The steepest daily correction appeared in the southern SEE markets. Montenegro’s BELEN exchange fell to €56.15/MWh, down more than €52/MWh day-on-day, while Serbia’s SEEPEX dropped to €63.79/MWh, declining by more than €59/MWh versus the previous session. Greece’s HENEX also corrected aggressively to €67.26/MWh, reflecting the return of stronger solar availability and softer regional balancing conditions.  

Hungary’s HUPX base price settled at €106.98/MWh, still remaining structurally above most SEE markets despite a daily fall of almost €35/MWh. Romania’s OPCOM closed at €103.04/MWh, Bulgaria’s IBEX at €102.44/MWh, Slovenia’s BSP at €97.46/MWh, and Croatia’s CROPEX at €98.16/MWh. Italy remained the structural premium market at €123.03/MWh, preserving the north-south export pull that continues to shape cross-border commercial flows across the Balkans.  

The regional correction was primarily driven by improving renewable conditions. Forecast solar generation across the SEE region climbed to 5,848 MW, while wind output increased sharply to 3,994 MW, adding more than 2.3 GW day-on-day.   At the same time, regional temperatures rose toward seasonal norms, reducing heating-related load pressure and easing balancing requirements. Weather forecasts for Serbia, Montenegro, Greece, Romania and Hungary all showed additional warming through the week.  

Generation structure data confirms the renewable-led softening. Hydro remained the dominant generation source at 27% of regional supply, while solar accounted for 20%, nuclear for 12%, gas for 14%, and coal for only 18%.   The increasing solar penetration again compressed midday pricing, particularly in Greece, Slovenia and Serbia, where intraday solar cannibalization effects are becoming increasingly visible.

The report also shows that total regional generation fell to 26,803 MW, down more than 1.3 GW day-on-day, but the decline was offset by lower demand and significantly reduced import dependency. Net regional imports shifted to -894 MW, compared with +924 MW one day earlier, indicating that SEE markets moved back toward a more balanced or partially exporting position.  

Cross-border dynamics remain one of the key structural themes in the regional market. Hungary continued importing heavily from Austria and Slovakia, while Greece maintained strong import demand from northern neighbors. Commercial flow data showed persistent exports from Romania toward Hungary and Serbia, while Bulgaria remained a significant transit corridor toward Greece and Turkey.  

Despite the spot market correction, forward markets remain relatively elevated compared with seasonal norms. Hungarian week-ahead power contracts traded around €98/MWh, while calendar 2026 contracts remained above €112/MWh.   This suggests that traders still price medium-term structural risk into the region, particularly around summer cooling demand, hydro volatility and gas exposure.

Gas markets themselves remained comparatively stable. Austrian CEGH gas traded around €52.78/MWh, while EUA carbon allowances rose to approximately €75/t, continuing to maintain pressure on coal-fired generation economics across SEE markets.   Higher carbon prices continue supporting the long-term economics of renewable projects, battery storage systems and flexible gas capacity.

The daily pricing profiles further illustrate the increasingly volatile shape of SEE electricity markets. Several exchanges recorded deep midday price collapses followed by strong evening recovery ramps, especially in Greece, Romania and Slovenia.   These price curves increasingly resemble Western European solar-saturated markets, reinforcing the growing strategic value of battery storage, flexible industrial demand and cross-border balancing infrastructure.

For Serbia specifically, the decline of SEEPEX toward €64/MWh reflects a combination of softer regional prices, higher renewable inflows from neighboring systems and lower import pressure. However, structurally, Serbia remains exposed to future balancing volatility due to growing renewable integration and relatively limited domestic flexibility capacity. This continues strengthening the long-term investment case for utility-scale BESS projects, flexible thermal reserve modernization and advanced balancing services.

At the same time, the widening divergence between daytime and evening prices increasingly supports merchant renewable-plus-storage business models. As CBAM and industrial decarbonization pressures accelerate across Europe, regional exporters and industrial consumers are expected to prioritize traceable low-carbon electricity procurement through PPAs, Guarantees of Origin and increasingly sophisticated balancing arrangements.

The broader regional picture also continues pointing toward deeper market integration. Greece’s offshore wind acceleration plans, Romania’s nuclear refurbishment program at Cernavoda, Turkey’s nuclear expansion incentives and Serbia’s continuing oil and gas upstream investments all reflect how SEE energy systems are simultaneously managing decarbonization, security-of-supply and industrial competitiveness pressures.  

The combination of stronger renewables, rising carbon prices, volatile imports and expanding transmission integration is steadily transforming SEE electricity markets from traditionally thermal-driven systems into increasingly weather-driven and flexibility-dependent trading environments.  

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The group posted a consolidated net profit of approximately €186.8 million, marking a 2.3% increase compared to the same period last year. However, total revenue fell by just over 10% year-on-year to around €411 million. At the same time, operating expenses also decreased, dropping by 10.3% to approximately €224.6 million in the January–March 2026 period.

Despite higher net profit, key profitability indicators showed some weakening. EBITDA declined by 7.4% to €232.4 million, while EBIT fell by 5.1% year-on-year to €205.5 million, reflecting pressure on core operational performance.

Production figures also pointed to a downward trend. Natural gas output reached 1.235 billion cubic meters, representing a 3.9% decrease compared to the previous year. Electricity generation saw a much sharper decline, falling by 46.4% to 106.98 GWh, highlighting reduced activity in the power segment.

At the same time, the company continued to strengthen its balance sheet. Total assets rose to just over €5 billion by the end of March, compared to €4.8 billion at the end of 2025, indicating ongoing financial expansion despite operational contraction.

Romgaz has also been advancing several strategic initiatives. Earlier this month, the company reached a preliminary agreement with fertilizer producer Azomureș regarding the potential acquisition of its operational business activities, signaling potential diversification and downstream integration in its portfolio.

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The company announced the successful completion of the first continuous concrete pour for permanent structures associated with the Unit 1 refurbishment project. The operation, described as the largest of its kind at the site since the construction of Unit 2, required approximately 3,470 cubic meters of concrete, equivalent to around 380 truck deliveries.

The works were carried out at the Intermediate Radioactive Waste Storage Facility (DIDR-U5). This facility will play a key role in the management, treatment, and temporary storage of radioactive waste generated during the refurbishment process, as well as in the future long-term operation of both Unit 1 and Unit 2.

According to CEO Cosmin Ghiță, this milestone represents the symbolic beginning of the large-scale modernization phase of the reactor. He stated that the project is expected to extend the operational life of Unit 1 by an additional 30 years following its planned return to service in 2030.

Nuclearelectrica received the necessary construction authorization for the storage facility from Romania’s nuclear regulator in September 2025, enabling civil engineering works linked to the refurbishment program to proceed according to schedule.

The modernization project is being implemented in three main phases. The current stage focuses on preparation and infrastructure works, which are expected to continue until the end of 2027. The final phase will involve the shutdown of Unit 1 and the execution of the full refurbishment process.

Once completed, the reactor is expected to be reconnected to Romania’s national electricity system in 2030, after which it will continue operating for an additional three decades.

Commissioned in 1996, Unit 1 at Cernavodă has been a cornerstone of Romania’s electricity system for nearly 30 years. According to Nuclearelectrica, the unit has generated more than 149 million MWh of electricity over its lifetime while avoiding approximately 145 million tons of CO₂ emissions.

The company also highlighted the reactor’s strong performance record, noting that it has consistently maintained a capacity factor above 90%, placing it among the most efficient nuclear units globally.

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The new SPV is expected to become operational in the near term, with its formation linked to reform milestones under Greece’s Recovery and Resilience Facility (RRF) program. Early discussions regarding participation in the structure have already included potential partners such as the electricity transmission system operator ADMIE and several financial institutions.

This entity will be responsible for conducting wind measurement campaigns and seabed mapping across marine zones selected for the initial phase of Greece’s offshore wind development. Authorities are targeting approximately 1.9 GW of offshore wind capacity in the early years of the next decade.

Separate from the 600 MW pilot offshore wind projects near Alexandroupoli, which are being developed under a distinct framework, the new survey program will focus on offshore areas associated with roughly 1.3 GW of future capacity. These zones include maritime regions near Evia, the island of Gyaros, eastern Crete near Sitia, and northeastern Rhodes.

Preparatory technical work has already been underway for some time, meaning that data collection activities could begin shortly after the SPV is officially established. The goal is to gather high-resolution data on wind resources and seabed conditions before projects progress into advanced development stages.

The initiative is now proceeding independently of the delayed approval process for Greece’s broader National Offshore Wind Development Program, even though most regulatory and administrative barriers were resolved years earlier. Greek authorities are reportedly aiming to capitalize on the current slowdown in global offshore wind investment activity by accelerating preparatory work in advance.

This strategy is intended to position Greece more competitively in the medium term, particularly once international financing conditions improve and floating offshore wind technology becomes more cost-effective and commercially scalable.

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The proposals follow an extensive investigation launched in March, triggered by the worsening conflict in the Middle East and its potential impact on fuel supply security and pricing dynamics. According to the regulator, the recommendations are based on detailed market analysis and ongoing as well as completed proceedings involving the Lukoil group.

The CPC stated that its report covered all major segments of Bulgaria’s fuel value chain, including refining, imports, storage, wholesale distribution, and retail sales. Authorities also reviewed the effectiveness of crisis measures introduced by the caretaker government during the period of heightened market stress.

One of the key findings was that government intervention helped slow fuel price increases, but was not sufficient to fully halt the upward trend. The Commission also identified market distortions linked to the appointment of a special administrator overseeing Lukoil operations in Bulgaria.

According to the report, discrepancies emerged between wholesale and retail fuel pricing at Lukoil-operated stations, which placed additional pressure on smaller fuel traders, importers, and producers. The CPC noted that after its intervention earlier in the year, the disputed pricing practices were discontinued.

A central recommendation is the creation of a permanent fuel market task force under the Council of Ministers. This body would include state institutions and industry representatives and would be responsible for monitoring fuel availability, price movements, storage levels, and supply risks.

The regulator also proposed the introduction of a weekly official fuel index, which would publish international benchmarks, domestic pricing data, trading margins, and reserve levels to improve market transparency and reduce uncertainty.

Additional measures include stricter oversight across the entire fuel supply chain, from refinery operations to retail distribution. The CPC also recommended developing contingency plans for refinery continuity and accelerating efforts to diversify crude oil supply sources.

Several proposals target sectors heavily dependent on fuel costs, including transport, agriculture, fisheries, and fertilizer production. The Commission suggested introducing compensation mechanisms to offset increased operational costs for these industries during periods of high fuel prices.

The package also includes short-term stabilization tools such as liquidity support mechanisms, supply guarantees for strategic fuel reserves, and potential postponement of toll increases during periods of extreme price pressure. A separate proposal calls for the creation of a temporary fuel stabilization fund, financed through additional VAT revenues generated by higher fuel prices.

The CPC further recommended temporary anti-speculation measures, adjustments to biofuel blending obligations, and flexible excise policies during prolonged market stress. It also proposed compensation systems for producers and importers, ensuring full supply chain traceability.

Long-term structural reforms include improving access to tax warehouses, expanding fuel storage infrastructure, encouraging new market entrants, and reducing fossil fuel dependency through transport electrification and energy efficiency measures.

At the same time, the CPC confirmed that investigations into the Lukoil group for suspected abuse of a dominant market position are still ongoing. Earlier this year, the regulator requested detailed operational and commercial data from Lukoil Neftochim Burgas, Lukoil Bulgaria, and other major wholesalers operating in the Bulgarian fuel market.

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The ruling concerns TPP Maritsa East 2 and follows a prolonged legal battle initiated by environmental groups Greenpeace Bulgaria and For the Earth. Activists described the decision as one of the most significant environmental court victories in Bulgaria in recent years.

The court upheld an earlier judgment issued by the Administrative Court in Stara Zagora, which had previously overturned a 2018 decision by Bulgaria’s Executive Environment Agency to amend the plant’s integrated operating permit.

At the center of the dispute was a derogation that allowed the power plant to bypass EU environmental standards related to sulfur dioxide emissions. Environmental organizations argued that this exemption effectively permitted pollution levels far above legal thresholds.

According to Greenpeace Bulgaria, the plant had been allowed to emit sulfur dioxide at nearly double the legal limit and mercury at more than four times the permitted level, without a clear timeline or binding reduction measures.

In its final ruling, the Supreme Administrative Court concluded that Bulgarian authorities failed to properly assess the cumulative environmental and health impacts of the emissions. Judges also found that the exemption ignored key scientific evidence and conflicted with local air quality policies in the municipality of Galabovo.

The court further stated that the exemption did not comply with European environmental law requirements governing derogations and referenced a related judgment by the Court of Justice of the European Union (CJEU), case C-375/21, which was considered during proceedings.

The case has gone through multiple stages of litigation in recent years. In 2023, the Supreme Administrative Court had already overturned a lower court ruling due to serious procedural issues and ordered the case to be reconsidered by a different judicial panel.

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The upward movement in oil prices was driven by a combination of geopolitical and supply-side risk factors. The United States’ rejection of Iran’s response to its peace proposal, combined with ongoing tensions affecting flows through the Strait of Hormuz, increased concerns about potential supply disruptions. At the same time, the risk of a breakdown in ceasefire expectations further supported bullish sentiment in crude oil markets.

In the European gas market, TTF natural gas futures (ICE, Front Month) registered their weekly minimum settlement price of €46.23/MWh on Monday, May 11. Prices then followed a steady upward trend throughout the week, reaching a weekly maximum of €50.17/MWh on Friday, May 15. This level was 14% higher than the previous Friday’s close and marked the highest price since April 8, based on AleaSoft Energy Forecasting data.

The increase in gas futures prices was mainly driven by the lack of progress in peace negotiations between the United States and Iran, alongside persistent concerns about potential disruptions in supply through the Strait of Hormuz. Additional upward pressure came from fundamentally tight European gas storage conditions, with average storage levels remaining below 40%, and several countries still under 25% capacity, reinforcing market sensitivity to supply risk.

Regarding CO₂ emission allowance futures (EEX, December 2026 contract), the market reached its weekly maximum settlement price of €77.17/t on Monday, May 11, the highest level since April 18. Throughout the rest of the week, prices mostly stayed above €75/t, although below the early-week peak. The weekly minimum was recorded on May 13 at €75.07/t, before prices recovered slightly toward the end of the week.

By Friday, May 15, CO₂ futures settled at €75.62/t, representing a modest increase of 0.6% compared to the previous week’s final session. Overall, the market showed a relatively stable but firm trend, with intermittent fluctuations driven by broader energy market sentiment and expectations around industrial demand and fuel switching dynamics, AleaSoft reports.

