The minister held discussions with coordinators of subgroups within an interministerial expert working group tasked with assessing whether Serbia should pursue nuclear energy development. The talks focused on preparing the necessary feasibility studies for the first phase of the program.

She noted that Serbia completed a preliminary technical study on the peaceful use of nuclear energy last year and has now entered the initial phase of a broader process. Most project tasks for this stage have already been defined, with the current priority being the swift launch of procurement procedures for the required studies.

These studies are expected to be conducted by both domestic and international experts and institutions, covering key areas that must be addressed before a final strategic decision can be made. These include technical, economic, environmental, and regulatory aspects of nuclear development.

Minister Đedović also said that the French Development Agency has expressed interest in financing part of the analytical work required at this stage. This support would cover areas such as workforce development, site selection, the role of domestic industry, and public communication, and would be carried out in cooperation with French energy company Électricité de France (EDF).

The government aims to complete all necessary studies by the middle of next year. If this timeline is met, Serbia could be ready by 2032 to select a technology and begin the contracting phase for a future nuclear plant.

Under this scenario, a Serbian nuclear power plant could potentially begin supplying electricity to the grid sometime after 2040, marking a major step in the country’s long-term energy strategy.

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The proposed changes, submitted by the city’s public urban planning company, cover an area of 86.25 hectares in the northeastern part of Novi Sad. The zone already includes the existing combined heat and power plant (TE-TO), while the updated planning framework also provides space for its future expansion and the development of additional energy facilities.

At the core of the proposal is a solar thermal project valued at approximately €105 million, with a financing agreement already secured with the European Bank for Reconstruction and Development (EBRD). The planned installation would feature a solar collector field of about 7.4 hectares, complemented by two seasonal heat storage units occupying roughly 15 hectares. Additional supporting infrastructure is also included in the design, bringing the total area of the solar thermal complex to around 29.7 hectares within the wider site.

The planning amendments also allow for the further development of the existing TE-TO facility, which currently spans about 19 hectares. This includes the potential construction of a new gas-steam unit, contributing to the modernization and diversification of Novi Sad’s energy system.

Much of the land within the planning area is currently undeveloped and primarily used for agricultural purposes, making the project a significant transformation of the local landscape.

According to the planning documentation, the main goal of the project is to gradually integrate renewable energy sources into Novi Sad’s district heating system, reduce dependence on fossil fuels, and enhance the efficiency and sustainability of the city’s existing energy infrastructure.

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Serbia sits at the centre of this shift. Based on 2024 trade patterns, electricity flows routed through Serbia toward the EU reached roughly 9.18 TWh, with an estimated CBAM exposure of €612.5 millionannually. On a unit basis, the implied carbon-adjusted cost is approximately €66.7/MWh, a level that materially compresses export margins in a market where typical regional prices have ranged between €80–120/MWh.

This is not a marginal surcharge. It is a structural repricing of Serbian electricity as an export product.

Carbon cost turns coal-based exports into conditional trade

The immediate impact of CBAM is most visible in Serbia’s coal-heavy generation base. With lignite capacity exceeding 4.3 GW, the system remains structurally exposed to high emissions intensity, and therefore to the full cost of CBAM when electricity is exported into the EU.

In commercial terms, this transforms coal-based exports from a stable baseload flow into a conditional product. Electricity originating from lignite can still be exported, but only in hours of system tightness when EU prices are sufficiently elevated to absorb the carbon cost.

Outside these periods, the CBAM-adjusted cost effectively removes Serbian coal power from the competitive export stack.

This does not eliminate cross-border trade, but it fundamentally changes its nature. Volume-driven exports give way to hourly optimisation, scarcity pricing, and selective dispatch, with traders increasingly avoiding long-duration positions exposed to carbon-adjusted losses.

Renewable generation becomes a premium export product

Against this backdrop, renewable producers in Serbia are moving into a structurally advantaged position.

Unlike coal-based generation, renewable electricity—particularly hydro and traceable wind or solar—does not carry the same CBAM burden when exported. This creates a widening differential between:

• Carbon-heavy Serbian electricity, effectively discounted by €60–70/MWh

• Low-carbon or renewable electricity, which can enter EU markets without that penalty

In practical terms, CBAM is converting renewable energy from a marginal, intermittency-constrained resource into a premium exportable product.

The shift is already visible in trading behaviour. EU counterparties are placing greater emphasis on traceability, guarantees of origin, and emissions profiles, with demand moving toward structured supply rather than generic grid-mix electricity.

For Serbian renewable producers, this introduces a second revenue dimension beyond wholesale price: carbon-adjusted competitiveness in cross-border trade.

Scale constraint: Renewables are valuable but not yet sufficient

The challenge is that Serbia’s renewable capacity remains too limited to fully capture this opportunity.

Hydropower accounts for roughly one-third of generation, but non-hydro renewables—wind, solar, and biomass—remain underdeveloped, with solar capacity still measured in the hundreds of megawatts and wind growing but not yet dominant.

Even with planned additions of ~200–250 MW annually in the near term, the system will remain heavily influenced by fossil-based generation through 2026–2027.

This creates a transitional imbalance. CBAM penalises the dominant generation base, while renewables benefit but lack sufficient scale to replace export volumes. The result is a period in which:

• Export volumes become more volatile

• Renewable output captures disproportionate value

• Portfolio optimisation replaces volume maximisation

Grid and market design become the binding constraints

The monetisation of renewable advantage is increasingly determined not by generation cost, but by system integration.

Grid capacity, connection timelines, and balancing capability are emerging as the key constraints on renewable expansion. Without sufficient transmission upgrades and flexibility resources—particularly storage—new renewable capacity risks curtailment or delayed connection, limiting its ability to capture CBAM-driven value.

At the same time, Serbia’s power market is evolving structurally. The introduction of negative prices on SEEPEX from May 2026, with a floor of -€500/MWh day-ahead, signals a transition toward a more dynamic, EU-aligned market environment.

This reinforces the shift away from flat baseload economics toward time-sensitive, flexibility-driven trading, where the value of electricity depends on when it is delivered as much as on how it is generated.

For renewable producers, this creates both opportunity and complexity. Revenues become increasingly linked to:

• Intraday optimisation

• Balancing market participation

• Integration with storage and flexible assets

Corporate PPAs emerge as a CBAM-driven demand layer

A parallel structural change is taking place on the demand side.

Export-oriented industrial companies—particularly those exposed to CBAM in sectors such as steel and manufacturing—are increasingly seeking long-term renewable power contracts to reduce embedded emissions in their products.

This is driving growth in corporate PPAs, where Serbian renewable producers can secure long-term offtake at stable prices, while industrial buyers hedge both energy cost and carbon exposure.

The logic is direct. Under CBAM, electricity is no longer just an input cost—it is part of the carbon footprint of exported goods. Securing renewable electricity therefore becomes a strategic cost-control mechanism, not just an ESG consideration.

Trading patterns shift toward carbon-aware arbitrage

For traders, CBAM introduces a new layer of complexity that is already reshaping behaviour.

The traditional arbitrage model—based on price differentials between Serbia and EU markets—is being replaced by carbon-adjusted arbitrage, where every position must account for:

• Embedded emissions

• CBAM certificate cost

• Origin traceability

• Compliance risk

This leads to several structural shifts:

• Reduced appetite for Serbian coal-based baseload exports

• Increased focus on renewable-heavy hours and portfolios

• Growth in intraday and short-term trading

• Greater use of structured contracts and origin-certified supply

Electricity is no longer a homogeneous commodity across borders. It is a screened product, where carbon content directly determines tradability.

EPS and system strategy: Renewables as export survival mechanism

The response from Serbia’s incumbent utility reflects this shift. EPS is advancing plans for ~1 GW of solar capacity with battery storage, alongside broader renewable investments.

This is not only an energy transition initiative—it is a commercial repositioning.

Without scaling renewables, Serbia risks:

• Structural loss of export competitiveness

• Persistent CBAM cost exposure

• Compression of trading margins

With renewables and storage, the system can:

• Rebuild export capacity on a lower-carbon basis

• Monetise flexibility and balancing services

• Participate in EU markets under more competitive conditions

Forward outlook: From volume exporter to selective supplier

The trajectory for Serbia’s electricity exports under CBAM is increasingly clear.

2026–2027: Transition Phase

Exports continue but become more selective, driven by price spikes and short-term optimisation. Renewable generation captures premium value but remains capacity-constrained.

2028–2030: Structural Shift

If renewable deployment accelerates and grid integration improves, Serbia can re-enter EU markets with a different product mix—lower-carbon, more flexible, and more aligned with EU market design.

Downside scenario

If renewable expansion and grid upgrades lag, CBAM effectively caps Serbia’s export potential, reducing cross-border trade to episodic flows and shifting the system toward domestic balancing.

Redefinition and repositioning 

CBAM is not simply increasing the cost of Serbian electricity exports. It is redefining what type of Serbian electricity can be exported at all.

Coal-based baseload, once the backbone of cross-border trade, is becoming a marginal product in EU markets. Renewable generation, by contrast, is moving to the centre of Serbia’s export strategy—not because of policy preference, but because of pure commercial necessity.

The decisive variables for the next phase are no longer price spreads alone. They are:

• Speed of renewable deployment

• Grid integration capacity

• Ability to certify and trade low-carbon electricity

In that sense, CBAM is compressing a decade of market evolution into a few years. It is forcing Serbia’s electricity sector to transition from a volume-based export model to a carbon-constrained, portfolio-optimised trading system, with renewable producers emerging as the critical gatekeepers of future market access.

Elevated by cbam.engineer

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As the European Union accelerates efforts to secure access to strategic resources under frameworks such as the Critical Raw Materials Act, Serbia’s resource base is gaining renewed significance. The country is not merely a supplier of raw materials; it is increasingly positioned as a potential processing and mid-stream hub within Europe’s evolving resource architecture.

The most advanced example of this shift is copper.

Operations in Bor, led by Zijin Mining, have transformed Serbia into one of Europe’s key copper producers, with annual output exceeding 200,000 tonnes. This places Serbia among the largest producers on the continent, at a time when copper demand is being driven by electrification, renewable energy, and grid expansion.

Copper is not just a commodity; it is a foundational material for the energy transition. Electric vehicles, wind turbines, solar installations, and grid infrastructure all require substantial amounts of copper, linking Serbia’s production directly to long-term structural demand.

However, the strategic value of copper lies not only in extraction, but in processing.

At present, a significant portion of value in the copper chain is realised through refining, semi-fabrication, and component manufacturing. These stages transform raw material into usable industrial inputs, capturing higher margins and creating more complex industrial ecosystems.

Serbia’s opportunity lies in moving beyond extraction toward these mid-stream activities.

The transition from concentrate exports to refined cathodes, semi-finished products, and eventually components represents a substantial increase in domestic value capture. Each additional stage of processing retains more economic value within the country and reduces dependence on external processing capacity.

This shift is already underway, though not yet complete. Investments in processing capacity are increasing, but the scale remains below the potential implied by resource availability.

Beyond copper, Serbia’s resource base includes other materials of strategic relevance. Lithium has attracted significant attention in recent years, reflecting its central role in battery production. While project development remains subject to regulatory, environmental, and political considerations, the presence of lithium deposits positions Serbia within a critical segment of future industrial supply chains.

Borates and other mineral resources add further depth, contributing to a diversified resource profile that aligns with emerging European priorities.

The strategic importance of these resources is amplified by the broader geopolitical context. Europe’s dependence on external suppliers—particularly for critical raw materials—has become a central policy concern. Efforts to diversify supply and reduce reliance on distant or politically sensitive sources have created a renewed focus on regional and near-shore resources.

Serbia’s geographic proximity to the EU, combined with its resource base, positions it as a potential near-source supplier within this framework.

However, resource availability alone is not sufficient to secure this role.

The key determinant is the level of industrial integration around those resources.

Extractive industries generate revenue, but their contribution to broader economic development is limited if value is realised elsewhere. Processing, refining, and component manufacturing create deeper linkages, supporting industrial diversification and increasing resilience.

The development of such an ecosystem requires significant investment. Processing facilities are capital-intensive, often involving hundreds of millions of euros in CAPEX for refining plants, smelters, and downstream manufacturing.

Energy is a critical input in these processes, linking the mining sector directly to the broader energy system. Stable and competitively priced electricity is essential for processing operations, particularly in metals.

This reinforces the interdependence between industrial strategy and energy policy. Expanding the mining sector without corresponding investment in energy infrastructure would create bottlenecks that limit value capture.

Environmental considerations also play a central role. Mining and processing activities are subject to increasing scrutiny, both domestically and within the EU framework. Compliance with environmental standards, emissions regulations, and ESG requirements is not only a regulatory necessity, but a prerequisite for integration into European supply chains.

This creates an additional layer of complexity, but also an opportunity. High standards can enhance the attractiveness of Serbian production within a European context, where sustainability is increasingly embedded in industrial policy.

From an investment perspective, the mining sector offers a distinct profile compared to manufacturing.

Projects are typically long-term, capital-intensive, and subject to commodity price cycles. Returns are influenced by global market conditions, but also by operational efficiency, resource quality, and regulatory stability.

At the same time, the strategic importance of critical raw materials introduces a policy dimension that can support investment through incentives, partnerships, and integration into broader European initiatives.

The potential scale of this sector is significant. Copper alone represents billions of euros in annual export value, depending on global prices. Expanding processing capacity could multiply this value, creating additional layers of economic activity.

The challenge lies in aligning multiple elements:

• Resource extraction

• Processing infrastructure

• Energy supply

• Environmental compliance

• Market integration

Each of these components must develop in parallel to create a coherent industrial ecosystem.

Serbia’s current position reflects the early stages of this alignment. The resource base is established, extraction capacity is significant, and initial steps toward processing are visible.

The next phase will determine whether Serbia remains primarily a supplier of raw materials or evolves into a more integrated player within Europe’s critical raw materials chain.

The distinction is central to long-term economic positioning.

A resource-export model generates revenue but limited structural transformation. A processing and integration model creates industrial depth, supports diversification, and increases resilience.

As Europe seeks to secure its supply chains, the opportunity for Serbia is not simply to supply materials, but to become part of the system that transforms them.

The direction of investment and policy over the coming years will determine how much of that opportunity is realised.

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The project represents one of the largest environmental investments in the regional electricity sector and is expected to substantially reduce harmful emissions from a key source of electricity production in Serbia. According to officials, the completion of the system will bring the country’s largest thermal capacities into compliance not only with national regulations but also with European environmental standards.

Serbian Mining and Energy Minister Dubravka Đedović stated that sulfur dioxide emissions at the plant are expected to decrease by up to 30 times once the system becomes fully operational. She also noted that particulate emissions are already being kept below required limits. The minister added that more than 420 million euros has been invested in desulfurization systems at TENT A and TENT B combined, with environmental benefits expected to extend beyond Obrenovac to Belgrade and surrounding areas.

EPS Director Dušan Živković said that the desulfurization facility at TENT B alone required an investment of around 250 million euros. The project was implemented in cooperation with Japanese and domestic partners, including Mitsubishi Heavy Industries, which carried out the works. The system uses modern flue gas cleaning technology based on a wet limestone process, which removes sulfur compounds from exhaust gases.

An additional benefit of the process is the production of gypsum as a by-product. EPS reports that the gypsum already produced at the site meets European quality standards, with annual output expected to reach around 200,000 tons. The company sees this as an opportunity to further support circular economy practices while reducing industrial waste.

Beyond environmental improvements, EPS emphasizes that the investment also strengthens the long-term operational reliability of one of the core pillars of Serbia’s electricity system, enhancing both efficiency and the expected lifespan of the plant.

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At its latest session, the government adopted a broad package of regulations and administrative decisions affecting multiple sectors. Among these measures was an amendment to the existing decision that temporarily limits the export of petroleum-related products.

The revised policy keeps the export ban in place until 2 May 2026. Authorities stated that the extension is necessary to reduce the risk of domestic shortages, as global market disruptions continue to affect supply chains and overall fuel availability.

Officials emphasized that the current international environment remains too unstable to ease the restriction, arguing that continued intervention is required to maintain balance and stability in the domestic market.

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The Serbian expansion, anchored in approximately 180 MW of wind capacity and 56–60 MW of solar, is expected to lift national electricity production to around 39.3 TWh, while reducing import dependence and marginally increasing export capability. These effects are economically meaningful but not transformative in isolation. Serbia’s installed generation base, exceeding 7.5 GW, remains dominated by lignite-fired thermal power and hydropower, with renewables still forming a relatively small share of total dispatchable capacity.

What gives the 2026 rollout strategic weight is its alignment with system limitations that are now visible across Europe. Recent system-wide analysis shows that at least 120 GW of planned renewable capacity across the EU is at risk due to insufficient grid capacity, with transmission-level bottlenecks accounting for roughly 104 GW of the shortfall. Among the most constrained systems are Romania and Bulgaria, both central to the SEE electricity corridor linking the Balkans with Central European markets.    

Within this context, Serbia’s measured approach to capacity expansion reflects a pragmatic recognition of grid physics. Large-scale renewable deployment—particularly clusters exceeding several hundred megawatts—requires substantial reinforcement of transmission infrastructure, new substations, and expanded interconnection capacity. In a region where permitting timelines are extended, financing for grid expansion remains uneven, and cross-border coordination is complex, such developments introduce execution risk that can delay projects for years.

By contrast, the addition of 237 MW represents a scale that can be more readily integrated into the existing system. It allows Serbia to increase renewable penetration without materially increasing curtailment risk or destabilising dispatch patterns. In effect, the country is pursuing a grid-compatible expansion model, where generation growth is calibrated to what the network can realistically absorb.

This approach positions Serbia differently from several EU markets where pipeline ambition has outpaced infrastructure readiness. In countries such as the Netherlands, Finland, and parts of Central Europe, large volumes of renewable capacity are currently stalled in connection queues, with total queued projects across reporting countries approaching 700 GW. In extreme cases, project pipelines exceed existing system capacity by an order of magnitude, creating a backlog that undermines investor confidence and complicates market forecasting.  

Serbia’s pipeline, while smaller in absolute terms, appears more closely aligned with connection feasibility. This reduces the risk of speculative project accumulation and improves the likelihood that announced capacity will translate into operational assets within expected timelines. For investors, this distinction is critical. Execution certainty—rather than theoretical pipeline size—is becoming the primary determinant of project value.

The implications extend beyond Serbia’s domestic market. South-East Europe functions as an interconnected system where constraints in one jurisdiction influence outcomes across the region. Transmission bottlenecks in Romania and Bulgaria, for example, limit the ability of renewable generation from the Black Sea basin and the Balkans to flow into Central European markets. This, in turn, affects price convergence, increases congestion costs, and shapes cross-border trading dynamics.

In this environment, Serbia’s role is evolving. Rather than acting solely as a national energy system, it is increasingly functioning as a balancing corridor within SEE, mediating flows between constrained EU grids and the Western Balkans. Its generation mix—combining flexible hydropower, thermal baseload, and gradually expanding renewables—provides a degree of operational stability that is particularly valuable in a system characterised by intermittent generation and uneven grid development.

The 2026 renewable additions reinforce this role without overextending the network. Incremental wind and solar capacity reduces marginal generation costs and import dependence, while maintaining sufficient dispatchable capacity to manage variability. This supports Serbia’s position in regional electricity markets, where price formation is increasingly influenced by cross-border flows and congestion patterns.

At the same time, the expansion highlights a broader structural divergence within Europe’s energy transition. While policy frameworks emphasise rapid scaling of renewables and electrification, the physical infrastructure required to support this transformation is not developing at the same pace. Grid readiness, as the analysis indicates, has become an indicator of economic readiness, determining not only energy outcomes but also industrial competitiveness.

This is particularly evident in the context of large-scale industrial electrification. In several European systems, including Bulgaria and Romania, available transmission capacity for new industrial loads is effectively exhausted. This creates a bottleneck for sectors such as battery manufacturing, data centres, and hydrogen production, which require reliable access to large volumes of electricity.

For Serbia, the implication is twofold. On one hand, limited regional capacity constrains the ability to attract energy-intensive industries at scale. On the other, it creates an opportunity to position the country as a flexible, mid-scale industrial platform, where projects can be developed within existing grid constraints. This aligns with a broader trend in SEE, where investment is shifting toward modular, phased developments rather than large, single-site facilities.

The distribution-level picture offers a partial counterbalance. Across Europe, distribution networks generally retain more capacity to support household electrification, including heat pumps and electric vehicle charging. This suggests that, even as transmission constraints limit large-scale projects, residential and small-scale commercial electrification can continue to expand.

However, this layer is not without risk. Limited distribution capacity is already affecting rooftop solar deployment in several markets, with at least 16 GW of planned capacity at risk, potentially impacting 1.5 million households.   For SEE, where distributed generation is often seen as a rapid pathway to decarbonisation, sustained investment in distribution infrastructure will be essential to avoid similar bottlenecks.

The most immediate lever for addressing these constraints lies in the adoption of non-wire solutions. Technologies such as dynamic line rating, advanced grid monitoring, and flexible connection agreements can significantly increase the utilisation of existing infrastructure. Across Europe, such measures are estimated to unlock between 140 GW and 185 GW of additional capacity, broadly equivalent to the current shortfall in grid hosting capability.  

For South-East Europe, these solutions offer a particularly attractive pathway. Large-scale grid expansion projects require substantial capital, long permitting timelines, and complex cross-border coordination. By contrast, non-wire solutions can be implemented more rapidly and at lower cost, providing immediate relief to constrained systems.

Regulatory reform is equally important. Efficient allocation of grid capacity—prioritising projects with high probability of completion—can reduce queue backlogs and accelerate connection timelines. Several European countries have already introduced such mechanisms, including competitive allocation processes and pre-reservation of capacity for renewable projects.

