operators and policymakers, they signal inefficiencies and the need for infrastructure investment.

The concept of congestion monetization is becoming increasingly relevant. Transmission capacity itself acquires value, as access to cross-border flows enables participation in price differentials. This has led to growing interest in capacity allocation mechanisms and financial transmission rights, which allow market participants to hedge or exploit congestion-related price differences.

From an investment perspective, cross-border infrastructure is emerging as a critical asset class. Expanding interconnection capacity can unlock value by reducing congestion, enhancing market integration and facilitating renewable deployment. Projects that strengthen key corridors—particularly those linking SEE to Central Europe and Italy—are likely to attract significant attention.

At the same time, the reliance on imports introduces strategic considerations. Dependence on external supply exposes the region to risks beyond its control, including changes in neighboring markets, geopolitical developments and infrastructure disruptions. Diversifying supply sources and strengthening internal generation capacity remain important objectives, even as cross-border integration deepens.

The interaction between cross-border flows and renewable generation adds further complexity. As solar and wind capacity expands across Europe, generation patterns become more correlated. This can reduce the availability of surplus energy for export, particularly during periods of widespread high renewable output. In such scenarios, the effectiveness of cross-border balancing is diminished, increasing the importance of domestic flexibility.

This trend is particularly relevant for SEE, where solar growth is concentrated in a relatively narrow geographic band. When Romania and Hungary experience high solar output simultaneously, their ability to export excess energy may be limited by both transmission capacity and similar conditions in neighboring markets. This creates a risk of localized oversupply and price collapse.

Conversely, during periods of low renewable output across Europe, competition for imports intensifies. SEE markets must compete with Central and Western Europe for available supply, potentially driving prices higher. This dynamic underscores the importance of maintaining a diversified and resilient system.

The evolution of cross-border flows is also influencing market design. As interconnection becomes more critical, regulatory frameworks must adapt to ensure efficient allocation of capacity and fair access for market participants. This includes harmonization of market rules, coordination between transmission system operators and the development of regional trading platforms.

The SEE region is already part of broader European market coupling mechanisms, which facilitate the integration of day-ahead and intraday markets. These mechanisms enhance efficiency by allowing prices to converge across interconnected markets. However, their effectiveness is ultimately constrained by physical infrastructure, reinforcing the need for continued investment in transmission capacity.

From a strategic perspective, cross-border flows can be seen as both a strength and a vulnerability. They enable the system to manage variability and optimize resource use, but they also create dependencies that must be carefully managed. The balance between integration and self-sufficiency is a central theme in the evolution of the SEE power market.

Looking ahead, the importance of cross-border flows is likely to increase rather than diminish. As renewable penetration rises, the need for geographic diversification of supply becomes more pronounced. Interconnections allow regions with surplus generation to support those with deficits, smoothing variability across larger areas.

However, this requires a step change in infrastructure investment. Existing networks are insufficient to handle the scale and complexity of future flows. Expanding capacity, upgrading existing lines and deploying advanced grid management technologies will be essential to support the next phase of the energy transition.

In this context, cross-border electricity flows are not merely a technical feature of the system—they are a central component of its economic and strategic architecture. They shape price formation, influence investment decisions and determine the system’s ability to integrate renewable energy.

For market participants, understanding these dynamics is critical. Trading strategies must account for corridor behavior, congestion patterns and external price signals. Investment decisions must consider not only local conditions but also the broader regional context.

The SEE power market is, in effect, a networked system where no country operates in isolation. Stability is achieved through interaction, not independence. As the system evolves, this interdependence will deepen, making cross-border flows an even more critical determinant of outcomes.

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The data snapshot from early April 2026 captures this dynamic with clarity. Day-ahead prices across key SEE markets clustered within a relatively tight band of €84–91/MWh, with Hungary (HUPX) clearing at €91.29/MWh, Serbia (SEEPEX) at €90.42/MWh, Romania (OPCOM) at €87.93/MWh, and Bulgaria (IBEX) at €84.58/MWh. These values do not reflect renewable production costs, which are effectively near zero at the margin. Instead, they reflect the cost of the last unit required to meet demand—almost invariably a thermal plant.

This persistence of thermal marginal pricing is rooted in the fundamental characteristics of renewable generation. Solar output, now exceeding 3.9 GW in the system, is highly concentrated during daylight hours and cannot be dispatched at will. Wind, contributing roughly 1.9 GW, is inherently variable and often poorly correlated with demand peaks. Hydropower, while flexible, is constrained by reservoir management and hydrological conditions. Together, these limitations mean that renewable generation cannot consistently meet demand across all hours, necessitating the continued operation of dispatchable thermal units.

Coal and gas plants therefore remain the system’s balancing backbone. On the observed day, coal generation stood at approximately 4,843 MW, while gas contributed around 2,502 MW, together representing more than a quarter of total output. More importantly, these units operate at the margin during periods of tight supply, determining the clearing price for the entire market.

The cost structure of these thermal units directly translates into power prices. Gas-fired generation, in particular, reflects the interplay between fuel costs, carbon pricing and operational efficiency. With gas benchmarks around €52/MWh, and assuming typical plant efficiencies of 50–55%, the implied fuel cost component of electricity generation lies in the range of €95–105/MWh before accounting for carbon costs. Adding CO₂ costs—currently around €70–75 per tonne, and translating to approximately €25–35/MWh depending on plant emissions intensity—pushes the marginal cost of gas-fired generation into the €120–140/MWh range under full load conditions.

However, observed market prices are often lower than these theoretical marginal costs, reflecting a combination of factors. First, not all gas units operate at full marginal cost due to long-term fuel contracts or efficiency variations. Second, coal plants, despite higher emissions, can provide marginal supply at lower short-term cost depending on coal prices and plant characteristics. Third, renewable output during certain hours suppresses prices by reducing the need for thermal dispatch.

Coal-fired generation remains particularly relevant in this context. With coal prices showing a declining trend—recently falling by approximately 5% in API2 benchmarks—and lower fuel costs relative to gas, coal units can undercut gas in the merit order during certain periods. This dynamic is especially pronounced in countries with significant coal capacity, such as Serbia and Bulgaria, where domestic lignite provides a relatively low-cost fuel source.

The interaction between coal and gas in the merit order creates a layered price structure. During periods of moderate demand and high renewable output, coal units may set the marginal price, resulting in lower overall price levels. As demand increases or renewable output declines, gas units move to the margin, pushing prices higher. This transition is clearly visible in intraday price patterns, where evening peaks—coinciding with the decline in solar output—often see prices rise sharply as gas-fired generation is required to balance the system.

Carbon pricing adds another dimension to this structure. The EU Emissions Trading System (ETS) imposes a cost on carbon emissions that disproportionately affects coal generation due to its higher emissions intensity. At current EUA levels of €70–75/t, coal plants face an additional cost of approximately €60–80/MWh, compared to €25–35/MWh for gas. This narrows the cost advantage of coal and, over time, shifts the merit order toward gas and eventually low-carbon alternatives.

Despite this, coal remains competitive in the SEE region due to structural factors, including domestic resource availability and existing infrastructure. The continued operation of coal plants therefore reflects not only cost considerations but also energy security concerns and the slower pace of transition compared to Western Europe.

The persistence of thermal marginal pricing has significant implications for market behavior and investment strategies. For renewable generators, it means that revenue is still largely determined by fossil fuel costs rather than their own production economics. While high renewable output can depress prices during certain hours, the overall price level remains linked to thermal generation costs, providing a degree of revenue stability.

For thermal generators, the situation is more complex. While they continue to set prices and capture high margins during peak periods, they face increasing operational challenges due to declining load factors and regulatory pressure. As renewable penetration increases, thermal plants are dispatched less frequently, reducing their overall utilization and revenue. However, their role in balancing the system ensures that they remain indispensable, at least in the medium term.

Forward markets reflect this underlying structure. Power forward prices for calendar year 2026 are trading around €113–114/MWh, indicating expectations of continued reliance on thermal generation and sustained carbon pricing. These forward levels incorporate both current fuel cost assumptions and anticipated market dynamics, including renewable expansion and potential policy changes.

The linkage between power prices and fuel markets also introduces volatility. Changes in gas prices, driven by global LNG dynamics, or shifts in carbon pricing can have immediate and significant impacts on electricity prices. This creates both risks and opportunities for market participants, particularly those engaged in trading and hedging activities.

The transition away from thermal marginal pricing will require a fundamental shift in system structure. Large-scale deployment of storage, capable of shifting renewable output across time, is a critical component of this transition. Demand-side flexibility, including industrial load management and electrification strategies, can also reduce reliance on thermal generation by aligning demand with renewable supply.

However, these solutions are still in the early stages of deployment in the SEE region. Until they reach sufficient scale, thermal generation will continue to define the marginal price, even as its share of total generation declines. This creates a transitional market environment in which old and new paradigms coexist, with pricing mechanisms lagging behind changes in the generation mix.

The implications for decarbonisation are significant. While increasing renewable capacity reduces overall emissions intensity, the persistence of thermal marginal pricing means that fossil fuels continue to play a central role in the system. Achieving deeper decarbonisation will require not only expanding renewable capacity but also transforming the mechanisms through which electricity is priced and dispatched.

In this context, the SEE market can be seen as a leading indicator of broader European trends. The region’s combination of growing renewable capacity, significant thermal infrastructure and limited storage mirrors conditions that are emerging across other parts of the continent. The dynamics observed here—particularly the coexistence of high renewable penetration and thermal price-setting—are likely to persist until flexibility solutions are fully integrated into the system.

For investors, understanding this dynamic is essential. The value of assets is increasingly determined not just by their generation profile, but by their position within the merit order and their exposure to fuel and carbon costs. Assets that can operate flexibly, respond to price signals and integrate with emerging technologies are likely to outperform in this evolving landscape.