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In the week of May 11, weekly average prices remained below €100/MWh in most European electricity markets. The Italian and British markets were the main exceptions, with averages of €116.22/MWh and €119.33/MWh, respectively. At the lower end of the spectrum, the French, Spanish, and Portuguese markets recorded the weakest prices, at €44.02/MWh, €49.83/MWh, and €49.98/MWh. In other analyzed markets, prices were relatively clustered, ranging from €90.29/MWh in Belgium to €98.87/MWh in Germany.

Regarding daily price movements, the Iberian markets—Spain and Portugal—along with France, frequently recorded prices below €50/MWh throughout the second week of May. The French market registered the lowest daily average of the week, falling to just €24.36/MWh on May 14, marking one of the weakest price levels among all analyzed markets.

On the opposite side, the Italian and British markets consistently experienced higher price pressure, with daily averages exceeding €100/MWh during the week. Several other markets, including Germany, Belgium, the Netherlands, and the Nordic region, also surpassed the €100/MWh threshold in at least one trading session. The Italian market recorded the highest daily price of the week, reaching €136.36/MWh on May 15.

In the week of May 11, increased wind and solar generation across Europe was the main driver of falling electricity prices, supported in some regions by lower electricity demand. However, forward-looking forecasts from AleaSoft Energy Forecasting suggest that prices may rise again during the third week of May, as wind energy production is expected to decline. At the same time, demand is projected to increase in certain markets, while gas prices are likely to remain a key influencing factor in shaping European electricity price dynamics, AleaSoft reports.

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During the same period, average temperatures fell across most of the analyzed markets. Belgium and Germany recorded the largest declines, with drops of 3.8°C and 3.7°C, respectively, while Italy saw the smallest decrease of 0.7°C. Great Britain and France also experienced cooler conditions, with temperature reductions of 2.4°C and 2.5°C. In contrast, the Iberian Peninsula was an exception, as Spain and Portugal recorded slight temperature increases of 0.1°C and 0.3°C.

The week also included the national holiday on May 14 (Ascension Thursday), which contributed to lower demand in Germany and Belgium. At the same time, colder weather conditions supported higher electricity consumption in France, Italy, and Great Britain, while slightly warmer temperatures in the Iberian Peninsula led to reduced demand in Spain and Portugal.

For the week of May 18, AleaSoft Energy Forecasting’s demand outlook points to increases in Germany, Italy, the Iberian Peninsula, and Belgium, while France and Great Britain are expected to experience declines in electricity demand, AleaSoft reports.

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For the week of May 18, AleaSoft Energy Forecasting’s solar outlook indicated higher solar generation in Italy, Germany, and Spain. This suggests a continuation of relatively strong photovoltaic output across key European power markets, driven by seasonal conditions and improving solar resource availability.

During the second week of May, wind energy production also increased across most European electricity markets compared to the previous week. Germany experienced the most significant rise, with wind generation jumping 120%, effectively reversing the downward trend seen in the previous two weeks. Spain recorded the smallest increase at 21%, extending its growth streak to a third consecutive week. France and Italy also saw strong rebounds, with increases of 50% and 100%, respectively, after prior periods of decline. In contrast, Portugal experienced a 7.1% decrease in wind output.

A notable highlight of the week was Tuesday, May 12, when the German market reached its highest daily wind energy production for May in the past four years, totaling 623 GWh. This underscores the volatility and scale of wind generation potential in Europe’s largest power market.

For the third week of May, AleaSoft Energy Forecasting’s wind forecasts point toward lower wind production across all analyzed European markets, signaling a potential short-term reversal after the strong gains observed in the previous week, AleaSoft reports.

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The first half of May 2026 made this shift visible. Prices rose across almost every major SEE market, but not evenly. Romania’s OPCOM averaged €115.88/MWh, Hungary’s HUPX €108.62/MWh, Croatia’s CROPEX €105.77/MWh, Bulgaria’s IBEX €104.98/MWh, Serbia’s SEEPEX €101.61/MWh, Montenegro’s BELEN €98.76/MWh, and Albania’s ALPEX €98.60/MWh. The spread pattern shows that national averages still matter, but the deeper commercial story is increasingly about where electricity can move, when it can move, and which corridor captures the scarcity premium.  

This is a major change from the older SEE market structure. Historically, the region was analysed through national generation mixes: Serbia as coal-heavy, Montenegro as hydro-sensitive, Bosnia and Herzegovina as coal-and-hydro based, Romania as hydro-nuclear-thermal, Bulgaria as nuclear-coal-solar, Greece as gas-and-renewables driven. That framework is still useful, but it is no longer enough.

The real market value now sits in the corridors between those systems.

The clearest signal came from cross-border flows. Net exports across the broader HU+SEE region deteriorated from -767 MW to -1,170 MW, meaning the region became more structurally import-dependent. Flows toward Italy reversed from +310 MW to -148 MW, while the Bulgaria–North Macedonia–Albania position toward Greece weakened to -1,129 MW.  

These are not small operational details. They show how fast market value can migrate when generation, demand, solar output, hydro availability, nuclear outages and cross-border capacity interact.

In this new structure, geography becomes a financial variable.

A renewable project in Serbia is no longer just a Serbian asset. Its value depends on access toward Hungary, Romania, Bosnia and Herzegovina, Montenegro, North Macedonia and the wider coupled market structure. A hydropower asset in Montenegro is no longer only a domestic balancing resource. Its revenue depends on Italian spreads, Albanian flows, Serbian liquidity, CBAM treatment and regional congestion. A Bulgarian battery is not just a storage project. It is a flexibility asset inside a corridor linking Greece, Romania, Turkey, North Macedonia and Central Europe.

This is corridor economics.

The first corridor to watch is the Greece–Bulgaria–Romania axis. Greece is becoming a renewable-heavy, gas-linked and LNG-enabled system with rising solar curtailment risk. Bulgaria is moving into storage and remains strategically important through nuclear, solar and cross-border positioning. Romania combines hydro, nuclear, wind, solar and growing industrial demand, but faces network connection and grid-access pressure.

Together, these three markets increasingly form the southern-to-central balancing corridor of SEE.

Gas strengthens that role. The Vertical Gas Corridor, the Alexandroupolis LNG route, Bulgarian transmission infrastructure and Romania’s gas and power system all create a combined energy corridor where gas availability and electricity prices increasingly interact. When gas becomes the marginal price setter, the corridor becomes more valuable. When renewables oversupply one zone and scarcity appears in another, the corridor captures the spread.

The second corridor is Serbia–Hungary. This is one of the most important strategic interfaces in the region because Hungary often functions as the Central European price anchor, while Serbia sits at the crossroads of Western Balkan flows. In May, HUPX averaged €108.62/MWh, while SEEPEX averaged €101.61/MWh, leaving Serbia at a discount to Hungary.  

That spread matters. It creates trading value, but it also signals Serbia’s potential role as a balancing and transit market. If Serbia strengthens transmission capacity, market liquidity, storage deployment and industrial renewable procurement, it can become a corridor hub rather than only a national power system.

But if grid bottlenecks persist, Serbia risks becoming a congestion buffer between stronger surrounding markets.

The third corridor is Bosnia and Herzegovina–Serbia–Croatia. This corridor is shaped by coal instability, hydro potential and transmission constraints. Bosnia has significant generation resources, but project delays, coal-plant stress and governance fragmentation weaken its reliability. Serbia provides scale and centrality. Croatia links the region toward Slovenia, Hungary and the Adriatic market space.

Coal instability is especially important here. RiTE Ugljevik reported a €18.3 million first-quarter loss after production disruptions, while RiTE Gacko saw profit fall to only around €50,000.   When coal plants in this corridor become less reliable, cross-border flows and regional prices become more volatile.

The fourth corridor is the Montenegro–Albania–Italy-linked axis. This corridor is strategically different because it combines hydropower, emerging wind, solar-plus-storage and Adriatic export logic. Montenegro’s EPCG has already felt CBAM-related export pressure, with an estimated €13 million revenue impact in the first quarter of 2026.   Albania is moving toward bankable solar-plus-storage through the 160 MW solar and 60 MW BESS project backed by a proposed €53 million EBRD loan within a total investment of around €105 million.  

This corridor could become one of the most interesting flexibility zones in SEE. Hydro, solar, storage and export positioning can create a valuable low-carbon supply platform. But it will depend on traceability, grid access, cross-border rights and storage integration.

The fifth corridor is the future gas-power-industrial corridor linking Greece, North Macedonia, Serbia and Central Europe. The decision for Serbia and North Macedonia to join the next phase of the Vertical Gas Corridor discussion is not only about gas supply. It is about industrial energy security and power-system flexibility.  

This corridor may become increasingly important as industrial exporters require reliable, traceable and competitively priced energy under CBAM pressure. Gas flexibility, renewable PPAs, storage and cross-border electricity access will increasingly be evaluated together, not separately.

That is the deeper market trend.

Electricity, gas, carbon, industrial exports and grid infrastructure are converging into corridor-based investment logic.

For traders, this means spreads matter more than national averages. A market desk should not only track Serbian, Romanian or Bulgarian prices in isolation. It should track corridor behavior: Romania–Hungary, Serbia–Hungary, Bulgaria–Greece, Montenegro–Albania, Croatia–Slovenia, Bosnia–Serbia, and Greece–Italy-linked dynamics.

For investors, corridor economics changes project selection. A wind farm, solar plant or battery should be evaluated by its corridor position. Does it sit near a congested node? Can it serve an industrial buyer? Can it access a premium export

Elevated by Virtu.Energy

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The first half of May 2026 already showed the structural direction. Solar generation across the broader HU+SEE system increased by 462 MW, while total electricity consumption declined by roughly 1,018 MW. At the same time, firm generation weakened: nuclear output fell by 1,686 MW, hydro declined by 357 MW, and coal dropped by 260 MW. Prices still rose, with OPCOM at €115.88/MWh, HUPX at €108.62/MWh, IBEX at €104.98/MWh, CROPEX at €105.77/MWh, and SEEPEX at €101.61/MWh.  

That combination captures the problem. SEE can have more renewable generation and still face higher prices if renewable output arrives in the wrong hours, at constrained nodes, without sufficient storage, flexible demand or cross-border capacity.

Curtailment begins as a technical issue but quickly becomes a financial one. A solar plant that cannot inject electricity during peak production hours loses revenue. A wind farm that faces grid constraints loses availability. A lender that assumed high generation capture sees weaker DSCR. An industrial buyer relying on renewable PPAs may not receive the expected low-carbon supply profile. A government that announced large RES additions may discover that installed capacity is not the same as usable energy.

Greece is already warning the region. Small solar investors face uncertainty from curtailments and low prices, while regulators are tightening rules for wind farm locations.   The lesson is clear: renewable expansion without grid discipline creates financial strain for developers and operational strain for system operators.

Bulgaria is moving faster into storage because the same risk is becoming visible. The country is emerging as a regional storage hub precisely because solar growth increasingly requires flexibility. Storage is not being added as a decorative ESG feature. It is becoming a practical hedge against curtailment, negative pricing and grid congestion.

Romania faces another version of the same problem. Renewable investors are increasingly sensitive to network connection rules, grid access and curtailment exposure. When developers cannot rely on stable grid availability, project finance becomes more difficult. Higher risk means higher required returns, more conservative debt sizing and tougher lender due diligence.

In Serbia, the issue is still developing but will become unavoidable. The country has significant solar and wind potential, but project value will depend heavily on connection quality, substation location, transmission reinforcement and balancing market access. A renewable project with weak grid positioning may look attractive in early development but become difficult to finance once curtailment risk is properly modelled.

Montenegro faces a more complex version because its system is smaller and more influenced by hydropower, cross-border trade and export monetization. EPCG’s reported €13 million Q1 export revenue impact from CBAM-related market effects shows that even low-carbon electricity can lose value when market access, carbon rules and buyer appetite shift.   Add curtailment risk to that environment and the economics of future wind and solar projects become more demanding.

Curtailment also changes PPA structures. Industrial buyers do not simply need annual renewable volume. They need credible delivery, predictable pricing, documentation and increasingly hourly matching. A PPA linked to a project facing frequent curtailment may fail to provide the supply certainty required by CBAM-exposed exporters.

This is why curtailment and CBAM are increasingly connected.

A Serbian or Montenegrin industrial exporter supplying the EU may want renewable electricity to reduce embedded carbon exposure. But if that electricity is curtailed during key hours, the buyer still needs replacement power. If replacement power comes from the grid mix, the compliance value weakens. If the contract lacks clear rules on curtailment, substitution and documentation, the buyer faces commercial and regulatory uncertainty.

For lenders, this becomes a bankability issue. Curtailment assumptions must now be treated as core financial variables, not footnotes. Base-case, downside and severe-case models should include reduced captured generation, lower captured prices, balancing penalties, compensation mechanisms and delayed grid reinforcement scenarios.

The strongest renewable projects in SEE will therefore be those designed around curtailment resilience. That means hybridization with batteries, stronger grid nodes, flexible offtakers, conservative generation capture assumptions, robust TSO documentation and clear contractual treatment of curtailment events.

The weakest projects will be those built on land availability alone.

Cheap land and strong irradiation do not guarantee bankability. If the transmission node is weak, if multiple projects queue behind the same substation, if grid reinforcement is delayed, or if local demand is insufficient, curtailment can destroy value.

Battery storage is the obvious response, but not the only one. Flexible industrial demand can also help. Data centers, electrolysers, cold storage, water pumping, district heating systems and industrial load management can absorb renewable output when prices are low. In SEE, this demand-side flexibility remains underdeveloped but may become increasingly valuable.

Hydropower can also reduce curtailment if managed as a flexibility asset. Reservoir hydro can hold back generation during solar-heavy hours and release power during evening scarcity. But this requires sophisticated dispatch, market participation and sometimes regulatory reform.

Gas generation remains relevant as backup flexibility, though it does not solve curtailment itself. It supports system stability when renewable output falls, but it does not absorb excess solar. That is why gas, storage and demand response must be treated as different flexibility tools rather than interchangeable solutions.

The policy challenge is that governments often announce renewable capacity targets without equally detailed grid absorption plans. Installed megawatts are politically attractive. Curtailment rates are not. Yet the financial system will increasingly price this difference.

A country that tenders 1 GW of solar without grid reinforcement may produce impressive headlines but weak investor returns. A country that tenders less capacity but pairs it with storage, grid upgrades and industrial demand may create stronger long-term value.

SEE is now entering that more disciplined phase.

Project developers should expect banks to ask harder questions. Where is the grid study? What is the curtailment scenario? What is the compensation regime? What happens if the TSO delays reinforcement by 12–18 months? How does curtailment affect DSCR? Can storage protect revenues? Is the PPA firm, pay-as-produced or shaped? Who bears balancing risk?