In SEE, where project pipelines are growing but infrastructure remains limited, the adoption of similar frameworks could significantly improve market efficiency. Without such reforms, the risk is that connection queues become increasingly congested, delaying viable projects and discouraging investment.

The broader policy environment provides a supportive backdrop. European initiatives, including the Grid Action Plan and subsequent regulatory packages, have established a framework for accelerating grid development and improving connection processes. However, implementation remains the responsibility of national authorities, creating variability in outcomes across the region.  

For Serbia, this decentralised structure presents both an opportunity and a challenge. It allows the country to tailor its approach to local conditions and move at a pace aligned with its institutional capacity. At the same time, it requires sustained coordination between government, regulators, and system operators to ensure that incremental capacity additions are supported by corresponding improvements in grid infrastructure and operational practices.

The strategic significance of Serbia’s 2026 renewable expansion therefore extends beyond its immediate contribution to generation capacity. It illustrates a transition model that is increasingly relevant across South-East Europe: one defined by incremental, grid-aligned growth, rather than rapid, large-scale deployment.

This model reflects a broader reality. The energy transition is no longer constrained by the availability of technology or capital. It is constrained by the ability of physical systems to integrate new capacity efficiently. In regions where grid development lags behind generation ambition, the pace of transition will be determined not by targets, but by infrastructure.

In this context, Serbia’s approach may prove instructive. By aligning renewable expansion with existing grid capacity, the country reduces execution risk, maintains system stability, and preserves optionality for future growth. As grid infrastructure evolves and new technologies are deployed, this foundation can support further scaling.

Across South-East Europe, similar strategies are likely to emerge. Countries will need to balance ambition with feasibility, prioritising projects that can be delivered within current constraints while investing in the infrastructure required to enable future expansion. The success of this approach will determine not only regional energy outcomes, but also the extent to which SEE can integrate into the broader European energy and industrial system.

The transition is therefore entering a new phase—one where the key question is no longer how much capacity can be planned, but how much can be connected. In this phase, the role of South-East Europe is both critical and conditional. Its geographic position, resource base, and market integration offer significant potential. Realising that potential, however, will depend on the ability to translate incremental progress into system-wide transformation.

Serbia’s 237 MW expansion is a small step in numerical terms. In structural terms, it reflects a much larger shift: the emergence of a grid-constrained energy transition, where the pace and direction of change are determined not by ambition alone, but by the capacity of networks to carry it forward.

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Recent developments indicate that the company is not only progressing toward potential mine development at the Piskanja boron deposit, but is also actively seeking additional resource positions in the same geological corridor, signalling an early-stage consolidation strategy in what could become one of Europe’s few boron production hubs.

From exploration to control: Strategic positioning intensifies

The Piskanja project, located near Baljevac na Ibru, has already advanced through key preparatory stages, including environmental impact assessment and submission of exploitation field approval documentation to Serbian authorities.  

However, the latest signals from the market suggest that Boron One is moving beyond a single-asset approach. The company is actively targeting nearby deposits and legacy mining assets, indicating a broader ambition to establish a vertically integrated boron production platform in Serbia.

This includes interest in previously developed or partially explored sites such as Pobrđe, where cooperation with state-owned mining structures has already been initiated through preliminary agreements.  

The implication is clear: rather than developing Piskanja as a standalone mine, the strategy appears to be evolving toward cluster development of multiple borate resources, enabling scale, cost optimization, and processing integration.

Resource base positions Serbia as a strategic boron node

Geological estimates underline the strategic significance of the Piskanja deposit. The project contains:

• Measured resources: 1.39 million tonnes

• Indicated resources: 5.48 million tonnes

• Average boron oxide (B₂O₃) grades above 34%  

This places the deposit among the more commercially attractive borate resources globally, particularly given Europe’s current reliance on imports from Turkey and the United States.

If developed, the project could position Serbia as:

• A rare European source of boron

• A potential supplier into EU industrial value chains (glass, ceramics, chemicals, battery materials)

Regulatory reality: Still no approved mine

Despite increasing investor activity, Serbian authorities have emphasized that no mining license has yet been granted, and that the process remains firmly within regulatory procedures.

The Ministry of Mining and Energy has clarified that:

• Submission of documentation does not equate to approval

• The project remains in pre-development phase

• Final exploitation rights depend on full compliance with legal, environmental, and technical requirements  

This distinction is critical for investors.

Serbia’s mining approval cycle is typically multi-year, often extending into a decade depending on environmental permitting, public consultation, and infrastructure readiness.

Economics: High-value industrial mineral with wide price range

Boron’s industrial applications make it a strategically valuable mineral across multiple sectors:

• Glass manufacturing (strength and thermal resistance)

• Ceramics and coatings

• Fertilizers and chemicals

• Potential applications in energy storage materials

Pricing varies significantly depending on processing level:

• Raw boric acid: ~€800 per tonne

• Refined and specialized products: up to ~€5,000 per tonne equivalent  

This wide pricing spectrum supports the case for on-site processing facilities, which would significantly enhance project economics and export value.

Emerging cluster model: From single mine to processing hub

The increasing interest in adjacent deposits suggests a likely development pathway:

1. Primary extraction at Piskanja

2. Rehabilitation or integration of nearby deposits (e.g., Pobrđe)

3. Construction of a boron processing plant (boric acid production)

4. Potential downstream integration into specialty materials

Such a model would shift Serbia’s position from:

→ Raw material exporter

to

→ Industrial processing hub for boron-based products

Market context: Europe’s structural supply gap

Europe currently lacks domestic boron production, relying heavily on imports.

If Serbian projects materialize, they could:

• Reduce EU dependency on Turkish supply chains

• Support CBAM-aligned local sourcing strategies

• Enable integration into European chemical and battery value chains

This aligns with broader EU policy direction under:

• Critical Raw Materials Act (CRMA)

• Strategic autonomy in industrial minerals

Risk layer: Environmental and social sensitivities

Boron extraction carries environmental considerations, particularly:

• Sensitivity of ecosystems to boron concentration

• Tailings management risks

• Water contamination thresholds (toxicity above certain levels)

Experts note that boron has a narrow margin between beneficial and harmful concentrations, especially for plant life and water systems.  

This introduces:

• Elevated permitting scrutiny

• Potential local opposition risks

• Extended project timelines

Strategic outlook: Early-stage consolidation with long lead time

The trajectory of Boron One’s activity suggests a clear shift from exploration toward resource consolidation and pre-development positioning.

However, the timeline remains long:

• Short-term (1–2 years): permitting and feasibility finalization

• Mid-term (3–5 years): construction decision (FID)

• Long-term (5–8 years): potential production start

The project’s evolution will depend on:

• Regulatory approvals

• Financing structure

• Ability to integrate multiple deposits into a scalable production model

Market signal

The move toward acquiring additional boron assets around Raška signals that Serbia is emerging as a potential new node in Europe’s critical minerals landscape, but one that remains firmly in the early development stage.

For investors and industrial players, the key takeaway is not immediate production, but the formation of a future boron supply platform that could reshape regional raw materials dynamics over the next decade.

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This convergence of mining and energy is not accidental. It reflects a structural reality: Europe’s decarbonisation agenda is driving demand for copper, critical minerals, and electricity-intensive industrial inputs, while simultaneously imposing carbon constraints on how those materials are produced. Serbia sits at the intersection of these forces, and Chinese investors have positioned themselves accordingly.

Zijin’s copper complex: The backbone of Serbia’s strategic position

At the core of this system lies the transformation of eastern Serbia into one of Europe’s most significant copper-producing regions. The entry of Zijin Mining into the Bor mining complex and the development of the Čukaru Peki deposit has reshaped not only Serbia’s industrial output but also its geopolitical relevance in raw materials supply.

Total investment commitments across Zijin’s Serbian portfolio now exceed $3.5–4.0 billion, making it one of the largest single clusters of Chinese industrial capital in Europe. The operational footprint includes:

• The Bor open-pit and underground mining system
• The Majdanpek mine expansion
• The Čukaru Peki high-grade underground deposit

Production levels have scaled rapidly. Serbia is now producing approximately 250–300 kilotonnes of copper equivalent annually, with additional gold output estimated at 5–7 tonnes per year. These volumes position Serbia among the top copper producers in Europe, at a time when EU domestic supply remains structurally constrained.

What distinguishes Zijin’s approach is not just the scale of extraction but the integration of processing capacity on-site, including smelting and refining. This allows copper concentrate to be converted into cathodes within Serbia, increasing value capture and reducing reliance on external processing hubs.

From a system perspective, this creates a closed-loop industrial model:

→ Extraction in eastern Serbia
→ Processing within the same industrial cluster
→ Export to EU manufacturing centres

This model aligns directly with Europe’s need for secure, near-shore supply of critical raw materials, particularly for electrification, grid expansion, and electric vehicle production.

Energy intensity as a structural constraint

Copper production at this scale is inherently energy-intensive. Smelting operations, in particular, require stable and large-scale electricity supply, making the viability of Serbia’s mining expansion directly dependent on its energy system.

Serbia’s current electricity mix remains dominated by lignite, which accounts for approximately 60–65% of total generation, with hydropower contributing around 25–30%. This structure has historically provided cost stability but now introduces a new layer of risk under European carbon regulation.

For Zijin and other industrial operators, the implications are twofold.

First, electricity costs are becoming increasingly volatile, particularly during winter periods when Serbia shifts into import dependency. Second, the carbon intensity of power generation directly affects the embedded emissions of exported metals, exposing them to CBAM-related costs when entering the EU market.

The combination of these factors is forcing a structural rethink. Mining operations can no longer be analysed independently of energy strategy. Instead, they must be viewed as integrated energy–industrial systems, where power sourcing, grid access, and carbon intensity are as critical as ore grades and production volumes.

HBIS and the parallel steel-energy dynamic

A similar dynamic is visible in the steel sector. The Smederevo plant, operated by HBIS Group, produces approximately 2 million tonnes of crude steel annually, making it one of the largest industrial energy consumers in Serbia.

Steel production shares the same structural exposure as copper:

• High electricity demand
• Sensitivity to carbon pricing
• Dependence on stable baseload generation

Under CBAM, the cost of carbon embedded in steel exports could reach €80–120 per tonne depending on emissions intensity and EU ETS benchmarks. This creates a direct margin pressure on Serbian-based production, particularly for exports into core EU markets.

For HBIS, as for Zijin, the response is increasingly converging toward energy integration. The next phase of investment is likely to include:

• Dedicated renewable energy capacity linked to industrial sites
• Long-term power purchase agreements (PPAs)
• Potential participation in grid-scale battery storage

This marks a transition from traditional heavy industry toward energy-aware industrial operations, where competitiveness depends as much on power sourcing as on production efficiency.

Grid constraints and industrial expansion limits

The expansion of mining and metallurgy in Serbia is now encountering a physical constraint that is becoming increasingly visible: grid capacity.

Eastern Serbia, where the Bor and Majdanpek complexes are located, was not originally designed to accommodate the scale of industrial electrification now underway. Transmission infrastructure, largely built in earlier decades, is under pressure from:

• Increased industrial load
• Variable renewable generation
• Cross-border electricity flows

EMS (Elektromreža Srbije) has initiated a series of upgrades, including new substations and transmission reinforcements, but the pace of industrial expansion is testing the limits of the system.

For investors, this introduces a new dimension of risk. Access to grid capacity is becoming a binding constraint on project development, particularly for energy-intensive industries. In practical terms, this means that future mining or processing expansions will increasingly require:

• Co-located generation capacity
• Private or semi-private grid solutions
• Direct investment into transmission infrastructure

This dynamic is already visible across Europe, but in Serbia it is amplified by the concentration of heavy industry within a relatively limited geographic area.

Renewable energy as industrial infrastructure

The convergence of mining and energy is accelerating Serbia’s renewable energy build-out, not as a purely environmental initiative but as an industrial necessity.

The national pipeline includes:

• Approximately 1–2 GW of solar capacity under development
• A similar scale of wind projects, including major developments such as the Gvozd wind project (~55 MW initial phase, scalable)
• Early-stage battery storage projects linked to grid stabilisation

For Chinese investors, this represents a natural extension of their existing presence. Companies that have established control over mining and metallurgy are now positioned to move into:

• Solar module supply chains
• Wind turbine procurement
• Battery storage systems

This creates a vertically integrated model where energy generation, industrial consumption, and export production are controlled within a single investment ecosystem.

From a financial perspective, the implications are significant. Co-located renewable energy can reduce effective electricity costs, hedge against market volatility, and lower carbon exposure. For a copper or steel operation, this can translate into margin improvements of €50–100 per tonne equivalent, depending on energy intensity and pricing structures.

Logistics and export flows: The Danube Corridor

Mining and energy systems in Serbia are ultimately oriented toward export. The physical movement of copper cathodes, concentrates, and steel products is facilitated by a logistics network that has been steadily upgraded with Chinese participation.

The Danube corridor plays a central role, providing a direct route to Black Sea ports and onward to global markets. Rail connections link eastern Serbia with Central Europe, while road infrastructure supports regional distribution.

The strategic importance of these routes lies in their ability to:

• Reduce transport costs for bulk commodities
• Enable high-volume export flows
• Integrate Serbia into broader China–Europe logistics networks

This reinforces the overall system logic. Mining output is not isolated—it is embedded in a continuous chain from extraction to export, with infrastructure designed to support scale.

Financial structure and capital discipline

The scale of investment in Serbia’s mining and energy sectors reflects a financing model that differs from conventional European project finance. Chinese investments are often backed by policy banks and structured with long-term strategic objectives rather than short-term financial returns.

For mining projects, this translates into:

• High upfront CAPEX with extended payback periods
• Integrated financing for both extraction and processing
• Willingness to absorb initial volatility in commodity prices

In energy, similar structures are emerging. Renewable projects linked to industrial consumption may be financed as part of broader industrial packages, rather than as standalone assets.

From an investor perspective, this creates a dual market structure:

• Strategic capital (primarily Chinese) operating with longer horizons
• Commercial capital (European and international) requiring defined returns and risk mitigation

The interaction between these two models will shape the next phase of development, particularly as Serbia moves closer to EU regulatory alignment.

CBAM and the repricing of industrial output

The introduction of the Carbon Border Adjustment Mechanism is the single most important external factor affecting Serbia’s mining–energy nexus. By imposing a carbon cost on imports into the EU, CBAM effectively extends EU climate policy beyond its borders.

For Serbia, the implications are immediate. Copper and steel exports, which form the backbone of Chinese-owned industrial activity, will face additional costs unless production processes are decarbonised.

This creates a powerful incentive for investment in:

• Renewable energy integration
• Energy efficiency upgrades
• Electrification of industrial processes

At the same time, it introduces uncertainty. The exact cost impact will depend on carbon pricing, emissions intensity, and regulatory alignment, making future revenue streams more complex to model.

Industrial system in transition

What is emerging in Serbia is not simply an expansion of mining or energy capacity. It is a transition toward a fully integrated industrial system, where the boundaries between sectors are increasingly blurred.

Mining operations are becoming energy projects. Energy infrastructure is being designed around industrial demand. Logistics networks are optimised for bulk commodity flows. And all of these elements are linked through a capital structure that is both global and highly coordinated.

In this system, Serbia’s role is defined not by its domestic consumption but by its position within a broader network. It is a production node, an energy hub, and a logistics corridor simultaneously, connecting Chinese capital with European industrial demand.

Scaling within constraints

The next phase of development will be defined by the ability to scale this system within emerging constraints. Grid capacity, carbon pricing, and regulatory alignment will all shape the trajectory of investment.

Chinese investors, already deeply embedded in Serbia’s mining sector, are likely to expand further into energy and infrastructure to protect and enhance their existing positions. European capital, in turn, may increasingly participate in areas where regulatory alignment and ESG compliance are critical.

The result will not be a replacement of one system by another, but a layering of capital structures, with Serbia acting as the interface.

Within that interface, the convergence of mining and energy will remain the defining feature. Copper, steel, electricity, and carbon will be managed not as separate variables but as components of a single industrial equation—one that is being recalibrated in real time as Europe’s energy transition accelerates and global capital adjusts to its implications.

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That import dependence sits inside a market structure that remains unusually concentrated even by regional standards. The Energy Community’s latest Serbia implementation material says Srbijagas secures roughly 75% of Serbia’s annual gas consumption through its long-term Gazprom-linked import position, with the balance sourced from the Hungarian market, smaller Azerbaijani volumes arriving through the Bulgaria interconnector, and limited domestic production tied mainly to NIS. AERS, Serbia’s energy regulator, is even more explicit in its certification documentation, stating that Srbijagas has a monopoly on the wholesale gas market in Serbia and is also a dominant retail player, which is why the regulator continues to treat the Serbian gas system as part of a vertically integrated energy structure rather than a genuinely liberalized market.  

That is the core commercial reality investors need to understand. Serbia’s gas market is not yet a broad open-access trading arena in which infrastructure automatically translates into competitive procurement. It is still a state-centered system in which route diversification, storage expansion and downstream gasification are all filtered through Srbijagas. In that sense, the country is building optionality without yet changing its ownership or market-power logic. The Serbia–Bulgaria gas interconnector, completed in late 2023, gives the system a nameplate capacity of 1.8 bcm a year, equivalent to about 60% of Serbia’s annual consumption, according to EU-backed project documentation. The Serbian government has also said the Serbia–North Macedonia interconnectorshould be built by the end of 2027 and start operating in early 2028, adding a further southern route into the system.  

Storage is the second pillar of that strategy. Serbia’s relationship with Gazprom is not only about imports; it also includes joint storage exposure at Banatski Dvor. Reuters reported this week that Serbia’s gas imports are managed through Srbijagas and include storage in Banatski Dvor and Hungary. Separately, Serbia’s Ministry of Mining and Energy has said the expansion of Banatski Dvor is intended to lift capacity from 450 million cubic metres to 750 million cubic metres, while increasing withdrawal capability to around 10–12 million cubic metres per day, with overall completion targeted for the end of 2026. That is commercially important because it gives Srbijagas a larger seasonal optimization tool at exactly the moment when Serbia is trying to reduce spot exposure without losing the pricing benefits of its Russian formula.  

Inside that market architecture, Millennium Team stands out as one of the most important domestic EPC contractors in Srbijagas’s physical buildout. I would be careful not to describe it as the sole dominant contractor, because public contracting data do not show every current award in one transparent place and Srbijagas also works with other domestic and regional engineering firms. But based on disclosed projects, route lengths and continuing execution status, Millennium Team is clearly one of the contractors most deeply embedded in Serbia’s active gas corridor and municipal gasification program. Its relevance comes from repeated participation in projects that extend the gas system both geographically and commercially.  

The most commercially relevant live corridor in Millennium Team’s visible portfolio is the Belgrade–Valjevo–Loznica gas pipeline. Millennium Team’s own project description states that it is the main contractor for geological and geodetic works, permitting documentation and construction of a 160 km distribution gas pipeline with 8 main metering and regulating stations. The project is split into two phases, with Phase I covering Belgrade–Valjevo from 2022 to 2025 and Phase II covering Valjevo–Loznica from 2024 and still in progress. That matters because this is not a dormant legacy scheme; it is an active westward expansion corridor that links industrial and municipal demand in western Serbia more firmly into the national gas grid. The National Assembly’s 2025 legislative agenda also included a state guarantee bill linked to a Bank Intesa loan for Srbijagas for the construction of the Belgrade–Valjevo–Loznica pipeline, which confirms the project’s financing importance at state level.  

The second major Millennium Team corridor is the Aleksandrovac–Kopaonik–Novi Pazar–Raška–Tutin pipeline. Millennium Team states that this Srbijagas-backed project has been underway since 2017, that it includes the construction of the gas pipeline and main metering-regulating stations, and that 116 km of network has already been executed. This southern corridor is strategically important because it extends gas availability into parts of central and southwestern Serbia that have historically had weaker access to the transmission-distribution network. In market terms, that is not just an engineering job. It enlarges Srbijagas’s addressable downstream base and supports eventual industrial, commercial and district-heating demand growth in municipalities that were previously constrained by lack of pipeline access.  

The Kraljevo gasification program shows the same logic at municipal scale. Millennium Team says it is the main contractor on a project with a planned 644 km polyethylene distribution network, 16.7 km of medium-pressure steel pipeline and 14 metering-regulating stations, with 374 km of PE network, 9.4 km of steel pipeline and 2 stations already executed. This is the kind of project that rarely produces headlines comparable to an interconnector or storage expansion, but for Srbijagas it is central to how the company translates trunk-line reach into recurring local demand. In a market where the wholesaler is also the dominant system builder, the downstream monetization of each newly gasified municipality matters as much as the high-profile import corridors.  

Millennium Team’s disclosed portfolio suggests that this role is broader still. The company lists active or ongoing Srbijagas-related gasification works in Zemun, Rakovica, Grocka, Smederevo and within Belgrade Waterfront, where it says it is responsible for design and construction of gas pipeline works and associated MRS facilities. The Belgrade Waterfront gas project is explicitly listed as a Srbijagas contract and remains marked “2018 – in progress.” This gives Millennium Team a notable position not only in inter-urban corridors but also in the capital’s urban and peri-urban gas consumption buildout.  

There is also a trunk-line and strategic-corridor dimension to Millennium Team’s record through projects associated with TurkStream. The company’s project archive includes TurkStream works and related energy-corridor activities, which reinforces that Millennium Team has not been confined to low-pressure distribution works or municipal expansion. Even when not every current contract value is publicly disclosed, the project pattern is clear: the company operates across the full ladder of Srbijagas-linked infrastructure, from distribution gasification to nationally significant pipeline corridors.  

From an investor or strategic-market perspective, the Serbian gas market today can be read through three overlapping layers. The first is commodity security, where the Russian formula still dominates because it remains materially cheaper than hub-based alternatives for Serbia. The second is route diversification, where the Bulgaria interconnector, the planned North Macedonia interconnector and LNG-related arrangements linked to Greece are gradually widening physical access. The third is domestic market deepening, where contractors such as Millennium Team are extending the network into new industrial zones, municipalities and commercial districts that can absorb more gas over time. Those three layers do not move at the same speed. Commodity diversification is still lagging, route diversification is advancing, and domestic network deepening is already visible on the ground.  