The SEE power market is therefore not yet post-thermal. It is a system in transition, where renewables are reshaping the supply curve but have not yet redefined the marginal price. The timing and trajectory of this transition will depend on the pace of investment in flexibility, the evolution of fuel and carbon markets, and the ability of policymakers to adapt market structures to a new reality.

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The dataset for early April 2026 illustrates this transformation with precision. Hydropower generation reached 6,859 MW, accounting for approximately 24% of total output, making it the single largest controllable renewable source in the SEE + Hungary system. Unlike solar and wind, hydro retains dispatchability, enabling operators to adjust output in response to real-time system conditions. This flexibility is now indispensable.

However, this centrality comes with an emerging vulnerability. Hydro output is inherently dependent on hydrological conditions, and the region is increasingly exposed to variability in river flows and reservoir levels. The Danube basin, which supports major generation assets in Romania, Serbia and Bulgaria, has shown fluctuations that directly translate into system-wide effects. Even relatively modest changes in flow can alter available generation by several hundred megawatts, with immediate consequences for price formation.

This sensitivity is already visible in operational data. Day-on-day variations in hydro output, including increases of around +380 MW, demonstrate the system’s dependence on water availability. In Montenegro, weaker hydrological conditions have constrained generation more visibly, highlighting the broader regional exposure. Hydro is no longer a fully reliable anchor; it is becoming a weather-linked flexibility asset, introducing an additional layer of uncertainty into market dynamics.

The implications of this shift extend beyond generation volumes. Hydro’s role as a balancing resource means that its availability directly affects the system’s ability to manage renewable intermittency. During periods of strong solar output, hydro plants can reduce generation, preserving water for later use. In the evening, when solar output collapses, hydro ramps up to meet demand. This intra-day storage function is critical, particularly in the absence of large-scale battery capacity.

Yet this balancing capability is finite. Reservoir levels, inflow rates and environmental constraints limit how much flexibility hydro can provide. During periods of low inflow, operators must choose between maintaining reservoir levels and generating electricity, creating trade-offs that can influence market outcomes. When hydro output is constrained, the system must rely more heavily on thermal generation or imports, both of which are more expensive and carbon-intensive.

This dynamic introduces a seasonal dimension to price volatility. In periods of strong hydrology, such as spring snowmelt, hydro output can be abundant, suppressing prices and reducing reliance on thermal generation. Conversely, during dry periods, reduced hydro availability tightens supply, pushing prices higher and increasing emissions. This variability complicates forecasting and increases risk for both generators and traders.

The strategic importance of hydro is therefore shifting. It is no longer sufficient to consider hydro capacity as a static component of the generation mix. Its operational profile, flexibility and exposure to hydrological conditions must be integrated into broader system planning and investment strategies. This includes coordination with emerging flexibility assets, particularly battery storage, which can complement hydro by absorbing excess generation and reducing the need for rapid ramping.

Investment in hydro modernization is becoming a key theme. Many existing plants in the region were built decades ago and can benefit from upgrades that enhance efficiency and responsiveness. Digital control systems, improved turbine technology and optimized reservoir management can increase the value of hydro assets without requiring new construction. In some cases, upgrades can increase output or flexibility by 5–15%, improving both economic and operational performance.

Pumped storage hydropower represents a more direct expansion of hydro’s flexibility role. By allowing water to be pumped back into reservoirs during periods of low prices and released during peak demand, pumped storage effectively functions as large-scale energy storage. However, the development of new pumped storage projects faces significant challenges, including high CAPEX, long permitting timelines and environmental considerations. As a result, while pumped storage offers substantial potential, its deployment is likely to be gradual.

The interaction between hydro and other generation sources is also evolving. As solar capacity expands, hydro is increasingly used to smooth intra-day fluctuations. This coordination requires advanced forecasting and system management, as operators must anticipate solar output and adjust hydro generation accordingly. The integration of digital tools and predictive analytics is becoming essential in this context.

Cross-border dynamics further complicate hydro’s role. In an interconnected system, hydro output in one country can influence prices and flows across the region. For example, high hydro generation in Romania can lead to exports to Hungary and Serbia, affecting prices in those markets. Conversely, low hydro output can increase import requirements, tightening supply across multiple countries. This interconnectedness amplifies the impact of hydrological variability, making it a regional rather than purely national issue.

From an investor perspective, hydro assets retain strong strategic value, but their risk profile is changing. Traditionally viewed as low-risk, stable generators, hydro plants are now exposed to greater variability in both output and prices. This does not diminish their importance, but it requires a more nuanced approach to valuation and risk management. Revenue streams are increasingly linked to flexibility and timing rather than pure volume.

Hydro’s interaction with carbon markets also deserves attention. During periods of low hydro output, increased reliance on coal and gas raises emissions, reinforcing the link between hydrology and carbon pricing. This creates indirect exposure for hydro assets, as their value can be influenced by broader energy and emissions markets.

The policy environment is adapting to these changes. Governments and regulators are recognizing the need to preserve and enhance hydro capacity as part of the energy transition. This includes support for modernization, incentives for flexibility services and integration with other renewable and storage technologies. However, environmental constraints remain significant, particularly for new projects, limiting the scope for expansion.

The broader implication is that hydro is transitioning from a legacy asset to a dynamic component of a modern, renewable-dominated system. Its ability to provide flexibility, stability and low-carbon generation ensures its continued relevance. At the same time, its exposure to hydrological variability introduces new challenges that must be managed through investment, technology and policy.

In the context of the SEE power market, hydro’s role is likely to remain central for the foreseeable future. While solar and wind capacity will continue to grow, the ability to manage their variability will depend heavily on hydro, at least until storage and other flexibility solutions reach sufficient scale. This positions hydro as both a cornerstone and a constraint—essential to system operation, but increasingly subject to external factors beyond direct control.

The evolution of hydro’s role reflects the broader transformation of the energy system. Stability is no longer guaranteed by predictable baseload generation; it must be actively managed through a combination of flexible resources. In this emerging paradigm, hydro stands at the intersection of old and new, bridging the gap between traditional power systems and the renewable future.

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The dataset for early April 2026 captures this transition with unusual clarity. Total system demand stood at 29,759 MW, while generation reached 26,197 MW, leaving a residual gap covered through imports. At first glance, this reflects a familiar regional characteristic: SEE remains partially dependent on cross-border supply. Yet a deeper reading reveals that the issue is not insufficient capacity. Installed generation across the region, particularly in solar, has expanded rapidly. The system is capable of producing more electricity than it can effectively use during certain hours of the day.

Solar generation reached approximately 3,927 MW, accounting for roughly 14% of instantaneous output, with growth heavily concentrated in Romania and Hungary. These additions are not marginal increments; they represent a structural shift in the generation profile. Solar output is now sufficiently large to influence system-wide price formation during daylight hours. The consequence is the emergence of sustained periods of oversupply, during which wholesale prices collapse and, increasingly, turn negative.

Negative pricing is not an anomaly but a signal of structural imbalance. It reflects a system in which production cannot be curtailed or shifted quickly enough to match demand. In traditional thermal systems, generation could be modulated to follow load. In a solar-dominated midday profile, output is largely fixed, driven by irradiance rather than dispatch decisions. Without adequate storage or flexible demand, the system is forced to absorb this excess energy at any price, including negative values.

The other side of this imbalance emerges during the evening peak. As solar output declines sharply, demand remains elevated, requiring rapid ramping from dispatchable sources. Hydropower provides a portion of this flexibility, but its capacity is finite and increasingly constrained by hydrological conditions. Gas-fired generation and coal plants fill the remaining gap, often at significantly higher marginal costs. This transition from oversupply to scarcity within a single day produces price spreads that can exceed €200/MWh, fundamentally altering market dynamics.

This widening intraday spread is the clearest indicator that the system has entered a flexibility-constrained phase. In such an environment, the value of electricity is no longer determined primarily by its production cost, but by its timing. Electricity generated at midday may have little or even negative value, while the same megawatt-hour delivered during the evening peak commands a substantial premium. This temporal differentiation creates a new hierarchy of assets and investment opportunities.

Battery energy storage systems are emerging as the most direct response to this structural shift. Their ability to capture low-cost or negatively priced electricity and redeploy it during high-price periods aligns precisely with the observed market dynamics. The economics of storage are increasingly driven by arbitrage rather than capacity payments or ancillary services alone. In the SEE context, where intraday volatility is pronounced, revenue potential is correspondingly high.

Romania provides the clearest illustration of this emerging investment wave. Large-scale storage projects, including multi-gigawatt-hour installations and distributed clusters, are progressing from planning to execution. These projects are not speculative; they are grounded in observable price spreads and system needs. Revenue expectations in the range of €100,000 to €250,000 per MW annually are becoming realistic under current volatility conditions, particularly for assets participating in multiple market segments.

However, storage alone cannot resolve the system’s flexibility deficit. Grid infrastructure represents the second critical constraint. The rapid deployment of solar capacity has outpaced the expansion of transmission networks, leading to localized congestion. During periods of high solar output, certain regions experience an inability to export surplus energy, forcing curtailment or further price suppression. Cross-border interconnections provide partial relief, but they too face capacity limits, especially when neighboring markets experience similar generation patterns.

This interplay between generation growth and grid limitations introduces a spatial dimension to flexibility. It is not sufficient to have flexible capacity somewhere in the system; it must be located where it can effectively respond to local imbalances. This raises the importance of grid planning and investment, as well as the strategic siting of storage and flexible generation assets.

Hydropower continues to play a central role in managing these dynamics, but its function is evolving. Traditionally viewed as a baseload renewable resource, hydro is increasingly operating as a balancing asset, adjusting output to compensate for solar and wind variability. On the observed day, hydro generation reached 6,859 MW, representing approximately 24% of total output. This scale underscores its importance, but also highlights its limitations. Hydrological variability introduces uncertainty, particularly during periods of low inflow, when hydro’s ability to provide flexibility is reduced.