These questions will separate bankable projects from speculative development pipelines.

Curtailment will also reshape asset pricing. Projects with strong grid access will trade at a premium. Projects in congested zones will face valuation discounts unless storage or contracted offtake reduces the risk. Early-stage developers may find that grid rights become more valuable than land rights.

This is already visible in more mature European markets, and SEE will follow.

For utilities, curtailment creates strategic tension. They need renewable capacity to decarbonize, but too much uncontrolled renewable injection can destabilize system economics. Utilities with hydro, storage and flexible assets will manage the transition better than those relying on legacy coal and merchant solar alone.

For TSOs, the pressure will intensify. Transmission planning cycles are slow, while renewable development cycles are faster. If grid operators cannot accelerate reinforcement, connection management and digital dispatch, curtailment will rise.

For governments, the economic consequence is straightforward: renewable energy that cannot be delivered does not support industrial competitiveness, export compliance or energy security.

The energy transition in SEE is therefore moving from a generation race to a system-integration test. The winning countries will not simply be those that install the most wind and solar. They will be those that convert renewable capacity into usable, traceable, dispatchable and financeable electricity.

Curtailment is the hidden cost that reveals whether that transition is real.

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The first half of May 2026 showed a regional power system already moving toward congestion-led market behavior. Prices increased sharply even though demand fell. Solar output rose, but it did not prevent higher system prices. Cross-border flows shifted materially, while several corridors showed signs of tightening, reversal or structural imbalance. The data points to a market where electricity value is increasingly determined not only by how much power is produced, but by whether it can physically reach the right market at the right hour.

This is the beginning of a congestion decade.

The regional figures are already telling. Net exports across the broader HU+SEE system deteriorated from -767 MW to -1,170 MW, meaning the region became more import-dependent during the observed period. Flows toward Italy reversed from +310 MW to -148 MW, while the Bulgaria–North Macedonia–Albania flow position toward Greece worsened to -1,129 MW.  

That movement is commercially important because the Balkans have historically relied on cross-border flexibility to smooth national generation imbalances. Hydro-rich systems exported during favorable hydrology. Coal-heavy systems provided baseload. Greece, Italy, Hungary and Romania acted as price anchors depending on season, weather and fuel spreads.

That structure is becoming less predictable.

The region is now dealing with several simultaneous pressures. Solar capacity is growing faster than grid reinforcement. Coal plants are becoming less reliable. Nuclear outages have stronger price impact. Hydro output is less consistently monetizable. Gas is returning as the marginal balancing fuel. CBAM is altering buyer behavior for Western Balkan electricity. At the same time, cross-border capacity remains limited by old network design, slow permitting and fragmented national investment planning.

The result is a market in which congestion becomes both a risk and a revenue source.

For traders, congestion creates spreads. For developers, it creates curtailment risk. For banks, it creates uncertainty around captured prices. For TSOs, it creates operational stress. For governments, it creates political pressure as renewable projects wait for grid access while consumers face higher wholesale volatility.

This is already visible in the regional price map. Romania’s OPCOM averaged €115.88/MWh in the first half of May, trading at a €7.65/MWh premium to Hungary’s HUPX. Bulgaria’s IBEX averaged €104.98/MWh, Croatia’s CROPEX €105.77/MWh, Slovenia’s BSP €103.85/MWh, Serbia’s SEEPEX €101.61/MWh, Montenegro’s BELEN €98.76/MWh, and Albania’s ALPEX €98.60/MWh.  

These differences are not large enough to indicate a fully fractured market, but they are wide enough to show that national and corridor constraints are increasingly shaping value.

Romania is a key example. It combines major generation resources, large renewable potential, nuclear exposure, hydro flexibility and cross-border links toward Hungary, Bulgaria, Serbia, Moldova and Ukraine. Yet it also faces network connection disputes and regulatory pressure around new grid access rules. The May data showed Romania at the top of the SEE price stack, above Hungary, Bulgaria and Serbia. That premium reflects not only generation conditions but also the difficulty of translating regional supply into smooth price convergence.

Bulgaria offers another version of the same problem. The country is rapidly becoming a solar and battery storage hub, but storage growth itself is a response to grid pressure. A system with too much uncontrolled solar and insufficient transmission capacity begins to experience curtailment, negative-price risk and local congestion. Batteries reduce the problem, but they do not replace the need for stronger transmission corridors.

Greece is the clearest warning sign. Strong solar growth, increasingly visible curtailment pressure and low-price uncertainty for small investors show what happens when renewable deployment outruns system flexibility.   The May flow data, where northern flows toward Greece deteriorated sharply, points to a market still heavily dependent on imported balancing under certain conditions, even as domestic solar can depress prices during other hours.

That contradiction will become more common across SEE.

Countries may simultaneously experience renewable oversupply in one zone and scarcity in another. A solar-heavy region can produce negative prices at noon while the national system still needs expensive imports in the evening. This is not a failure of renewable generation. It is a failure of grid timing, flexibility and spatial coordination.

Serbia sits directly inside this emerging congestion map.

Its geographic position gives it strategic importance between Hungary, Romania, Bulgaria, Bosnia and Herzegovina, Montenegro, Kosovo and North Macedonia. It can become a regional balancing corridor, but only if transmission investment, market coupling, grid-code enforcement and renewable connection planning keep pace with project development.

If not, Serbia risks becoming a congestion buffer between stronger surrounding markets rather than a value-capturing hub.

The same logic applies to Montenegro. Its hydropower and wind resources have strong regional value, but export monetization increasingly depends on access to premium corridors. EPCG’s reported €13 million Q1 export revenue impact from CBAM-related market effects shows that even low-carbon generation can lose value when trade rules and corridor economics change.   Add physical congestion to that regulatory pressure and the value gap becomes larger.

Bosnia and Herzegovina faces a different but equally serious constraint. Aging coal assets, delayed hydropower projects and fragmented institutional governance create uncertainty around future supply reliability. Projects such as HPP Dabar, HPP Mrsovo, Poklecani wind farm and Vlasic wind farm all illustrate the difficulty of moving from resource potential to bankable grid-connected capacity.  

For investors, this changes due diligence priorities.

A renewable project in SEE can no longer be evaluated only by resource quality, EPC cost, permitting status and PPA price. Grid location is becoming a primary bankability variable. The key questions are now more specific: which substation, which voltage level, which congestion zone, which neighboring market, which curtailment probability, which balancing access, which cross-border spread, which TSO reinforcement timeline.

A 100 MW solar project with excellent irradiation but weak grid access may be less bankable than a smaller project near a strong transmission node with lower curtailment risk and better industrial offtake options.

This is a material shift in capital allocation.

The next generation of SEE renewable investment will likely favor projects that are designed around grid value rather than land availability alone. Developers that secured cheap land in weak-grid zones may face declining financing appetite. Developers with access to robust nodes, industrial consumers, storage integration and documented connection rights will command stronger valuation.

Banks will respond accordingly.

Lenders are likely to demand more detailed grid studies, TSO correspondence, curtailment scenarios, congestion sensitivity models, power-flow analysis, dispatch simulations and independent technical review before committing long-term debt.

This will also increase the value of Owner’s Engineer and technical advisory roles. Transmission risk is not easily understood through legal documentation alone. It requires integrated engineering, market and financial analysis.

The congestion decade will also reshape battery storage economics.

Storage is valuable not only because it shifts solar output from noon to evening. It is also valuable because it can reduce congestion at specific nodes, support grid stability and participate in balancing markets. The best storage locations will therefore be defined by network stress, not simply by co-location with generation.

This creates a new locational investment class: congestion-relief batteries.

A strategically placed battery near a constrained renewable cluster can generate revenue from arbitrage while also supporting grid reliability. In more advanced market designs, such assets may eventually receive regulated or semi-regulated compensation for grid services.

SEE is not yet fully there, but the direction is clear.

Transmission congestion also affects industrial policy. Industrial buyers exposed to CBAM will increasingly need traceable low-carbon electricity. But renewable electricity is only commercially useful if it can be delivered, documented and balanced. A factory cannot rely on a distant renewable asset if congestion prevents credible physical supply or hourly matching.

This means grid constraints may directly influence industrial relocation, export competitiveness and PPA bankability.

A CBAM-exposed manufacturer in Serbia or Montenegro will prefer renewable supply linked to credible network delivery paths, metering systems and balancing arrangements. Low-cost renewable generation stranded behind congestion will not solve the compliance problem.

This is why electricity-market congestion is becoming an economic development issue, not just a power-sector issue.

Governments across SEE will need to decide whether transmission investment remains a slow regulated utility function or becomes a strategic industrial policy priority. The difference will determine whether renewable capacity turns into export competitiveness or stranded production.

The most attractive future energy zones in SEE will likely combine four characteristics: strong renewable resources, robust transmission access, nearby industrial demand and storage potential. Areas with only one or two of those features may struggle to attract bankable capital.

Cross-border coordination will be equally important.

No single SEE country can solve congestion alone because the region’s electricity economics are corridor-based. Flows between Bulgaria and Greece, Serbia and Hungary, Romania and Hungary, Montenegro and Italy-linked markets, and Bosnia with Serbia and Croatia all interact. Reinforcing one national grid without aligning cross-border capacity can simply move congestion from one border to another.

The May data is therefore more than a short-term market snapshot.

It shows the early shape of a structural transition in which transmission becomes the central scarce asset. Generation remains essential, but grid access increasingly determines price capture, financing quality and strategic value.

The winners of the next decade will not necessarily be the countries with the most renewable megawatts.

They will be the countries that can move electrons efficiently, document their origin, balance their volatility and connect them to the highest-value consumers and export corridors.

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The shift is already visible across the region. Albania is advancing a 160 MW solar project with a 60 MW battery energy storage system, backed by a proposed €53 million EBRD loan package within a total investment of around €105 million. The storage component includes a 30 MW / 80.25 MWh battery system connected through the Blue Solar platform in Fier.  

This is not just another renewable project. It is a signal that lenders increasingly view storage as a risk-control instrument.

The market case is straightforward. Solar output across SEE is rising, but the value of solar electricity is becoming more time-sensitive. Midday generation increasingly pressures spot prices, while evening demand ramps still require flexible capacity. That spread between low-price solar hours and high-price balancing hours creates the commercial foundation for batteries.

In the May data, solar generation increased by 462 MW, while total demand fell by around 1,018 MW. At the same time, nuclear, coal and hydro output weakened, forcing gas generation higher by 362 MW.   This combination is exactly the environment in which storage becomes bankable: excess renewable output in some hours, scarcity in others, and growing price volatility between the two.

Banks are beginning to understand that storage does not merely improve renewable integration. It changes the entire revenue model.

A standalone solar project mainly sells energy. A solar-plus-storage project can sell energy, shift output, reduce curtailment, participate in balancing markets, provide grid services, manage congestion exposure and support structured industrial PPAs. That makes the cash-flow profile broader and more resilient.

For SEE, this matters because the region is entering the same solar-cannibalisation cycle already visible in more mature European markets. Greece is facing curtailment and low-price pressure for solar investors. Bulgaria is rapidly positioning itself as a regional storage hub. North Macedonia is adding batteries to solar projects, including the Oslomej and Probistip developments. Montenegro’s EPCG has signed cooperation with PowerX on energy storage development.  

These are not isolated announcements. They point to a new investment pattern.

Storage is becoming the technology that allows renewable projects to remain financeable in increasingly volatile markets.

For developers, the advantage is obvious. A battery can protect a project from selling too much output during low-price hours. It can improve captured price, support evening delivery, reduce negative-price exposure and strengthen PPA negotiations with industrial buyers.

For lenders, the appeal is different but equally important. Storage reduces merchant revenue risk and creates a more sophisticated collateral story. A project that can respond to market signals is easier to finance than a project locked into uncontrollable production during increasingly crowded solar hours.

This is especially important under CBAM.

As industrial exporters in Serbia, Montenegro, Bosnia and North Macedonia face rising pressure to document low-carbon electricity consumption, renewable PPAs are becoming strategic tools. But buyers do not need only annual renewable volumes. They increasingly need credible, traceable and usable electricity supply structures. Batteries help convert intermittent renewable output into a more commercially reliable product.

That is why storage is likely to become central to CBAM-linked industrial power procurement.

A Serbian steel processor, aluminum supplier or automotive component manufacturer exporting to the EU may prefer a renewable supply contract backed by storage, hourly metering and auditable delivery evidence. Such a structure is more valuable than a simple annual green certificate because it supports compliance credibility.

This creates a new bankability layer: the compliance value of electricity.

Storage-backed renewables therefore carry two forms of value. The first is market value, derived from arbitrage, balancing and congestion management. The second is industrial value, derived from carbon documentation, PPA credibility and CBAM-sensitive export protection.

The strongest projects will be those that combine both.

Bulgaria is already showing how fast this market can move. The country’s emergence as a storage hub is linked to solar growth, grid pressure and the need to manage intra-day volatility. Storage assets are no longer being treated as experimental infrastructure. They are being deployed as commercial tools for market participation and grid resilience.  

Romania follows a similar direction, although its challenge is more closely tied to network connection rules and grid bottlenecks. Developers face increasing uncertainty around access, connection queues and curtailment exposure. In that environment, batteries become a way to improve dispatchability and strengthen project negotiations with grid operators and lenders.

Greece provides the clearest warning. Strong solar growth without sufficient flexibility creates curtailment, depressed midday prices and investor uncertainty. SEE countries still have time to avoid the worst version of that outcome, but only if storage is integrated early enough into project design.

This is where Serbia becomes particularly important.

Serbia’s renewable buildout is still less saturated than Greece or parts of Bulgaria, but the direction is clear. Wind projects, solar projects and hybrid assets will increasingly compete for grid access and bank financing. Projects with storage will have stronger arguments: lower curtailment risk, stronger delivery profile, better balancing capability and higher value for industrial offtakers exposed to CBAM.

A pure solar plant selling merchant power into SEEPEX may face weakening captured prices as solar penetration rises. A solar-plus-storage project linked to an industrial buyer with EU export exposure may attract stronger bank interest because it solves multiple problems at once: energy cost, carbon documentation, price volatility and supply reliability.

That is the real investment story.

Storage is not just an electricity-market technology. It is becoming a financing bridge between renewable generation, industrial competitiveness and grid stability.

The same logic applies to Montenegro. EPCG’s reported €13 million Q1 export revenue impact from CBAM-related market effects shows that even hydro-rich systems are no longer protected from changing European electricity trade rules.   Storage cooperation with PowerX therefore has strategic relevance beyond technical modernization. It can support EPCG’s ability to manage export timing, reduce exposure to weak price windows and develop more flexible low-carbon electricity products.