That mismatch explains why Srbijagas remains so central. The company is not just an importer. It is still the main allocator of physical system growth, the principal beneficiary of new storage and corridor flexibility, and the gatekeeper through which most new gas demand is connected. As long as AERS and the Energy Community continue to describe the market as monopolized or quasi-monopolized, contractors that repeatedly win Srbijagas-linked work will retain strategic importance far beyond normal EPC status. They become part of the state-led expansion mechanism itself.  

For Millennium Team, that means its importance is best understood not through one headline-grabbing contract but through cumulative positioning. The company appears deeply embedded in western expansion through Belgrade–Valjevo–Loznica, in southern extension through Aleksandrovac–Tutin, in municipal demand capture through Kraljevo and other local gasification projects, and in urban consumption buildout through Belgrade-area schemes. Publicly available sources do not give a complete current backlog value across all Srbijagas-related projects, so I would avoid putting a precise aggregate contract number on the portfolio. But the footprint is large enough to say that Millennium Team is one of the principal domestic execution vehicles for Srbijagas’s current gas buildout.  

The weakness in Serbia’s gas model is obvious: true market liberalization still lags infrastructure growth. The strength is also obvious: the country is gradually building a wider and more resilient physical system, with more storage, more interconnection options and deeper distribution penetration. For now, however, the commercial hierarchy has not changed. Srbijagas remains the market’s center of gravity, Russian gas remains the main supply anchor, and Millennium Team remains one of the most important EPC contractors turning that centralized gas strategy into physical assets on the ground.  

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The timing of the transaction is critical. Serbia is entering a multi-cycle capital deployment phase estimated at €5–7 billion across generation, distribution and transmission by 2030, driven by decarbonisation, grid stabilisation requirements and gradual alignment with EU market coupling mechanisms. MVM’s move effectively positions Južna Bačka as a localized execution platform within that investment wave, rather than a purely domestic contractor dependent on episodic public tenders.

Before the majority takeover, Južna Bačka already held a durable role in substation construction, grid reinforcement and electro-mechanical works. The minority MVM stake functioned as a strategic foothold, offering visibility into Serbian infrastructure without full operational integration. The closing of the transaction in September 2025, however, coincided almost immediately with entry into higher-value EPC roles, most visibly through the €109.7 million modernization of the Vlasina hydropower cascade, signed with EPS in November 2025.

That contract is not only the largest identifiable award in the post-acquisition period but also a signal of structural repositioning. The Vlasina system, a cluster of hydro plants within EPS’s southern portfolio, is being upgraded to deliver approximately +8 MW of incremental capacity, alongside a 20–30 year extension of operational life. The project’s technical architecture reflects a hybrid delivery model, with Južna Bačka acting as primary contractor while ANDRITZ was selected in March 2026 to supply 10 turbine units, anchoring the project within a broader European OEM supply chain.

This shift from domestically anchored contracting toward integrated EPC–OEM structures aligns closely with MVM’s operating model across Central Europe, where asset ownership, engineering and procurement are increasingly coordinated within a single industrial framework. In Serbia, that approach effectively elevates Južna Bačka into a higher tier of project delivery, capable of managing mid-scale generation CAPEX envelopes exceeding €100 million.

Parallel to generation rehabilitation, the company has deepened its exposure to Serbia’s distribution-level transformation, particularly through the ongoing rollout of advanced metering infrastructure financed in part by international lenders. Contracts awarded in late 2025 include €25.79 million for the Niš region and €11.05 million for the Čačak/Kraljevo area, bringing confirmed distribution-related backlog to approximately €36.8 million.

While smaller in nominal value than hydro modernization, these projects embed Južna Bačka into the digital layer of the electricity system, where investment cycles are longer, more iterative and closely tied to regulatory alignment. Serbia’s push to reduce technical and commercial losses, integrate distributed solar generation and prepare for more dynamic pricing frameworks depends heavily on such infrastructure. The company’s positioning here extends beyond physical installation into system architecture and data-enabled grid management, a segment expected to expand materially as regional markets adopt EU-aligned balancing and flexibility mechanisms.

Additional contracts tied to urban infrastructure—most notably grid works associated with the Belgrade EXPO development, valued at more than RSD 1.4 billion (approximately €10–12 million)—reinforce the breadth of Južna Bačka’s engagement across the electricity value chain. These projects, while less capital-intensive, provide continuity of execution and visibility within politically significant developments, further consolidating the company’s role as a preferred contractor for state-backed infrastructure.

Taken together, the identifiable backlog accumulated between the initial MVM ownership increase in July 2025 and early 2026 converges around a range of €160–170 million, with a structure that is heavily weighted toward generation and distribution. Approximately 65–70% of this pipeline is linked to EPS generation assets, primarily hydro, while 20–25% relates to distribution digitalisation, leaving less than 10% attributed to transmission-related activity in the current cycle.

This imbalance does not reflect a structural withdrawal from transmission but rather the timing of procurement cycles within EMS’s investment program. Južna Bačka’s earlier participation in projects such as the Trans-Balkan Corridor substation packages, valued at around €6.5 million, demonstrates established capability within high-voltage infrastructure. The absence of newly confirmed EMS awards in the 2025–2026 window appears linked to longer tender cycles, increased competition from regional EPC consortia and the sequencing of transmission CAPEX, rather than any erosion of technical positioning.

Serbia’s transmission system remains in the early stages of a broader expansion phase that will require 400 kV interconnections, reactive power compensation assets and grid stabilization investments to accommodate rising renewable penetration and cross-border trading volumes. As these projects move from planning into execution, Južna Bačka’s historical footprint within EMS provides a platform for re-entry, particularly under MVM ownership, which brings both financing capacity and regional integration logic.

The strategic significance of MVM’s majority control becomes more evident when viewed against the evolving structure of the SEE power market. Daily trading dynamics already show increasing price convergence with Central Europe, rising volatility and a growing dependence on cross-border flows. In this context, infrastructure execution is no longer a purely domestic activity but part of a regional system optimization process, linking generation assets, transmission corridors and market operations.

MVM’s broader portfolio—spanning generation, trading and grid investments across Hungary and neighbouring markets—positions Južna Bačka as a potential execution arm for cross-border CAPEX, particularly in projects that combine infrastructure with long-term asset ownership or strategic market positioning. This introduces a different risk-return profile compared with traditional EPC contracting, where revenue is tied primarily to project delivery rather than system-level integration.

Financially, the integration with MVM improves access to capital and enhances the company’s ability to participate in larger and more complex projects, including those requiring turnkey delivery, performance guarantees and multi-year execution timelines. It also aligns Južna Bačka with financing structures increasingly used in the region, where EBRD, EIB and commercial lenders co-finance grid and generation investments, often requiring contractors with both technical capacity and balance sheet support.

Within Serbia, the immediate trajectory suggests a three-phase positioning model. In the short term, revenue stability is anchored by EPS-driven projects, particularly in hydro modernization and distribution upgrades. Over the medium term, the expected acceleration of EMS transmission investments should rebalance the portfolio toward high-voltage infrastructure. Beyond that, MVM ownership opens the possibility of regional expansion, where Južna Bačka operates not only as a contractor but as part of a broader investment and execution platform spanning the Western Balkans.

What emerges from the 2025–2026 contract cycle is not merely an increase in backlog but a redefinition of role. Južna Bačka is evolving from a domestically focused engineering contractor into a strategically positioned infrastructure integrator, operating at the intersection of generation rehabilitation, grid digitalisation and future transmission expansion. The presence of MVM in its ownership structure provides both the capital base and the regional logic to scale that role further as South-East Europe’s power systems move deeper into a phase of structural transformation.

The post MVM’s majority takeover of Južna Bačka reshapes Serbia’s power engineering market as EPS contracts anchor €160m pipeline appeared first on Serbia SEE Energy Mining News.

The average daily base price on the day-ahead market in March stood at €94.67/MWh, marking a significant 38% increase compared to February. The average euro-peak price reached €83.26/MWh, rising by 12.4% month on month.

The SEEPEX exchange was officially launched on 17 February 2016, when the traded volume was only 1,925 MWh. It is jointly owned by EMS (the Serbian electricity transmission system operator) and EPEX SPOT, with the goal of supporting the development of a competitive, transparent, and reliable electricity market in Serbia and across Southeast Europe, while also boosting trading activity in the region.

In addition to its day-ahead market, SEEPEX expanded its operations with the launch of an intraday market in July 2023, further strengthening liquidity and flexibility in electricity trading.

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He explained that the latest arrangement with Russia ensures price stability, though it is not a completely new contract but rather an extension of the existing agreement. This extension primarily addresses payment mechanisms and the interpretation of European sanctions, while also guaranteeing uninterrupted transit through third countries at least until early 2028.

A central component of Serbia’s gas pricing remains the oil-indexed formula, which helps smooth out market volatility compared to spot pricing. Since this model is based on a nine-month average, sudden spikes in European gas prices do not immediately impact domestic tariffs.

Although gas prices across Europe remain elevated due to tight supply, declining storage levels, and geopolitical tensions, Bajatović noted that Serbia is largely shielded from immediate price shocks. He also indicated that a significant drop in European prices is unlikely in the near term.

At the same time, Serbia continues to pursue supply diversification. Negotiations with Azerbaijan are expected to resume in April, with potential imports of up to 2 million cubic meters per day, although volumes remain limited by production capacity and infrastructure constraints. Alternative routes, including LNG imports via Germany, are technically feasible but currently less cost-effective.

Gas storage plays a crucial role in ensuring security of supply. Serbia currently stores around 120 million cubic meters of gas in Hungary and 478 million cubic meters at the Banatski Dvor storage facility. Expansion work at Banatski Dvor is ongoing and is expected to double daily withdrawal capacity to approximately 12 million cubic meters.

In parallel, Serbia is investing in new pipeline infrastructure, including connections toward North Macedonia, Romania, and both eastern and western parts of the country. These developments are aimed at further strengthening the resilience and flexibility of Serbia’s gas network.

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According to Mining and Energy Minister Dubravka Đedović, the initial stage of the program will include the construction of the Niš–Velika Plana gas pipeline section, along with the preparation of technical documentation for subsequent phases. This marks the beginning of a broader effort to strengthen Serbia’s energy infrastructure.

Future phases are expected to involve further expansion of the gas network, including a planned pipeline from Mokrin to Belgrade, as well as the development of new gas storage capacities and the necessary connecting infrastructure to support them.

The Minister stated that the program aims to address weak points in Serbia’s transmission system and improve the reliability of gas flows across the country. A key objective is to eliminate bottlenecks that currently limit efficient transport and distribution.

In parallel, the Government plans to enhance regional energy connectivity over the next two years through the construction of two new gas interconnectors—one with North Macedonia and another with Romania—as part of a broader strategy to diversify supply routes and strengthen energy security.

During discussions with the World Bank delegation, both sides also explored the future adaptability of Serbia’s gas infrastructure, including the potential to repurpose parts of the network for hydrogen transport as the energy transition advances.

Beyond gas infrastructure, Belgrade is seeking continued cooperation with the World Bank in the field of energy efficiency. Serbian authorities emphasized the need for ongoing support in modernizing public facilities such as schools, kindergartens, and hospitals, as well as additional programs for households.

The World Bank delegation, led by Stephanie Gill, expressed readiness to support Serbia’s priority energy investments, particularly in the gas sector, and noted that the country’s pace and level of ambition in this area stand out within the region.

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The agreement, signed in Belgrade on 15 February 2026, establishes a framework lasting two years, with the possibility of automatic renewal. It is intended to strengthen bilateral energy relations while securing long-term natural gas supplies from Azerbaijan and opening parts of the Serbian electricity market to SOCAR.

Under the deal, both governments will jointly finance the initial development phase. This includes the preparation of key project documentation such as a spatial plan, feasibility study, environmental impact assessment, and construction design. After these steps are completed, a dedicated project company will be established to oversee the development, operation, and management of the plant.

A key element of the partnership is ensuring a stable supply of Azerbaijani gas, which is expected to serve as the foundation for reliable electricity generation at the future facility.

Serbian authorities have emphasized that the project will not require additional funding from the state budget. According to planning documents, the plant is expected to be located north of the village of Krušca near Niš, although the exact location will be determined through a detailed urban development plan.

The project timeline envisions signing a construction contract in Azerbaijan in April, with completion of the plant targeted for 2029.

The post Serbia and Azerbaijan approve plan for gas-fired power plant in Niš appeared first on Serbia SEE Energy Mining News.

The introduction of sub-zero pricing is expected to improve price formation by allowing electricity values to drop below zero during periods of oversupply, creating more accurate and realistic signals for market participants. It also represents an important step toward Serbia’s future integration into the EU coupled electricity market. The implementation will depend on the successful completion of technical testing, after which the new pricing framework will apply to both the day-ahead and intraday segments of the exchange.

On the day-ahead market, the first auction featuring negative pricing is scheduled for 5 May 2026, with electricity delivery planned for 6 May. On the intraday continuous market, trading at sub-zero prices for contracts with delivery on the same date will begin after 23:00 CEST on 5 May.

The introduction of negative prices will also bring changes to SEEPEX price limits. The current minimum clearing price of 0 euros/MWh will be replaced with a floor of -500 euros/MWh on the day-ahead market. For the intraday market, the lower limit will extend to -9,999 euros/MWh, aligning with harmonized standards across the European Union.

SEEPEX also clarified the tax implications of the new system. Under Serbian VAT regulations, a negative electricity price is treated as a payment for a service rather than a standard commodity transaction. As a result, the applicable 20% VAT will apply only to domestically registered companies selling electricity at negative prices. Foreign participants will need to determine the tax treatment based on their own national regulations.

In preparation for the change, SEEPEX has advised clearing members and trading participants with active cash limits to review their exposure and adjust financial limits where necessary, given the potential impact of negative pricing on settlement and risk management.

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The extension was confirmed following a phone conversation between Serbian President Aleksandar Vučić and Russian President Vladimir Putin. Under the renewed arrangement, Serbia will continue to purchase gas based on an oil-indexed pricing formula, which keeps prices at roughly half of prevailing market levels across Europe.

This pricing structure allows Serbia to keep its import costs well below those faced by many other European countries, providing a notable economic advantage amid ongoing volatility in energy markets.

The agreement also maintains a level of flexibility in supply. Alongside the baseline volumes, Serbia retains the option to procure more than 6 million cubic meters of gas per day if domestic demand increases.

The short-term extension gives Serbia additional time to ensure energy security while broader negotiations and regional market developments continue to unfold.

The post Serbia secures short-term gas deal with Russia at below-market prices appeared first on Serbia SEE Energy Mining News.

The physical network explains the starting point. Serbia connects to Hungary through high-capacity 400 kV lines in the north, providing direct access to Central European markets. To the east, interconnections with Romania link the system to a diversified generation base, including nuclear and wind. Southward, connections with North Macedonia and Bulgaria extend into the southern Balkans and Greece, while westward links with Bosnia and Herzegovina and Montenegro complete a loop that ties together the Western Balkans. The aggregate capacity of these connections exceeds 5,000 MW, but the commercially available capacity at any given time is significantly lower, constrained by internal bottlenecks, loop flows and security margins.

This disparity between theoretical and available capacity is central to Serbia’s role. When electricity flows from Hungary into the Balkans, or from Romania towards the Adriatic, the Serbian network often becomes the limiting factor. Congestion within the system reduces available transfer capacity, creating price differentials between markets that would otherwise converge. These differentials are not static; they respond to seasonal demand, generation patterns and cross-border flows. In winter, when heating demand increases and hydropower output declines, north–south flows intensify, amplifying congestion. In summer, solar generation in southern regions creates reverse flows, again placing pressure on the network.

The financial implications of this positioning are significant. Price spreads between Hungary and Serbia, or between Serbia and Bulgaria, frequently range between €5 and €20 per megawatt-hour, expanding to €40–60/MWh during stress periods. These spreads are not anomalies; they are recurring features of the market, driven by structural constraints. For traders, they represent arbitrage opportunities. For system operators, they translate into congestion revenues. For developers, they define the value of electricity at different points within the network.

Serbia’s internal grid structure further reinforces this dynamic. The northern part of the system, anchored around substations near the Hungarian border, benefits from strong connectivity and relatively low congestion. Electricity injected into this area can be exported with minimal restriction, aligning local prices closely with Central European benchmarks. In contrast, central and southern regions face more frequent constraints. Power generated in these areas must compete for limited transmission capacity, particularly during periods of high renewable output or strong cross-border flows.

The result is a form of implicit nodal pricing within a formally zonal market. Projects located in the north capture higher prices and experience lower curtailment, while those in the south face discounts and greater volatility. This differentiation is becoming increasingly important as renewable capacity expands. Solar and wind projects are often developed in regions with favourable resources rather than optimal grid access, leading to clusters of generation in areas where transmission capacity is already constrained.

The interaction between these factors gives Serbia a degree of market power that is not immediately visible in traditional metrics. It does not set prices in the same way as a large generator or a dominant utility. Instead, it influences the conditions under which prices are formed across the region. By constraining or enabling flows between markets, the Serbian grid effectively determines the extent to which price convergence can occur. This influence is particularly evident in the corridor linking Hungary, Serbia, Bulgaria and Greece, where flows through Serbia shape price relationships across four distinct markets.

Investment in transmission infrastructure is both a response to and a driver of this dynamic. Projects such as the Trans-Balkan corridor, with estimated investments of €300–400 million, aim to increase transfer capacity between Serbia, Romania and Bosnia. Internal reinforcements, including upgrades to key substations and lines, are designed to reduce bottlenecks and improve system reliability. These investments will alter flow patterns and reduce some price differentials, but they are unlikely to eliminate them entirely. As capacity increases, new constraints emerge, often in different parts of the network.

The integration of renewable energy adds another layer of complexity. As solar and wind capacity grows, the variability of generation increases, creating new patterns of flow and congestion. During periods of high solar output, electricity from southern regions may attempt to move northward, reversing traditional flow directions. This can create congestion in parts of the network that were previously unconstrained. Conversely, during periods of low renewable output, the system may rely more heavily on imports from Hungary or Romania, again stressing different parts of the grid.

For investors, the key insight is that Serbia’s value lies not only in its generation assets but in its position within the network. Projects that align with this positioning—by locating near strong interconnections or incorporating flexibility through storage—can capture higher and more stable revenues. Those that do not may find themselves exposed to the full extent of congestion and price volatility.

Storage is becoming an important tool in this context. By absorbing excess generation in constrained areas and releasing it when transmission capacity becomes available or prices increase, battery systems can mitigate the effects of congestion. In southern Serbia, where curtailment risk is higher, storage can transform a marginal project into a viable investment by improving capture prices and reducing volatility. This aligns with broader regional trends, where storage is increasingly deployed not only for balancing but for arbitrage and congestion management.

Industrial demand also interacts with Serbia’s transit role. Energy-intensive industries located within the country benefit from access to multiple supply sources, including domestic generation and imports. Long-term contracts with renewable developers can secure stable prices and reduce exposure to carbon costs, while the grid’s connectivity provides flexibility in sourcing. For export-oriented industries, this combination of stability and flexibility is a competitive advantage.

Market participants operating through Electricity.Trade are increasingly focused on Serbia’s role as a transit hub. Trading strategies are built around the anticipation of flows through the Serbian network, with positions taken in multiple markets to capture expected spreads. Capacity rights on key interconnections are treated as strategic assets, providing access to arbitrage opportunities when congestion arises.

The regulatory environment is evolving to support greater integration, including the expansion of market coupling and the harmonisation of rules across borders. These developments will improve efficiency and reduce some barriers to trade, but they will not remove the underlying physical constraints that define the system. As long as transmission capacity remains finite and generation patterns remain uneven, Serbia’s position as a central node will continue to shape market outcomes.

The long-term trajectory suggests a gradual shift towards greater integration, but not complete convergence. Transmission investments, renewable expansion and market reforms will alter the landscape, but they will do so incrementally. In the meantime, the existing structure provides a framework within which value can be created and captured.

Serbia’s role in this framework is both structural and dynamic. It is structural in the sense that geography and network design place it at the centre of regional flows. It is dynamic in the sense that the value of this position changes with market conditions, generation patterns and investment decisions. Understanding this interplay is essential for anyone seeking to navigate the South-East European electricity market.

As the region continues to evolve, the importance of grid positioning will only increase. The ability to move electricity efficiently between markets will remain a key determinant of price formation, and those who control or access these pathways will shape the distribution of value. Serbia, by virtue of its location and network, will remain at the heart of this process, influencing not only its own market but the broader dynamics of the region.

virtu.energy

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Serbia’s Ministry of Environmental Protection has launched a screening procedure to determine whether the planned wind farm will require a full environmental impact assessment. The project is being developed by local company WPP Black Mud, which operates within the broader Greenvolt Power Group.

The proposed development, known as the Crni Kao and Rujiste wind project, is planned in the municipality of Ražanj. The site is expected to span approximately 1,134 hectares and could accommodate up to 25 wind turbines, with a total installed capacity of around 180 MW, representing a significant addition to Serbia’s renewable energy capacity.

According to the current timeline, construction could begin as early as this year, while commissioning is targeted for 2027, depending on the outcome of the permitting process and further regulatory steps.

WPP Black Mud was established in 2022 and is fully owned by Greenvolt Power Group, the Polish-based arm of the broader Greenvolt group. The company is active in renewable energy development across multiple European markets, with a growing portfolio of wind and solar projects.

The post Serbia: Greenvolt advances large wind project as environmental review begins appeared first on Serbia SEE Energy Mining News.