The persistence of thermal generation in the system further reflects the incomplete nature of the transition. Coal and gas plants, delivering a combined ~7,300 MW, remain essential for ensuring reliability. More importantly, they continue to set the marginal price in most hours. This means that, despite the growing share of renewables, power prices remain closely linked to fuel and carbon costs. Gas prices around €52/MWh and carbon prices in the €70–75/t range effectively establish the price floor for the market.

This duality—high renewable penetration alongside thermal price-setting—defines the current phase of the SEE power market. Renewables influence volatility and intraday patterns, while thermal generation determines overall price levels. The transition to a fully renewable-driven pricing mechanism will depend on the scaling of storage and other flexibility solutions to the point where thermal units are no longer required as marginal providers.

Cross-border trading adds another layer of complexity. The SEE region operates as an interconnected system, with flows from Central Europe playing a crucial role in balancing supply and demand. On the observed day, net imports of approximately 1,002 MW were required to meet demand. These flows are highly dynamic, responding to price differentials and generation patterns across the broader European market.

The reliance on imports introduces both opportunities and risks. On one hand, it enhances system resilience by providing access to external supply. On the other, it exposes the region to external price signals and potential constraints in neighboring markets. As renewable penetration increases across Europe, the correlation of generation patterns may reduce the availability of surplus energy for export, increasing the importance of domestic flexibility.

The transformation of the SEE power market is therefore not a simple story of renewable expansion. It is a multi-dimensional shift involving generation, flexibility, grid infrastructure and market design. Each of these elements interacts with the others, creating a system that is more complex but also more dynamic.

For investors, the implications are profound. Traditional metrics, such as installed capacity or average prices, are no longer sufficient to assess opportunities. Instead, attention must focus on volatility, flexibility and spatial dynamics. Assets that can respond quickly to price signals, whether through storage, flexible generation or advanced trading strategies, are positioned to capture disproportionate value.

This shift also challenges policymakers. Ensuring system stability in a flexibility-constrained environment requires coordinated action across multiple domains. Investment in grid infrastructure must be accelerated, regulatory frameworks must support storage and demand response, and market designs must evolve to reflect the value of flexibility.

The SEE power market is not unique in this transition, but its characteristics—high hydro dependence, rapid solar growth and limited storage—make it an early example of the broader changes underway across Europe. The patterns observed today are likely to intensify as renewable penetration continues to rise.

The system is moving from a paradigm in which electricity was scarce and predictable to one in which it is abundant but variable. Managing this variability is the central challenge of the next phase of the energy transition. In SEE, that challenge is already visible, shaping prices, flows and investment decisions.

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Day-ahead prices reflected a fragmented market structure rather than a uniform directional move. Hungary’s HUPX cleared at 94.42 €/MWh, up 3.1 €/MWh day on day, while Serbia’s SEEPEX jumped to 97.39 €/MWh, gaining 7.0 €/MWh, making it the strongest-performing market in the region. In contrast, Romania (80.63 €/MWh), Bulgaria (80.41 €/MWh) and Greece (80.41 €/MWh)all posted declines between 4–7 €/MWh, consolidating a lower-priced southeastern block.  

Italy remained structurally elevated at 127.98 €/MWh, continuing to anchor the upper bound of regional spreads, though without directly pulling up the Balkan complex.

The divergence comes despite a broadly improved regional supply picture. Total consumption across the SEE + Hungary system rose to 31,058 MW, an increase of 1,626 MW, but generation expanded more sharply, reaching 28,571 MW, up 2,148 MW. The increase was driven primarily by solar (+728 MW to 4,997 MW), hydro (+608 MW to 7,459 MW) and gas (+630 MW to 3,116 MW), offsetting a decline in coal output.  

As a result, the region shifted from a net import position to near balance. Net imports dropped to -160 MW, a sharp improvement of 1,021 MW day on day, indicating that the system required significantly less external supply.

However, the key driver behind price strength in Hungary and Serbia was not absolute scarcity, but changes in cross-border flow dynamics. Core imports into the Hungary-Slovenia system from Austria and Slovakia fell to 1,955 MW, down 478 MW, while flows from Italy into the SEE region also declined. At the same time, the Hungary-Germany spread widened to 7.45 €/MWh, up 6 €/MWh, reinforcing the premium of the Hungarian hub relative to Western Europe.  

This tightening of core inflows effectively isolated the Hungary-Serbia pricing zone, allowing local fundamentals to dominate.

In Serbia, the premium widened significantly against neighboring markets, with SEEPEX trading nearly 17 €/MWh above Romania and Bulgaria. That spread indicates localized balancing constraints and stronger evening peak exposure, rather than system-wide tightness. With wind generation slightly lower and solar dominating the intraday profile, the market structure likely produced deep midday price softness followed by sharp evening ramps, a pattern increasingly visible across the region.

Renewable output forecasts support this interpretation. Total RES generation stood at 10,179 MW, including 4,320 MW solar and 3,394 MW wind, with solar increasing day on day while wind eased. This combination typically amplifies intra-day volatility, especially in markets with limited storage or interconnection flexibility.

Forward markets, meanwhile, signaled a more cautious outlook. Hungarian baseload forwards edged higher, with Week 16 at 116.50 €/MWh, May-26 at 100.50 €/MWh, and Cal-26 at 115.50 €/MWh, supported by firmer gas and stable carbon pricing. CEGH gas rose to 53.88 €/MWh, while EUA held at 71.51 €/t.  

Yet forward spreads to Germany softened slightly across the curve, suggesting that today’s prompt tightness is not fully expected to persist, particularly if renewable generation continues to improve and interconnection flows normalize.

Across the wider region, structural developments continue to reshape market behavior. Bulgaria’s partial return of the Chaira pumped-storage plant, Greece’s completion of 2.13 GW of solar capacity, and Hungary’s expansion of battery storage—now targeting 2.4–2.5 GW of capacity—all point toward a system increasingly driven by renewable intermittency and balancing flexibility.  

In the near term, the trading focus remains on regional spreads rather than outright price direction. The Romania–Bulgaria–Greece corridor around 80 €/MWh is acting as a soft floor, while Hungary and Serbia continue to command a premium driven by localized constraints. Any easing in cross-border congestion or further gains in renewable output could compress these spreads quickly.

For now, however, the market remains structurally split, with Serbia emerging as the tightest node in the Balkan system, and Hungary maintaining its role as the core pricing pivot between Western and South-East Europe.

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Following the meeting, officials confirmed that fuel companies operating in Romania are continuing to source products at international market prices, with no current signs of supply shortages or stress. At the same time, a permanent communication mechanism has been established between the Presidency, the Government, and private-sector operators to enable continuous monitoring and a rapid response should market conditions deteriorate.

The assessment comes amid a surge in global oil prices, which climbed above $110 per barrel on Asian markets on 6 April, driven by rising tensions in the Middle East. The escalation followed threats by US President Donald Trump to target critical Iranian infrastructure, further heightening concerns over global energy security.

While Romania’s domestic supply situation remains stable for now, uncertainties persist regarding external crude oil flows. A recent positive development was the restart of KMGI’s Petromidia refinery, which resumed operations at the end of last month after a scheduled shutdown that coincided with the early phase of the Middle East tensions.

However, new risks have emerged in the Black Sea region. Reports of explosions in Novorossiysk, a major Russian oil export hub, have raised concerns. Some accounts suggest that an oil terminal was targeted in a drone strike, with potential damage reported at the Sheskharis oil terminal. This port is a crucial export point for both Russian and Kazakh crude, hosting the CPC terminal with multiple offshore loading points and onshore infrastructure.

This development is particularly significant for Romania, as Kazakhstan is currently its largest crude oil supplier, accounting for more than half of total imports. Any disruption to export routes through Novorossiysk could therefore pose a serious risk to Romania’s oil supply, especially at a time when geopolitical tensions in the Middle East are already affecting the global movement of oil, fuels, and gas through key transit routes such as the Strait of Hormuz.

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The Romanian distribution operator, part of the PPC Group, reported that projects commissioned during the year were valued at around €241 million. Of the total investment, about €182 million came from the company’s own resources, while the remaining funds were secured from external financing sources.

The investment program covered the regions of Muntenia, Banat, and Dobrogea, focusing on the modernization of both high-voltage and medium-voltage infrastructure. Key activities included upgrading primary and secondary substations, expanding and rehabilitating underground and overhead lines, and strengthening overall network reliability. During 2025, the company commissioned two new primary substations and modernized four existing ones. It also constructed 1 km of new high-voltage line, refurbished about 64 km of existing high-voltage infrastructure, added 303 km of new medium-voltage lines, and upgraded an additional 453 km.

Digitalization remained a central component of the investment strategy. The company installed 575 new remote-control points, introduced nearly 1,000 new secondary substations, and modernized a further 440. A major milestone was also reached in smart metering, with the total number of installed smart meters rising to 2 million, the highest in Romania’s electricity distribution sector.

Looking ahead, Retele Electrice Romania plans to maintain a similar level of investment in 2026, with expected commissioned projects totaling around €261 million. Of this amount, approximately €165 million will come from its own funds, while the rest will be financed through external sources.

The 2026 investment plan focuses on replacing ageing medium- and high-voltage cables, rehabilitating both overhead and underground networks, and improving network redundancy and reliability through reconfiguration and the creation of new loops. It also includes expansions of transformer stations, upgrades to switching and protection systems, and further deployment of automation and remote-control technologies.

In parallel, the company continues to implement externally financed projects over the medium term. Between 2026 and 2029, Retele Electrice Romania plans to advance investments supported by the Modernization Fund across Muntenia Sud, Banat, and Dobrogea, with a total value of €273 million, including approximately €201 million in grant funding.