For Albania, the Blue Solar structure shows how early integration of storage can change project perception. The combination of 160 MW solar, 60 MW storage and 220 kV grid connection creates a more bankable platform than solar capacity alone.  

For North Macedonia, storage additions at Oslomej and Probistip indicate that even smaller systems are beginning to understand the same market logic. Storage allows countries with limited balancing depth to absorb more renewable generation without destabilizing the system.

For banks, the due diligence framework around storage will become more demanding.

Traditional renewable project finance focused on resource assessment, EPC contracts, grid connection, PPA structure and operating costs. Storage adds new layers: battery degradation, cycle limits, warranty terms, replacement reserves, merchant arbitrage assumptions, balancing-market access, software controls, fire safety, grid-code compliance, revenue stacking and dispatch optimization.

This will require stronger technical advisory work.

A battery project can look attractive on paper but fail bankability tests if its revenue assumptions are too aggressive or if degradation is not properly modelled. Lenders will increasingly demand independent engineering reviews, dispatch simulations, market-price scenarios and contractual protections around availability and performance.

Storage also changes EPC risk.

Unlike conventional solar construction, battery projects involve more complex integration with EMS, SCADA, grid protection systems, fire suppression, cybersecurity protocols and market communication platforms. This increases the importance of commissioning tests, grid-code verification and long-term O&M capability.

In SEE, where grid operators are still adapting to rapid renewable growth, these technical details will become decisive.

The most valuable storage assets will not simply be the largest. They will be the ones located at the right congestion points, connected to the right substations, integrated with the right generation profiles and contracted with the right offtakers.

That means storage valuation will become highly locational.

A 50 MW battery near a congested solar-heavy node may be more valuable than a larger asset in a weaker market location. A battery connected to a CBAM-exposed industrial cluster may have stronger strategic value than one exposed only to merchant arbitrage. A storage asset paired with flexible hydro or gas may unlock wider system benefits than one tied only to standalone solar.

This is why SEE’s storage market should not be viewed as a simple capacity race.

It is becoming a grid-positioning race.

The investors that understand congestion, balancing rules, cross-border spreads, industrial demand and carbon compliance will capture the strongest returns. Those treating batteries as generic add-ons may struggle once competition increases and arbitrage margins compress.

The next wave of SEE energy finance will therefore likely favor hybrid platforms: solar-plus-storage, wind-plus-storage, hydro-plus-storage optimization, industrial renewable PPAs, and grid-service batteries located near strategic transmission constraints.

Battery storage is becoming bankable because it sits at the intersection of all the pressures now reshaping the region: renewable growth, negative prices, CBAM, grid congestion, industrial decarbonization and the decline of conventional baseload reliability.

In that structure, storage is no longer optional infrastructure.

It is becoming the asset class that makes the rest of the energy transition financeable.

Elevated by Energy.Clarion.Engineer

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The most aggressive daily moves were recorded in the lower-priced Balkan markets. Serbian SEEPEX prices jumped by almost 41 % day-on-day to EUR 123.23/MWh, while Montenegro’s BELEN market rose 24.6 % to EUR 108.84/MWh. North Macedonia’s MEMO climbed 26.3 % to EUR 113.22/MWh, while Albania’s ALPEX recovered to EUR 77.29/MWh despite remaining the lowest-priced market in the region.  

Hungary’s HUPX remained the regional pricing anchor at EUR 141.79/MWh, only marginally lower day-on-day, while Romanian OPCOM closed at EUR 142.69/MWh, effectively maintaining full correlation with Hungarian pricing. Slovenia’s BSP and Croatia’s CROPEX remained tightly coupled with Central European fundamentals near EUR 140/MWh, confirming continued integration between SEE and core continental markets.  

The underlying driver of the rebound was a major increase in system demand. Regional consumption climbed to 28,647 MW, up by almost 1,500 MW from the previous day, while imports into the SEE-Hungary balancing area surged by more than 1 GW day-on-day.  

The import structure remains strategically important. Core inflows from Austria and Slovakia toward Hungary and Southeast Europe rose to more than 1,065 MW, highlighting continued structural dependence of SEE markets on Central European balancing capacity during volatile renewable output periods.  

At the same time, renewable generation dynamics shifted materially. Solar production recovered strongly to 5,710 MW, rising by almost 945 MW day-on-day, partially offsetting a sharp collapse in wind generation, which fell by more than 700 MW to 2,033 MW.  

This divergence between solar and wind output continues to define spring market volatility across SEE. Solar production remains increasingly dominant during midday hours, suppressing intraday pricing, while weak evening wind conditions continue to create steep evening ramp pricing between 19:00–22:00 CET. Hourly curves across HUPX, BSP, OPCOM and HENEX all showed strong evening price spikes above EUR 230–260/MWh during peak balancing hours.  

Hydro production also strengthened materially, reaching 7,366 MW, supported by elevated Danube flows near 6,839 m³/s, significantly improving hydro flexibility across Romania and the wider Danube-connected system.  

Coal and gas generation both increased simultaneously, reflecting the system’s growing need for conventional flexibility despite rising renewable penetration. Coal generation reached 4,601 MW, while gas-fired generation rose to 3,510 MW.  

Forward markets nevertheless weakened modestly despite stronger spot conditions. Hungarian week-ahead baseload contracts declined toward EUR 102/MWh, while June-2026 Hungarian baseload forwards eased toward EUR 112/MWh, suggesting traders continue pricing expectations of stronger solar availability and softer continental gas fundamentals later in the quarter.  

Gas markets remained relatively stable, with Austrian CEGH front-month contracts near EUR 51.92/MWh, while EU carbon allowances held above EUR 75/tCO₂, maintaining continued structural pressure on coal-fired marginal generation economics across SEE markets.  

The widening divergence between Southern Balkan pricing and Central Europe also remains notable. Greece’s HENEX market surged almost 30 % day-on-day to EUR 129.48/MWh, although still trading at a discount to Hungary due to stronger domestic renewable output and improving interconnection balances.  

Commercial flow data continues to illustrate the increasingly fragmented structure of regional balancing. Romania remained a major exporter toward Hungary, averaging more than 1,200 MW over the last seven days, while Greece continued exporting strongly toward Turkey. Bosnia and Herzegovina maintained exports toward both Serbia and Montenegro, highlighting the ongoing importance of hydro and lignite flexibility within the western Balkan system.  

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Under the new system, households and small producers will be able to allocate excess electricity to one or more recipients through contractual arrangements. Participants will not need to be located in the same area, meaning electricity generated in one part of Slovenia could be assigned administratively to consumers anywhere in the country. The main goal of the scheme is to improve the use of surplus renewable energy and reduce waste from excess solar production during periods of low self-consumption.

The mechanism will not involve the physical transfer of electricity between users. Instead, it will operate through an accounting-based system within the power network, where injected electricity is tracked and assigned to selected consumers.

Recipients of shared electricity will be able to reduce the energy portion of their electricity bills, while network charges and other regulated fees will still be applied based on the actual electricity drawn from the grid.

The settlement process will take place in 15-minute intervals. If a recipient does not consume the full allocated amount within a given interval, any unused portion will automatically be transferred to the electricity supplier. Producers participating in the scheme will be allowed to sell surplus electricity at freely agreed prices, or transfer it under non-commercial arrangements to relatives, friends, or other users.

Participation in the system will require formal registration and notification of both distribution system operators and electricity suppliers. Authorities plan to open registration in June, with full implementation expected to begin in July.

However, not all market participants will have equal rights under the new framework. Large companies and entities engaging in electricity sharing as a commercial activity will face certain restrictions. Additionally, producers already enrolled in Slovenia’s annual net-metering scheme will only be allowed to act as energy providers and will not be eligible to receive shared electricity.

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In the same period last year, the plant produced 503,994 MWh of net electricity, which was also close to expectations, although it fell slightly short of its planned figure of 515,000 MWh, representing a deviation of 0.8%.

The plant continued to operate under strict technical specifications, with all safety systems fully functional throughout the reporting period. Both the availability factor and the capacity factor remained at 100%, indicating stable and uninterrupted performance. No technical issues or operational disruptions were reported during the month.

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PM Bolojan criticized the project led by state-owned energy company Nuclearelectrica in partnership with private firm Nova Power and Gas, which is based on SMR technology developed by US company NuScale Power. According to the prime minister, more than 240 million dollars has already been invested despite the fact that the technology has not yet been commercially deployed anywhere in the world. He warned that Romania risks ending up with only land and technical studies instead of an operational nuclear facility.

The prime minister argued that Nuclearelectrica should instead focus on expanding the existing nuclear infrastructure at NPP Cernavoda, particularly through the long-planned construction of units 3 and 4, which he described as more advanced and capable of delivering concrete energy production results.

The criticism also reignited debate over the financial structure of the Doicesti project. Nova Power and Gas, which holds a 50 % stake in the project company, had previously acquired the site before later selling it to the joint venture. The company defended the transaction after concerns were raised regarding the valuation of the property.

In response, Nova Power and Gas stated that the site was transferred for around 24 million euros and included far more than undeveloped land. According to the company, the assets included a 50-hectare industrial platform, electrical infrastructure, a transformer station, internal roads, office buildings, and other operational facilities. The valuation was reportedly supported by assessments from three independent consulting and appraisal firms, including two international advisory companies.

Meanwhile, Nuclearelectrica defended the progress of the SMR initiative, stating that development activities remain on schedule and that the project is currently advancing through preliminary engineering and technical evaluation stages required for nuclear projects of this scale. The company noted that FEED 1 and FEED 2 analyses were completed during 2023 and 2024.

PM Bolojan has become the first senior Romanian official to openly question the viability of the project since its launch. He also expressed concerns about the broader financing structure, as the full development of the planned six-module facility could require investments of between 6 and 7 billion dollars.

Earlier this year, Nuclearelectrica approved a final investment decision to continue preparatory activities for the project. However, the current strategy foresees construction of only the first 77 MW reactor module initially, while the remaining five units would proceed only if the first reactor proves both commercially and technically successful.

According to the current timeline, the first reactor module could begin commercial operations in July 2033, while the entire planned 462 MW SMR complex could become fully operational by the end of 2034, depending on future agreements regarding the remaining modules.

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The future hydropower facility will be constructed at the existing Otilovići dam on the Cehotina river and is planned with an installed capacity of 2.96 MW. Annual electricity generation is expected to reach approximately 11.56 GWh, while the total investment value is estimated at around 8.2 million euros, including VAT.

According to the decision published by Montenegro’s Environmental Protection Agency, EPCG will still be required to comply with all technical standards, environmental protection measures, and safety regulations during both the construction and operational phases of the project. Authorities also emphasized that all mitigation measures outlined in the submitted project documentation must be fully implemented.

The project is based on the use of already existing infrastructure, including the Otilovići reservoir and dam, without changing the current hydrological regime of the river system. Officials highlighted that the selected location significantly reduces environmental impact, as the hydropower plant will be positioned directly downstream from the existing dam structure.

Development plans include the construction of a water intake pipeline, a powerhouse equipped with electro-mechanical systems, a control facility, and a substation for connection to Montenegro’s national electricity grid. The Government of Montenegro issued urban and technical conditions for the project in 2023, while EPCG formally submitted its environmental assessment request at the end of April this year.

Authorities have also approved a 10-month extension for completing the first phase of the project. According to earlier statements from EPCG, construction of the hydropower plant could be finalized by October 2027. Most activities during this year will focus on preparing the main design, securing permits, and completing additional environmental documentation, while on-site construction works are expected to begin in autumn and continue for approximately one year.

Earlier this year, EPCG signed a turnkey agreement with local company Vigoris Ecotech for the implementation of the project. The contract includes detailed design work, civil construction, delivery and installation of equipment, as well as testing and commissioning of the future hydropower facility.

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According to the Greek Energy Ministry, the release is being carried out through a 12-week distribution program, with the largest share of fuel entering the domestic market during the early stages of the operation. Around 1.3 million barrels were scheduled for distribution during the first week alone.

The program includes a wide range of petroleum products such as petrol, diesel, jet fuel, fuel oil, and liquefied gas. Eight major energy companies are participating in the process to help maintain stable fuel supplies and prevent additional pressure on domestic fuel prices.

Following the significant initial release, fuel distribution volumes are expected to gradually decrease. Authorities stated that approximately 70,000 tons would be released during the second week, while weekly supply volumes are expected to stabilize between 50,000 and 60,000 tons until the program ends in mid-June.

The decision was made despite oil prices remaining below the 100-dollar-per-barrel level, as concerns continue to rise over geopolitical instability and potential disruptions to global shipping routes, particularly around strategic transit points such as the Strait of Hormuz.

Under the allocation plan, Helleniq Petroleum will release nearly 180,000 tons of crude oil, while Motor Oil is expected to supply more than 26,000 tons of light fuels, over 25,000 tons of diesel and heating oil, and approximately 35,000 tons of heavy fuel products.

Additional volumes will be provided by other market participants. Aegean will contribute close to 1,000 tons of heavy fuels, while Coral is set to release additional quantities of petrol, aviation fuel, and diesel. The total amount entering the market represents roughly one week of Greece’s national fuel consumption and equals around 13 % of the country’s estimated strategic petroleum reserves, which are believed to total between 14 million and 15 million barrels.

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Electricity consumption in the country also recorded significant growth in 2026, rising by 7.18 % to 16.78 TWh. As a result of higher domestic demand, Bulgaria registered net electricity imports of 215 GWh during the observed period.

Baseload power plants, including coal-fired and nuclear facilities, generated a combined 11.58 TWh of electricity in 2026, representing a decline of 10.6 % compared to the previous year. At the same time, electricity production from renewable energy sources (RES) continued to grow. RES generation connected to the transmission network increased by 11.37 %, reaching 1,408.7 GWh, while renewable electricity production within the country’s distribution network rose by 3.12 % to 1,385.5 GWh.

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These upgrades form part of wider regional efforts to strengthen energy connectivity and diversify supply routes as demand for liquefied natural gas (LNG) continues to grow across Central and Southeastern Europe. Malinov stated that major international LNG suppliers, particularly leading US energy companies, increasingly recognize the region’s gas infrastructure as both reliable and strategically important. He added that close cooperation between transmission system operators, regulators, and the European Commission has already helped establish a framework for long-term tariff optimization across the corridor.

According to Malinov, the revised tariff structure is expected to improve the market’s attractiveness, encourage stronger competition, and create better conditions for securing gas supplies under more favorable commercial terms, including LNG imports. He emphasized that stronger regional coordination in negotiating future supply agreements could provide significant advantages for participating countries. By combining gas demand across nations connected through the Vertical Gas Corridor, regional buyers may gain greater bargaining power with LNG exporters, potentially securing lower long-term prices while also reducing overall transmission costs throughout the network.