The contract was awarded through Serbian company Energotehnika Južna Bačka, with Andritz’s portion valued in the low double-digit million euro range. The project forms part of the wider revitalization of the Vlasina cascade, a crucial component of Serbia’s electricity system for nearly seven decades. Located on the Vrla River, the complex consists of four hydropower plants that have been in operation since 1955 and currently provide around 130 MW of installed capacity. Following the upgrade, the system is expected to gain an additional 8 MW, while significantly enhancing reliability and operational longevity.

Under the agreement, Andritz will handle the design, production, and supervision of installation and commissioning for ten turbine units, including four Pelton turbines and six Francis turbines, along with the associated equipment. The project is structured to allow electricity generation to continue throughout the reconstruction, minimizing any impact on power supply stability.

The modernization is being implemented under a program led by state-owned EPS and supported by international financial institutions, including the European Bank for Reconstruction and Development (EBRD). The goal is to improve efficiency, safety, and dependability while strengthening Serbia’s renewable energy capacity. The broader Vlasina revitalization project, valued at nearly €110 million, officially entered the implementation phase in February after a launch meeting with EPS and project partners.

In addition to Energotehnika Južna Bačka and Andritz Hydro, the project involves Gamesa Electric and subcontractor Gosa Montaža. Other participants include the Mihajlo Pupin Institute, responsible for upgrading the control system, while supervision is being carried out by the Swiss-Serbian consortium Gruner-NET Invest. The financing structure combines a €67 million EBRD loan, a €15.43 million EU grant through the Western Balkans Investment Framework (WBIF), and €27.26 million in funding from EPS.

EPS CEO Dušan Živković emphasized that the continued modernization of hydropower assets remains strategically important, stressing the need to adhere to the agreed implementation timeline. He noted that while the Vlasina system has a nominal capacity of 129 MW, the complexity of the project lies in upgrading four separate plants and ten generating units that have been operating for more than 70 years.

The Vlasina hydropower plants hold a unique position within EPS’s generation portfolio, operating in a cascade system that produces electricity in successive stages. This configuration makes them an important source of peak-load generation and a vital component of Serbia’s electricity system.

The post Serbia: Andritz to supply turbines for modernization of Vlasina hydropower cascade project appeared first on Serbia SEE Energy Mining News.

From January 2026, electricity exported from Serbia into EU markets will be subject to CBAM reporting and, progressively, financial obligations linked to embedded emissions. For a system still dominated by lignite generation, this introduces a material cost layer that directly impacts export competitiveness.

Serbia’s generation mix remains heavily carbon-intensive, with around 61% lignite, roughly 5% gas, and just over 30% low-carbon sources, primarily hydro. Under current CBAM methodology, default emission factors are applied based on the fossil portion of the exporting system, meaning that most Serbian exports will be treated as high-emission electricity unless explicitly proven otherwise.

At current EU ETS levels, this translates into a significant carbon cost overlay. With allowance prices in the range of €65–95/tCO₂, Serbian electricity exports face an additional burden of approximately €65–95/MWh under a high-emission default case. Even when using a system-average emission factor, the implied carbon cost still ranges between €40–60/MWh.

Against regional wholesale prices near €100/MWh, the carbon component is no longer marginal. It can eliminate most export margins for coal-based generation, particularly during normal market conditions. As a result, Serbian exports into EU markets are expected to become increasingly limited to high-price hours, system stress periods, or transactions backed by lower-carbon supply.

The shift effectively removes the historical advantage of Serbian coal-based generation as a low-cost export source. Instead, electricity trade becomes dependent on carbon-adjusted competitiveness, aligning Serbia’s export economics more closely with EU internal market dynamics.

On the import side, CBAM does not directly apply to electricity entering Serbia. However, the mechanism still exerts upward pressure on import prices through regional market coupling.

Neighbouring EU markets such as Romania and Hungary already reflect full EU ETS carbon pricing in their wholesale power prices. As a result, Serbian import prices are increasingly anchored to carbon-inclusive benchmarks, rather than pure energy costs.

Recent regional price data illustrate this convergence. Romania’s day-ahead market averaged around €114/MWh in 2025, while Serbia’s rolling annual base price on SEEPEX stood close to €99/MWh. As carbon costs become more deeply embedded in neighbouring markets, the import parity price for Serbia is expected to rise structurally.

A simplified pass-through model highlights the scale of the effect. Assuming partial transmission of EU carbon costs into regional prices, Serbian import benchmarks could increase by roughly €15–70/MWh, depending on carbon price levels and market conditions. This reflects indirect carbon pricing rather than a direct CBAM charge, but the economic impact is comparable.

The result is a dual pressure on the Serbian market: exports become less competitive due to carbon costs, while imports become more expensive as neighbouring systems internalise emissions pricing.

Trading strategies across the region are already adapting. The focus is shifting away from straightforward geographical arbitrage toward short-term optimisation, balancing markets and carbon-aware portfolio management. Hourly price spreads, congestion constraints and renewable intermittency are becoming more important drivers of value than average cross-border differentials.

At the same time, CBAM is accelerating demand for traceable low-carbon electricity. Industrial consumers exposed to EU carbon costs are increasingly seeking renewable-backed supply, either through direct power purchase agreements or guarantees of origin. This is beginning to create a premium segment for “CBAM-compliant” electricity, where emissions can be demonstrated and minimised.

For Serbia, this introduces a clear structural signal for investment. Renewable generation, particularly when combined with storage or flexible dispatch, becomes not only a cost-competitive option but also a necessity for maintaining export relevance and supporting industrial competitiveness.

The ability to provide verified low-carbon electricity is emerging as a key differentiator in regional power markets. In contrast, coal-based generation is likely to remain economically viable primarily within the domestic system or in non-EU export corridors where carbon pricing is not yet enforced.

CBAM marks a decisive shift in Southeast Europe’s electricity trading landscape. For Serbia, the transition moves the market from a volume-driven export model toward one defined by carbon-adjusted pricing, portfolio flexibility and emissions transparency, with long-term implications for both trading behaviour and generation investment.

The post CBAM set to reshape Serbian power trade as carbon costs redefine export margins appeared first on Serbia SEE Energy Mining News.

Following a meeting with NIS CEO Kirill Tyurdenev, Mining and Energy Minister Dubravka Đedovic stated that the company has already raised crude processing volumes and plans to further increase output in April to secure adequate supplies of all petroleum products for the domestic market.

She emphasized that the Government remains committed to ensuring an uninterrupted fuel supply across the country, including for smaller fuel stations, and expects both large and small customers purchasing from NIS to continue receiving deliveries without disruption.

The Minister also noted that the operational license granted to NIS by the US Office of Foreign Assets Control (OFAC) remains valid until 17 April. In addition, Serbia has released 40,000 tons of diesel from its strategic reserves to support oil companies as part of broader market stabilization measures.

According to the Ministry, the Government has introduced several emergency measures to limit the impact of market disruptions, including a ban on exports of diesel, gasoline, and crude oil, a 20% reduction in excise duties, and the distribution of state diesel stocks to fuel suppliers.

Minister Đedovic said these steps have so far helped prevent shortages and excessive price increases, noting that all fuel produced by NIS is currently being directed to the domestic market and that overall demand is being met. She also pointed to a significant decline in imports of refined products due to rising oil prices and highlighted that the market continues to face multiple pressures, including instability from conflicts in the Middle East and Ukraine, as well as prolonged sanctions-related challenges affecting NIS.

The post Serbia boosts NIS output and uses strategic reserves to stabilize fuel market appeared first on Serbia SEE Energy Mining News.

The proposed financing package includes a senior secured loan of up to 36.2 million euros, alongside a guarantee facility of up to 2.52 million euros. This guarantee is intended to support the project’s obligations under Serbia’s Contract for Difference (CfD) mechanism, which provides long-term revenue stability for renewable energy projects. A final decision on the loan is expected by 29 April.

The Solarina project, located in the Zaječar area, represents a total investment of approximately 155.7 million euros. Once operational, it is expected to generate significant environmental benefits, with annual carbon dioxide savings exceeding 230,000 tons, contributing to Serbia’s decarbonization goals.

The development will span around 320 hectares and will include three solar generation zones, a transformer substation, and underground cable infrastructure. The project also features a detailed grid connection, including a 16.8-kilometer 110 kV overhead line and 1.45 kilometers of underground cables connecting to the existing PV Bor 2 substation.

CWP Europe, which specializes in renewable energy across southeastern Europe, reported having 938 MW of projects either operational or under construction by the end of 2025. The company also maintains a development pipeline of around 7 GW across ten countries, including Serbia and neighboring markets, highlighting its growing presence in the regional energy transition.

The post Serbia: Solarina project nears financial close with EBRD backing appeared first on Serbia SEE Energy Mining News.

According to NIS, all of its petrol stations across Serbia remain fully operational and stocked with all fuel types, with no disruptions reported in sales or distribution. The company stated that it has taken the necessary measures to preserve business stability, secure crude procurement, and maintain reliable deliveries to the domestic market.

While concerns have increased over the potential impact of the Middle East conflict on oil supply and fuel prices, NIS has indicated that it continues to operate in line with government regulations, including Serbia’s rules on limiting petroleum product prices. The situation remains manageable largely because the Pančevo refinery has undergone modernization, enabling it to process a broader range of crude grades. This flexibility allows NIS to purchase oil from whichever markets remain accessible and commercially viable.

Historical data show that Serbia has long relied heavily on imported crude, with domestic production covering only a small share of total demand. Although many assumed that Russian oil dominated NIS’s supply mix following Gazprom’s acquisition, imported volumes were primarily sourced from Iraq for years, with Russia representing a smaller but still significant portion, alongside Kazakhstan and Norway.

In 2022, Serbia imported more than 3.2 million tons of crude oil, with Iraq accounting for the largest share. However, the import structure shifted after the outbreak of the war in Ukraine, when NIS temporarily increased Russian oil purchases while reducing volumes from Iraq. This changed again after the European Union introduced its sixth package of sanctions against Russia, banning the purchase, import, and transport of Russian oil. Serbia did not receive an exemption, effectively forcing NIS to stop importing crude from Russia and further diversify its sourcing strategy.

The post Serbia: NIS diversifies crude supply amid geopolitical tensions and EU sanctions appeared first on Serbia SEE Energy Mining News.

The new deadline is now set for 22 May, granted just hours before the original 24 March deadline, which had been linked to the required restructuring of NIS’s ownership. The Serbian company has faced scrutiny due to its majority stake being held by Russian entities, placing it under the scope of US sanctions targeting Russia’s energy sector.

Under the sanctions framework managed by the US Office of Foreign Assets Control (OFAC), NIS was required to resolve the future of shares held by Gazprom and GazpromNeft, which together control a majority of the Serbian energy group. Earlier this year, MOL signed a binding agreement with the Russian shareholders to acquire their combined stake, with UAE-based ADNOC expected to join the deal as a minority partner. The latest US decision provides additional time for the parties to finalize the sale agreement and complete the necessary transaction documents.

The extension also allows US financial institutions to participate in the transaction, a key step in completing a deal of this scale.

If finalized, the acquisition would transfer 56.15 % of NIS from the Gazprom group to MOL, granting the Hungarian company a dominant ownership position and significant management influence over the Serbian firm. NIS plays a strategically important role in the regional energy market, including ownership of Serbia’s sole oil refinery.

The transaction still requires approval from both the US Treasury and the Serbian Government before it can be completed.

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At its core, the project is relatively straightforward. The pipeline will connect Serbia’s oil system—centred on the NIS refinery in Pančevo—to Hungary’s segment of the Druzhba pipeline, creating a new northbound corridor for crude imports. The Serbian section is expected to span approximately 128 kilometres, with an additional 190 kilometres on Hungarian territory, and a projected throughput capacity of around 4–5 million tonnes per year. Total investment is estimated in the range of €300–350 million, with implementation led by Transnafta on the Serbian side and MOL Group in Hungary.

Yet the strategic significance of the pipeline lies far beyond its physical specifications. Its acceleration reflects a deeper reordering of energy priorities across Central and South-East Europe, where recent disruptions have exposed the fragility of existing supply chains.

The immediate catalyst came in early 2026, when flows through the Druzhba system were temporarily halted following infrastructure damage linked to the war in Ukraine. The interruption reverberated quickly across Hungary and Slovakia, forcing emergency rerouting and drawing down strategic reserves. While the disruption was temporary, it underscored a critical point: even legacy pipelines—long treated as stable backbones of the regional energy system—can no longer be assumed to provide uninterrupted supply.

For Serbia, the episode reinforced an already evident structural weakness. The country remains heavily dependent on a single external corridor for crude imports via the JANAF pipeline in Croatia, combined with a single domestic processing hub at Pančevo. That concentration risk has been amplified in recent years by geopolitical tensions and sanctions dynamics, which have periodically complicated access to Russian-origin crude and introduced uncertainty into transit arrangements.

In that context, the Serbia–Hungary pipeline is less an expansion project than a redundancy mechanism. It offers an alternative inland route, anchored in bilateral coordination rather than third-country transit, and reduces reliance on infrastructure subject to external political leverage. The logic closely mirrors Serbia’s earlier pivot in the gas sector, where the commissioning of TurkStream connections created a parallel supply architecture alongside traditional routes.

Hungary, for its part, brings a distinct set of incentives to the project. As one of the few European Union member states continuing to import significant volumes of Russian crude, Budapest has been actively working to secure and extend its access to eastern supply channels. Strengthening the southbound link to Serbia not only supports the operational stability of the MOL refining system, but also positions Hungary as a critical intermediary in the region’s evolving energy map.

This dual dynamic—Serbia seeking diversification of routes, Hungary consolidating its role as a supply hub—has created a shared interest in accelerating execution timelines. Officials on both sides have signalled that permitting and preparatory phases are being streamlined, with construction potentially beginning as early as 2026 under an accelerated scenario.

Even so, the timeline remains contingent on several variables. Environmental approvals, financing coordination between Transnafta and MOL, and broader geopolitical developments—particularly those affecting transit through Ukraine—will all shape the pace of delivery. The base case still points to commissioning in the 2027–2028 window, though partial early operation cannot be ruled out if project milestones are met ahead of schedule.

Beyond immediate supply security, the pipeline carries wider implications for Serbia’s energy market structure. The introduction of a second major import corridor would alter the balance of negotiating power with transit operators, particularly Croatia’s JANAF system, where tariff and access terms have long been a point of sensitivity. A dual-route configuration provides not only physical flexibility, but also commercial leverage in securing more favourable conditions.

For the domestic economy, the stabilisation of crude supply feeds directly into industrial cost structures. The Pančevo refinery, operated by NIS, underpins fuel availability across transport, manufacturing and agriculture. Any disruption to feedstock flows has immediate downstream effects on pricing and production. In an environment where carbon border measures and energy costs are increasingly shaping export competitiveness, predictability in input supply becomes a critical variable.

At a regional level, the project forms part of a broader shift in how energy systems across South-East Europe are being configured. Traditional westward-oriented routes—anchored in Adriatic infrastructure—are being complemented, and in some cases partially displaced, by north–south corridors linked to Central Europe. This reflects not only geopolitical alignment, but also a recognition that single-route dependency is no longer tenable.

The result is the emergence of parallel supply architectures, where multiple pathways coexist, each carrying different political and commercial characteristics. Gas flows through TurkStream, oil through both JANAF and Druzhba-linked systems, and increasing interconnection in electricity markets all point to a more fragmented but also more resilient network.

In this evolving landscape, Serbia is positioning itself less as a terminal market and more as a flexible node within a wider system. The capacity to switch between supply routes, optimise sourcing strategies and maintain continuity under stress conditions is becoming as valuable as the underlying infrastructure itself.

The acceleration of the Serbia–Hungary oil pipeline should therefore be read not simply as a bilateral infrastructure decision, but as a signal of how the region is recalibrating its approach to energy security. The emphasis has shifted decisively—from minimising costs in stable conditions to ensuring continuity under uncertain ones.

The post Serbia and Hungary accelerate oil pipeline plans as regional supply risks intensify appeared first on Serbia SEE Energy Mining News.

While the visit itself was framed around knowledge exchange, institutional cooperation and geological expertise, its significance lies in the timing. It comes as both Berlin and Brussels accelerate efforts to secure access to critical raw materials, particularly those linked to electrification, battery production and industrial decarbonisation.

Germany’s engagement with Serbia in this sector is not new, but it is becoming more structured. Over the past year, bilateral discussions have increasingly centred on lithium, copper and broader mineral potential, alongside the development of environmentally compliant extraction frameworks and downstream value chains. 

The presence of a German delegation focused specifically on geology signals a shift from political agreements toward technical alignment and project-level collaboration—a necessary step if resource partnerships are to translate into bankable industrial flows.

From strategic agreements to technical execution

The Serbia–Germany relationship in raw materials has evolved rapidly since the signing of broader cooperation frameworks tied to battery value chains and electric mobility. These agreements positioned Serbia as a potential upstream supplier within Europe’s industrial ecosystem, particularly in the context of lithium.

However, translating political alignment into operational outcomes requires a deeper layer of engagement. Geological surveys, resource validation, environmental standards and permitting frameworks all need to be harmonised with European expectations.

This is where the German delegation’s visit becomes relevant. It reflects an attempt to bridge the gap between resource potential and industrial execution, bringing together:

• Geological institutes
• Mining authorities
• Academic and research institutions
• Regulatory bodies

Such cooperation is essential in a sector where data quality, reserve classification and environmental compliance directly determine whether projects can attract financing and move into construction.

Serbia’s resource base draws renewed attention

Serbia’s geological profile has long been recognised as diverse, with deposits spanning copper, lithium, boron, gold and industrial minerals, supported by a complex tectonic structure linking the Dinarides, Carpathians and Balkan metallogenic belts. 

Recent policy developments have reinforced this potential. The government has adopted a long-term strategy for mineral resources extending to 2040 with projections to 2050, explicitly prioritising critical and strategic raw materials and aiming to reduce import dependence while strengthening domestic value chains. 

This policy framework aligns closely with EU priorities under the Critical Raw Materials Act, effectively positioning Serbia as a nearshore supply partner rather than a peripheral mining jurisdiction.

Germany’s industrial imperative

For Germany, the motivation is clear. Its industrial base—particularly automotive manufacturing—faces a structural challenge: securing reliable access to raw materials essential for electric vehicles, renewable technologies and advanced manufacturing.

Lithium remains the most visible example. German policymakers have repeatedly emphasised the need for diversified supply chains within Europe and its immediate neighbourhood, combining domestic projects with partnerships in countries such as Serbia. 

At the same time, German industry is increasingly sensitive to:

• ESG compliance
• Supply chain traceability
• Political and regulatory stability

This creates a dual requirement: securing material flows while ensuring that extraction meets European environmental and social standards.

The delegation’s focus on geology and mining cooperation therefore reflects not only resource access, but also standard-setting and risk mitigation.

Between opportunity and constraint

The expansion of German–Serbian cooperation in mining is unfolding against a complex domestic backdrop. Resource development in Serbia—particularly lithium—has triggered significant public debate, protests and environmental scrutiny, highlighting the tension between economic opportunity and social acceptance.

Previous projects, such as the Jadar lithium development, have illustrated the challenges of securing a social licence to operate, with environmental concerns and community opposition capable of delaying or reshaping investment timelines. 

For international partners, including Germany, this introduces an additional layer of risk. Technical cooperation alone is insufficient if projects cannot achieve regulatory clarity and societal acceptance.

This is likely one of the underlying drivers of the current engagement model. By focusing on geological cooperation, research and institutional alignment, both sides are effectively building a foundation that precedes large-scale extraction.

Toward a processing and integration model

What is increasingly evident is that Serbia’s role in Europe’s raw materials system may not follow a traditional mining trajectory. Instead, the emerging model points toward a hybrid position combining extraction, processing and engineering services, integrated into wider European supply chains.

This reflects both structural constraints and competitive advantages. Serbia offers:

• Established mining and metallurgical base (Bor, Majdanpek)
• Competitive industrial costs
• Flexible energy system relative to EU core markets
• Geographic proximity to European manufacturing hubs

Rather than competing with large-scale producers, Serbia is positioning itself as a processing and execution hub, capable of stabilising material flows feeding European industry. 

German engagement in geology and mining can therefore be seen as part of a broader effort to anchor this role within EU-aligned industrial frameworks.

Strategic implications for investors

The visit of a German delegation, while technical in form, signals several underlying shifts relevant to capital allocation.

First, it reinforces the view that Europe is moving from policy design to supply chain construction, with tangible efforts to secure upstream resources within its extended industrial perimeter.

Second, it highlights the growing importance of cross-border technical alignment, where geological data, environmental standards and permitting processes must converge to enable project financing.

Third, it underscores the emergence of Serbia as a strategic interface between EU industry and regional resource potential, particularly as supply diversification becomes a priority.

For investors, the implication is that value creation in the sector will increasingly depend not only on resource ownership, but on integration into policy-backed, contract-driven supply chains.

A gradual but structural shift

The presence of German experts in Serbia’s geology and mining sector marks another step in a gradual but unmistakable transition. Europe’s raw materials strategy is no longer confined to internal production or distant imports; it is expanding into a network of closely aligned partner countries, where technical cooperation precedes industrial integration.

In that architecture, Serbia is not yet a dominant supplier, but it is becoming an increasingly relevant node—one where geology, policy and industrial demand intersect.

The significance of such visits lies precisely in that intersection. They are less about immediate project announcements and more about building the conditions under which future projects—whether in lithium, copper or other critical materials—can move from geological potential to bankable, EU-aligned industrial assets.

The post German delegation signals deepening Serbia–EU alignment in geology and mining appeared first on Serbia SEE Energy Mining News.

The project also includes a long-term maintenance agreement spanning 30 years, with the option to extend it by an additional five years. The turbines will be equipped with anti-icing systems, ensuring stable performance even under challenging weather conditions and improving overall reliability.