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The facility was developed by MVM Zöld Generáció, a subsidiary of the state-owned MVM Group, and represents another important step in Hungary’s energy transition. The storage system is capable of supplying electricity equivalent to the needs of around 3,000 households, or alternatively charging approximately 400 electric vehicles, highlighting its practical contribution to system stability and energy balancing.

The total investment in the project amounts to about €7.8 million, with approximately €3.5 million provided through European Union funding. This financial support underlines the role of EU-backed initiatives in accelerating the deployment of clean energy infrastructure across member states.

During the inauguration, Energy Minister Csaba Lantos emphasized that Hungary’s energy storage capacity has grown rapidly in recent years, rising from 20 MW to 436 MW. He described this progress as an intermediate stage, noting that further expansion remains a key priority for the government.

Looking ahead, Hungary aims to significantly increase its storage capacity to between 2,400 MW and 2,500 MW, supported by a dedicated state program designed to accelerate the rollout of additional storage projects. This expansion is intended to strengthen grid reliability and facilitate the integration of more renewable energy sources into the system.

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Total gas demand between January and March reached 26.42 TWh, marking an 18.5% increase compared to 22.3 TWh in the same period of 2025. A key driver of this growth was a surge in exports, which climbed to 5.99 TWh from just 1.44 TWh a year earlier. This development further reinforces Greece’s growing role as a regional gas transit and trading hub.

In contrast, domestic gas consumption decreased slightly, reaching 20.43 TWh, down 2.1% year-on-year. DESFA noted that this shift reflects changes in consumption patterns, with reduced gas use in electricity generation offset by increases in industrial demand, compressed natural gas (CNG), and distribution network consumption.

Gas imports during the quarter totaled 26.4 TWh, with liquefied natural gas (LNG) accounting for the majority share. LNG deliveries reached 14.9 TWh, representing about 56% of total imports and increasing significantly compared to 10.96 TWh in the same period last year. This highlights Greece’s growing reliance on LNG as a key supply source.

The Revythoussa LNG terminal remained the country’s primary entry point, receiving 11.44 TWh, or approximately 43% of all imports. The Alexandroupoli terminal also contributed with 3.46 TWh (around 13%). Pipeline imports continued to play an important role, with 8.77 TWh entering via Sidirokastro and 2.73 TWh through Nea Mesimvria.

Within the domestic consumption mix, gas use in power generation declined to 12.48 TWh from 13.33 TWh a year earlier. Meanwhile, industrial consumption and CNG demand increased to 2.28 TWh, up from 2.13 TWh, and deliveries to distribution networks rose to 5.67 TWh, compared to 5.40 TWh in Q1 2025.

The United States remained Greece’s leading LNG supplier, providing 7.6 TWh, or roughly two-thirds of total LNG imports. It was followed by Nigeria with 3.02 TWh, while smaller volumes were supplied by Egypt (0.51 TWh) and Mauritania (0.35 TWh).

Despite a reduction in the number of LNG cargoes, total imported volumes increased. A total of 16 cargoes were delivered in the first quarter of 2026, transferring 11.48 TWh, compared to 20 cargoes and 10.65 TWh a year earlier. This suggests larger shipments per cargo and improved import efficiency.

Growth was also evident in the small-scale LNG segment, where activity nearly doubled. A total of 273 LNG trucks were loaded during the quarter, compared to 144 in the same period last year. Truck-loading volumes rose to 12,496 cubic meters, while the energy delivered increased by approximately 92% to 83,252.18 MWh. These trends highlight the rapid development of Greece’s small-scale LNG market alongside its expanding role in regional energy flows.

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The newly finished solar portfolio has a total installed capacity of 2,130 MW and is expected to generate approximately 3,150 GWh of electricity annually. This represents nearly 6% of Greece’s total electricity consumption and is sufficient to supply around 750,000 households. The project is also projected to reduce carbon dioxide emissions by more than 1.5 million tons each year, marking a significant environmental milestone.

Alongside solar development, PPC is strengthening its energy storage infrastructure to support the integration of renewable energy into the grid. Through its subsidiary PPC Renewables, the company has already completed two battery energy storage systems in Ptolemaida and Meliti, while a third system is under construction in Amyntaio. In addition, PPC has secured approvals for two pump-storage projects planned in Kardia and South Field.

Key assets within the solar portfolio include the 550 MW Phoebe solar plant near Pontokomi, expected to produce around 880 GWh annually, and the 940 MW Amyntaio solar complex, developed in cooperation with RWE across multiple sites such as Rodonas, Filotas, Lakkia, and Perdikkas. The Amyntaio complex alone is projected to generate approximately 1,500 GWh per year. Other completed projects include the 200 MW Helios Velos 1 plant near Ptolemaida, as well as the 80 MW Exochi 7 and 80 MW Akrini solar plants, along with ten smaller installations on former lignite land.

PPC emphasizes that large-scale storage systems are essential for managing this growing renewable capacity. Battery and hydro storage solutions allow surplus electricity to be stored when production exceeds demand and released when needed, helping to stabilize the power system. The existing battery facilities in Western Macedonia have a combined capacity of 98 MW and 196 MWh, while the new project near Amyntaio will add 50 MW and 200 MWh, with the ability to supply power for up to four hours.

In parallel with its energy investments, PPC is advancing a local participation initiative tied to the Western Macedonia transition plan. As part of commitments announced in April 2025, the company launched a €5 million bond issue on 13 March, targeting residents of Kozani and Florina. The bonds allow local communities to invest directly in the region’s energy transition. Subscriptions are open until 17 April, with each bond valued at €100, allowing participation from five up to 250 bonds. PPC states that the instrument offers an annual return of 8% and a total capital growth of 40% before tax over five years, aiming to engage local stakeholders in the region’s economic transformation.

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During a visit to the facility, caretaker Energy Minister Traicho Traikov stated that two of the plant’s four units are now operational, emphasizing Chaira’s growing role in supporting the national electricity system. He highlighted that the plant is crucial for maintaining balance in the network and ensuring overall system security.

Hydro unit 3 has successfully completed repair works and passed its final start-up and pre-commissioning tests. The unit is currently operating in test mode and will continue under this regime until it receives Act 16, the official certificate required for full commercial operation. Testing began on 17 February with dry start-up procedures, aimed at verifying coordination across all major systems. According to Minister Traikov, the unit has already completed a successful 72-hour trial run.

At the same time, hydro unit 2 is already in operation and is expected to switch into pumping mode, taking advantage of periods with lower electricity prices. This flexibility is a key feature of pump-storage plants, allowing them to store energy when prices are low and release it back into the system during periods of higher demand.

Minister Traikov also underlined the plant’s strategic importance in emergency situations, noting that Chaira can provide internal electricity supply to the Kozloduy nuclear power plant in the event of a system-wide disruption. He described the facility as one of the most valuable stabilizing resources in Bulgaria’s energy sector.

Preparations are now underway for further rehabilitation, with documentation being finalized for the public procurement process related to hydro unit 1. The equipment supply has been separated from construction and installation works, a structure expected to attract strong market interest. This unit is currently planned to return to operation in 2028.

The Ministry is also exploring future pump-storage developments across the country. Analyses have already identified ten potential locations suitable for similar projects. Meanwhile, according to Krasimir Dimitrov, CTO of the state-owned National Electricity Company (NEK), all command and control systems on hydro unit 3 have been fully modernized. The unit is expected to receive its operating permit in May.

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Price movements showed mixed trends during the month. The average baseload price on the day-ahead market stood at 103.54 euros/MWh, reflecting a 4% increase from February’s 99.57 euros/MWh. In contrast, the average peak price dropped significantly by 20%, settling at 83.07 euros/MWh, suggesting softer demand or improved supply during peak hours. The number of registered market participants rose to 153, an increase of three compared to the previous month, further pointing to growing market engagement.

On the intraday continuous market, trading activity surged more strongly. A total of 754,579.6 MWh was traded, representing a substantial 37% increase compared to February. Despite higher volumes, the average weighted price declined by 4.7%, reaching 88.19 euros/MWh, indicating increased short-term supply flexibility and possibly more efficient balancing within the market.

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At the same time, electricity consumption increased significantly, rising by 6.88% to 12.59 TWh. As a result of higher demand and lower domestic generation, Bulgaria recorded net electricity imports of 403 GWh, marking a reversal from a more balanced or export-oriented position in previous periods.

Production from baseload power plants, including coal and nuclear facilities, dropped sharply. These sources generated 8.7 TWh, representing a 14.2% decrease compared to 2025, indicating reduced reliance on traditional, stable generation capacity.

Meanwhile, the renewable energy sector showed mixed trends. Electricity generation from RES in the transmission network increased by 6.72%, reaching 871.4 GWh, suggesting stronger performance in large-scale renewable installations. However, RES output within the distribution network slightly declined by 0.43%, totaling 828.3 GWh, reflecting uneven developments across different segments of the renewable sector.

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That changes the economics of Western Balkan power exports to the EU immediately. The legal obligation sits with the EU importer, but the commercial burden does not stay there. In practice, traders and counterparties reprice the cost back through lower bid prices for imported electricity, tighter spreads, shorter tenors and more selective sourcing. The Energy Community has been explicit that CBAM will affect arbitrage options, the amount and pattern of commercial exchanges, and the profitability of generation assets across the region and in neighbouring EU member states.  