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Yet the first half of May 2026 revealed a different reality.

Gas has quietly returned to the center of regional electricity pricing.

During the observed period, gas-fired generation across the broader HU+SEE system increased by approximately 362 MW, even as total regional electricity demand declined by roughly 1,018 MW. At the same time, nuclear output fell sharply by 1,686 MW, coal generation declined by 260 MW, while hydro output weakened by another 357 MW.  

This combination forced gas back into the marginal balancing role precisely when renewable volatility and declining thermal reliability were intensifying across the region.

The resulting market reaction was immediate.

Romania’s OPCOM surged to €115.88/MWh, Hungary’s HUPX reached €108.62/MWh, Bulgaria’s IBEX climbed to €104.98/MWh, Croatia’s CROPEX averaged €105.77/MWh, while Serbia’s SEEPEX moved above €101/MWh.

These prices emerged despite weaker consumption and improving temperatures.

That matters because it confirms the region is no longer operating under a demand-driven pricing structure. Instead, marginal generation scarcity increasingly determines electricity pricing — and gas remains the technology most capable of filling that balancing gap.

This is one of the most strategically important developments currently unfolding across Southeastern Europe.

The return of gas marginality does not mean the region is abandoning decarbonization. On the contrary, the rise of intermittent renewables is precisely what makes flexible gas generation more commercially important.

Solar and wind continue expanding rapidly across Bulgaria, Greece, Romania, Serbia and North Macedonia. But renewable generation alone cannot stabilize hourly balancing dynamics, particularly during evening ramps, low-wind periods or seasonal hydro fluctuations.

Coal fleets are simultaneously becoming less reliable.

Across Bosnia and Herzegovina, Montenegro and Serbia, aging coal infrastructure increasingly faces operational instability, maintenance challenges, financing stress and environmental pressure.

RiTE Ugljevik spent months offline before returning to operation in early May.   RiTE Gacko reported sharply deteriorating profitability.   Montenegro’s Pljevlja coal operations also showed worsening financial performance.  

Nuclear generation meanwhile experienced significant outages and maintenance interruptions. Bulgaria’s Kozloduy Unit 5 entered maintenance, while Romania’s Cernavoda Unit 2 remained affected by extended technical issues.  

As these baseload systems weaken, gas increasingly becomes the only scalable balancing mechanism capable of responding quickly enough to renewable volatility.

This changes the strategic logic surrounding regional gas infrastructure.

For several years, projects such as Alexandroupolis LNG terminal, the Vertical Gas Corridor and expanded interconnections across Greece, Bulgaria, Serbia and North Macedonia were primarily discussed through the lens of diversification away from Russian supplies.

That narrative remains relevant.

But gas infrastructure now carries a second strategic role: enabling renewable-heavy electricity systems to remain operationally stable.

The timing is important because SEE electricity markets are entering a structurally more volatile phase.

Solar generation across the region continues accelerating rapidly. Bulgaria is emerging as a major storage and solar hub. Greece increasingly experiences curtailment pressure and midday oversupply. Romania continues expanding renewable capacity while struggling with grid bottlenecks. Serbia is gradually moving toward larger-scale solar deployment alongside wind growth.

This creates a system where daytime oversupply increasingly coexists with evening scarcity.

Gas becomes the bridge between those two conditions.

Unlike coal, gas plants ramp quickly. Unlike hydro, gas availability is not tied to hydrological conditions. Unlike batteries, gas provides extended-duration balancing capability without current storage duration limitations.

This operational flexibility increasingly translates directly into market pricing power.

The importance of the Vertical Gas Corridor therefore extends beyond fuel diversification.

Regional discussions involving Greece, Serbia, Bulgaria and North Macedonia around corridor expansion reflect growing recognition that gas interconnectivity is becoming essential for electricity market stability itself.  

The corridor’s future role could become especially important if Russian pipeline flows into Europe continue declining.

TurkStream deliveries to Europe fell again in April, declining both month-on-month and year-on-year.   Yet despite lower physical flows, gas prices remained elevated because global LNG markets continue experiencing geopolitical volatility tied to Middle Eastern disruptions and tighter supply competition.

This creates a paradox for SEE policymakers.

The region requires more gas flexibility precisely when long-term gas procurement becomes more geopolitically and financially uncertain.

That tension increasingly shapes investment decisions.

Utilities and governments now simultaneously pursue:

• Renewable expansion.
• Battery storage deployment.
• Gas interconnection development.
• LNG access diversification.
• Coal phase-down strategies.
• Grid modernization.
• Balancing infrastructure investment.

Rather than replacing gas immediately, renewable growth is temporarily increasing the strategic importance of flexible gas systems.

This transition also reshapes power trading dynamics.

Historically, SEE electricity traders focused heavily on hydro conditions, coal availability and seasonal demand swings. Going forward, gas spreads, LNG flows, storage levels and balancing fuel availability increasingly influence regional electricity pricing behavior.

The correlation between gas hubs and SEE power exchanges is therefore strengthening again.

CEGH gas prices averaged approximately €46.64/MWh during the period, while Greek gas prices remained near €45.22/MWh.   Although carbon prices slightly weakened to around €74.96/t, the combined fuel and carbon cost structure still supported elevated thermal marginal pricing.

This reinforces one of the central contradictions of Europe’s current energy transition.

Renewables reduce long-term fossil dependency.

But until large-scale storage, transmission reinforcement and flexibility infrastructure fully mature, intermittent renewable penetration often increases short-term balancing dependence on gas.

The implications for project finance are substantial.

Gas-fired assets that once appeared strategically vulnerable increasingly regain value as balancing providers. Combined-cycle plants, flexible peakers and hybrid gas-renewable systems may experience stronger utilization assumptions than many investors anticipated several years ago.

At the same time, pure baseload gas exposure remains risky due to decarbonization pressure and carbon pricing escalation.

This creates a new premium around flexibility rather than fuel type itself.

Assets capable of ramping quickly, participating in balancing markets and stabilizing renewable-heavy grids increasingly capture higher strategic value regardless of whether they are gas turbines, hydro reservoirs or battery systems.

The same principle applies to sovereign energy strategies.

Countries capable of combining:

• Flexible gas access.
• Renewable generation.
• Battery storage.
• Cross-border interconnections.
• Hydropower balancing.
• industrial demand response.

will likely achieve stronger pricing stability and greater energy security than systems overly dependent on any single generation source.

Greece appears increasingly positioned as the regional hub within this evolving structure.

Its LNG infrastructure, interconnection investments and expanding renewable base place it at the center of emerging SEE energy corridors. Bulgaria similarly strengthens its role through storage deployment and transmission positioning.

Serbia’s strategic importance also grows because of its central geographical role linking Central Europe, the Balkans and future corridor expansions.

This transformation ultimately extends beyond electricity itself.

Industrial competitiveness, data center development, hydrogen projects, aluminum processing economics and even regional export structures increasingly depend on reliable flexible energy supply rather than purely low-cost generation.

Gas therefore re-emerges not as the dominant fuel of the future but as the stabilizing mechanism underpinning the transition toward a far more renewable-heavy regional power system.

The first half of May 2026 demonstrated how quickly that reality is already shaping Southeastern European electricity markets.

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The impact is emerging before the system has even entered full financial implementation.

During the first quarter of 2026, Montenegro’s state utility EPCG reported that CBAM-related market effects reduced electricity export revenues by approximately €13 million, despite strong hydrological conditions and higher physical export volumes. This was one of the first public confirmations from a regional utility that CBAM is no longer merely a future regulatory issue but an active market force already influencing pricing behavior, buyer appetite and cross-border electricity economics.

The significance extends far beyond Montenegro.

Across the Western Balkans, electricity exporters are increasingly discovering that European buyers no longer evaluate imported electricity purely on price, availability or balancing value. Carbon exposure, traceability, generation origin and regulatory uncertainty are becoming embedded pricing variables.

In effect, CBAM is beginning to create a two-tier electricity market across Southeastern Europe.

The first tier consists of fully traceable low-carbon electricity supported by renewable generation portfolios, Guarantees of Origin, physical delivery documentation and increasingly sophisticated MRV frameworks.

The second tier includes electricity carrying uncertain or mixed carbon characteristics, particularly in systems still heavily influenced by coal generation or lacking auditable renewable traceability structures.

This distinction matters because European counterparties increasingly prioritize compliance certainty alongside energy procurement itself.

The Western Balkans occupy a uniquely vulnerable position within this transition.

Unlike EU member states fully integrated into the European carbon and regulatory framework, countries such as Serbia, Bosnia and Herzegovina, Montenegro and North Macedonia remain partially outside the EU customs and ETS structures while simultaneously exporting electricity into interconnected European markets.

That creates regulatory ambiguity.

From a physical system perspective, Western Balkan electricity is deeply integrated into the European grid. From a carbon compliance perspective, however, it increasingly faces treatment as an external import exposure.

This is precisely the contradiction regional energy ministers highlighted in their May appeal to the European Parliament requesting revisions to electricity-related CBAM treatment.  

Their argument was strategically revealing.

Regional officials acknowledged support for European decarbonization goals but warned that the current framework risks undermining electricity market integration itself. In practical terms, European buyers are becoming increasingly reluctant to purchase electricity originating from Western Balkan systems regardless of whether the physical generation source is hydropower, wind or solar.

This creates one of the most important structural distortions currently emerging in SEE electricity markets.

Historically, regional exporters benefited from strong hydro production, flexible balancing capability and competitive generation costs. But CBAM increasingly attaches carbon-related risk perception to entire national systems rather than individual generation assets.

For exporters, this means renewable generation alone may no longer guarantee commercial competitiveness.

Documentation quality becomes critical.

Guarantees of Origin therefore move from a secondary certificate mechanism into a core commercial infrastructure layer.

Under the previous electricity market structure, many regional generators treated GOs primarily as supplementary revenue instruments. Under CBAM-linked trade dynamics, however, traceability itself increasingly determines market access.

Industrial buyers inside the EU now face growing pressure to demonstrate low-carbon sourcing not only for direct industrial inputs but also for electricity consumption embedded within exported products.

This creates a cascading effect throughout SEE electricity markets.

Renewable producers capable of offering:

• Auditable hourly matching.
• Physical supply verification.
• Substation-level delivery traceability.
• Independent MRV documentation.
• PPA-linked renewable sourcing.
• Carbon accounting integration.
• increasingly obtain strategic advantages over conventional merchant generation exposure.

This transition could fundamentally reshape project bankability across the region.

For years, merchant renewable projects in SEE relied primarily on wholesale price assumptions and balancing market access. Going forward, long-term industrial PPAs tied to CBAM-exposed exporters may become significantly more valuable.

Steel producers, aluminum processors, fertilizer manufacturers and automotive suppliers across Serbia, Montenegro and Bosnia increasingly require low-carbon electricity procurement structures not simply for ESG positioning but for commercial survival within EU supply chains.

This transforms electricity itself into a compliance-linked industrial input.

The implications for Serbia are particularly significant.

The country maintains one of the region’s largest industrial export bases into the EU while simultaneously operating a power system still heavily dependent on coal generation. As CBAM implementation deepens, Serbian industrial exporters may increasingly compete not only on labor costs or logistics but also on the carbon profile of their electricity procurement structures.

This creates a strategic opportunity for renewable developers.

Wind, solar and battery projects capable of offering dedicated industrial PPAs with robust MRV structures may become materially more bankable than pure merchant projects.

Banks and export-oriented industrial buyers increasingly view renewable electricity not simply as an energy source but as a mechanism for protecting export competitiveness and reducing future CBAM liabilities.

That logic is already influencing investor behavior across the region.

Projects integrating renewable generation with storage, dedicated industrial supply structures and traceable energy delivery increasingly attract stronger financing interest than standalone merchant renewable developments exposed entirely to volatile wholesale pricing.

The economics become even more compelling when combined with the broader evolution of European electricity markets.

Negative pricing risks, solar cannibalization and intraday volatility weaken traditional merchant revenue stability. Long-term industrial PPAs tied to CBAM compliance therefore provide a more stable financing foundation.

In this environment, renewable generation acquires dual value:

• Electricity production value.
• Carbon compliance value.
• The second component may ultimately become more strategically important than the first.
• Cross-border flows already reflect this transition.

Regional export structures increasingly respond not only to physical supply-demand balances but also to carbon-adjusted buyer behavior. Electricity flows toward Italy, Austria and Central Europe increasingly interact with evolving carbon compliance perceptions and procurement preferences.

This introduces an entirely new layer of complexity into SEE trading strategies.

Traders must increasingly evaluate:

• Carbon-adjusted spreads.
• Origin traceability.
• ETS exposure.
• CBAM treatment uncertainty.
• Renewable certification structures.
• Cross-border documentation integrity.
• Industrial buyer compliance requirements.

Electricity trading therefore begins converging with carbon market mechanics.

The transformation also accelerates political pressure for deeper regional market integration.

Western Balkan governments increasingly understand that fragmented national electricity systems weaken their negotiating position and complicate alignment with EU decarbonization frameworks.

Regional interconnection projects, balancing market integration and harmonized renewable certification systems therefore acquire broader geopolitical importance.

The Vertical Gas Corridor discussions, Drina hydropower cooperation and expanding transmission investments all increasingly intersect with this wider carbon-adjusted market restructuring.

Even utilities traditionally focused on domestic supply security are being forced to adapt.

EPCG’s experience demonstrates how quickly external carbon-policy mechanisms can reshape regional revenue structures even without direct physical export exposure into EU markets.

That lesson will likely influence investment strategies throughout the Western Balkans.

Utilities may increasingly prioritize:

• Renewable traceability systems.
• Battery storage.
• Industrial PPAs.
• Digital MRV infrastructure.
• Flexible generation.
• Grid modernization.
• Carbon reporting frameworks.

This transition also strengthens the strategic importance of independent verification and engineering services.

As electricity becomes a compliance-sensitive traded product, technical documentation quality becomes commercially material. Substation mapping, SCADA integration, metering accuracy, renewable verification protocols and auditable reporting systems increasingly influence transaction credibility and financing outcomes.

In effect, electricity markets are evolving toward documentary-intensive commodity structures similar to those already visible in carbon trading, LNG procurement and industrial commodity supply chains.

The first phase of this transformation is already underway.

CBAM is no longer simply a future industrial regulation.

It is becoming one of the most important forces restructuring electricity economics across Southeastern Europe.

Elevated by CBAM.Clarion.Engineer

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That model is beginning to fracture.