According to the timeline, installation of the first turbine is scheduled for April 2027, while electricity generation is expected to begin in July the same year. Once fully operational, the wind farm is projected to produce more than 270 GWh annually, contributing significantly to Serbia’s clean energy supply.

The Jasikovo project has already secured the necessary construction permits, covering both turbine installation and supporting infrastructure. Plans include the development of a 33/110 kV substation, a 10 kV facility, and an internal cable network extending roughly 16 kilometers across the municipalities of Majdanpek and Žagubica.

The post Serbia: Nordex to supply turbines for Jasikovo wind farm appeared first on Serbia SEE Energy Mining News.

At the same time, MOL Group is reportedly exploring alternative scenarios, including discussions with ADNOC about acquiring a minority stake in NIS. This reflects broader strategic interest in reshaping the company’s ownership structure amid shifting geopolitical and market dynamics.

Developments in US policy could also play a role. Signals from Washington indicate that certain shipments of Russian crude already in transit may be exempt from sanctions, potentially easing pressure on global oil markets and slowing recent price increases linked to instability in the Middle East.

These dynamics are particularly significant for Serbia, as its refining system has traditionally depended on Russian Urals crude. However, supply routes have increasingly diversified, with alternative deliveries being secured via the JANAF pipeline.

Meanwhile, the extension of the operating license granted to NIS by the Office of Foreign Assets Control (OFAC) until 17 April is seen as a stabilizing factor. The decision is expected to help ensure continuity of fuel supply, both in Serbia and across the wider region.

The post Serbia: Talks intensify over NIS ownership as MOL explores stake acquisition appeared first on Serbia SEE Energy Mining News.

The 70MW Jasikovo wind farm, located in the Bor–Zaječar grid zone, is being developed as a utility-scale installation integrating modern wind turbine technology supplied by Nordex, grid-compliant substation infrastructure and full supervisory control systems aligned with Serbia’s transmission requirements. The project forms part of a broader shift in the Serbian power system toward diversified renewable capacity, particularly in areas historically linked to mining and heavy industry consumption.

Under its mandate, Clarion Engineer is responsible for full Owner’s Engineer services, including design verification, EPC supervision, construction monitoring and commissioning oversight. Acting as the investor’s independent technical representative, Clarion is tasked with ensuring compliance with Serbian grid codes, FIDIC-based contractual structures and lender-driven technical standards, while maintaining strict control over schedule, cost and execution quality.

The scope includes continuous on-site supervision of civil, mechanical and electrical works, as well as verification of high-voltage infrastructure and grid connection systems in coordination with EMS Serbia. Particular emphasis is being placed on testing and validation protocols during commissioning, including LVRT/HVRT compliance, SCADA integration and dispatch readiness, all of which are critical for long-term operational stability and market participation.

The Jasikovo appointment comes as Clarion Engineer continues to scale its presence across the region’s renewable energy sector. The company is currently engaged on a 150MW wind project under active construction, where it is delivering comparable Owner’s Engineer and supervisory services, reinforcing its role in ensuring bankable execution across complex EPC environments.

In parallel, Clarion is supporting Investor as Owners Engineer on a hybrid solar-plus-battery storage project, reflecting the next phase of energy system evolution in South-East Europe. The integration of solar generation with battery storage is increasingly critical in markets such as Serbia, where grid flexibility, balancing capacity and curtailment management are becoming central challenges as renewable penetration rises.

Beyond project delivery, Clarion Engineer has positioned itself within the emerging regulatory and compliance layer of the energy transition. The company is actively supporting clients on Carbon Border Adjustment Mechanism (CBAM) implementation and ESG reporting frameworks, working in cooperation with EU-based partners and verification bodies. This includes plant-level emissions analysis, compliance structuring and alignment with European standards for carbon reporting and sustainability disclosure.

This dual capability—combining engineering oversight with regulatory and ESG advisory—reflects a broader shift in how energy and industrial projects are financed and evaluated. Lenders and investors are increasingly requiring integrated technical and compliance assurance, where engineering performance, carbon exposure and ESG metrics are assessed as part of a unified risk framework.

Clarion’s client base spans developers, institutional investors and financial lenders, with services tailored to support project bankability, due diligence processes and ongoing operational compliance. In practice, this involves not only technical supervision but also structured reporting, risk assessment and interface management across multiple stakeholders, including EPC contractors, grid operators and regulatory authorities.

The expansion of Clarion’s portfolio aligns with the rapid growth of renewable energy pipelines across South-East Europe, where projects are becoming larger, more technically complex and more tightly integrated with European regulatory frameworks. As a result, the role of the Owner’s Engineer is evolving from a purely technical function into a broader project assurance and governance platform, bridging engineering, finance and compliance.

Within this context, the Jasikovo wind farm represents both a project-specific mandate and a continuation of a wider regional strategy. By combining on-site supervisory expertise, grid integration knowledge and ESG-aligned advisory services, Clarion Engineer is positioning itself at the intersection of infrastructure delivery and regulatory transformation.

As construction progresses, the focus remains on ensuring that Jasikovo is delivered to full technical and regulatory compliance, with operational performance aligned to investor expectations and lender requirements. At the same time, the company’s expanding engagement across wind, solar and battery storage projects signals a deeper integration into the region’s evolving energy landscape—where execution discipline and compliance readiness are increasingly defining project success.

Clarion.Engineer

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The planned acquisition process will cover multiple cadastral zones across the municipalities of Nova Varoš and Priboj, including areas such as Radoinja, Rutoši, Seništa, Čelice, Kratovo, and Pribojske Čelice. All procedures will be carried out in accordance with the relevant spatial planning documents governing the Bistrica project and the nearby Poteć hydropower system, ensuring alignment with existing spatial and regulatory frameworks.

State-owned power utility Elektroprivreda Srbije has been appointed as the beneficiary of the expropriation, meaning that it will take control of the land and facilities once the legal process is completed, in order to proceed with construction activities. This designation places EPS at the center of project execution and future asset management.

The HPP Bistrica project forms part of Serbia’s broader strategy to strengthen its electricity system, particularly by increasing flexibility and reliability through pump-storage capacity. Authorities expect the facility to play a significant role in balancing supply and improving overall system performance, contributing to enhanced grid stability and integration of variable renewable sources. Preparatory works for the project are expected to begin within the year, marking the transition from planning to on-the-ground implementation.

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Construction activities are scheduled to start in 2026, marking the first major step in developing the interconnector. Earlier projections had pointed to a possible completion in 2027, but updated expectations indicate a slight delay, highlighting the challenges often associated with large-scale cross-border energy developments and permitting processes.

Once finalized, the interconnector will have an annual capacity of around 1.5 billion cubic meters and will extend further south toward Greece. This route is intended to provide access to alternative gas sources, including supplies from the Trans-Anatolian (TANAP) pipeline as well as liquefied natural gas delivered through Greek terminals, thereby enhancing supply diversification.

The project is part of a broader effort to reduce dependence on a limited number of supply routes and improve regional resilience. Authorities emphasize that stronger regional integration is essential for achieving long-term energy security, particularly in a context of evolving global gas markets and geopolitical uncertainty.

In this framework, Serbia, North Macedonia, Greece, and Bulgaria are working to deepen coordination, with a focus on infrastructure development and information exchange. Closer cooperation among these countries is seen as a key factor in strengthening the overall energy system resilience across southeastern Europe.

Serbia has already taken steps to secure future supplies, including booking long-term gas capacity at the Greek LNG terminal in Alexandroupoli, where it has reserved 300 million cubic meters annually for a decade. This move supports its broader strategy of integrating into regional LNG and pipeline networks while ensuring more stable and flexible access to gas supplies.

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According to the Ministry of Mining and Energy, the country’s main refinery in Pančevo continues to operate normally, ensuring uninterrupted supply of fuel. Officials stress that there is no shortage of petroleum products and that consumers do not need to create additional reserves. The situation has been further complicated by disruptions in crude oil deliveries, which had been absent for an extended period, as well as ongoing instability in the Middle East. Despite these challenges, the domestic market has remained supplied without major disturbances, reflecting a relatively resilient supply chain.

To reinforce stability, the Government has already implemented several measures, including a reduction in fuel excise duties and the planned release of significant diesel volumes from strategic reserves. Additional steps are expected if needed, as authorities aim to keep both supply and prices under control in a turbulent global environment, while maintaining market continuity and energy security.

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At the centre of the disagreement lies a fundamental mismatch between ambition and infrastructure. Serbia today operates a power system dominated by legacy lignite assets under Elektroprivreda Srbije (EPS), with thermal capacity still accounting for roughly 65–70% of generation, complemented by hydropower and a rapidly growing but still secondary renewable segment. The country has no operating nuclear facilities, no independent nuclear regulator with full operational capacity, no fuel-cycle infrastructure, and no long-term waste management solution. Against that baseline, the introduction of SMRs is not an incremental upgrade. It is a systemic leap.

SANU’s Energy Committee has framed this leap in stark terms. Its assessment suggests that SMRs, despite their branding as flexible and modular, remain commercially unproven in large-scale civilian deployment, with cost structures that remain opaque and, in many cases, higher than conventional alternatives. The critique is not limited to capital expenditure alone. It extends into lifecycle economics, where smaller units tend to lose the scale efficiencies that underpin traditional nuclear economics.

Globally, SMR capital costs are still being established, but current indicative ranges suggest €4,000–€8,000 per kW installed, depending on design and localisation. For a hypothetical 300 MW SMR unit, this translates into €1.2–2.4 billion per reactor, excluding financing costs, regulatory build-out, grid integration and waste management infrastructure. In a Serbian context, where total annual energy-sector investment has historically fluctuated in the €1–2 billion range, a single SMR project would absorb a disproportionate share of national capital allocation.

That imbalance becomes even more pronounced when financing structures are considered. Nuclear projects, including SMRs, require long-duration, low-cost capital, typically backed by sovereign guarantees or regulated asset base models. Serbia’s sovereign borrowing costs, while improved in recent years, still reflect emerging-market risk premiums. Eurobond yields have traded in the 5–7% range, significantly above the financing assumptions underpinning nuclear projects in Western Europe. The result is a direct escalation in levelised cost of electricity, pushing nuclear generation into a range that is difficult to reconcile with domestic tariff structures.

SANU’s intervention also highlights a less visible but equally consequential dimension: institutional capacity. Building a nuclear programme is not a construction project. It is a multi-decade institutional commitment involving regulatory oversight, safety culture, training pipelines and international compliance frameworks. Even SMRs, often presented as simplified systems, require the same foundational architecture as large reactors. The International Atomic Energy Agency (IAEA) has consistently emphasised that newcomer countries must establish full-scope regulatory and safety frameworks before deployment, a process that typically spans 10–15 years.

In that light, Serbia’s nuclear ambitions intersect with a timeline mismatch. The country’s immediate challenge is not long-term baseload scarcity but medium-term system balancing. As renewable capacity expands—particularly solar projects with capacity factors of 15–20% and wind projects reaching 30–40%—the grid increasingly requires flexibility, storage and dispatch optimisation. The key constraint is not the absence of generation capacity per se, but the lack of system flexibility to manage variability.

This is where the opportunity cost of nuclear investment becomes more tangible. A €2 billion allocation into SMRs could alternatively finance a diversified portfolio of assets delivering immediate system benefits. Utility-scale solar in Serbia is currently being developed at €600,000–€900,000 per MW, while onshore wind ranges between €1.2–1.6 million per MW. Battery energy storage systems (BESS), increasingly critical for balancing, are entering the market at €400,000–€700,000 per MWh installed, depending on configuration and duration.

In practical terms, the capital required for a single SMR could fund a portfolio equivalent to 1,500–2,000 MW of solar, 500–800 MW of wind, and 500–1,000 MWh of storage, fundamentally reshaping Serbia’s generation mix within a 3–5 year execution window. These assets also align more directly with EU financing frameworks, including EIB, EBRD and IPA III funding, where renewable and grid-modernisation projects benefit from concessional financing and grant components that significantly reduce cost of capital.

SANU’s argument on waste management further complicates the nuclear proposition. Serbia would not only need to build reactors but also establish a long-term strategy for spent fuel and radioactive waste. This includes interim storage, transportation, and eventual disposal, all under strict international oversight. For countries with established nuclear fleets, these systems have evolved over decades. For Serbia, they would need to be created from the ground up, adding both financial and political complexity.

The geopolitical dimension is equally relevant. Nuclear technology is not a neutral commodity. It is tied to supply chains, fuel provision, maintenance contracts and long-term strategic partnerships. Whether sourced from Western vendors, Korean consortia or other providers, each pathway introduces dependencies that extend well beyond energy policy into foreign policy alignment. In contrast, renewable energy supply chains—while not entirely free of geopolitical exposure—offer a broader and more diversified vendor landscape.

Yet the political logic behind Serbia’s nuclear interest remains understandable. Electricity demand is expected to rise as industrial activity expands, particularly in sectors exposed to CBAM-related decarbonisation pressures. Large consumers, including copper production in Bor, steel manufacturing in Smederevo and chemical processing clusters, will require stable, low-carbon electricity to maintain export competitiveness. Nuclear power, in theory, offers precisely that: firm, low-carbon baseload capacity.

The challenge is timing. SMRs are unlikely to deliver commercial electricity in Serbia before the mid-2030s at the earliest, given the lead time required for regulatory development, site selection, licensing and construction. By contrast, Serbia’s decarbonisation pressures—both from EU policy alignment and industrial competitiveness—are already materialising in the 2026–2030 window.

This creates a structural gap between the technology under consideration and the problem it is meant to solve. SANU’s critique effectively argues that Serbia risks investing in a long-term solution that does not address its immediate system needs, while diverting capital from technologies that can.

From an investor perspective, the contrast is even sharper. Renewable projects in Serbia are increasingly structured around long-term power purchase agreements (PPAs) with industrial offtakers, creating bankable revenue streams that support project financing. The emergence of CBAM-exposed industries as creditworthy offtakers strengthens this model, enabling higher leverage and lower cost of capital. Nuclear projects, by comparison, would require state-backed revenue frameworks, exposing public finances to long-term liabilities.

There is also a question of grid integration. Serbia’s transmission system, operated by EMS (Elektromreža Srbije), is already undergoing upgrades to accommodate increased cross-border flows and renewable integration. Large nuclear units, even modular ones, introduce concentrated generation nodes that require robust grid reinforcement. In contrast, distributed renewable assets can be integrated more incrementally, aligning investment with grid expansion.

None of this eliminates nuclear energy from Serbia’s strategic horizon. What SANU’s intervention does is shift the discussion from inevitability to sequencing. Nuclear power may still emerge as a long-term component of Serbia’s energy mix, particularly if SMR technologies achieve cost reductions and commercial maturity over the next decade. But the current question is not whether Serbia should ever build nuclear capacity. It is whether now is the right moment to commit to a pathway that demands substantial capital, institutional transformation and long-term risk absorption.

As the debate evolves, it is becoming less about technology preference and more about capital efficiency. Serbia is entering a phase where every major energy investment carries system-wide implications, from grid stability to industrial competitiveness and sovereign balance sheet exposure. SANU’s position introduces a disciplined counterweight to political momentum, insisting that energy policy must remain anchored in economic realism and institutional readiness.

The outcome of this debate will shape not only Serbia’s generation mix but also its broader economic trajectory. In a region where energy systems are being rapidly reconfigured under the dual pressures of decarbonisation and industrial policy, the ability to allocate capital efficiently may prove as important as the technologies themselves.

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The underlying driver is clear. Serbia’s energy-intensive industries—steel, cement, fertilisers, chemicals—are increasingly exposed to carbon-adjusted pricing through their exports into the European Union. Electricity sourcing is no longer just a cost line. It is directly embedded in product competitiveness. This is transforming how these industries approach energy procurement and, in turn, how renewable projects are financed.

From electricity buyer to credit anchor

In the traditional Serbian market, industrial consumers purchased electricity primarily through supply contracts indexed to wholesale prices or bilateral arrangements with utilities. These contracts were often short to medium term, with flexibility built in to reflect production cycles and price movements.

For lenders, this type of demand offered limited comfort. Electricity was a variable cost, and contracts could be renegotiated if market conditions shifted.

That logic is now changing.

An industrial exporter in Serbia that fails to secure low-carbon electricity faces a measurable financial exposure. Indirect emissions linked to electricity consumption can translate into €20–40 per tonne of product in carbon-related costs when exporting to the EU. For a large steel or fertiliser producer, this is not a marginal adjustment—it can determine whether export margins remain positive.

This creates a new form of demand.

Electricity becomes a non-discretionary input tied to export viability, and renewable sourcing becomes a strategic requirement rather than a cost optimisation tool.

For lenders, this is critical. The offtaker is no longer simply buying electricity. It is securing continued access to its core market.

Why lenders are reassessing Serbia

This shift is already influencing how lenders evaluate renewable projects in Serbia.

Historically, bankability was constrained by:

• High merchant exposure

• Limited long-term PPAs

• Volatile SEEPEX price environment

Today, projects backed by industrial offtake are being viewed differently.

From a credit perspective, three elements stand out.

First, contract durability improves. An industrial buyer exposed to carbon-adjusted export costs has a strong incentive to maintain renewable supply agreements. Defaulting on a PPA does not simply mean losing electricity; it means increasing production costs and weakening competitiveness in EU markets.

Second, cash flow visibility increases. Long-term PPAs—typically 10–15 years—provide predictable revenue streams, allowing lenders to model debt service with greater confidence.

Third, counterparty risk is redefined. Large industrial companies in Serbia, particularly those integrated into European supply chains, offer stronger credit profiles than purely merchant market exposure.

As a result, lenders are becoming more willing to:

• Increase leverage to 65–75% of CAPEX

• Extend tenors to 12–15 years

• Offer more competitive pricing

This represents a significant improvement compared to earlier renewable projects in the market.

Structuring the new industrial PPA

The nature of PPAs in Serbia is also evolving.

Contracts are becoming more sophisticated, reflecting both price and carbon considerations.

Typical structures now include:

• Hybrid pricing mechanisms, combining fixed price floors with market-linked upside

• Volume flexibility, aligned with industrial production schedules

• Carbon traceability provisions, ensuring electricity can be attributed to specific generation assets

• Reporting frameworks, aligned with EU methodologies

For lenders, these features are not ancillary. They are central to risk assessment.

A PPA that includes robust documentation and traceability is more likely to support the offtaker’s compliance obligations, increasing the likelihood that the contract remains in force over its full term.

Direct industrial participation in projects

Beyond offtake, Serbian industrial companies are beginning to explore direct participation in renewable projects.

This takes several forms:

• Equity stakes in solar or wind projects

• Joint ventures with developers

• Co-investment in battery storage

• On-site or near-site generation

The rationale is straightforward.

By investing directly, industrial buyers can secure long-term access to low-carbon electricity while also capturing a share of project returns. This reduces reliance on third-party supply and aligns energy sourcing with broader business strategy.

For lenders, this further strengthens project credit.

An offtaker that is also an equity participant has a direct financial interest in project performance. This reduces the risk of contract renegotiation or default and improves alignment across stakeholders.

In practical terms, such structures can support:

• Higher debt capacity

• Lower perceived risk

• Greater flexibility in financing terms

Interaction with Serbia’s electricity market

Serbia’s evolving electricity market reinforces this trend.

SEEPEX prices have increasingly reflected regional dynamics, with baseload levels typically in the range of €80–130/MWh, and intraday volatility often reaching €30–70/MWh. This volatility creates uncertainty for both producers and consumers.

Industrial PPAs provide a hedge against this uncertainty, stabilising part of the electricity cost base while also addressing carbon exposure.

At the same time, Serbia’s gradual integration with EU electricity markets means that carbon pricing is indirectly influencing domestic price formation. This further strengthens the case for renewable sourcing.

Role of multilateral and commercial lenders

International financial institutions are playing a key role in this transition.

Institutions such as the EBRD and EIB are increasingly active in Serbia’s renewable sector, providing:

• Long-tenor debt

• Co-financing structures

• ESG validation

Their involvement often acts as a catalyst for commercial lenders, reducing perceived risk and enabling larger financing packages.

Commercial banks, both local and international, are following this lead, particularly in projects with strong industrial offtake.

The combination of industrial demand and multilateral support is creating a financing environment that was largely absent in earlier phases of the market.

A new bankability threshold

What is emerging in Serbia is a new threshold for bankability.

Projects that can demonstrate:

• Long-term industrial offtake

• Strong counterparty credit

• Robust carbon and reporting structures

are able to access financing on increasingly competitive terms.

Projects that rely purely on merchant exposure, by contrast, face greater scrutiny and more conservative financing assumptions.

This creates a clear differentiation within the project pipeline.

Electricity as industrial infrastructure

The broader implication is that renewable energy in Serbia is transitioning from a peripheral sector to core industrial infrastructure.

Electricity is no longer just a utility service. It is a strategic input linked to:

• Export competitiveness

• Carbon compliance

• Long-term business viability

For industrial companies, energy procurement is becoming a central component of strategy.

For developers, success depends on the ability to integrate into industrial value chains.

For lenders, the opportunity lies in financing assets that are not only technically viable but also commercially embedded in the economy.

Lenders move from caution to participation

The direction of travel is clear.

Lenders that were previously cautious about Serbia’s renewable sector are now reassessing their position. The emergence of industrial offtake as a credit anchor provides the missing link between project development and financing.

As more projects adopt this model, lender participation is likely to increase, bringing greater liquidity and competition into the market.

This, in turn, will support further project development, creating a reinforcing cycle.

From risk to opportunity

For Serbia, the implications are significant.

The country’s ability to attract investment into renewable energy—and to integrate that energy into its industrial base—will shape its position in a carbon-constrained European economy.

Industrial offtake provides a pathway to achieve this.

It aligns the interests of developers, industrial companies and lenders, creating a framework in which renewable projects are not just viable, but strategically essential.

In this framework, the question for lenders is no longer whether to participate.