The scale is not marginal. Based on 2024 trade and system data, the Energy Community’s CBAM Readiness Tracker estimates that the annual CBAM exposure of EU electricity importers buying from the region could reach about €1.17bn. The country breakdown is especially revealing: Serbia €612.5m, North Macedonia about €200m, Montenegro about €190m, Bosnia and Herzegovina about €158m, Moldova about €6m, while Albania is assessed at zero CBAM-related cost because its electricity mix is overwhelmingly renewable. The estimated average CBAM cost per megawatt-hour is around €66.71/MWh for Serbia, €73.37/MWh for Bosnia and Herzegovina, €62.45/MWh for Montenegro, €59.71/MWh for North Macedonia and €33.14/MWh for Moldova.  

Those numbers matter because they are large enough to wipe out a substantial part of the historical export margin from coal-heavy systems in normal market conditions. In a year when regional day-ahead prices are around €80–120/MWh, an added carbon border cost of €60–70/MWh is not a surcharge at the edges; it is a structural repricing of the product. It effectively turns part of the region’s legacy baseload export stack into a marginal or uneconomic flow for EU buyers unless the hour is extremely tight, the underlying supply is unusually cheap, or the exporter can demonstrate materially lower embedded emissions. This cost logic follows directly from the Commission’s certificate-pricing methodology and the Energy Community’s estimated per-MWh exposure.  

This is why the trade pattern is likely to change before the physical generation mix changes. The first market response is not the disappearance of all flows from the Western Balkans into the EU. It is segmentation. Coal-linked baseload becomes harder to place. Low-carbon hours become more valuable. Hydro-rich, renewable-rich and mixed portfolios with lower emission intensity gain relative competitiveness. That is also why Albania is in a radically different position from coal-dependent exporters: under the tracker’s assessment, its exports are not carrying the same CBAM burden.  

For traders, the practical consequence is a shift from simple regional arbitrage to carbon-adjusted arbitrage. The old model—buying on the Western Balkans side and selling into the EU when nominal spreads opened—now needs a carbon overlay embedded in every position. Import desks need emissions data, registry compliance, contractual protections and a view on whether the origin mix is actually bankable under CBAM. The European Commission’s implementation architecture is already live, with customs validation and authorisation checks integrated into border procedures, which means this is no longer a theoretical 2026 issue but an operational one.  

That operational shift is also changing which trades are worth doing. Shorter-duration, hour-selective and flexibility-driven trades become more attractive than broad baseload structures when the carbon cost can swing effective import economics so sharply. The early regional market commentary from ADEX points in the same direction: more intraday activity, more algorithmic trading and a growing role for renewables in the intraday segment, while CBAM’s first local impacts are being seen in weaker liquidity on some power exchanges, a wider gap versus EU exchange prices and greater caution toward new green investments.  

The regional exchange architecture is reinforcing that shift. ADEX says its overall traded volume rose from 49 TWh in 2023 to 66 TWh in 2025, with much of the growth driven by intraday rather than day-ahead activity. SEEPEX, meanwhile, is introducing negative prices from May 2026, cutting the day-ahead floor to -€500/MWh and the intraday floor to -€9,999/MWh. That is important because it pushes the Western Balkans further into the same market logic now visible across the EU: once solar and weather volatility deepen, the value migrates away from undifferentiated megawatt-hours and toward timing, balancing, storage, hydro flexibility and trading sophistication.  

The result is that CBAM and market modernisation are landing at the same moment. On one side, carbon-heavy exports into the EU are being repriced upward. On the other, local exchanges are becoming more granular and more volatile, with intraday and negative-price capability increasing the premium on fast optimisation. That combination changes trader behaviour. Portfolios are likely to become more defensive on forward exports into the EU, more selective by hour, more reliant on intraday re-optimisation and more focused on origin-screened low-carbon volumes. This is partly a direct reading of the policy and market changes, and partly an inference from the way carbon cost and short-term price optionality interact.  

There is another effect that matters for the region’s internal price formation. If EU off-take becomes harder for carbon-heavy generators, some electricity that would previously have cleared westward may remain inside the Western Balkans more often. In the short run, that can soften local prices in some hours and pressure domestic generators’ realised margins, especially if hydrology is good and renewable output rises. But this does not automatically mean cheaper systems overall. It can also mean sharper volatility: lower prices in oversupplied hours, higher prices when flexibility is scarce, and a bigger premium on reserve, balancing and hydro assets. The Energy Community itself warns that CBAM will affect commercial exchange patterns and neighbouring EU markets, not just exporting countries.  

The timing on exemptions is crucial. The Energy Community says no contracting party currently qualifies for a CBAM exemption for electricity, even though Serbia, Moldova, North Macedonia and Montenegro are approaching a “point of no return” on the regulatory path toward EU market coupling. The mechanism does contain a route to a time-limited exemption for electricity, but it is conditional on market coupling, adoption of key EU electricity, renewables, environment and competition rules, a climate-neutrality roadmap, and meaningful progress on carbon pricing. Market coupling with the EU is now widely discussed as a 2028 to early-2029 event rather than something imminent in 2026 or 2027.  

That timing means the market has to assume at least a multi-year period in which CBAM remains a real cross-border cost for Western Balkan electricity exports into the EU. This is especially significant for investment decisions. If developers cannot be confident that low-carbon generation will obtain either a credible exemption path or tradable value recognition in cross-border markets before 2028–2029, some projects may face slower final investment decisions even though, paradoxically, the long-run answer to CBAM is more renewables and more market integration. ADEX has already flagged increased caution toward new green investments as one of the first visible market effects.  

There is also a methodological and system-operations issue that should not be ignored. ENTSO-E supports CBAM’s objective but has warned that the current framework still creates legal and methodological uncertainty for electricity, including how to compute embedded CO2 intensity and how to avoid imposing disproportionate burdens on TSOs for regulated system-stability actions such as reserve sharing, redispatch and countertrading. That matters for traders because uncertainty around what exactly is in scope tends to widen risk premia and reduce willingness to hold long-duration positions.  

The most likely market trend through 2026–2027 is therefore not a collapse of all EU imports from the Western Balkans, but a strong reshaping of the flow profile. Carbon-heavy baseload exports should lose share. Weather-driven hydro and lower-carbon hours should retain access. Intraday trading should continue to grow faster than day-ahead as portfolios try to optimise around emissions-adjusted economics and renewable volatility. Exchange liquidity in some local markets may remain under pressure until participants get more comfortable with the new carbon cost architecture, but the more sophisticated hubs and the most connected exchanges should gain relative importance.  

By 2028–2030, the market splits into two plausible paths. In the first, coupling progresses, domestic carbon-pricing frameworks deepen and renewable capacity continues to expand; in that case, a growing share of Western Balkan electricity can re-enter EU trade on a more competitive carbon basis, and cross-border trade shifts from coal arbitrage to flexibility, hydro, storage and renewable balancing value. In the second, market coupling slips, carbon pricing stays partial and coal-heavy systems remain dominant; in that case, EU imports from the region increasingly become occasional scarcity trades rather than a stable export channel, and the region’s price convergence with the EU slows materially. The Energy Community’s own tracker shows the reform vector moving in the right direction, but the calendar now matters almost as much as the direction.  

The bigger conclusion is that CBAM has turned electricity from the Western Balkans into a screened product rather than a generic product. The EU will still import from the region, but not on the same basis as before. The relevant variables are no longer just border prices, transmission capacity and hydrology. They now include embedded emissions, certificate cost, proof of carbon paid, compliance readiness and the likelihood of eventual market coupling. That is why trader behaviour is changing first, even before generation fleets fully change. And that is why the next two years will be less about raw export volume and more about which parts of the Western Balkans’ power stack remain commercially credible once carbon is fully priced at the border.  

Elevated by cbam.engineer

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A recent meeting between senior representatives of both companies centered on the planned Kruševo hydropower project, which is emerging as the cornerstone of their collaboration. The discussions aimed to establish a clearer framework for cooperation and outline a concrete roadmap for the next phase of project development.

According to EPCG, the talks addressed a wide range of key issues needed to move the project forward. These included the regulatory environment, potential support mechanisms, preparation of technical and feasibility studies, further project development steps, and the basis for a future joint development agreement. Alongside HPP Krusevo, the two sides also explored additional opportunities in battery energy storage systems and renewable energy projects, aligning with EPCG’s broader investment strategy.

Both companies emphasized the importance of close coordination with public authorities and international financial institutions, noting that future progress will depend not only on corporate alignment but also on regulatory support and access to financing.

The meeting concluded with a mutual commitment to further develop the partnership model and accelerate practical steps toward implementation, as EPCG and EDF aim to build cooperation around several strategic energy initiatives in Montenegro.

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Among neighboring markets, Bulgaria recorded an average price of 106.9 euros/MWh, while Italy was the most expensive, at 115.03 euros/MWh. Greece saw a 2.7% annual increase, compared to a stronger rise of 4.24% in Bulgaria and 6% in Italy.

Price developments throughout the year were uneven. February stood out as the most expensive month, with average prices reaching 154 euros/MWh, while August was the cheapest at 73 euros/MWh. The lowest hourly price of the year was recorded on 1 May, when prices dropped to -50 euros/MWh.

On the trading side, electricity demand in the day-ahead market remained broadly stable compared to the previous year. At the same time, volumes linked to renewable energy sources increased by 8%, highlighting the growing role of clean generation in Greece’s energy mix.

Cross-border electricity flows also shifted significantly. Imports fell by 2,833 GWh (a decline of 36.8%), while exports rose slightly by 106 MWh. As a result, Greece closed the year with net electricity exports of 2,732 GWh. The highest daily trading volume in the day-ahead market was recorded on 25 July, when total activity reached 254 GWh.

In terms of market structure, PPC remained the dominant supplier, accounting for 50.08% of total supply.

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A new provision introduced by the Ministry of Environment and Energy, as part of draft legislation implementing the EU’s RED III directive, will allow wind and seabed surveys to begin immediately. The measure aims to accelerate early-stage development and avoid further delays in the country’s offshore wind expansion.