The first half of May 2026 exposed how rapidly the economics surrounding SEE hydropower are changing. Despite relatively favorable hydrological conditions across parts of the Western Balkans, hydro generation in the broader HU+SEE system declined by approximately 357 MW compared to the previous observation period.   More importantly, the market value of hydroelectric exports weakened even where physical generation remained strong.

This is not merely a weather issue. It is a structural market transition driven by solar penetration, changing cross-border flows, CBAM distortions, Italian midday oversupply and increasingly volatile intraday pricing structures.

The most visible evidence emerged in Montenegro. State utility EPCG acknowledged that CBAM-related market effects reduced electricity export revenues by approximately €13 million during the first quarter of 2026, despite strong hydrological conditions and higher export volumes.  

This development marks a fundamental break from historical SEE market behavior.

Traditionally, strong hydrology automatically translated into stronger profitability for regional utilities. Reservoir-rich systems such as Montenegro, Bosnia and Albania exported surplus generation into higher-priced neighboring markets, especially Italy. Hydropower’s low marginal costs allowed utilities to capture strong spreads and stabilize national trade balances.

But Europe’s electricity market structure has changed.

Italy increasingly experiences midday solar oversupply, compressing prices during precisely the hours when Balkan hydro historically maximized exports. Solar growth across Southern Europe is eroding the daytime premium once captured by flexible hydro generation.

The result is a structural decline in hydro monetization efficiency.

This shift is already visible in regional commercial flow data. Net exports from the broader SEE region toward Italy moved from approximately +310 MW during the previous observation period to -148 MW in the first half of May. This reversal is strategically important because Italy has historically functioned as the premium balancing market for SEE exporters.

Instead of exporting profitable daytime electricity toward Italy, parts of the region are increasingly confronted with weaker spreads and declining demand during solar-heavy hours.

Hydropower is therefore losing its role as a simple baseload exporter and becoming something more operationally complex: a flexibility asset competing inside a volatility-driven electricity system.

That distinction matters enormously for both utilities and investors.

Hydro assets with storage reservoirs now increasingly derive value not from annual generation totals but from timing optimization. Operators capable of preserving water during low-price solar hours and releasing generation during evening balancing periods gain commercial advantages.

In effect, hydroelectric reservoirs begin functioning like giant batteries.

This transformation changes how hydro portfolios are financed, dispatched and valued.

Countries such as Romania illustrate the transition particularly well. Hidroelectrica reported sharply improved profitability during the first quarter of 2026 despite broader regional volatility.   But this profitability increasingly depends on sophisticated market positioning rather than simply hydrological abundance.

Hydropower operators must now optimize around:

• Evening balancing spreads.
• Cross-border congestion.
• Negative price avoidance.
• Intraday volatility.
• Ancillary service revenues.
• Carbon-linked export economics.
• Battery competition.

This is a far more financially intensive operating environment than the traditional hydro-dominated system that characterized SEE markets for decades.

The consequences extend directly into regional infrastructure investment strategies.

Across Bosnia and Serbia, renewed discussions surrounding Drina hydropower cooperation reveal how governments still view hydro as a strategic long-term resource.   Yet the economics underpinning future hydro development are no longer straightforward.

Large hydropower projects increasingly face three simultaneous pressures.

First, construction costs continue rising due to inflation, permitting delays, environmental compliance and financing complexity.

Second, European market prices are becoming more volatile and less predictable due to renewable penetration.

Third, future hydro profitability increasingly depends on flexibility value rather than pure generation volume.

This creates a much more complicated investment environment for new projects.

Projects designed primarily around stable baseload export assumptions may face weaker long-term returns than initially projected. Conversely, assets capable of rapid ramping, balancing support and cross-border flexibility optimization could become increasingly valuable.

The operational risks are already visible across Bosnia and Herzegovina’s hydropower sector.

Projects such as HPP Dabar and HPP Mrsovo illustrate how financing disruptions, permitting complexity and contractual disputes increasingly threaten traditional infrastructure delivery models.  

The broader market transition makes these risks even more consequential because future project bankability depends not only on engineering feasibility but also on increasingly uncertain market monetization structures.

Hydro also faces growing competition from battery storage.

Historically, pumped hydro and reservoir systems represented the dominant balancing technologies in Europe. But rapidly declining battery costs are changing the equation.

Battery systems now increasingly compete directly with hydro for balancing revenues, intraday arbitrage and ancillary service markets.

This is particularly relevant in SEE because solar growth is accelerating faster than transmission expansion. As midday oversupply intensifies, balancing assets become more valuable. Batteries respond faster than hydro and often require lower upfront environmental and permitting complexity.

That does not mean hydro loses strategic importance. On the contrary, hydro may become even more critical precisely because of its scale and storage duration advantages. But its commercial logic changes fundamentally.

Instead of acting as passive baseload exporters, hydro operators increasingly resemble active market traders managing flexibility portfolios.

The political dimension further complicates the transition.

Western Balkan governments continue promoting hydropower as both a decarbonization tool and a sovereign energy security asset. Yet local opposition to new hydro projects remains strong in many areas due to environmental concerns, biodiversity impacts and tourism considerations.

European financing institutions also apply increasingly strict ESG standards to large hydro developments.

This creates a paradox for SEE governments.

Hydro remains one of the region’s few scalable domestic low-carbon resources capable of providing balancing flexibility. But financing and permitting such projects becomes progressively more difficult.

As a result, regional energy systems may increasingly rely on hybrid structures combining:

• Hydropower.
• Battery storage.
• Gas balancing.
• Cross-border interconnections.
• Renewable curtailment management.
• Flexible industrial demand.

The future SEE electricity system therefore becomes less dependent on single dominant technologies and more dependent on integrated flexibility ecosystems.

For investors, this changes asset valuation logic across the entire regional power sector.

A hydropower plant can no longer be evaluated purely through annual generation projections and long-term average hydrology assumptions. Instead, analysts increasingly examine:

• Hourly price capture.
• Balancing participation.
• Interconnection access.
• Curtailment exposure.
• Storage optimization.
• CBAM-linked export economics.
• Transmission congestion.

This financialization of hydro operations represents one of the most important structural transitions currently unfolding across SEE electricity markets.

The first half of May 2026 provided a clear warning.

Hydropower still matters enormously.

But it no longer stabilizes Southeastern European electricity markets in the simple, predictable manner that defined the previous generation of regional energy economics.

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For SEE markets, the implications extend far beyond trading algorithms or exchange settlement procedures. Negative pricing changes the economic logic of generation assets, battery storage, cross-border interconnections, balancing reserves, industrial demand response and even project finance assumptions for new renewable developments.

The region’s price structure during the first half of May already revealed the emerging imbalance. Despite regional electricity demand falling by roughly 1,018 MW, average prices surged across almost all SEE exchanges. Romania’s OPCOM climbed to €115.88/MWh, Bulgaria’s IBEX reached €104.98/MWh, Croatia’s CROPEX rose to €105.77/MWh, while Serbia’s SEEPEX averaged €101.61/MWh.  

At first glance, higher prices and negative pricing risks appear contradictory. In reality, they reflect the same structural phenomenon: increasingly violent intraday price dislocations driven by renewable intermittency and declining flexibility in conventional generation fleets.

Solar generation rose by approximately 462 MW during the period, while wind added another 37 MW. At the same time, nuclear output dropped by 1,686 MW, coal generation fell by 260 MW, and hydro declined by 357 MW.   The market therefore experienced two simultaneous dynamics. During daylight hours, solar increasingly suppressed marginal pricing. But during evening ramps and periods of lower renewable output, tightening thermal availability forced gas generation back into the marginal position, sharply increasing balancing costs.

This is precisely the environment where negative prices and price spikes begin to coexist.

Historically, SEE power systems were dominated by relatively stable hydro and coal baseload structures. Solar penetration remained too low to fundamentally distort intraday curves. That reality is changing rapidly. Bulgaria, Romania and Greece have accelerated utility-scale solar deployment, while Serbia, North Macedonia and Albania are now moving into larger merchant solar development cycles combined with storage.

The most visible evidence comes from Greece, where regulators and grid operators are already confronting curtailment pressure and declining midday price realization for photovoltaic operators. In Bulgaria, battery storage deployment is accelerating specifically because solar production increasingly creates midday oversupply events that conventional market structures struggle to absorb.

This creates a new hierarchy of asset value inside SEE electricity markets.

For years, the dominant investment narrative centered on pure renewable generation capacity additions. Installed megawatts became the primary valuation metric. That model is beginning to weaken. Under negative pricing environments, the ability to control timing becomes more valuable than pure energy output.

Battery storage therefore shifts from a supplementary technology into a central market infrastructure asset.

The economics increasingly support this transition. Volatility between midday and evening prices is widening. Daytime oversupply depresses prices during solar peaks, while evening scarcity strengthens balancing spreads. Storage operators positioned between those two windows gain access to growing arbitrage revenues.

The Albanian market offers one of the clearest regional examples. The EBRD-backed project combining 160 MW of solar generation with a 60 MW battery storage system is not simply a renewable project. It is a structural hedge against negative price risk and curtailment exposure.  

This distinction matters enormously for banks and institutional investors.

Merchant solar projects without storage increasingly face weaker bankability assumptions across Europe because revenue predictability deteriorates as renewable penetration rises. Price cannibalization reduces captured power prices exactly during peak production hours. The SEE region is now entering the same transition phase already visible in Germany and Spain, albeit from a lower penetration base.

In practical terms, two solar plants with identical installed capacity may soon carry dramatically different financing profiles depending on whether they include storage, balancing access, flexible offtake structures or cross-border optimization capability.

Cross-border transmission flows further reinforce this transformation.

The May flow structure showed a substantial deterioration in exports toward Italy, with the SEE region moving from +310 MW net exports toward Italy during the previous period to -148 MW.   This reversal is strategically important because Italy has historically acted as a premium-price export destination for Balkan electricity producers, particularly hydro generators.

As Italian solar penetration deepens, however, daytime import demand weakens. This undermines the traditional monetization model of Balkan hydro exports during daylight hours. The value of flexibility therefore rises while the value of uncontrolled renewable injection falls.

Hydropower operators now increasingly resemble storage providers rather than conventional baseload generators. Reservoir management, ramping flexibility and evening balancing capability become commercially more important than raw annual generation totals.

The same logic applies to gas infrastructure.

Gas generation across SEE increased by 362 MW during the observed period despite lower overall demand.   This demonstrates that gas remains the primary balancing technology capable of stabilizing the regional system during renewable volatility and declining coal availability.

Consequently, infrastructure such as the Vertical Gas Corridor, Alexandroupolis LNG terminal and TurkStream-linked systems acquire a second strategic role beyond supply diversification. They become indirect enablers of renewable integration.

Without flexible gas capacity, negative price events become more frequent and balancing instability intensifies.

This explains why countries across the region continue simultaneously expanding renewables while also supporting gas interconnections and storage projects. Policymakers increasingly understand that renewable expansion without balancing infrastructure creates systemic instability rather than decarbonization efficiency.

The political implications are equally significant.

Negative prices expose weaknesses in legacy subsidy structures and auction systems. Feed-in tariffs and fixed-price support mechanisms become increasingly difficult to sustain in environments where wholesale prices periodically collapse below zero.

Developers, banks and regulators therefore move toward more sophisticated structures involving Contracts for Difference, hybrid PPAs, storage integration and ancillary service revenues.

This transition is already visible in investor behavior. Capital increasingly favors projects capable of participating across multiple revenue streams rather than pure merchant energy exposure.

Battery storage is particularly attractive because it monetizes volatility itself.

For SEE countries, this could become one of the defining investment themes of the next decade. The region still possesses relatively lower renewable penetration than Western Europe while simultaneously maintaining significant solar irradiation advantages, hydropower flexibility and improving interconnection potential.

That combination creates the possibility for SEE to evolve into one of Europe’s most important balancing and flexibility regions rather than merely a peripheral generation exporter.

Serbia, Bulgaria, Romania and Greece are especially well positioned in this emerging structure because they combine growing renewable capacity with strategic transmission corridors linking Central Europe, the Balkans and the Eastern Mediterranean.

But the transition also carries substantial risks.

Grid congestion is already worsening. Curtailment risks are rising. Merchant exposure becomes more volatile. Industrial consumers increasingly require sophisticated procurement strategies involving hourly matching, renewable traceability and balancing optimization.

CBAM further complicates the equation because carbon-related trade distortions now influence electricity flow economics alongside conventional market fundamentals.

The result is a regional electricity market becoming vastly more financialized, interconnected and operationally complex than at any point in its history.

Traditional baseload thinking no longer fully explains price behavior.

Instead, SEE electricity markets are entering a flexibility-driven phase where value increasingly concentrates around balancing capability, storage access, interconnection optimization and controllable generation profiles.

The importance of this transition extends beyond the energy sector itself.

Industrial competitiveness, data center investments, hydrogen development, aluminum smelting economics and even regional sovereign financing conditions increasingly depend on whether SEE countries can successfully manage this shift toward volatile renewable-heavy market structures.

The next several years will therefore likely determine which countries become regional flexibility hubs and which become structurally congested renewable oversupply zones suffering persistent price compression.

The first half of May 2026 suggests the transition has already begun.

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The first half of May 2026 offered several signals of this shift. In Bosnia and Herzegovina, RS Energy Minister Petar Đokić held talks with Sinohydro on possible new projects in hydropower, solar, wind, mining and wider infrastructure, with the completed 35 MW HPP Ulog presented as a reference project for future cooperation. In Turkey, Chinese turbine suppliers remained active in hybrid wind and storage projects, while across the wider SEE region Chinese-linked engineering and equipment providers continued to appear in renewable and grid-adjacent investment pipelines.  

This is not simply a continuation of the old Belt and Road infrastructure model. It is a shift in sector positioning.

The previous Chinese infrastructure cycle in the Balkans was heavily associated with large EPC contracts, state-backed financing, coal-related assets, transport corridors and politically visible projects. That model is now under pressure. EU accession rules, environmental litigation, Energy Community obligations, CBAM, public debt scrutiny and lender ESG requirements make coal-heavy or weakly documented infrastructure harder to finance and defend.

Chinese contractors are therefore increasingly adapting to the investment language of the next cycle: renewables, storage, hydropower flexibility, grid modernization and industrial decarbonization.

The Republic of Srpska illustrates both the opportunity and the risk. Sinohydro, part of PowerChina, has already delivered HPP Ulog, a 35 MW hydropower facility commissioned in 2024. That gives the company a local reference in a sector where Western Balkan governments continue to see hydropower as strategic. At the same time, Bosnia’s energy sector remains burdened by delayed projects, financing disputes and governance complexity.