It is how quickly they can position themselves within a market where electricity, carbon and trade are becoming inseparable.

Elevated by virtu.energy

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For several years, BESS projects in Southeast Europe struggled to reach financial close. The core issue was straightforward: no clear revenue stack. Without developed ancillary service markets, capacity mechanisms or long-term contracts, storage assets were largely dependent on merchant arbitrage—buying low, selling high—within relatively shallow and illiquid markets.

That environment is now shifting, and Serbia is at the centre of that transition.

The Serbian power system is entering a phase of tightening flexibility. With annual electricity demand stabilising around 32–35 TWh, and coal still accounting for roughly 60% of generation, system balancing has historically relied on dispatchable lignite and hydropower. However, ageing thermal assets, increasing maintenance cycles and hydrological variability are reducing system responsiveness.

At the same time, renewable capacity is expanding. Policy targets under the National Energy and Climate Plan aim for 45.2% renewable electricity by 2030, implying a significant increase in solar and wind penetration over the next decade. This introduces a structural mismatch between variable generation profiles and relatively inflexible legacy assets, creating a growing need for fast-response balancing capacity.

BESS sits directly in that gap.

From optional asset to system necessity

The first driver of bankability is therefore physical: system need.

As solar penetration increases—particularly in northern Serbia—midday generation peaks are becoming more pronounced. Without storage, this leads to price compression during high-output hours and potential curtailment. With storage, excess generation can be shifted into evening demand periods, where prices are typically higher.

Recent market behaviour illustrates this dynamic. Day-ahead baseload prices on SEEPEX have ranged between €80/MWh and €130/MWh, while intraday spreads frequently reach €30–70/MWh, with peak-day volatility exceeding €100/MWh. These spreads are no longer sporadic; they are becoming a structural feature of the market, driven by renewable intermittency in neighbouring EU systems and increasing cross-border coupling.

For BESS operators, this translates into a monetisable opportunity. A 1-cycle-per-day operation capturing a €40/MWh spread on a 50 MWh system can generate €0.7–1.0 million annually, depending on utilisation rates. Under higher volatility scenarios, this can increase significantly.

Revenue stack evolution

The second driver of bankability is the emergence of a multi-layered revenue stack.

Historically, storage projects relied almost exclusively on arbitrage. Today, revenue streams are diversifying:

• Intraday and day-ahead arbitrage, driven by widening price spreads

• Balancing and ancillary services, as EMS gradually develops flexibility markets

• Capacity-like value, particularly during peak demand or system stress

• Hybrid integration with renewables, reducing curtailment and enhancing PPA value

In hybrid configurations—such as solar-plus-storage—BESS becomes part of the contracted revenue structure. By improving dispatchability, it allows renewable projects to secure stronger PPAs with industrial offtakers, indirectly monetising storage through higher contract prices or improved contract tenors.

This is a critical shift. Storage no longer needs to be fully merchant to generate returns; it can be partially embedded in contracted renewable portfolios, improving overall project bankability.

CBAM-driven demand for flexibility

The third and increasingly decisive driver is CBAM-induced demand from industry.

Serbia’s energy-intensive industries—steel, cement, fertilisers—are now under pressure to reduce the carbon intensity of their electricity consumption. This is not only a question of sourcing renewable energy, but also of ensuring that supply profiles align with production needs.

Solar generation alone does not match industrial load curves. Without storage, a factory may still rely on grid electricity during evening or night hours, often dominated by lignite. This dilutes the carbon benefit of renewable sourcing.

BESS solves this mismatch.

By storing solar output and delivering it during non-generation hours, storage enables a higher share of “qualified electricity” in industrial consumption. This directly reduces embedded emissions and, therefore, CBAM exposure.

In this context, industrial offtakers are no longer indifferent to storage. They are increasingly willing to support or co-contract BESS capacity as part of their energy procurement strategy.

For developers, this creates a new type of demand: flexibility-linked PPAs, where storage is explicitly valued as part of the supply package.

Lender perspective: risk profile improves

From a financing standpoint, these changes are material.

Lenders have historically been cautious on standalone BESS due to:

• Revenue uncertainty

• Lack of long-term contracts

• Regulatory ambiguity

However, the evolving Serbian market is addressing each of these concerns.

First, price volatility is becoming structural, not episodic. This improves the predictability of arbitrage revenues.

Second, hybrid project structures allow storage to be partially de-risked through contracted renewable output.

Third, industrial demand linked to CBAM provides a new class of creditworthy counterparties, whose need for flexibility is tied to export competitiveness rather than discretionary energy purchasing.

As a result, lenders are beginning to consider higher leverage levels for storage-integrated projects, particularly when:

• At least 40–60% of revenue is contracted or quasi-contracted

• The project is integrated with a renewable asset

• There is exposure to industrial offtake

Debt tenors for hybrid projects can extend to 10–12 years, with improving terms as market structures mature.

CAPEX and return profile

The capital cost of BESS in the region is currently in the range of €350–500/kWh, depending on system configuration and supplier. For a 50 MWh system, this implies an investment of €18–25 million.

Return profiles vary depending on market conditions:

• Base case IRR: 10–12%

• Upside (high volatility + strong spreads): 13–16%

• Downside (low spreads, limited ancillary markets): 7–9%

The key variable is utilisation. As renewable penetration increases, utilisation rates are expected to rise, supporting higher returns.

Grid constraints as both risk and opportunity

Serbia’s transmission system is a double-edged factor for BESS bankability.

On one hand, grid constraints—particularly in Vojvodina—create curtailment risk for renewables and limit cross-border flows. On the other hand, these same constraints increase the value of localised flexibility, which storage can provide.

In congested nodes, BESS can:

• Absorb excess generation

• Reduce local price volatility

• Support grid stability

This enhances its system value, even in the absence of fully developed ancillary markets.

From merchant asset to infrastructure class

The combined effect of these trends is a reclassification of BESS within the Serbian energy landscape.

Storage is no longer viewed as a speculative, merchant-driven asset. It is becoming:

• A grid stabilisation tool

• A renewable integration enabler

• A carbon compliance instrument for industry

This multi-functional role supports a more robust investment case.

For developers, the strategic question is no longer whether to include storage, but how to optimise its integration with generation and offtake structures.

For lenders, the focus is shifting from technology risk to revenue architecture and market positioning.

Market demand reshapes bankability

Ultimately, the bankability of BESS in Serbia is being driven by a convergence of three demand sources:

• System demand for flexibility, as renewables scale

• Market demand for arbitrage and volatility capture

• Industrial demand for carbon-qualified electricity profiles

It is this combination that is unlocking financing.

In a market where electricity is increasingly defined by when it is delivered and how it is produced, storage becomes essential. And in a trade environment where carbon defines competitiveness, flexibility becomes monetisable.

BESS projects in Serbia are now positioned at the intersection of these dynamics—no longer peripheral assets, but increasingly central to both the power system and the industrial economy it supports.

Elevated by virtu.energy

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Until recently, most renewable projects in Serbia faced a familiar dilemma. Without fully developed long-term support schemes or deep corporate PPA markets, many assets were forced into merchant exposure, relying on SEEPEX day-ahead prices or short-term bilateral contracts. This created revenue volatility, with baseload prices fluctuating between €80/MWh and €130/MWh and intraday spreads often exceeding €30–70/MWh. For lenders, this translated into limited visibility, higher risk premiums and conservative leverage structures.

CBAM is beginning to change that equation fundamentally.

What is emerging is a new category of offtaker: CBAM-exposed industrial exporters, particularly in steel, cement, fertilisers and chemicals. These companies are no longer simply seeking electricity supply; they are seeking carbon-adjusted input structures that allow them to maintain competitiveness in EU markets.

For a renewable developer, this transforms the nature of the contract.

A long-term PPA with such an industrial buyer is no longer anchored solely in electricity demand. It is anchored in export continuity. The offtaker is not buying power as a discretionary cost input. It is securing a component of its ability to sell products into the EU without margin erosion from carbon costs.

This distinction materially strengthens the credit profile of the contract.

In traditional corporate PPAs, industrial offtakers often prioritised price flexibility, short tenors or optionality, reflecting uncertainty about future market conditions. In the CBAM-driven environment, the incentives shift. A steel or cement producer facing potential carbon costs of €20–40 per tonne of output linked to indirect emissions has a clear economic rationale to lock in renewable supply over longer periods.

This creates the foundation for 10–15 year PPAs, increasingly aligned with project finance requirements.

From a lender’s perspective, this changes the risk profile in several ways.

First, revenue visibility improves. Instead of relying on volatile merchant prices, the project secures a contracted revenue stream tied to an industrial offtaker with strong incentives to maintain the agreement. Even partial contracting—covering 50–70% of output—can significantly stabilise cash flows.

Second, counterparty risk is redefined. The industrial buyer is no longer simply exposed to electricity price fluctuations; it is exposed to carbon-adjusted export margins. Defaulting on a PPA could mean losing access to low-carbon electricity and facing higher CBAM costs at the border. This raises the economic cost of non-performance, effectively strengthening contract durability.

Third, price formation becomes more structured. Instead of purely fixed-price PPAs, hybrid models are emerging, combining fixed components with market-linked elements or floors and caps. These structures allow both parties to share upside from market volatility while maintaining downside protection.

In practical terms, this enables lenders to model cash flows with greater confidence. Debt sizing can move toward 65–75% of total CAPEX, with tenors extending to 12–15 years, compared to shorter tenors and lower leverage typically associated with merchant projects.

The bankability premium becomes even more visible when comparing two otherwise identical solar projects.

A merchant solar plant selling 100% into SEEPEX faces full exposure to price volatility, curtailment risk and market liquidity constraints. Its revenue profile may swing significantly year to year, depending on hydrology, regional demand and cross-border flows.

A contracted solar plant supplying an industrial exporter under a long-term PPA, by contrast, anchors a substantial portion of its revenue in a non-discretionary demand base, linked to industrial production and export activity. Even if wholesale prices fall, the industrial buyer still requires the electricity—and, crucially, the carbon attributes attached to it.

This creates a different type of asset.

It is no longer purely a generation asset exposed to market cycles. It becomes a quasi-infrastructure asset embedded in an industrial value chain, closer in risk profile to a regulated or contracted utility project.

For equity investors, this shift introduces a new layer of optionality.

On the downside, contracted revenues provide stability, supporting base-case returns in the range of 10–12% IRR. On the upside, uncontracted volumes—particularly when combined with battery storage—can capture intraday volatility, where spreads of €50–100/MWh are increasingly observed in Southeast Europe.

This dual structure—stable contracted base plus market-driven upside—is particularly attractive in a transitioning market like Serbia, where volatility is high but long-term decarbonisation signals are strengthening.

There is also a geographic dimension to this transformation.

Serbia sits at the intersection of EU and non-EU electricity markets, with increasing integration through interconnections and market coupling processes. As EU carbon pricing increasingly influences regional price formation, the value of CBAM-compliant electricity rises not only domestically but also in cross-border trading contexts.

Renewable projects positioned near key transmission corridors—such as those linking Serbia to Hungary, Croatia or Romania—gain additional strategic value. They can serve both domestic industrial demand and, potentially, export-oriented electricity flows aligned with EU carbon requirements.

Over time, this could lead to the emergence of industrial-renewable clusters, where large export-oriented facilities co-locate with or directly contract renewable generation assets. In such configurations, the boundary between energy production and industrial consumption begins to blur, with electricity procurement becoming an integrated part of industrial planning.

For developers, this implies a shift in business model.

Success will depend not only on securing land, permits and grid connections, but also on the ability to structure bankable, compliance-ready PPAs, backed by robust documentation of carbon intensity and aligned with EU methodologies. Developers who can offer this integrated package—electricity, data, certification and contractual flexibility—will be better positioned to attract both lenders and industrial offtakers.

In this emerging framework, the traditional distinction between merchant and contracted projects becomes less relevant. What matters is whether the project can position itself within a carbon-constrained industrial ecosystem, where electricity is valued not only for its energy content but for its role in enabling trade.

The result is a redefinition of bankability itself.

It is no longer driven solely by price forecasts and load factors. It is increasingly driven by the ability of the asset to support industrial competitiveness under carbon constraints.

For Serbia’s renewable sector, this represents a transition from peripheral generation to core economic infrastructure, embedded directly in the country’s export model and increasingly central to how value is created and preserved in a carbon-priced European market.

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The change is not theoretical. It is being driven by the European Union’s Carbon Border Adjustment Mechanism, which is transforming electricity from a commodity input into a traceable, emissions-linked component of export pricing. For Serbian producers of steel, cement, fertilisers and other energy-intensive goods, the question is no longer whether power can be purchased cheaply. The real question is whether that power can be credibly classified as low-carbon in the eyes of EU regulators and customers.

This distinction is beginning to redraw procurement strategies, reshape industrial margins and create a new market layer in which electricity is traded not only as energy, but as a bundle of carbon attributes, documentation and compliance value.

Serbia’s starting position is well known. The electricity system remains dominated by lignite, accounting for roughly 60% of generation, with hydropower contributing about 30% and other renewables still below 10%. On a purely operational basis, this has historically provided relatively low production costs, often in the range of €50–60/MWh for coal-based generation. Yet under CBAM, this cost advantage becomes increasingly illusory.

When Serbian goods are exported into the EU, their embedded emissions—both direct and indirect—become subject to carbon pricing aligned with EU ETS levels. With carbon prices fluctuating around €60–80/tCO₂, the implicit carbon cost embedded in coal-based electricity can add €60–80/MWh to the effective cost of energy when translated into export exposure. In other words, what appears as “cheap electricity” domestically can translate into expensive electricity at the border.

This is where the concept of “qualified electricity” begins to take shape.

For an industrial exporter, electricity must now meet two conditions simultaneously. It must be competitively priced, and it must be verifiably low in carbon intensity. Without the second condition, the first loses much of its relevance.

The mechanisms through which this qualification can be achieved are already emerging. Long-term renewable power purchase agreements are becoming the most direct pathway. By contracting electricity from solar or wind projects, industrial companies can begin to ring-fence a portion of their consumption as low-carbon, provided that the supply is properly documented and aligned with recognised methodologies.

Self-generation is another route. Large industrial sites are increasingly evaluating on-site solar installations or hybrid systems that combine generation with storage. While these may not cover total demand, they provide a controlled and auditable source of low-carbon electricity, which can be attributed to specific production processes.

Guarantees of Origin, where applicable, add another layer. Although their role in CBAM accounting is still evolving, they are becoming part of a broader documentation framework that supports claims around electricity sourcing and emissions intensity.

What connects all these mechanisms is the need for traceability. It is no longer sufficient to state that electricity is “green” in general terms. It must be linked to specific generation assets, time profiles and delivery volumes, with documentation robust enough to withstand regulatory scrutiny.

This is where private renewable developers enter the picture as strategic counterparts rather than just suppliers. A Serbian solar or wind project is not simply offering megawatt-hours into the market. It is offering a structured supply of qualified electricity, backed by data, certification and contractual alignment with industrial needs.

The economics of this shift are becoming increasingly clear. Consider a Serbian exporter of cement or steel. If the company relies entirely on grid electricity dominated by lignite, its indirect emissions profile remains high. Under CBAM, this translates into higher certificate costs at the EU border. If, however, the company secures even partial renewable supply—say covering 30–50% of its electricity consumption—the embedded emissions intensity of its products can be materially reduced.

Even a reduction of 0.2–0.4 tCO₂ per tonne of output can translate into €15–30 per tonne of avoided carbon cost at current EU price levels. Across large export volumes, this becomes a meaningful margin lever, often exceeding the initial price differential between renewable and conventional electricity.

In this sense, renewable electricity is no longer simply an input cost. It becomes a financial hedge against carbon exposure.

Serbia’s policy direction supports this transition, even if implementation remains uneven. The National Energy and Climate Plan sets a target of 45.2% renewable electricity by 2030, implying a significant expansion of solar and wind capacity over the next decade. A pipeline of projects—ranging from utility-scale solar parks in Vojvodina to wind developments in eastern Serbia—is gradually moving forward, alongside increasing interest in hybrid systems combining generation with battery storage.

As this capacity comes online, the availability of renewable electricity for industrial offtake will increase. At the same time, market structures are evolving. The Serbian day-ahead market, SEEPEX, is becoming more integrated with regional markets, with prices increasingly reflecting cross-border dynamics and EU market signals. Baseload prices in recent months have ranged between €80 and €130/MWh, while intraday volatility has intensified, creating additional incentives for flexible and optimised procurement strategies.

Within this environment, industrial companies can no longer behave as passive electricity consumers. They are being pushed toward a role more akin to portfolio managers of energy and carbon attributes.

This involves balancing multiple elements simultaneously: securing long-term renewable supply through PPAs, maintaining flexibility to respond to market prices, managing exposure to carbon costs, and ensuring that all elements are properly documented and aligned with evolving EU requirements.

For some companies, this will mean building internal capabilities in energy procurement and carbon accounting. For others, it will involve partnerships with developers, traders and service providers who can structure integrated solutions.

What is clear is that the traditional model—buying electricity at the lowest available price and treating it as a homogeneous input—is no longer sufficient.

The shift toward qualified electricity also has implications for the broader Serbian energy system. As more industrial demand becomes linked to renewable sourcing, developers gain stronger incentives to build capacity with contracted offtake, improving project bankability. At the same time, the grid must adapt to accommodate higher shares of intermittent generation, increasing the importance of storage, flexibility and transmission upgrades.

In effect, CBAM is acting as a catalyst that connects three previously separate domains: electricity markets, industrial strategy and trade policy.

For Serbia’s exporters, the implications are immediate. Competitiveness in EU markets will increasingly depend not only on production efficiency and logistics, but also on the carbon profile of electricity used in production. Companies that move early to secure qualified electricity are likely to preserve margin and market access. Those that do not may find that what once looked like cheap power becomes an increasingly expensive constraint.

In this new landscape, electricity is no longer just energy. It is evidence, compliance and competitive positioning, all at once.

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Located near Sremska Mitrovica, the project is being developed as a hybrid system combining up to 270 MW of solar capacity with battery storage scaling to approximately 72 MWh, alongside an initial phase of 90 MW solar paired with 36 MWh of storage. With a secured grid connection of around 180 MW AC, the project is positioned to operate directly within Serbia’s balancing and day-ahead market framework while maintaining optionality for cross-border trading.

Serbian market shifts toward tighter fundamentals

Serbia’s electricity system, historically dominated by lignite generation from EPS, is entering a more constrained operating environment. Ageing thermal capacity, periodic outages and hydrological variability have reduced system flexibility, while demand has stabilised at elevated levels of approximately 32–35 TWh annually.

At the same time, wholesale price formation is increasingly influenced by neighbouring EU markets through interconnections with Hungary, Romania, Bulgaria and Croatia. Day-ahead prices on SEEPEX have frequently tracked Central European benchmarks, with baseload levels fluctuating between €80/MWh and €130/MWh in recent months, and peak periods exceeding €150/MWh during winter demand spikes.

This growing price coupling is occurring in parallel with rising volatility. Intraday spreads in Serbia and the wider region are now regularly reaching €30–70/MWh, driven by intermittent renewable output in surrounding EU systems and constrained dispatch flexibility domestically.

Hybrid assets gain importance in dispatch structure

Within this evolving system, hybrid solar-plus-storage assets are beginning to play a more central role in balancing supply and demand.

The Fortis project’s battery component is expected to enable:

• Intraday arbitrage across SEEPEX and neighbouring markets
• Peak shifting from midday solar generation to evening demand periods
• Participation in ancillary and balancing services as Serbia expands its flexibility markets

This is particularly relevant in northern Serbia, where solar capacity additions are accelerating and grid congestion is becoming more pronounced during high-generation hours.

Without storage, solar output risks increasing curtailment exposure. With storage, the same output can be reshaped into a more dispatchable profile, improving system integration and revenue stability.

Carbon pricing indirectly reshaping Serbian price formation

Although Serbia does not yet operate a full EU ETS-equivalent carbon pricing system, the impact of carbon costs is increasingly reflected in domestic prices through market coupling.

EU ETS prices in the range of €70–90/tCO₂ are adding an estimated €55–85/MWh to thermal generation costs in neighbouring EU markets. As Serbia imports and exports electricity across these borders, these carbon-adjusted prices are increasingly influencing SEEPEX price formation.

This creates a dual dynamic:

• Domestic lignite generation remains relatively low-cost at €50–60/MWh
• Imported or EU-linked prices reflect higher carbon-adjusted levels, often exceeding €100–130/MWh

The result is a widening spread between production cost and market price, reinforcing the value of low-marginal-cost renewable generation.

Revenue optimisation linked to market volatility

The Fortis project is expected to generate over 365 GWh annually, placing it among the larger renewable contributors in Serbia’s evolving generation mix.

At current baseload price levels of €80–120/MWh, this implies annual revenue potential of €30–45 million, with upside in periods of tight supply.

However, a growing share of value is expected to come from short-term market dynamics rather than baseload production alone.

Battery storage allows the project to capture:

• Intraday price spreads frequently reaching €50–100/MWh
• Price spikes during evening peaks or system stress events
• Balancing market opportunities as flexibility demand increases

This aligns the asset more closely with a trading-oriented revenue model, rather than a purely generation-based one.

Grid constraints and curtailment risk remain key variables

Serbia’s transmission system, operated by EMS, is facing increasing pressure from renewable integration, particularly in Vojvodina where multiple solar and wind projects are under development.

Curtailment risk is becoming a central consideration for new projects. During periods of high solar output and limited export capacity, generation may need to be reduced to maintain system stability.

The Fortis project mitigates this risk through:

• Integrated battery storage, enabling output shifting
• Strategic location near key transmission corridors
• Secured grid connection capacity of 180 MW AC

Even so, delays in grid reinforcement or interconnection expansion could impact project performance. A 12–18 month delay in grid upgrades could reduce equity returns by 2–4 percentage points, according to market estimates.