To support this process, the Hellenic Hydrocarbons and Energy Resources Management Company (EDEYEP) is expected to establish a special purpose vehicle in the second quarter of 2026. This entity will oversee the surveys, which are planned to be completed by June, in line with targets linked to the EU Recovery and Resilience Facility. Once the surveys are completed, EDEYEP will identify the most suitable offshore zones and publish them in the Official Gazette. These areas will form the basis for the first wave of offshore wind projects, expected to total around 1.9 GW.

In practice, this approach effectively restarts concession preparations even though the national offshore program has not yet been formally adopted. The broader regulatory framework has remained stalled for over a year, as the required joint ministerial decision has not been issued, leaving official development zones undefined.

The government appears to be using this delay strategically, advancing technical preparations so that projects can move forward once market conditions improve and costs decline. Authorities note that survey and permitting processes alone can take up to two years, making early groundwork essential.

The draft legislation also introduces changes for the Alexandroupoli offshore area, where 600 MW of pilot wind projects are planned. This zone will no longer be part of the fast-track renewable framework, requiring developers to complete full environmental impact assessments for the entire site. The pilot projects are being developed by PPC, TERNA Energy, and Motor Oil.

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The procurement includes supervision and owner’s engineering support for a solar project valued at approximately 39 million euros, according to tender details published with support from the European Bank for Reconstruction and Development (EBRD). Interested companies have until 18 May to submit their bids.

The planned project consists of two adjacent solar power plants with a combined capacity of 50 MW, to be built in the village of Gracanica within the municipality of Bugojno. The site was previously used for coal mining but has since been rehabilitated, marking a notable step in land repurposing for clean energy.

Financing for the project has already been secured. In August 2024, the EBRD approved a 25 million euros loan, while UniCredit Bank contributed an additional 15 million euros through a parallel financing arrangement.

This Gracanica project is expected to be one of the first utility-scale solar developments undertaken by EPBiH, as the company gradually shifts its investment focus toward renewable energy in line with its broader decarbonization strategy.

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The company has asked the Federal Ministry of Energy, Mining and Industry to approve a 4.59% price adjustment, which would set the wholesale price at 442.48 euros per 1,000 cubic meters. Energoinvest stated that the proposed change is limited in scope and is intended to reflect higher procurement costs without fully transferring the burden to the domestic market.

According to the company, the adjustment follows rising purchase prices from suppliers, driven by broader movements in international gas and oil markets. However, Bosnia and Herzegovina remains less exposed than many other countries, as its pricing model is based on long-term contracts and an oil-indexed formula rather than direct exposure to spot market volatility.

Energoinvest also emphasized that it maintained January pricing through March to protect both households and businesses from sudden cost increases. This decision, the company said, helped soften the impact of rapid price changes seen elsewhere in Europe.

Management maintains that the newly proposed increase will have only a limited impact on end-users. For households, the effect is expected to be minimal, particularly as gas demand typically declines during the warmer months. Industrial consumers are still expected to benefit from relatively competitive pricing compared to much of Europe.

The company added that it will continue to actively manage procurement and pricing in order to preserve market stability and ensure reliable supply amid ongoing uncertainty in global energy markets.

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What stands out immediately is the degree of convergence inside the SEE region. The price differentials versus Hungary were narrow almost everywhere: Romania was €3.35/MWh below HUPX, Bulgaria €6.71/MWh below, Greece €5.97/MWh below, Slovenia €1.37/MWh below, Croatia €0.97/MWh below, and Serbia €0.87/MWh below. That kind of clustering suggests a region trading as one interconnected block rather than a series of fragmented national markets. For traders, this reduces the value of simple neighboring day-ahead arbitrage and shifts attention toward the external edges of the system, especially the Italian premium and the core-European import corridor. The page 2 charts reinforce that reading: Central Eastern and Eastern spot markets tracked each other closely, while Italy preserved a distinct premium curve.  

The core physical explanation for the rebound was straightforward. Regional forecast consumption rose to 29,759 MW, up 1,015 MW day on day, while average temperature fell to 10°C, down 2.5°C. At the same time, total net imports into the SEE+Hungary system dropped to 1,002 MW, a fall of 1,545 MW, while core inflows from Austria and Slovakia eased to 2,627 MW, down 559 MW. This meant the region had to rely more heavily on its own generation fleet. Total generation rose to 26,197 MW, up 776 MW, with hydro at 6,859 MW, coal at 4,843 MW, gas at 2,502 MW, solar at 3,927 MW, and nuclear at 5,807 MW. The weak point in the stack was wind, which fell to 1,892 MW, down 299 MW. In trading terms, the market lost part of its low-marginal-cost cushion just as load recovered and import support weakened, which was enough to reprice the whole complex higher.  

This does not yet look like a scarcity market. It looks like a shoulder-season market in which small changes in renewable output and cross-border flows can swing prices sharply from one day to the next. That distinction matters. A structurally tight market would be driven by persistent fuel scarcity, major outage stress, or deeply constrained interconnection. What the April 7 data show instead is a system still capable of balancing itself, but doing so at meaningfully higher prices when wind softens and imports retreat. The power balance chart on page 3 and the import charts on page 2 show this clearly: imports remained positive, but at a much lower level than the previous session, while internal generation had to step up.  

The hourly pattern is even more important than the daily average. On page 15, the Hungarian profile still shows a minimum hourly price of -€12.5/MWh on April 7, even though the daily baseload average recovered to €91.3/MWh and the intraday maximum reached €181.1/MWh. Slovenia and Romania show similar swing patterns in the hourly charts. That means the SEE market remains fundamentally split between weak solar-heavy hours and expensive evening ramp hours. This is no longer a market where a trader’s main question is whether prices are high or low. The real question is where the value sits inside the day. Flexible hydro, batteries, peakers and portfolios with strong intraday execution should outperform flat baseload strategies in this regime.  

For the regional system, Italy remains the most important structural anchor. At €127.92/MWh, the Italian day-ahead market held a premium of €36.64/MWh over Hungary and an even wider premium over Bulgaria, Greece and Albania. That keeps the economics of southbound exports attractive and supports the value of transmission capacity from the SEE region toward Italy. In practical terms, even when internal SEE spreads compress, the external pull from Italy still helps set the regional floor. This is one reason why the SEE complex can reprice upward quickly even without a domestic supply shock: the system is not trading only on local load and renewable balances, but also on the continued strength of adjacent premium markets.  

Forward indicators also point to an expensive but not panicked market. Hungarian benchmark forwards were quoted at €99.50/MWh for Week 15, €114.50/MWh for Week 16, €97.50/MWh for May-26, and €113.50/MWh for Cal-26. Gas at CEGH stood at €52.06/MWh, Greek gas at €51.5/MWh, and EUA carbon at €71.06/t, while coal forwards were $119/t for May-26 and $124.5/t for Q3-26. That cost stack is still high enough to keep thermal price support in place, particularly in evening and low-renewables hours, but it does not yet imply a crisis regime. Instead, it suggests the region will continue to trade in a wide but manageable range, with weather sensitivity and renewable intermittency doing most of the day-to-day work.  

The commercial flow table on page 7 gives added context for how integrated the SEE system has become. Flows across the Balkan corridor remain active in both base and peak structure, confirming that the region behaves less like isolated national pools and more like a transit-and-balancing platform linking Central Europe, the Balkans, Greece and Italy. That has strategic implications. Markets such as Serbia, Croatia, Slovenia, Bulgaria and Romania still matter operationally, but their price formation increasingly reflects regional balancing and transmission conditions rather than purely domestic fundamentals. As a result, the best opportunities are shifting away from simple country-by-country directional bets and toward corridor trading, balancing exposure, and flexibility monetization.  

For the next few sessions, the central variable will be whether wind recovers and whether the import corridor from Austria and Slovakia re-expands. If both improve, the SEE region can soften back toward the €75–85/MWh area fairly quickly, especially in off-peak periods. If wind stays weak and the region remains more reliant on internal thermal and hydro balancing, then the current €85–95/MWh cluster looks sustainable. Either way, the April 7 session makes one point very clearly: SEE is not a one-directional high-price market, but a highly tradable volatility market in which hourly profile, interconnector access and flexibility matter more than outright baseload conviction.  

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Italy recorded weekly traded volumes of approximately 21,940 GWh, far exceeding those of SEE markets. By comparison, Serbia’s SEEPEX exchange recorded volumes of around 100 GWh, highlighting the substantial disparity in market depth.

This imbalance has important implications for pricing and volatility. Highly liquid markets such as Italy benefit from greater transparency and more efficient price discovery, while smaller markets are more susceptible to price swings due to limited trading activity.

The dominance of Italy also reflects its structural position as the largest importing market in the region. High demand and limited domestic generation capacity make Italy a key driver of cross-border flows, influencing prices across interconnected markets.

For SEE countries, the liquidity gap presents both challenges and opportunities. On one hand, limited market depth can increase volatility and reduce efficiency. On the other hand, it creates opportunities for traders able to navigate less liquid environments.

Efforts to enhance market integration and increase liquidity are ongoing, including the development of regional coupling mechanisms and improvements in cross-border capacity allocation.

However, progress remains uneven, and structural differences between markets continue to limit full integration.

From a trading perspective, the liquidity gap underscores the importance of understanding market-specific dynamics. Strategies that work in highly liquid markets may not be directly applicable in SEE, where local conditions play a more significant role.

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Greece recorded LNG inflows of 663.84 GWh, representing a 31% week-on-week decline, while Italy saw imports fall by 11.4% to 3,799.35 GWh. Croatia also experienced a decrease of 6%, with inflows reaching 537.33 GWh.

The decline in LNG arrivals reflects a combination of factors, including global supply constraints, shifting cargo destinations, and operational considerations at import terminals.