The stalled HPP Dabar project shows the problem. Construction slowed after China Exim Bank suspended payments, with unresolved contractual milestones tied to a 12-kilometer tunnel and wider works involving China Gezhouba Group Company Limited. The case demonstrates that Chinese involvement does not automatically remove delivery risk. Financing structures, milestone logic, local contractor performance, permitting and state utility obligations remain decisive.

That distinction is important for investors. Chinese EPC capacity can accelerate project delivery, but only where the contractual, grid, environmental and financing framework is bankable. In weaker governance settings, Chinese participation may coexist with the same risks that delay domestic or European-backed projects.

The next phase will therefore likely be more selective.

Hydropower remains a natural area for Chinese contractors because of their global construction experience. But new hydro projects in SEE face rising environmental scrutiny, water-management disputes and permitting complexity. Investors will increasingly distinguish between brownfield rehabilitation, reservoir optimization and new greenfield river development.

Brownfield hydro modernization may be the more financeable opportunity. Existing plants need turbine upgrades, automation, SCADA modernization, dam safety works, sediment management and digital dispatch systems. These projects usually carry lower permitting risk than new dams and align better with grid-flexibility needs.

Wind is another area where Chinese positioning may strengthen.

Chinese OEMs have become increasingly competitive in turbine supply, including larger machines suitable for complex terrain and hybrid project configurations. In SEE, where wind development is moving into more difficult sites and bankability depends on EPC performance, grid-code compliance and long-term service availability, Chinese equipment suppliers may compete aggressively against European OEMs.

But wind finance is not only about turbine price.

Banks will examine warranty strength, spare-parts availability, cybersecurity, grid-code certification, power-curve guarantees, service track record and lender acceptance. A cheaper turbine does not automatically produce a lower cost of capital. The decisive question is whether the full technical-risk package satisfies lenders, owners’ engineers and grid operators.

This is particularly relevant in Serbia and Montenegro, where new wind projects are increasingly connected to complex terrain, transmission constraints and lender-driven compliance frameworks. A wind project can fail bankability tests if its equipment package creates uncertainty around availability, curtailment, grid-code response or long-term O&M.

Chinese suppliers therefore face a strategic choice. They can compete only on price, or they can move toward full bankability packages that include warranties, local service, transparent documentation, SCADA integration, grid-code testing support and lender-grade technical evidence.

The second route is more powerful.

Battery storage is likely to become the most important new arena for Chinese repositioning.

China dominates global battery manufacturing and supply chains. As SEE moves toward solar-plus-storage, grid batteries and industrial energy management systems, Chinese technology providers may find expanding demand. Albania’s 160 MW solar plus 60 MW BESS project demonstrates the regional financing direction, while Montenegro’s EPCG–PowerX cooperation points to growing storage ambition.  

The storage market, however, is not a simple equipment sale. It involves fire safety, degradation warranties, dispatch software, grid-forming capability, cybersecurity, EMS integration, revenue stacking and performance guarantees. Chinese battery suppliers can be highly competitive, but European lenders will demand strong documentation and compliance with technical standards.

This creates a role for independent engineering oversight.

Owners, banks and utilities will need to verify whether equipment specifications match revenue assumptions, whether warranty structures are enforceable, whether degradation is properly modelled and whether integration with grid systems is secure. In this sense, Chinese technology participation may actually increase the need for local and international technical supervision.

Grid infrastructure is another likely growth area.

The Balkan grid is approaching a congestion decade. Renewable projects are moving faster than transmission reinforcement. Cross-border flows are becoming more volatile. Batteries and flexible generation require stronger substations, protection systems and digital control. Chinese contractors with experience in transmission, substations and power electronics may seek a stronger position in this market.

But grid infrastructure is geopolitically sensitive.

Transmission systems are strategic assets. EU-aligned markets will scrutinize technology vendors, cybersecurity exposure and operational control. This does not exclude Chinese participation, but it makes transparency, procurement discipline and system-security safeguards more important.

The same applies to digital energy systems.

As SEE utilities modernize dispatch, metering, SCADA, grid automation and market platforms, technology choices will increasingly intersect with cybersecurity policy. Chinese providers may offer cost-competitive solutions, but sensitive infrastructure will face deeper review from regulators, TSOs and European partners.

For Western Balkan governments, the attraction of Chinese partners remains clear. They can offer EPC capacity, equipment availability, financing relationships and willingness to enter complex markets where European private capital may be cautious.

But the financing environment has changed.

European institutions such as EBRD, EIB and KfW are increasingly central to renewable, grid and environmental financing across the region. Their involvement brings stricter procurement, ESG, permitting and documentation standards. Projects seeking European capital cannot rely only on political agreements or fast-track EPC structures.

That creates a hybrid investment environment.

Chinese contractors may build projects financed or partially de-risked by European institutions, but only if they comply with lender standards. Alternatively, Chinese finance may support projects outside European lending frameworks, but those projects may face greater scrutiny if connected to EU market integration, CBAM-sensitive exports or public debt exposure.

This hybrid model will define the next phase of Chinese activity in SEE.

The old binary narrative — Chinese finance versus European finance — is becoming too simplistic. In practice, projects may combine Chinese equipment, local developers, European banks, state utilities, international technical advisers and EU-aligned regulatory obligations.

That complexity favors the most disciplined sponsors.

For investors, the key question is not whether Chinese participation is good or bad. The key question is whether the project structure is bankable.

A bankable Chinese-backed or Chinese-supplied project in SEE will need clear ownership, transparent EPC scope, enforceable warranties, grid-code compliance, environmental approvals, reliable O&M arrangements, cybersecurity safeguards, realistic dispatch assumptions and credible financing documentation.

Without those elements, Chinese participation may reduce upfront cost but increase long-term project risk.

With those elements, Chinese participation could accelerate the regional energy transition.

The opportunity is large. SEE needs new renewable capacity, storage, transmission upgrades, hydro modernization, balancing resources and industrial energy infrastructure. European contractors and OEMs alone may not provide sufficient speed or cost competitiveness. Chinese firms can fill part of that gap if integrated into higher-standard project frameworks.

This is where the strategic repositioning becomes visible.

Chinese companies are not withdrawing from SEE energy. They are adapting to a market where coal is weaker, renewables are stronger, storage is emerging, grids are congested and EU-linked compliance standards are harder to avoid.

That adaptation will not be frictionless. It will involve disputes, regulatory scrutiny, lender caution and political debate. But it will also create new project combinations across hydropower, wind, solar, storage and transmission.

The winners will be neither purely Chinese nor purely European projects. The strongest platforms are likely to be those that combine competitive equipment and construction capacity with bankable European-style governance, transparent documentation and robust technical supervision.

That is the new infrastructure contest now forming across Southeastern Europe.

Elevated by Virtu.Energy

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The first half of May 2026 showed how exposed the region remains to aging lignite and coal-fired assets, even as policy language increasingly shifts toward renewables, storage and grid integration. Coal generation across the broader HU+SEE system fell by approximately 260 MW, while prices still rose sharply across the region. Serbia’s SEEPEX averaged €101.61/MWh, Montenegro’s BELEN stood at €98.76/MWh, Bulgaria’s IBEX reached €104.98/MWh, and Romania’s OPCOM climbed to €115.88/MWh.  

That price movement matters because it shows a system losing cheap firm capacity faster than replacement flexibility can fully absorb. Coal plants remain politically important, but their operational and financial quality is deteriorating.

The clearest example is RiTE Ugljevik in the Republic of Srpska. The plant returned online in early May after months of inactivity caused by coal-supply and operational problems. Its financial position deteriorated sharply: the company reported a €18.3 million loss in the first quarter of 2026 after revenue collapsed from €18.8 million a year earlier to only €2.2 million, while expenses remained above €20 million.  

This is not a normal cyclical downturn. It is a structural warning. When a coal plant cannot operate because mining preparation, overburden removal or fuel supply fails, it stops functioning as baseload and becomes a contingent liability.

The Republic of Srpska’s decision to acquire Comsar Energy RS and its Ugljevik Istok 2 concession for more than €120 million shows the scale of state intervention now required to keep coal infrastructure alive. What once looked like generation security increasingly resembles fiscal exposure.

RiTE Gacko shows a softer but equally important deterioration. The company posted only around €50,000 net profit in the first quarter of 2026, down from €440,000 in the same period last year, despite revenue of €24.3 million. Expenses rose to roughly €24.2 million, leaving almost no earnings buffer.  

That thin margin is important. Coal plants with almost no profitability buffer are vulnerable to any additional shock: equipment failure, coal-quality deterioration, environmental costs, wage pressure, carbon-related trade impacts, fuel logistics disruptions or forced outage.

Montenegro faces a similar problem through Pljevlja. The coalmine recorded significantly lower profit in 2025, while EPCG reported a €92 million loss in 2025 before returning to stronger profitability in the first quarter of 2026.   The mixed performance shows the tension inside hydro-coal utility systems: strong hydrology can improve earnings, but coal exposure remains structurally difficult.

For Serbia, the issue is larger because coal remains central to the national power system. EPS reported higher profit in 2025 and €129 million profit in the first quarter of 2026, but the broader market direction still points toward rising pressure on lignite-based generation.   Profitability today does not remove transition risk tomorrow.

The Western Balkan coal problem has four layers.

The first is technical. Many plants are old, maintenance-heavy and tied to mines with declining operational efficiency. Outages increasingly have market-wide consequences because firm capacity is still needed during low hydro, low wind or evening peak periods.

The second is financial. Coal assets require continuous capital just to remain operational. Mine expansion, overburden removal, environmental upgrades, spare parts, workforce costs and debt restructuring all compete with investment needs in renewables, storage and grids.

The third is regulatory. EU accession, Energy Community obligations, environmental compliance and CBAM-linked trade effects are steadily reducing the commercial comfort zone around coal-heavy systems.

The fourth is market-based. As solar expands, coal plants face weaker utilization during midday periods but remain needed during evening and winter scarcity. That reduces their operating logic: they must stay available but may run less predictably.

This is a difficult financial model.

Baseload coal economics work best when plants run steadily at high load factors. A system with growing solar and wind requires flexibility, ramping and reserve capability. Old lignite units were not built for that role.

The consequence is increasingly unattractive: high fixed costs, lower operating predictability, more maintenance stress and rising political sensitivity.

For governments, this creates a sovereign-risk issue. Coal utilities often sit close to public balance sheets. When plants fail, the state frequently steps in through guarantees, concession acquisitions, liquidity support or regulated tariff decisions. That means energy transition risk can become fiscal risk.

For banks, coal-linked exposure becomes harder to justify. Even where lending is not directly for coal generation, exposure to utilities, industrial offtakers or public infrastructure linked to coal systems carries transition risk. Credit committees increasingly ask whether cash flows depend on assets that may face declining utilization, higher compliance costs or regulatory restrictions.

For electricity traders, coal instability means higher volatility. A sudden outage at a major lignite unit can tighten the regional stack quickly, especially when nuclear or hydro output is also weak. The May data showed exactly that type of environment: lower firm generation, higher gas generation and rising prices despite weaker demand.  

For renewable developers, coal instability is a double-edged signal. On one side, declining coal reliability strengthens the case for new renewable capacity, battery storage and flexible assets. On the other, weak grid planning and slow replacement of firm capacity can increase system risk, curtailment and balancing costs.

The investment answer is not simply “replace coal with solar”. That is too narrow.

Western Balkan systems need coordinated replacement portfolios: wind, solar, storage, hydro optimization, grid reinforcement, demand response, flexible gas where necessary, and industrial PPAs. Coal capacity cannot be removed without replacing both energy and system services.

This is why battery storage and flexible hydro are gaining strategic importance. Coal plants historically provided inertia, voltage support, reserve capacity and dispatchability. Renewables alone do not automatically provide the same services unless supported by grid-forming inverters, storage, advanced control systems and stronger transmission networks.

The political challenge is that coal plants still support employment and local economies. Mines and thermal plants are often among the largest employers in their regions. Any serious transition therefore requires social and financial planning, not only energy modelling.

Yet delaying the transition does not remove the cost. It may increase it.

Each year of underinvestment in replacement flexibility raises the probability of emergency imports, forced public support and politically difficult tariff adjustments. Coal assets that appear cheap because their capital costs are already sunk can become expensive when outages, mining failures and environmental liabilities are counted properly.

The Western Balkans are approaching that point.

The financial instability of Ugljevik, the margin compression at Gacko, the volatility around Pljevlja, and the continuing reliance on coal-heavy systems in Serbia all point to a region where coal is moving from security asset to managed decline problem.

The strategic issue is not whether coal disappears immediately. It will not.

The real question is whether governments and utilities use the remaining coal operating window to finance credible replacement capacity, or whether they spend that window keeping old assets alive until failures become more expensive than transition itself.

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Hungary’s HUPX day-ahead baseload price surged to €143.22/MWh, up more than €55/MWh day-on-day, while Romania’s OPCOM closed at €143.19/MWh, Croatia’s CROPEX at €143.24/MWh, and Slovenia’s BSP at €143.18/MWh, confirming renewed price convergence across Central and South-East Europe. Serbia’s SEEPEX remained structurally decoupled at €82.27/MWh, while Albania and Montenegro also traded materially below core regional hubs at €61.67/MWh and €84.19/MWh respectively.  

The main market driver was the collapse in regional wind output. Forecast wind generation across the SEE system dropped by approximately 1,029 MW day-on-day, falling to around 1,651 MW, while solar generation partially compensated with an increase of nearly 978 MW. The generation balance clearly shifted back toward thermal and imported marginal pricing during evening peak hours, especially around hour 21 where most regional exchanges recorded daily maxima above €250/MWh.  

Regional consumption simultaneously rebounded strongly after the weekend. Total SEE plus Hungary forecast demand climbed to roughly 27.9 GW, increasing by more than 1.7 GW day-on-day, while temperatures across the region also moved higher.   This demand normalization coincided with a sharp contraction in net regional imports, which fell to only -80 MW versus over 1.5 GW one day earlier. The reduction of cheaper core European inflows materially tightened local pricing structures.

Hydro conditions nevertheless remain structurally supportive for the region. Total hydro generation stayed elevated at roughly 6.3 GW, representing around 25% of the overall generation mix. Danube flow levels also remain significantly above long-term averages near 6,848 m³/s, reinforcing strong hydropower performance in Romania and the wider Balkan system. This explains the exceptionally strong Q1 financial results now being reported by hydro-dominated utilities such as Romania’s Hidroelectrica and Montenegro’s EPCG.  

Romania continues emerging as one of the strongest regional generators structurally. Q1 2026 electricity production rose by 8.8%, with hydropower generation increasing by 38.3% and wind output by 18% year-on-year.   Hidroelectrica’s net profit more than doubled to approximately €263 million, benefiting from elevated wholesale market monetization and stronger balancing revenues.  