Investment case supported by structural market change

The total investment envelope for the project is estimated at €220–285 million, including solar generation, storage systems and grid infrastructure.

Debt financing is expected to cover 65–75% of CAPEX, supported by interest from international lenders attracted by Serbia’s growing renewable pipeline and the project’s hybrid design.

Equity returns are projected in the range of:

• 10–13% IRR (base case)
• 14–18% IRR (upside, driven by volatility and trading gains)
• 8–10% IRR (downside, under higher curtailment or price compression)

The inclusion of storage is a key factor in maintaining returns under variable market conditions.

Role within Serbia’s evolving power mix

The Fortis project reflects a broader shift in Serbia’s electricity system, where new capacity additions are increasingly renewable and market-linked.

Coal remains dominant, but its role is gradually being challenged by:

• Rising maintenance costs and operational constraints
• Increasing alignment with EU carbon pricing mechanisms
• Growing penetration of wind and solar capacity

In this context, hybrid renewable assets are emerging as a bridge between legacy baseload generation and a more flexible, market-driven system.

Transition toward a volatility-driven market

Serbia’s electricity market is moving toward a structure where price formation is shaped by:

• Cross-border carbon-adjusted pricing
• Renewable intermittency
• Short-term trading dynamics

In this environment, value is shifting from pure generation to flexibility, timing and market access.

The Fortis solar-plus-storage platform is positioned within this transition, combining low-cost renewable generation with the ability to respond to price signals in real time.

As carbon pricing continues to influence regional markets and grid constraints tighten, such hybrid assets are likely to play an increasingly central role in both system balancing and investment strategies across Southeast Europe.

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This shift is being driven by the European Union’s Carbon Border Adjustment Mechanism, which is changing how value is calculated across supply chains. For Serbian exporters, especially in sectors such as steel, cement, aluminium and fertilisers, electricity is no longer simply an input cost. It is now a carbon-bearing component of the final product, directly influencing access to EU markets and pricing power.

At the centre of this transformation lies a new type of contract: the renewable power purchase agreement, not merely as a hedging tool, but as a compliance and margin-preservation instrument.

Serbia’s electricity system still relies heavily on lignite, with coal accounting for roughly 60% of generation. From a pure cost perspective, this has historically provided relatively low marginal production costs, often in the range of €50–60/MWh. However, once carbon is factored in—whether directly or through CBAM—the effective cost of coal-linked electricity rises dramatically. With EU carbon prices in the range of €60–80/tCO₂, the implicit carbon burden of lignite-based electricity translates into approximately €60–80/MWh of additional cost when embedded into export products.

This is where renewable energy fundamentally changes the equation.

A Serbian solar or wind project, typically operating with a levelised cost of electricity in the range of €45–70/MWh depending on financing and site conditions, does not carry the same carbon liability. On paper, the difference may appear marginal or even unfavourable compared to legacy coal generation. But in the context of CBAM, the value proposition reverses.

For an industrial exporter, procuring renewable electricity through a long-term PPA does more than stabilise part of the power bill. It allows the company to lower the embedded emissions intensity of its output, directly affecting the number of CBAM certificates required at the EU border. In sectors where margins are often measured in tens of euros per tonne, this can be decisive.

Take the example of steel production. A Serbian producer exporting flat steel to the EU faces increasing scrutiny not only on direct emissions from the blast furnace but also on indirect emissions from electricity consumption. If that electricity is sourced from lignite-heavy generation, the carbon intensity of the final product rises accordingly. If, however, a portion of that electricity is contracted from a renewable source under a traceable PPA, the embedded emissions can be partially reduced.

This creates a measurable economic effect. A reduction of even 0.3–0.5 tCO₂ per tonne of product in indirect emissions can translate into €20–40 per tonne of avoided CBAM cost at current carbon price levels. Across large export volumes, this becomes a material lever on profitability.

In this context, renewable producers are no longer competing solely on price per megawatt-hour. They are competing on carbon intensity per megawatt-hour, and on their ability to provide credible, auditable documentation of that intensity.

This is where the structure of the contract becomes as important as the electricity itself. A modern renewable PPA in Serbia is increasingly expected to include not only price terms and volume profiles, but also:

• Verified generation data
• Time-stamped delivery profiles
• Carbon intensity certification
• Alignment with EU reporting methodologies

For industrial buyers, this documentation is essential. Under CBAM, exporters must provide detailed emissions data for their products, including indirect emissions linked to electricity consumption. Without verifiable data, default values may be applied—often to the disadvantage of the exporter.

Renewable producers who can offer a fully documented, compliance-ready electricity product therefore gain a competitive edge. They are effectively selling a bundled service: physical power, carbon attributes, and regulatory alignment.

The Serbian electricity market itself is reinforcing this shift. Prices on the SEEPEX day-ahead market have increasingly reflected regional dynamics, with baseload levels typically ranging between €80 and €130/MWh in recent months. Intraday volatility has intensified, with spreads frequently reaching €30–70/MWh due to renewable intermittency in neighbouring EU systems and limited flexibility in the domestic grid.

In such an environment, renewable producers—particularly those integrating battery storage—are not only able to optimise timing of sales, but also to structure supply profiles that better match industrial consumption patterns. This further enhances their attractiveness as long-term partners for energy-intensive industries.

At the same time, Serbia’s gradual integration into European electricity markets, including ongoing market coupling initiatives with Hungary and Bulgaria, is increasing the relevance of EU price signals and carbon economics in domestic price formation. Even without a full domestic carbon pricing system, the Serbian market is becoming indirectly “carbon-priced” through its connections with the EU.

This creates a structural incentive for industrial consumers to decouple, at least partially, from the average grid mix and secure dedicated renewable supply.

The implications for renewable developers are significant. A solar or wind project in Serbia is no longer just a merchant asset exposed to wholesale price volatility. It can become a strategic supplier to export-oriented industry, with long-term contracted revenues linked not only to electricity demand but also to carbon compliance needs.

This opens a new layer of bankability. Lenders evaluating renewable projects are increasingly aware that PPAs with CBAM-exposed industrials offer a different risk profile compared to traditional merchant exposure. The offtaker is not only buying electricity; it is securing a component of its export viability. This strengthens contract durability and reduces counterparty risk.

For equity investors, the upside is equally clear. Renewable projects positioned within industrial supply chains gain access to premium offtake structures, potentially at higher or more stable price levels than purely merchant sales. They also benefit from structural demand growth, as more industrial players seek to align with EU carbon requirements.

What is emerging is a reconfiguration of Serbia’s energy-industrial interface. Renewable producers are moving upstream into the industrial value chain, while industrial consumers are moving downstream into energy procurement strategy.

In practical terms, the megawatt-hour is no longer the only unit of value. It is accompanied by tonnes of CO₂ avoided, certificates issued, and compliance thresholds met.

For Serbia’s export economy, this shift is likely to accelerate. As CBAM moves from transitional reporting into full financial enforcement, the cost of carbon will become increasingly visible in trade flows. Industries that fail to adapt their electricity sourcing will see margins compressed, while those that secure low-carbon supply will retain access and pricing power in EU markets.

Within that landscape, renewable energy is no longer just part of the energy transition narrative. It becomes part of the trade infrastructure—a tool through which Serbian industry can maintain competitiveness in a carbon-constrained European economy.

Elevated by cbam.rs

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The starting point is Serbia’s generation mix. According to a U.S. government market guide published in January 2026, about 60% of Serbia’s electricity in 2024 came from coal, mainly lignite, roughly 30% from hydropower and around 10% from other renewables. Serbia’s own just transition documents describe the power sector as largely coal-based, while the Energy Community’s 2025 Serbia report shows the country had 3,985 MW of renewable capacity in 2024 and a policy target of 45.2% renewables in electricity generation by 2030. In other words, the system is moving, but not yet fast enough to remove coal from the industrial cost base. 

That is where CBAM becomes commercially painful. The EU benchmark carbon price fell to €64.93/tCO2 on 17 March 2026, after the Commission signalled possible market intervention, but even at that lower level the carbon component remains material. Serbia’s greenhouse-gas inventory uses a country-specific lignite emission factor of 106.95 kg CO2/GJ for lignite burned in thermal power plants. Using that official Serbian factor, a typical lignite power station can be inferred to emit roughly around 1.0–1.1 tCO2 per MWh of electricity output, depending on plant efficiency. At an EU carbon price near €65/t, that implies a carbon cost in the order of roughly €65–72/MWh for coal-based electricity. Serbia has introduced a national carbon tax of €4/tCO2 from 1 January 2026, but on the same simplified power-sector basis that is only around €4–5/MWh. The gap between Serbia’s domestic carbon burden and the EU carbon benchmark therefore remains very large. 

For industrial buyers, this is the central problem. A steel mill, cement plant or fertiliser producer in Serbia may still be buying electricity in a domestic market that looks cheaper than many EU peers on the surface, but the export customer in the EU increasingly prices the product as if the electricity behind it carried a carbon cost closer to the EU ETS. The EU is Serbia’s main trading partner, accounting for 58.3% of Serbia’s total trade in 2024, while Serbia’s exports to the EU were close to €19bn. That means the country is heavily exposed to a buyer base that is no longer looking only at ex-works price and freight, but also at embedded emissions and documentation quality. 

The sectors most exposed are not abstract. In Serbia, the industrial names that sit closest to this pressure are obvious: steel around HBIS Serbia in Smederevo, cement producers, and fertiliser and chemical producers such as the wider Serbian fertiliser chain. Industry groups in Serbia have already begun framing the issue in exactly those terms, with the Association of Serbian Energy-Intensive Industry bringing together companies from the steel, cement and fertilizer sectors. These industries are exposed in three ways at once: as large electricity buyers, as exporters into the EU, and, increasingly, as potential buyers or sponsors of renewable supply arrangements that can improve the carbon profile of their output. 

The Serbian electricity market is also changing in ways that make this problem more immediate. Serbia’s organised day-ahead market is more liquid than it was a few years ago. SEEPEX day-ahead traded 404,970.3 MWh in January 2026 and 414,520.1 MWh in February 2026. On the exchange homepage, day-ahead base prices for 15–19 March 2026 ranged from €89.24/MWh to €109.53/MWh, with daily traded volumes broadly around 13.3–14.2 GWh. Serbia is also moving toward market coupling, with implementation work progressing on the Serbia-Hungary border and activity beginning for Serbia-Bulgaria. That means domestic industrial power costs are increasingly influenced by regional wholesale conditions rather than by a closed national logic. 

This has two consequences. First, energy-intensive industry is more exposed to wholesale volatility. Second, even if Serbian power is physically produced from lignite at a relatively low short-run cash cost, the market price paid by industrial buyers can still be pulled upward by regional scarcity, hydrology, gas prices and neighbouring EU power prices. The result is a difficult combination: Serbia’s industry does not enjoy the full climate advantage of a low-carbon grid, but it also does not always enjoy the price advantage that a purely domestic lignite system might suggest. It gets much of the carbon downside and not all of the pricing upside. 

This is why the discussion is shifting from “cheap electricity” to “qualified electricity”. For a Serbian steel, cement or fertiliser exporter, the question is no longer simply whether power can be bought at an acceptable €/MWh level. The more important question is whether that power can be credibly ring-fenced as lower-carbon electricity through PPAs, self-generation, Guarantees of Origin where relevant, or dedicated renewable sourcing structures that improve the emissions profile of exported goods. Private renewable developers are the natural counterparties here. Serbia’s renewable build-out is still incomplete, but policy direction is clear, with the NECP targeting 45.2% renewables in electricity by 2030. As more solar, wind and hybrid solar-storage projects come online, Serbian industrials will increasingly need to behave not only as electricity consumers but as portfolio managers of carbon attributes. 

That creates a new position for renewable producers. A Serbian solar or wind project is no longer only selling megawatt-hours into SEEPEX or a bilateral contract. It can also sell carbon relief. For a CBAM-exposed exporter, a renewable PPA can do more than stabilise part of the electricity bill; it can potentially reduce embedded indirect emissions in products shipped to the EU, strengthen customer negotiations and defend export margin. In practical terms, the renewable producer is no longer selling only power, but a package of electricity, documentation, and trade competitiveness. 

The asymmetry between coal electricity and renewable electricity will therefore increasingly show up inside Serbian industry’s margin structure. A coal-linked industrial buyer may still face a wholesale power bill somewhere around current regional market levels, but once embedded emissions are translated into CBAM exposure, the true all-in export cost becomes far higher. A renewable-linked buyer may pay a similar or even slightly higher contracted power price in nominal terms, yet end up with a lower effective export cost because the carbon add-on at the border is smaller. That is the strategic inversion now underway: what used to look like more expensive power can become cheaper industrial competitiveness. 

For Serbia, the commercial map is now fairly clear. Coal-based electricity remains important to keep the domestic system running, but it is becoming progressively worse as an export-enabling input for CBAM-exposed industry. Energy-intensive companies will increasingly split into three camps. One group will remain largely merchant buyers of grid electricity and absorb rising carbon-adjusted export pressure. A second group will try to secure long-term renewable supply through PPAs or self-generation. A third group, likely the strongest strategically, will combine both: partial renewable sourcing, storage or flexibility, and active procurement linked to wholesale market conditions. In the next phase of the Serbian market, the most competitive industrial exporter may not be the one buying the cheapest electricity today, but the one buying the cleanest bankable electricity for tomorrow’s EU customer. 

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In parallel with the extension, authorities will release an additional 40,000 tons of diesel from strategic reserves. This step is intended to reinforce market supply and ease potential tensions in the coming days, while supporting short-term fuel availability.

Officials say that the decision is driven by continued volatility in international oil markets, influenced by geopolitical developments in the Middle East. Rising crude prices, which have surged significantly in recent weeks, have increased the risk of both supply shortages and higher fuel costs domestically, putting additional pressure on the local energy system.

The export ban is part of a wider set of interventions aimed at maintaining price stability. Earlier measures included a reduction in fuel excise duties by 20%, designed to limit the impact of global price increases on consumers and businesses. By combining administrative controls with the release of reserves, the Government aims to ensure sufficient fuel availability while preventing sharp price fluctuations in the domestic market.

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The study, prepared under the auspices of the Ministry of Mining and Energy, is structured along the methodology of the International Atomic Energy Agency (IAEA) Milestones Approach, which defines nuclear development as a phased national programme rather than a project. This framing is critical. Serbia is not evaluating a single asset, but the creation of an entirely new industrial and regulatory ecosystem that spans decades.

At the centre of the analysis is a projected structural increase in electricity demand. While the study avoids overly aggressive forecasts, it clearly signals that Serbia’s current consumption level—approximately 30–35 TWh annually—is expected to rise significantly by mid-century. Electrification of transport, industrial decarbonisation and the expansion of digital infrastructure are identified as primary drivers. In parallel, peak demand volatility is expected to increase, particularly during winter periods when hydropower output is constrained and heating demand surges.

This demand outlook intersects with a generation fleet that remains heavily dependent on lignite. Serbia’s state-owned utility, EPS, continues to rely on coal-fired plants for the majority of baseload supply, with installed coal capacity exceeding 4,000 MW. These assets, while still operationally central, face increasing pressure from European carbon policy, aging infrastructure and environmental compliance requirements. The study does not prescribe a fixed coal phase-out timeline, but it implicitly acknowledges that maintaining current levels of coal generation beyond the 2035–2040 horizon will become increasingly untenable.

Against this backdrop, the expansion of renewable energy is presented as both necessary and insufficient. Serbia has already begun accelerating its renewable pipeline, with wind and solar projects moving through auction schemes and private development channels. However, the study quantifies a key limitation: even with substantial renewable deployment, the system will face periods of low generation due to weather variability. In such conditions, reliance on imports becomes structurally embedded unless firm capacity is introduced.

This is where nuclear energy enters the analysis—not as a replacement for renewables, but as a complement that stabilises their integration. The study explicitly models nuclear as baseload generation with capacity factors in the range of 85–90%, significantly higher than wind or solar. This allows it to serve as a continuous supply backbone, reducing the need for balancing imports and mitigating curtailment risks during periods of excess renewable generation.

The capacity scenarios outlined in the study converge around a ~1,000 MW nuclear unit entering operation around 2040, with the possibility of additional units depending on demand evolution. At this scale, nuclear would account for approximately 15–20% of Serbia’s projected electricity mix, assuming continued growth in renewables. In absolute terms, a 1,000 MW reactor operating at high capacity factors could generate 7–8 TWh annually, equivalent to roughly a quarter of Serbia’s current consumption.

The technology assessment within the study is deliberately non-committal but analytically structured. Large conventional reactors—typically in the 1,000–1,600 MW range, such as European Pressurised Reactors or similar designs—are evaluated alongside Small Modular Reactors, which generally range between 50–300 MW per unit. The study recognises that large reactors offer proven performance and economies of scale, but at the cost of higher upfront investment and longer construction timelines, often exceeding 10–12 years.

SMRs, by contrast, are presented as a potentially more flexible solution, allowing phased deployment and lower initial capital commitments. However, the study is explicit about their current limitations. Commercial deployment remains limited, cost benchmarks are still evolving and supply chains are not yet fully established. As a result, Serbia’s strategy remains open-ended, with both pathways kept under consideration until further technological and market clarity emerges.

The financial implications of either pathway are substantial. While the study refrains from providing explicit cost estimates, it references international benchmarks that place large reactor CAPEX in the range of €6–10 billion per GW, depending on technology and financing structure. SMRs are estimated at €3–6 billion per GW equivalent, though these figures carry higher uncertainty due to limited deployment history. For Serbia, this translates into a single project representing a significant share of national GDP, underscoring the need for complex financing arrangements.

The study highlights several potential financing models, including:

• State-backed investment with sovereign guarantees
• Strategic partnerships with vendor countries (such as France, South Korea or the United States)
• Hybrid structures involving international financial institutions

In all scenarios, long-term revenue stability is identified as a prerequisite, likely requiring mechanisms such as power purchase agreements, capacity payments or regulated tariffs to ensure cost recovery over the plant’s operational lifetime, which typically exceeds 60 years.

Beyond generation and financing, the study devotes significant attention to institutional readiness. Serbia currently lacks a fully developed nuclear governance framework, and the report identifies 19 key infrastructure issues that must be addressed before any construction decision can be made. These include:

• Establishment of an independent nuclear regulatory authority
• Development of a comprehensive legal and licensing framework
• Creation of nuclear safety and radiation protection institutions
• Human resource development, including specialised engineering and operational training

The workforce dimension is particularly emphasised. Nuclear energy requires highly specialised skills across engineering, operations, safety and regulation. The study estimates that developing this human capital base will take at least 10–15 years, requiring coordinated efforts across universities, technical institutes and international partnerships.

Grid integration is another critical component. Serbia’s transmission system, operated by EMS, will require upgrades to accommodate large-scale nuclear generation, particularly in terms of load balancing and cross-border interconnections. A single 1,000 MW unit represents a significant addition to the system, necessitating reinforcement of transmission corridors and potentially new substations to ensure stable integration.

Waste management and fuel cycle considerations are addressed within the framework of international best practices. The study assumes that Serbia would initially rely on international fuel supply and potentially external spent fuel management arrangements, at least in the early stages of programme development. Long-term solutions, including domestic storage or participation in regional facilities, remain open questions that would need to be resolved in subsequent phases.

The timeline presented in the study reflects the complexity of these requirements. The current phase, focused on feasibility and institutional preparation, is expected to extend through 2025–2027. This would be followed by a decision phase involving technology selection, partner identification and financing structuring, likely extending into the early 2030s. Construction and commissioning would then span the remainder of the decade, with first electricity targeted around 2040.

This extended timeline introduces a critical strategic consideration. Serbia must make near-term decisions about a technology that will only deliver benefits in the long term, while simultaneously managing immediate system pressures. This creates a dual-track challenge: accelerating renewable deployment and grid modernisation in the short term, while laying the groundwork for nuclear integration in the long term.

The study also situates nuclear energy within Serbia’s broader European integration trajectory. As the European Union advances its decarbonisation agenda, access to low-carbon electricity becomes increasingly important for industrial competitiveness. Nuclear generation, by providing stable low-carbon power, could support Serbia’s export-oriented industries in maintaining access to EU markets, particularly under mechanisms such as the Carbon Border Adjustment Mechanism.

At the same time, the geopolitical dimension of nuclear development is implicit throughout the study. Technology selection will likely determine long-term partnerships, supply chains and financing structures, embedding Serbia within specific international frameworks for decades. This adds a layer of strategic complexity that extends beyond the energy sector.

Public acceptance is identified as a necessary condition for progress. The study emphasises the need for transparent communication, stakeholder engagement and adherence to the highest safety standards. While Serbia does not have a history of nuclear power generation, public perception will play a critical role in shaping the feasibility of any future programme.

What ultimately emerges from the study is a reframing of Serbia’s energy strategy. Nuclear energy is not presented as an immediate solution, but as a long-term structural option that addresses multiple system constraints simultaneously. It offers a pathway to reduce import dependence, stabilise a renewable-heavy grid and align with European decarbonisation trajectories. However, it also requires a level of institutional, financial and political commitment that extends far beyond conventional infrastructure projects.

The decision facing Serbia is therefore not simply whether to build a nuclear plant, but whether to undertake the transformation required to support it. The study provides the analytical foundation for that decision, quantifying the benefits, outlining the requirements and exposing the risks. The next phase will determine whether those insights translate into policy and, ultimately, into infrastructure that reshapes the country’s energy landscape for generations.

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In nuclear development, communication is not a parallel activity. It is part of the infrastructure. Countries that treat it as an afterthought tend to encounter resistance precisely at the moment when technical progress accelerates. Serbia, now entering what the IAEA defines as Phase 1—feasibility and readiness—has a narrow window in which communication can be structured proactively rather than reactively.