From a market perspective, the reduction in LNG inflows is particularly significant given the current state of European gas storage. While inventories are not critically low, they remain below historical averages in several key markets, increasing the importance of steady inflows during the injection season.

The timing of the decline is also notable. As the market transitions from winter demand to summer storage refill, the availability of LNG becomes a critical determinant of price stability. Any disruption to inflows during this period can lead to increased competition for available cargoes and upward pressure on prices.

For SEE markets, which rely on LNG imports either directly or indirectly through interconnected systems, the decline in inflows adds another layer of uncertainty. Reduced availability can translate into higher gas prices, which in turn feed through into electricity markets.

Traders are closely monitoring LNG flows as a key indicator of market balance. While short-term fluctuations are not uncommon, sustained declines could signal tightening conditions and increased volatility.

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In 2025, Norway emerged as the largest supplier of gas to the European Union, accounting for nearly one-third of total imports. The United States followed as a major contributor, reflecting the rapid expansion of LNG export capacity.

Russia’s share of European gas supply has declined sharply, falling from approximately 40% in 2021 to around 13% in 2025 when combining pipeline gas and LNG. This shift represents one of the most significant structural changes in the European energy landscape.

The transition away from Russian pipeline gas has increased Europe’s reliance on LNG imports, which are inherently more flexible but also more volatile. Unlike pipeline gas, which is typically delivered under long-term contracts, LNG is traded on a global market, with prices influenced by supply-demand dynamics across multiple regions.

This shift has introduced new complexities into the European gas market. Prices are now more sensitive to global events, including weather patterns, shipping constraints, and geopolitical developments.

For SEE markets, the implications are particularly significant. As gas remains the marginal fuel for electricity generation in many countries, changes in gas pricing directly impact power markets.

The increased reliance on LNG also raises questions about supply security. While diversification has reduced dependence on a single supplier, it has also introduced new risks related to global competition and logistical constraints.

Looking ahead, the role of LNG is expected to grow further, particularly as new export capacity comes online in the United States and other regions. However, this expansion will need to keep pace with rising global demand to prevent further price volatility.

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One of the most significant developments was the impact of a tropical cyclone off the coast of Western Australia, which disrupted operations at the Gorgon and Wheatstone LNG facilities. These plants collectively account for more than 5% of global LNG supply, making any reduction in output a matter of concern for global markets.

Although both facilities continued to operate at reduced capacity, the incident underscored the vulnerability of LNG supply chains to extreme weather events. In a market already operating with limited spare capacity, even temporary disruptions can have outsized effects on pricing and availability.

At the same time, geopolitical risks in the Middle East continued to dominate market sentiment. The ongoing tensions involving Iran, combined with threats to shipping routes in the Strait of Hormuz, raised the possibility of significant supply disruptions.

Analysts have warned that a prolonged disruption to LNG exports from Qatar—one of the world’s largest suppliers—could have severe consequences for global markets. A three-month halt in Qatari exports could remove up to 21 million tonnes (Mt) of LNG from the market, potentially driving European gas prices toward €155/MWh.

Such a scenario would have far-reaching implications, not only for gas markets but also for electricity prices, particularly in regions such as SEE where gas remains a key marginal fuel.

The interaction between global LNG markets and regional energy systems has become increasingly direct. Europe’s reliance on LNG imports has grown significantly in recent years, making it more exposed to global supply dynamics and competition from other regions, particularly Asia.

This shift has transformed LNG from a balancing mechanism into a primary price driver. Events occurring thousands of kilometers away—whether weather-related or geopolitical—now have immediate implications for European energy markets.

For traders, the re-emergence of LNG as a central risk factor reinforces the importance of monitoring global supply chains. Price movements are no longer determined solely by regional fundamentals but are increasingly shaped by global developments.

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The Dutch TTF front-month contract averaged €54.59/MWh, marking a 1.9% week-on-week decrease, with prices moving within a relatively wide intra-week range. The week opened at elevated levels of €56.68/MWh, before falling sharply to a low of €52.81/MWh mid-week. A brief rebound followed, with prices rising by 4.5% on 26 March, before easing again toward the end of the week.

The trajectory of TTF prices during CW13 reflects a market struggling to reconcile short-term supply signals with broader geopolitical risks. Early-week declines were driven by expectations of easing tensions in the Middle East, as diplomatic signals suggested the potential for de-escalation between the United States and Iran.

However, this sentiment proved fragile. Market participants remained acutely aware of the potential for renewed escalation, particularly given ongoing threats to critical energy infrastructure and shipping routes. The Strait of Hormuz, through which a significant share of global LNG flows transit, remains a focal point for risk assessment.

At the same time, supply-side developments introduced additional uncertainty. Reports of outages at major LNG export facilities in Australia, triggered by extreme weather conditions, raised concerns about short-term availability. Although the disruptions were not expected to have an immediate large-scale impact on European supply, they reinforced the perception of a tight and vulnerable global LNG market.

From a structural perspective, the gas market continues to operate under a “risk premium regime.” Even in the absence of immediate supply disruptions, prices remain supported by the possibility of future shocks. This dynamic is particularly evident in forward curves, which have shown limited downside despite recent spot market softness.

Storage levels also remain a critical factor. While European gas inventories are not at critically low levels, they are below the five-year average in key markets such as Germany and the Netherlands. This creates an additional layer of support for prices, particularly as the market begins to focus on the upcoming injection season.

The interplay between gas and power markets remains strong. The modest decline in TTF prices during CW13 contributed to lower electricity prices across SEE, but the effect was limited by the persistence of the geopolitical premium.

Looking ahead, traders expect volatility to remain elevated. The gas market is increasingly sensitive to both geopolitical developments and global LNG dynamics, with price movements likely to remain reactive rather than trend-driven.

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Total net imports rose by 27.91%, with several markets increasing their reliance on external supply. Hungary recorded a 40.86% increase in net imports, while Croatia rose by 33.66%, indicating tighter domestic supply conditions.

Italy remained the largest importing market by a considerable margin, reinforcing its structural deficit and central role in regional price formation. Despite increased renewable output, Italy continues to rely heavily on imports to meet demand.

On the export side, several markets reduced their net export positions. Greece saw exports decline by 25.05%, Romania by 67.27%, and Bulgaria by 34.47%, reflecting tighter domestic balances and increased internal demand.

Türkiye also reduced its export position by 18.51%, as rising domestic consumption limited available surplus.

Serbia stood out with a significant reduction in net imports of 76.93%, moving closer to a balanced position. This shift reflects improved domestic generation, particularly from renewable and hydro sources.

The increase in cross-border flows highlights the importance of interconnections in balancing the SEE system. However, congestion on key transmission corridors continues to limit the efficiency of these flows, contributing to price divergence between markets.

From a trading perspective, the intensification of cross-border flows creates opportunities for arbitrage, but also introduces additional complexity related to transmission constraints and capacity allocation.

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Total thermal generation fell by 7.24%, with gas-fired output dropping by 12.78%. This reflects the displacement of marginal gas units during periods of improved renewable availability and lower demand in certain markets.

Italy recorded the largest decline, with thermal output falling by 24.75%, driven by a reduction in gas-fired generation of over 26%. Hungary also saw a substantial decrease of 24.58%, while Serbia recorded a sharp contraction of 48.71%, primarily due to reduced lignite generation.

The decline in gas-fired output is particularly notable, given the role of gas as the marginal price-setting fuel in most SEE markets. When renewable and hydro generation increase, gas plants are pushed out of the merit order, leading to lower overall generation levels.

However, coal and lignite generation remained broadly stable, declining by only 0.66%. This suggests that these sources continue to provide a base level of supply, particularly in markets with significant domestic coal resources.

In some markets, thermal generation moved in the opposite direction. Bulgaria and Türkiye both recorded increases, with Türkiye showing strong growth in both coal and gas output, aligned with its surge in electricity demand.

The data underscores the transitional nature of SEE power systems. While renewable generation is increasingly displacing gas during certain periods, thermal generation—particularly coal—remains a critical component of the supply mix.

From a pricing perspective, the reduction in gas-fired output contributed to the modest price declines observed during the week. However, as gas remains the marginal fuel during peak periods, its influence on price formation remains dominant.

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Türkiye was the primary driver of the increase, with output rising by 28.24% (+607.7 GWh). This surge suggests improved reservoir inflows or enhanced dispatch from hydro facilities, contributing significantly to the regional supply balance.

Croatia and Serbia also recorded strong increases, with hydropower generation rising by 244.26% and 153.98%, respectively. While these gains were from relatively low baselines, they nonetheless provided meaningful support to local systems, reducing reliance on thermal generation.

In contrast, several core markets experienced declines. Greece saw hydropower output fall by 38.67%, while Bulgaria declined by 23.48%. Italy and Romania also recorded smaller reductions.

The divergence reflects localized hydrological conditions, including rainfall patterns and reservoir management strategies. Unlike wind and solar, which are influenced by broader weather systems, hydro output can vary significantly between neighbouring countries depending on river basins and storage levels.

From a market perspective, the increase in hydropower provided temporary relief to system tightness, particularly in markets where hydro plays a balancing role. By displacing higher-cost generation, hydro contributed to the modest price declines observed during the week.

However, the variability of hydro output limits its reliability as a long-term stabilizing factor. Traders noted that while hydro can provide short-term flexibility, its contribution is highly dependent on seasonal and climatic conditions.

As the region moves into the spring and early summer period, hydro output is expected to remain an important variable, particularly in the Western Balkans. However, the extent of its impact will depend on rainfall patterns and reservoir management decisions.

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Total renewable generation rose by 12.2% to 3,914.7 GWh, with solar providing the dominant contribution. Solar output surged by 27.7%, reflecting longer daylight hours and improving seasonal conditions. This increase had a noticeable impact on daytime pricing, particularly in markets with higher solar penetration.

Wind generation, by contrast, rose only 4.1%, underscoring the continued variability of wind resources across the region. In several markets, weaker wind conditions limited the overall impact of renewable growth on system balance.

Italy recorded the most dramatic increase, with total renewable output rising by 205.1%, driven by strong performance in both wind and solar. This surge played a key role in reducing Italy’s reliance on thermal generation during the week, although the country remained structurally import-dependent.

Hungary and Serbia also recorded substantial increases, albeit from lower baselines. Hungary’s renewable output expanded sharply due to a spike in solar generation, while Serbia saw a doubling of renewable production, primarily from wind.

However, the regional picture remains highly uneven. Romania and Türkiye both experienced declines in renewable output, largely due to weaker wind conditions. Greece also saw a net reduction in renewable generation, as a significant drop in wind output outweighed gains in solar.

The data highlights a critical challenge for SEE markets: while renewable capacity is expanding, its contribution to system stability remains inconsistent. Solar generation provides predictable daytime output, but wind variability continues to introduce uncertainty into supply balances.

This dynamic has important implications for price formation. During periods of strong solar output, daytime prices can soften, but the absence of consistent wind generation limits the duration and extent of these effects. As a result, evening peak prices remain elevated, particularly when gas-fired generation sets the marginal price.

The growing role of solar also underscores the increasing importance of flexibility assets, including battery storage and demand response mechanisms. As solar penetration rises, intraday price spreads are expected to widen, creating opportunities for arbitrage but also increasing system complexity.

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Türkiye recorded a 13.91% surge (+816 GWh), accounting for the vast majority of incremental demand across the SEE system. This scale of increase effectively rebalanced the regional load profile, reinforcing Türkiye’s position as the single most influential demand center in South-East Europe.

The drivers behind Türkiye’s surge appear to be a combination of weather normalization, industrial activity, and potentially increased cooling demand as temperatures began to shift. Given the size of its system relative to neighbouring markets, movements in Turkish demand tend to have outsized implications for regional flows and price formation.

Outside Türkiye, demand dynamics were more subdued and fragmented. Hungary posted a moderate increase of 2.64%, while Croatia rose by 4.94%, reflecting localized weather-driven consumption. Bulgaria recorded a smaller increase of 1.05%, suggesting relatively stable conditions.

In contrast, several markets saw declining demand. Greece fell by 3.28%, while Serbia declined by 1.30%, and Italy edged lower by 0.43%. These movements point to softer industrial load and milder weather conditions in parts of the region.

The divergence highlights a structural feature of SEE demand: the absence of synchronized consumption patterns. Unlike more integrated Western European systems, demand across SEE remains heavily influenced by local conditions, including weather, industrial cycles, and national economic activity.

From a market perspective, Türkiye’s demand surge had immediate implications for cross-border flows. Increased domestic consumption reduced export availability, tightening supply in interconnected markets and contributing to localized price pressure.

The demand rebound also coincided with the broader volatility observed in early April pricing. As consumption increased in key markets, system margins tightened, reinforcing upward price movements.

Looking ahead, traders are closely monitoring demand elasticity as the region transitions toward warmer months. Cooling demand, particularly in Türkiye and Southern Europe, is expected to become a more significant driver of load patterns, potentially amplifying volatility during periods of reduced renewable output.

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The government adopted the national spatial plan for the Družmirje floating solar power plant, enabling one of the country’s most ambitious renewable energy projects to move forward. With an estimated capacity of 140 MW, the installation is expected to become one of the largest floating solar facilities in the wider region.

The approved planning document defines the technical, environmental, safety, utility, and urban design requirements necessary for project implementation. The solar plant will be installed directly on the surface of the lake and will include all associated infrastructure required for its operation.

In addition to electricity generation, the project is expected to incorporate energy storage systems and grid connection equipment, enhancing reliability and ensuring more stable power output. The initiative aims to expand Slovenia’s renewable energy capacity while efficiently utilizing an existing water surface.

The adopted spatial plan also includes supporting documentation gathered during the public consultation process, including responses to comments and proposals from municipalities and the public. These inputs were reviewed alongside the project’s variant study, environmental assessment, and draft planning proposal, ensuring that the final framework reflects both technical analysis and community feedback.

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Under a new decree, authorities decided to temporarily reduce the excise duty on standard diesel, while simultaneously introducing a special charge on exceptional earnings generated by oil producers and retailers. The move is part of a broader response to rising energy costs linked to geopolitical tensions in the Middle East.

The government specifically targeted diesel for tax relief due to its dominant role in domestic consumption and its strong influence on inflation. From 7 April, the excise duty will be lowered by approximately 0.06 euros per liter (or 0.072 euros including VAT). This adjustment will bring the tax level to around 500 euros per 1,000 liters and is expected to cost the state budget about 118 million euros.

To offset this fiscal impact, the decree introduces a solidarity levy on companies involved in crude oil extraction and sales. The contribution applies only to extraordinary profits generated under current market conditions and may reach up to 60% of additional earnings. Depending on oil price movements, the measure is projected to generate between 14 and 130 million euros in public revenue.

This latest intervention builds on earlier measures introduced at the end of March, when the government declared a temporary crisis in the oil and petroleum products market for the period from April through June. At that time, authorities also imposed caps on commercial margins across the fuel supply chain, limiting mark-ups to average levels recorded in 2025.

Despite these measures, fuel prices remain elevated. 95-octane petrol currently averages around 1.68 euros per liter, while diesel stands at approximately 2.025 euros per liter, highlighting continued pressure on both households and businesses.

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Total electricity production reached 3,373 GWh, while gross consumption amounted to 3,410.71 GWh, exceeding projections by more than 5%. At the same time, overall generation came in 17.42% below planned levels, highlighting a notable supply gap throughout most of the year.

A major factor behind the shortfall was the environmental upgrade of the Pljevlja thermal power plant, which remained offline for eight months. Due to this extended shutdown, thermal generation was limited to 525.32 GWh, with the plant achieving 89.34% of its reduced production target.

Renewable sources made up the bulk of electricity production, contributing 1,847 GWh, though performance varied across technologies. Large hydropower plants underperformed due to unfavorable water conditions, with HPP Perućica reaching 75.21% of its plan and HPP Piva achieving 73.81%. In contrast, small hydropower plants exceeded expectations, delivering 106.32% of planned output. Wind farms produced 91.44%, while solar generation outperformed forecasts, reaching 112.52% of planned levels.

Hydrological conditions throughout the year were below the long-term average, significantly reducing hydroelectric output. Compared to previous years, hydropower generation declined by 17.5% from 2024 and 34.1% from 2023, when water availability was particularly strong.

The overall generation structure was heavily influenced by the prolonged outage of Pljevlja, with hydropower accounting for around 60% of total production, thermal for 22%, wind for 13%, and solar increasing its share to 4%.

Domestic production was sufficient to meet consumption only during the first quarter, when both hydrological conditions and thermal generation were favorable. For the remainder of the year—especially between May and October—the system faced a persistent seasonal deficit.

System losses also exceeded expectations, totaling 460.06 GWh, which is about 2.7% above planned levels, though still 2.45% lower than in 2024. Transmission losses amounted to 131.47 GWh, performing better than expected and below the previous year’s level. However, distribution losses rose to 328.60 GWh, nearly 10% above plan, remaining broadly in line with 2024 figures.

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The project is designed to directly connect the transmission networks of the two countries, a step expected to significantly strengthen energy supply security and improve regional electricity trading across the Balkans.

On the North Macedonian side, the project includes the construction of a 97.5-kilometer transmission line, a new transformer substation near Ohrid, and an additional transmission bay in Bitola. Authorities have set a completion timeline of 30 months, aiming to accelerate integration with neighboring energy systems.

Financing for the project has been supported by the European Bank for Reconstruction and Development (EBRD), which approved a €37 million loan and helped secure an additional €12 million grant through the Western Balkans Investment Framework (WBIF). The total investment value, however, has not been publicly disclosed.

The project initially entered the construction phase in early 2022, but implementation was later disrupted. In late 2024, MEPSO terminated its contract with Energo-invest, citing non-performance and additional payment requests. Following this, a new contractor tender was launched in April 2025 to move the project forward.

At the same time, Albania began construction of its section of the interconnection at the end of 2023. The restart of works on the North Macedonian side now represents a key step toward completing the cross-border link, which is expected to enhance regional grid stability and support deeper market integration.

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According to data from London’s ICE exchange, the average price of front-month futures linked to the Dutch TTF benchmark reached 631.9 dollars per 1,000 cubic meters, marking the first time since early 2023 that the monthly average exceeded the 600-dollar threshold. The last time prices were higher on a monthly basis was in January 2023, when the average stood at 711.6 dollars per 1,000 cubic meters.

The upward trend began on 2 March, immediately after reports of US and Israeli strikes on Iran. In the days that followed, gas prices surged by 38.2%, quickly approaching 540 dollars per 1,000 cubic meters. Throughout the month, the market remained under sustained pressure as traders priced in risks linked to both regional instability and potential supply chain disruptions.

A key driver of volatility was the uncertainty surrounding critical infrastructure, including the Strait of Hormuz, as well as disruptions affecting gas facilities across the Middle East. These developments kept prices elevated, with markets consistently trading well above levels seen over the previous two years.

The most significant spike occurred on 19 March, when prices briefly reached 853.7 dollars per 1,000 cubic meters. This jump followed a report from QatarEnergy indicating damage to two of its 14 LNG production units. The event highlighted how sensitive global gas markets remain to even localized disruptions in supply.

Despite the sharp increases, current price levels remain well below the extreme highs recorded during Europe’s energy crisis in 2021 and 2022. The all-time peak was reached in early 2022, when gas prices soared to 3,892 dollars per 1,000 cubic meters, the highest level ever observed in European gas markets.

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