The starting point is narrative discipline. The study positions nuclear energy not as a preferred technology, but as a response to structural constraints in the power system. Serbia’s electricity demand, currently in the range of 30–35 TWh annually, is expected to increase steadily as electrification deepens across transport, heating and industry. At the same time, the country remains heavily reliant on lignite, with more than 4,000 MW of installed coal capacity, while renewable expansion introduces variability that the system is not yet fully equipped to absorb.

These are not abstract pressures. They are already visible in winter import patterns, price volatility across regional markets and increasing strain on balancing mechanisms. A communication strategy that begins with technology—reactors, vendors, megawatts—risks missing this point entirely. The more effective framing, and the one implicitly supported by the study, is to present nuclear as system stability infrastructure. Not a project, but a response to a system problem that is already unfolding.

This distinction is not semantic. It determines whether the public debate evolves around necessity or preference. In the early stages of nuclear programmes, countries that anchor communication in system realities—import exposure, price shocks, supply security—tend to build a more resilient base of understanding. Those that move too quickly into advocacy often trigger opposition before the underlying problem has been fully internalised.

Serbia’s immediate task, therefore, is not to build support for nuclear, but to build literacy around the energy system itself. This aligns closely with the objectives of Phase 1 under the IAEA framework, which emphasises institutional readiness, stakeholder engagement and public understanding. The communication objective at this stage is legitimacy, not consensus.

Practically, this requires a shift in how information is presented. The technical study, while comprehensive, is not designed for broad public consumption. Translating its findings into accessible formats—data dashboards, simplified reports, scenario visualisations—becomes essential. A regularly updated view of Serbia’s energy balance, including imports, price differentials with neighbouring markets and renewable variability, would do more to ground the debate than any standalone campaign.

One of the most effective tools at this stage is transparency. A real-time energy system dashboard, showing daily imports, generation mix and market prices, would anchor the nuclear discussion in observable data. When the system experiences stress—low hydro output, weak wind generation, price spikes—the connection between system constraints and long-term solutions becomes tangible. Nuclear, in this context, is not introduced as an abstract future asset, but as a measurable contributor to system stability. A single 1,000 MW unit, as outlined in the study’s indicative scenarios, translates into roughly 7–8 TWh of annual generation, equivalent to a quarter of current consumption. Communicated correctly, this is not a number; it is a reference point.

Institutional structure is equally important. Serbia currently lacks a dedicated communication body for nuclear development, and this gap is more significant than it appears. Fragmented messaging across ministries, utilities and academic institutions can quickly erode credibility, particularly in a field where technical complexity is high and public sensitivity is acute. Establishing a centralised nuclear communication office—technically literate, operationally independent and aligned with the broader programme—is not a branding exercise. It is a governance requirement.

The credibility of that office will depend heavily on who speaks first. Nuclear communication that begins with political leadership often struggles to gain traction, particularly in environments where public trust in institutions is uneven. The study’s reliance on international frameworks such as the IAEA provides a clear direction: communication should be led initially by engineers, system operators and technical experts. Universities, research institutes and grid operators carry a different type of authority, one grounded in expertise rather than policy. Their role is not to advocate, but to explain.

This is particularly relevant when addressing the most persistent challenge in nuclear communication: risk perception. The study acknowledges, albeit implicitly, the scale of the undertaking. Nuclear projects involve long timelines—typically 10–15 years from decision to operation—and substantial capital commitments, often in the range of €6–10 billion per gigawatt for large reactors. Attempting to minimise or defer these realities tends to undermine trust. A more effective approach is to present them early, within a global context, and to explain how different countries have managed similar challenges.

The same applies to technological uncertainty. Serbia’s decision to keep both large-scale reactors and small modular reactors under consideration reflects a rational assessment of market evolution. Communicating this as flexibility rather than indecision is essential. The global nuclear landscape is shifting, and Serbia’s position is that of a late entrant with the advantage of observing how technologies and financing models mature. This is a strategic choice, not a delay.

Workforce development offers one of the strongest entry points for positive engagement. The study estimates that building the necessary human capital base will take 10–15 years, spanning engineering, operations, safety and regulation. This timeline aligns closely with the broader programme and provides an opportunity to frame nuclear not only as infrastructure, but as an investment in national capability. Announcing academic programmes, international partnerships and scholarship pathways early in Phase 1 transforms the narrative from distant technology to immediate opportunity. It signals that Serbia is building competence before committing capital.

Local engagement, while often associated with later project phases, should also begin early, albeit in a different form. Before site selection, communication should focus on explaining what hosting nuclear infrastructure entails—economically, environmentally and institutionally. The absence of early engagement is one of the most common causes of local resistance once projects become concrete. Introducing the topic in a non-site-specific context allows for a more balanced discussion, detached from immediate concerns about location.

The broader economic narrative is equally important. The study situates nuclear energy within Serbia’s long-term alignment with European energy and climate frameworks. This connection should be made explicit. Access to low-carbon electricity is becoming a defining factor for industrial competitiveness, particularly under mechanisms such as the Carbon Border Adjustment Mechanism. Nuclear energy, by providing stable low-carbon supply, supports not only system stability but also export competitiveness. Framed in this way, nuclear moves beyond the energy sector into the domain of industrial policy.

What distinguishes successful nuclear communication strategies is not their ability to persuade, but their ability to remain consistent over time. Phase 1 is where this consistency is established. It is also where the risk of misalignment is highest. Overly optimistic messaging, premature commitments or fragmented communication structures can create expectations that are difficult to manage in later phases. Conversely, a measured, transparent and technically grounded approach builds resilience into the programme before major decisions are taken.

Serbia’s study provides the analytical foundation for this approach. It quantifies the system challenges, outlines the institutional requirements and frames nuclear as one of several tools available to address them. The communication strategy that follows should mirror that structure: grounded in data, aligned with phased development and anchored in technical credibility.

The next two to three years will determine whether nuclear energy remains an option on paper or evolves into a defined national programme. In that period, communication will play a role that is often underestimated but ultimately decisive. It will shape how the programme is understood, how risks are perceived and how decisions are received. In a sector where timelines extend across generations, the early narrative is not just the beginning of the story. It is the framework within which the entire story will unfold.

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The initiative originates from Serbia’s Energy Development Strategy to 2040, where hydrogen is recognized as a strategic energy resource. Officials are placing particular focus on its application in industrial processes and the transport sector, areas where achieving deep decarbonization remains challenging.

In parallel with policy development, work is ongoing to establish a comprehensive regulatory framework. This framework is expected to regulate the entire hydrogen value chain, including production, storage, transport, and end-use, while ensuring compliance with European Union standards. The process is being supported through cooperation with the EU, which is helping Serbia address regulatory gaps and develop a modern legal structure for hydrogen deployment.

Alongside institutional and legislative efforts, practical implementation is also progressing through pilot and demonstration projects aimed at building domestic expertise. One of the key initiatives is the planned development of a hydrogen production and storage facility at the Vinca Institute, intended to serve as a testing ground for new technologies and approaches.

The project is also expected to demonstrate how hydrogen can contribute to grid stability, particularly by supporting the integration of intermittent renewable energy sources such as wind and solar.

Authorities emphasize that the combination of regulatory advancement and real-world implementation will be crucial for successfully incorporating hydrogen into Serbia’s energy mix and supporting the country’s broader energy transition goals.

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During 2025 alone, Europe added 19.1 GW of new wind capacity, with approximately 90 % built onshore. Within the EU-27, 15.1 GW of new wind projects were installed, representing a 16 % increase compared with 2024. Wind power accounted for around 19 % of total electricity consumption across the EU, with some markets demonstrating far deeper integration of wind energy into their power systems.

Countries such as Denmark generated roughly 50 % of electricity from wind, while Lithuania and Ireland reached about 33 %, and Sweden approximately 30 %. These figures illustrate the degree to which wind energy has evolved from a marginal renewable technology into a core component of European power generation portfolios.

Germany remained the primary driver of wind capacity expansion across the continent. The country installed 5.7 GW of new capacity during 2025, maintaining its position as Europe’s largest wind market. Other leading additions came from Turkey with 2.1 GW, Sweden with 1.8 GW, Spain with 1.6 GW, France with 1.4 GW, and the United Kingdom with 1.3 GW.

Investment activity continued to accelerate. Financing decisions for wind projects reached €45 billion during the year, covering projects representing 20.9 GW of future installed capacity. These investment flows signal that the next phase of Europe’s wind expansion is already embedded in development pipelines.

Southeast Europe still represents a small share of Europe’s wind capacity

Despite this rapid growth across Europe, the countries of Southeast Europe remain comparatively modest contributors to the continent’s wind capacity. Historically, electricity systems in the region have relied heavily on coal-fired power plants and large hydropower facilities, leaving wind development slower than in Western and Northern Europe.

By the end of 2025 the Southeast European region had approximately 2.56 GW of installed wind capacity, representing less than 1 % of Europe’s total wind fleet. Nevertheless, recent years have begun to show a gradual but clear shift toward wind energy investment across the Western Balkans and neighboring markets.

Within the region, Croatia currently leads in installed wind capacity, followed by Serbia, while Montenegro, North Macedonia and Bosnia and Herzegovina are developing a growing pipeline of mid-scale projects. Slovenia, by contrast, remains largely absent from regional wind development.

The latest regional analysis by the renewable energy association OIE Serbia indicates that Southeast Europe is entering a more active phase of wind investment. However, the speed and scale of development differ significantly between countries.

Croatia has already built a sizeable fleet of operational wind farms. Serbia is expanding capacity through a combination of private developers and state-backed investments. Montenegro and North Macedonia are gradually entering a new phase of project development. Bosnia and Herzegovina is advancing wind projects through partnerships between domestic utilities and international investors.

Serbia builds a diverse wind portfolio

Serbia currently represents the second-largest wind market in Southeast Europe, with 13 operational wind farms totaling 824.2 MW of installed capacity.

During 2025 alone, an additional 199 MW of wind capacity was connected to the Serbian grid, representing a 24 % increase compared with 2024. This growth reflects an increasingly diversified development landscape combining international developers, local investment groups, and state participation.

The largest wind project currently operating in Serbia is Čibuk 1, with an installed capacity of 158 MW. The project was developed by Vetroelektrane Balkana d.o.o. with financing of €270 million provided by the IFC group and the European Bank for Reconstruction and Development (EBRD).

Another major project is Kovačica wind farm, with 104.5 MW of installed capacity. Developed by Electrawinds K-Wind d.o.o., the project involved an investment of approximately €189 million, financed through loans from Erste Bank and EBRD.

Additional wind capacity in Serbia includes Alibunar wind farm, operated by Elicio Ali VE d.o.o., with 42 MW of capacity and an investment of €72 million, as well as Malibunar wind farm with 8 MW.

One of the most recent large projects is Čibuk 2 wind park, with 154 MW of installed capacity. The project is backed by Masdar and Taaleri, with project financing provided by UniCredit Bank and Erste Bank, and a total investment estimated at €212 million.

Another significant development is Pupin wind park, located near the Kovačica wind farm. The project has a capacity of 94 MW and an investment value of roughly €100 million.

Serbia’s state-owned utility has also entered the wind sector. Elektroprivreda Srbije (EPS) developed Kostolac wind park, the first wind project implemented by the utility. The project has 66 MW of capacity, consisting of 20 wind turbines rated at 3.3 MW each, located on reclaimed land from former coal mining operations near Kostolac.

In eastern Serbia, the Krivača wind project represents another large investment. With 103.3 MW of installed capacityand a value of €155 million, the project was developed by MK Group together with the Slovenian investment fund Alfi.

The MK-Fintel Wind platform has also contributed several projects to Serbia’s wind fleet. These include La Piccolina wind farm with 6.6 MW, Košava wind park with 68 MW and an investment of €117 million, financed through loans from Erste Bank, the Austrian Development Bank, UniCredit Bank Serbia and Zagrebačka Banka, and Kula wind farm with 9.9 MW, valued at approximately €15 million.

Additional projects include Alibunar I wind farm with 9 MW, developed through a €15.5 million investment by Rudis and Nova Ljubljanska Banka, while the smallest facility remains Devreč wind turbine, the first wind installation in Serbia with a capacity of 0.6 MW.

Croatia remains the regional wind leader

Croatia continues to hold the leading position in Southeast Europe in terms of installed wind capacity.

According to the Croatian transmission system operator, by November 2025 Croatia had 29 operational wind farms with a combined installed capacity of 1,181 MW, and an approved grid connection capacity of 1,156.85 MW. Two additional wind projects were either under construction or undergoing testing, adding 83 MW of additional capacity.

WindEurope data indicates that Croatia had 1,264 MW of wind capacity connected to the grid by the end of 2025, including 27 MW installed during that year.

Among the largest projects in Croatia are Senj wind farm with 156 MW, Krš-Pađene wind farm with 142 MW, and ZD2P&3P wind complex with 125 MW, which together form key components of Croatia’s renewable energy transition.

Montenegro expands its wind portfolio with Gvozd project

Montenegro’s wind sector remains relatively small but continues to expand gradually.

The country’s first major wind project was Krnovo wind farm, commissioned in 2017 with 72 MW of installed capacity. The project was developed through a partnership between Akuo Energy and Masdar, representing Montenegro’s first commercial wind installation. The €139 million investment was financed through loans from KfW and the European Bank for Reconstruction and Development, and the facility includes 26 GE wind turbines.

The second wind project in Montenegro is Možura wind farm, with 46 MW of capacity, commissioned in 2019. Investors include Enemalta plc from Malta and Shanghai Electric Power from China, with a total investment of approximately €90 million.

Together, Krnovo and Možura currently represent 118 MW of installed wind capacity in Montenegro.

No new wind capacity was connected to the Montenegrin grid during 2025, but construction is underway on Gvozd wind park, a project with 54 MW of capacity being developed by Elektroprivreda Crne Gore (EPCG). Financing for the project includes an €82 million loan from the European Bank for Reconstruction and Development.

North Macedonia enters a new phase of wind expansion

North Macedonia’s wind sector expanded during 2025, with 30 MW of new capacity installed, bringing total wind capacity in the country to 103 MW.

The first wind project in the country was Bogdanci wind farm, commissioned in 2014 with 36.8 MW of capacity. The project represented an investment of €55.5 million and was developed by the state-owned utility Elektrani na Severna Makedonija.

A second project, Bogoslovec wind park, with 36 MW of installed capacity, entered operation in 2023. The wind farm includes eight Siemens-Gamesa turbines and was developed through cooperation between BNB Kompani and the Green for Growth Fund (GGF).

The third major development is Dren wind farm, with 44 MW of capacity, located near Demir Kapija. The project entered trial operation in late 2025 and was developed by the Turkish company Kaltun Enerji, with construction carried out by YEO Teknoloji.

Additional capacity is expected from Rosoman wind park, with 30 MW, while the most ambitious development currently underway is Štip wind complex, a project with 400 MW of capacity and an estimated investment of €500 million, being developed by Alcazar Energy Partners.

Bosnia and Herzegovina shows gradual growth

Bosnia and Herzegovina has experienced steady but moderate growth in wind energy over recent years. By the end of 2025 the country had 244 MW of installed wind capacity, although no additional capacity was commissioned during the year.

The country’s first wind farm was Mesihovina, located near Tomislavgrad, with 50.6 MW of capacity. The project was commissioned in 2018 by Elektroprivreda HZ BiH, representing an €81 million investment with 22 Siemens turbines. The utility is also planning the Poklečani wind project.

Another important project is Podveležje wind farm, developed by Elektroprivreda BiH, which includes 15 turbines with a combined capacity of 48 MW and produces approximately 120 GWh of electricity annually.

Future projects under development include Bitovnja wind farm with up to 90 MW and Vlašić wind farm with up to 50 MW.

Private developers have also entered the market. Jelovača wind farm, with 36 MW, developed by F.L. Wind, entered operation in 2019. The largest project so far is Ivovik wind farm, with 84 MW of capacity, commissioned in 2024 by Lager d.o.o. Posušje together with China National Technical Import and Export Corporation (CNTIC).

Another project currently under development is Ivan Sedlo wind farm, with 25 MW of capacity, developed by Kelag International, equipped with five Siemens Gamesa 5.0 turbines.

Slovenia remains a marginal wind market

In contrast to its regional neighbors, Slovenia has seen very limited development of wind energy.

The country’s first wind project was Dolenja Vas wind turbine, commissioned in 2012 by Alpen Adria Energie, with a capacity of 2.3 MW using a single Enercon turbine. Another small installation of 0.9 MW exists, but Slovenia’s total wind capacity remains negligible.

Wind capacity in the region could double by 2030

Forecasts indicate that wind development across Southeast Europe is likely to accelerate during the coming decade.

Across Europe, wind industry projections suggest that 151 GW of new wind capacity could be installed between 2026 and 2030, averaging approximately 30 GW per year. Within the EU-27, about 112 GW of new capacity is expected, although this remains below the EU target of 425 GW of wind capacity by 2030.

Approximately 77 % of new installations are expected to remain onshore, while the repowering of older turbines with more efficient models is likely to increase electricity generation without expanding turbine numbers significantly.

For Southeast Europe, projections suggest that regional wind capacity could exceed 5.19 GW by 2030, assuming that around 2.6 GW of currently planned projects are successfully developed. This would represent a 103 % increase compared with current installed capacity.

By 2030, forecasts indicate that Serbia could reach around 2,100 MW of installed wind capacity, followed by Croatia with approximately 1,640 MW, North Macedonia with about 520 MW, Bosnia and Herzegovina with 510 MW, and Montenegro with around 310 MW. Slovenia could exceed 100 MW during the same period if additional projects proceed.

For Serbia and the wider region, the coming decade will require alignment with broader European energy transition dynamics. Faster permitting procedures, stronger transmission infrastructure, and stable investment frameworks will be necessary to support the next wave of wind development.

Croatia and Serbia already form the core of regional wind expansion. Montenegro, North Macedonia and Bosnia and Herzegovina are entering a new investment phase, while Slovenia continues to lag significantly behind both regional and European averages.

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In its submission to US authorities, NIS highlighted the significance of uninterrupted operations for Serbia’s economy and energy sector. The company stressed that stable activity at NIS is particularly important amid heightened global energy market uncertainty and ongoing shifts in the international oil industry.

The request also points to ongoing discussions regarding a potential restructuring of the company’s ownership. According to NIS, negotiations on this issue are well advanced, which the company believes further supports the case for maintaining operational continuity while the process unfolds.

In a public statement, NIS expressed appreciation for the support it has received from domestic institutions and international partners. The company noted that such cooperation is essential to ensure it can continue functioning normally and contribute to the stability of Serbia’s energy system.

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Under the new decision, excise taxes on gasoline and diesel have been lowered by 20% compared to the rates in effect since mid-February 2026. The adjustment applies to leaded and unleaded petrol as well as gas oil.

Following the reduction, the revised excise levels stand at 0.52 euros/liter for leaded petrol, 0.49 euros/liter for unleaded petrol, and 0.5 euros/liter for diesel. Before the change, the state collected significantly higher duties: 0.65 euros/liter for leaded petrol, 0.61 euros/liter for unleaded petrol, and 0.63 euros/liter for diesel.

The Government explained that the decision was prompted by increased producer prices for petroleum derivatives, driven by the recent rise in crude oil prices worldwide.

The measure does not affect all fuel types. The excise duty on liquefied petroleum gas (LPG) remains unchanged at 0.48 euros per kilogram and is not included in the temporary reduction.

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Energy and Mining Minister Dubravka Đedović announced the completion of the works during a visit to the facility, which remains Serbia’s only pump-storage plant. She noted that the plant originally entered service in 1982 and has now undergone its first major refurbishment since commissioning.

The rehabilitation project, valued at approximately 35 million euros, was carried out by the state-owned power utility EPS. It involved a broad modernization of the plant’s technical infrastructure, including upgrades to generating units, electrical systems, and control equipment. A significant part of the project also focused on civil engineering works, including the overhaul of the water supply and discharge tunnel, which stretches roughly 8 kilometers and is crucial for plant operation. The modernization has extended the operational lifespan of the facility while improving the reliability and efficiency of its units.

Officials describe HPP Bajina Bašta as a type of energy storage system for the country. By pumping water during low demand periods and generating electricity during peak consumption, it helps stabilize the network and support system flexibility. This balancing function is increasingly important as Serbia expands its share of renewable energy sources, such as wind and solar power, whose output can vary depending on weather conditions.

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Following talks with an EDF delegation led by company president Bernard Fontana, Energy and Mining Minister Dubravka Djedović said the document outlines the next steps required for launching Serbia’s nuclear program. The study includes recommendations covering 19 key milestones identified by the International Atomic Energy Agency (IAEA) as necessary for countries introducing nuclear energy.

According to the Minister, the focus now shifts to implementing the first phase of the program. Authorities plan to define priorities, establish a timetable, and begin addressing the institutional and regulatory requirements needed to move the process forward. Serbia currently lacks a complete legal and institutional framework for nuclear energy development, which the government considers a main issue to address in the coming period. Work on legislative analysis and institutional preparation will therefore be a central part of the next stage.

As part of this process, the government plans to establish a national body responsible for coordinating the development of nuclear energy for peaceful purposes. The planned institution, NEPIO, will oversee the early stages of the nuclear program and help organize cooperation with international partners.

Officials argue that introducing nuclear energy would strengthen Serbia’s energy system by diversifying supply sources and providing a stable, low-emission electricity option. The Minister also highlighted the importance of developing human resources capable of supporting such a program. While Serbia already has specialists in relevant fields, expanding and training the workforce will be a major priority over the next year. Cooperation with EDF is expected to include education programs, training, and professional development for engineers and technical experts.

EDF representatives confirmed their readiness to support Serbia’s plans. Fontana said the company has extensive experience helping countries build nuclear expertise, including training engineers and establishing technical capabilities during the early stages of nuclear energy programs. EDF’s teams are prepared to assist Serbia across all aspects of the project in line with the pace set by Serbian authorities.

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