Montenegro’s EPCG also reported a substantial profitability improvement, with Q1 net profit reaching €36.5 million compared to €10.2 million a year earlier, supported by hydrology and increased thermal production at Pljevlja.  These results are becoming increasingly important from a CBAM and regional electricity-trading perspective because hydro-heavy generation portfolios are strengthening the long-term commercial attractiveness of low-carbon regional electricity exports into EU-linked industrial supply chains.

The futures curve meanwhile indicates that traders still expect structurally elevated power pricing into summer despite current renewable expansion. Hungarian Week 21 baseload forwards traded around €118.5/MWh, while June 2026 contracts remained above €113/MWh. EUA carbon prices also stabilized around €75.6/tCO₂, continuing to underpin coal and gas marginal pricing economics across the SEE region.  

Gas markets remain another critical structural variable. CEGH gas prices traded around €50.67/MWh, while regional strategic positioning around the Vertical Gas Corridor continues accelerating. Greece, Serbia, North Macedonia and Bulgaria formally advanced discussions on expanding the corridor deeper into the Western Balkans, reinforcing the strategic role of South-East Europe as a future gas and electricity transit hub.  

One of the most important structural developments remains the growing divergence between fully coupled EU exchanges and the still partially isolated SEE markets. Serbia’s SEEPEX prices staying roughly €60/MWh below HUPX on the same delivery day again highlighted how local balancing conditions, generation mix and cross-border congestion continue fragmenting regional pricing dynamics. For traders, industrial buyers and future battery-storage operators, these spreads increasingly represent both arbitrage opportunities and emerging congestion-risk signals.

Battery storage economics continue improving under exactly these volatility conditions. Albania’s planned 160 MW solar + 60 MW battery project backed by potential EBRD financing illustrates how investors are repositioning around hybrid flexibility assets rather than standalone renewables. The growing evening ramp between collapsing solar output and weakened wind generation is now repeatedly producing high-value peak spreads across SEE markets, particularly during hour 20–22 windows visible across HUPX, OPCOM and BSP intraday profiles.  

At the same time, thermal generation remains materially embedded in regional balancing structures. Coal and gas still represented approximately 28% of total SEE+Hungary generation on 18 May, despite strong hydro and solar conditions. Greece’s closure of the 1,595 MW Agios Dimitrios lignite plant therefore carries wider implications beyond decarbonization alone, because it increases regional dependence on gas, interconnections and flexible balancing capacity.  

The broader market picture increasingly suggests that SEE electricity markets are entering a structurally more volatile phase where hydrology, solar cannibalization, evening peak scarcity, cross-border congestion and CBAM-linked low-carbon electricity demand will simultaneously shape pricing. Daily averages alone are becoming less relevant than hourly volatility structures, particularly for traders, BESS operators and industrial consumers exposed to intraday balancing costs.  

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Between January and March, the group generated around 1.5 billion euros in revenue, broadly unchanged compared to the same period last year. However, net profit fell sharply by 73%, while EBITDA declined by 39% to 41 million euros. Operating profit also dropped significantly, decreasing by 65% to 14.8 million euros.

According to Petrol, the most severe pressure occurred in March, when regulatory fuel pricing measures reportedly led to losses of 27.5 million euros, even though sales volumes increased notably during the month. The company argued that the current pricing framework in Slovenia no longer reflects real operating costs and has become unsustainable for fuel retailers.

Petrol also noted that government signals regarding potential fuel price adjustments created additional uncertainty in the market, further complicating operations. Despite these challenges, the company maintained uninterrupted fuel and energy supply throughout the quarter.

During the first three months of 2026, Petrol sold approximately one million tons of fuels and petroleum products, representing a 10% increase year-on-year. Revenue from merchandise and services rose by 8% to 152.9 million euros, while gross profit declined slightly by 4% to 151.9 million euros.

CEO Sašo Berger stated that the current regulatory environment does not allow for sustainable long-term operations in the fuel retail sector, adding that regulated pricing is directly generating operational losses and increasing supply risks. He also confirmed that the company will continue pursuing legal actions and compensation claims linked to the pricing model, while calling for the removal of fuel price controls.

Supervisory Board Chairwoman Vesna Južna emphasized that regulated retail margins have remained largely unchanged for more than a decade, despite rising inflation and significantly higher operating costs. She noted that inflation over the past four years reached around 20%, while operating expenses increased by more than 35%, severely impacting profitability.

In response to the challenging environment, the Supervisory Board instructed management to prepare a protocol for situations in which regulated fuel sales may no longer support profitable operations. At the end of March, the group employed 5,759 people, about 2% fewer than a year earlier, and invested 26.8 million euros during the quarter while maintaining a stable financial position and favorable credit outlook.

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Industrial consumption remained relatively stable at 9.85 TWh, showing a slight decline of 0.1% year-on-year. Household electricity use fell more noticeably to 2.86 TWh, representing a 9.2% drop. In contrast, electricity used for public lighting increased by 5.3%, reaching around 115.1 GWh.

At the same time, Romania’s total electricity production reached 14.37 TWh in the first three months of 2026, an increase of 8.8% compared to the previous year. Thermal power generation declined by 3%, totaling 5.05 TWh, while hydropower output rose significantly by 38.3% to 3.77 TWh.

Production from the Cernavodă nuclear power plant decreased slightly by 3%, reaching 2.86 TWh. Meanwhile, wind energy generation increased by 18%, reaching 1.9 TWh, and solar power production, including prosumers, grew by 10.17% to 774.1 GWh.

Electricity trade also improved during the period, with exports rising by 13.9% to 3.66 TWh, while imports declined by 15.4% to 3.84 TWh, indicating a narrowing gap between domestic production and external supply.

In the primary energy sector, total production reached 4,116 million tons of oil equivalent, a 2.3% decline compared to 2025. Coal production fell sharply by 22.7%, oil output decreased by 8.3%, while natural gas production recorded a modest decline of 1.5%.

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The company achieved a net profit of 36.5 million euros for the January–March period, a significant rise compared to 10.2 million euros recorded in the same quarter last year. Operating profit also improved sharply, reaching 36.8 million euros, up from 9.4 million euros a year earlier.

Revenue from electricity sales increased to 142 million euros, compared to 126 million euros in the first quarter of 2025. At the same time, total operating expenses declined from 110 million euros to 97 million euros, while labor costs were slightly reduced to 8.1 million euros.

According to EPCG, the improved results were primarily driven by exceptionally favorable hydrological conditions, which boosted electricity production well above planned levels. Total generation in the first three months of 2026 reached 1,204 GWh, exceeding internal projections by 49%.

Hydropower facilities were the main driver of output growth. The 307 MW HPP Perućica produced 493 GWh, surpassing expectations by 48%, while the 342 MW HPP Piva generated 323 GWh, or 43% above planned levels.

Electricity production also rose at Montenegro’s only thermal power plant, the 225 MW TPP Pljevlja, which produced 385 GWh during the quarter, exceeding planned output by 83%. Small hydropower plants operated by EPCG added another 2.7 GWh, also outperforming expectations.

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Economy and Energy Minister István Kapitány authorized the sale of 150 million liters of 95-octane gasoline and an additional 425 million liters of diesel from national stockpiles. The decision is aimed at ensuring stability in domestic fuel supply while preventing potential shortages.

The released fuel will be sold exclusively within Hungary and only at regulated capped prices, designed to limit pressure on consumers. The government has set net pre-tax prices at approximately 0.75 euros per liter for gasoline and around 0.83 euros per liter for diesel. The measure is intended to support both retail fuel stations and end-users across the country.

According to the decision, members of the Hungarian Hydrocarbon Stockpiling Association will have until the end of June 2026 to purchase the released reserves. At the same time, authorities have mandated the immediate replenishment of strategic stocks once the sales begin, with a requirement to fully restore reserves by 30 June 2027.

The Hungarian government also stated that revenues generated from the fuel sales will be reinvested into rebuilding the national emergency fuel reserves, ensuring long-term security and continuity of supply.

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The closure represents a significant milestone in Greece’s broader decarbonization strategy and for the country’s Public Power Corporation (PPC). Throughout its operational history, the facility was essential for supporting industrial growth and ensuring national electricity supply, while thousands of workers employed at the plant and nearby lignite mines depended on its activity.

At the same time, the environmental impact of the plant was substantial. Since the introduction of the EU emissions trading system in 2005, the facility is estimated to have emitted nearly 200 million tons of carbon dioxide. In 2012 alone, annual emissions reached around 14.7 million tons of CO2, placing the power plant among Europe’s largest polluters during that period.

Despite environmental concerns, the shutdown also creates serious economic and social challenges for the lignite-producing region of Western Macedonia. The transition away from coal has not yet fully compensated for the loss of jobs and economic activity, while uncertainty remains regarding future financial support after the current EU Just Transition funding period expires.

The city of Kozani is also facing additional difficulties, as its district heating network relied on the Agios Dimitrios plant for more than 30 years. Local authorities are now expected to depend on oil-based heating solutions during the upcoming winter season, while longer-term alternatives linked to natural gas infrastructure are still unfinished.

The closure has additionally reignited debate about the future structure of Greece’s electricity market. Energy experts and environmental organizations are questioning whether the lost lignite production will mainly be replaced by renewable energy sources or whether fossil gas will take on a larger role in electricity generation, potentially influencing both climate objectives and electricity prices in the years ahead.

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Hydropower plants generated 563 GWh of electricity, accounting for 44.9 % of total production. Thermal power plants produced 212 GWh or 16.9 %, while wind farms contributed 289 GWh, representing 23 % of total electricity generation. Solar power plants produced 115 GWh, accounting for 9.2 % of overall electricity production during the month.

At the same time, Croatia imported 1,090 GWh of electricity in March 2026, which was 14.7 % higher compared to the same period last year, when imports stood at 950 GWh. Electricity exports reached 701 GWh, marking a 10.5 % decline compared to March 2025, when exports totaled 783 GWh.

In the hydrocarbon sector, Croatia produced 62 million cubic meters of natural gas in March 2026, an increase of 5.1 % compared to the same month last year. Natural gas imports amounted to 262 million cubic meters, representing a significant 37.9 % increase year-on-year.

Meanwhile, crude oil production stood at 38,000 tons, which was 2.6 % lower compared to the previous year. Production of petroleum products reached 138,000 tons in March 2026, significantly below the 276,000 tons recorded in the same month last year.

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The overall investment, estimated at around 105 million euros, combines utility-scale solar power generation with advanced battery storage technology. The project is expected to become one of the first integrated solar-plus-storage developments of this scale in the wider region operating under market-based conditions.

The financing would be provided to two Albanian special purpose companies jointly controlled by Blessed Investment and Matrix Konstruksion. The EBRD is expected to make its final decision regarding the transaction by mid-June 2026.

The project includes a total of 160 MW of solar capacity together with a 60 MW battery energy storage system. While part of the development is already operational, additional phases remain under construction or are still in the pre-development stage.

The solar complex consists of the Blue Solar 2 and Blue Solar 3 projects located in the municipality of Fier. Blue Solar 2 Phase 1, with an installed capacity of 64 MW, has already entered commercial operation, while the 55 MW second phase is currently under construction. Meanwhile, the 43 MW Blue Solar 3 project remains in the preparatory phase.

The energy storage segment includes a 30 MW battery system with a storage capacity of 80.25 MWh, which will be installed within the existing Blue Solar 2 substation area. The development plan also includes the construction of a 220 kV transmission line that will connect the facilities to Albania’s national electricity network.

According to project documentation, the investment could additionally benefit from risk protection support under the European Fund for Sustainable Development Plus Hi-Bar guarantee mechanism, which is intended to encourage investment in renewable energy and strategic infrastructure projects across the region.

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One of the key outcomes of the meeting was the agreement to advance cooperation on expanding the Vertical Corridor gas route. Serbia and North Macedonia are expected to become the first countries included in the next stage of the transport corridor’s development, which connects Greece with central and eastern European energy markets.

The ministers focused on enhancing regional interconnections, increasing the resilience of national energy systems, and accelerating strategic infrastructure investments designed to reduce supply risks and support deeper market integration throughout southeastern Europe. The four countries also agreed to formalize their cooperation framework through regular ministerial meetings, with the next gathering scheduled to take place in Serbia this September.

Greek Environment and Energy Minister Stavros Papastavrou emphasized that regional energy cooperation is increasingly being viewed as a key instrument for stability and economic growth. He underlined Greece’s role in promoting infrastructure projects, market integration, and interconnection initiatives intended to strengthen both regional energy security and broader geopolitical resilience.

According to Papastavrou, the meeting reflected a growing alignment among the participating countries, with cooperation now moving toward the concrete implementation of projects focused on securing long-term energy supply and supporting sustainable economic development across the region.

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Between May 11, 2026 and May 17, 2026, 80 articles were published.

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This transition is unfolding at a moment when European energy markets are simultaneously confronting renewed geopolitical stress, persistent LNG insecurity and accelerating electrification linked to artificial intelligence, data centers and industrial decarbonization. The combined effect is beginning to transform the strategic role of SEE power systems inside the broader European electricity landscape.

The most immediate shift is visible in the relationship between renewable generation and cross-border electricity pricing. Historically, renewable buildout in SEE was primarily viewed as a domestic decarbonization challenge or an investment opportunity tied to feed-in support and merchant upside. Today, renewable generation increasingly acts as a geopolitical and commercial instrument linked directly to European industrial competitiveness.

That dynamic is particularly evident in the growing divergence between electricity produced with verifiable renewable origin and electricity sourced from mixed or coal-heavy systems. As CBAM gradually tightens around industrial supply chains, European buyers are becoming increasingly selective regarding the structure and traceability of imported electricity. This is beginning to create differentiated market value for renewable-backed electricity products even within the same interconnected regional market.

The Western Balkans’ coordinated request for adjustments to CBAM electricity treatment reflects rising concern that regional producers could lose competitiveness unless Brussels formally recognizes the structural limitations and transition realities of SEE power systems. Governments in Serbia, Montenegro, Bosnia and Herzegovina and North Macedonia are increasingly aware that electricity exports may soon require much more than competitive pricing alone. Future exportability may depend on demonstrating auditable renewable sourcing, contractual transparency and physical traceability.

That shift has important pricing implications. Electricity connected to verified renewable PPAs and Guarantees of Origin could increasingly command premium market access into parts of the European industrial system exposed to CBAM pressure. Conversely, exporters dependent on carbon-intensive portfolios may face widening commercial discounts or reduced liquidity in forward contracting markets.

Grid congestion is simultaneously emerging as one of the defining structural features of the SEE electricity market. The rapid expansion of renewable generation across the Balkans has not been matched by equivalent transmission investment, creating growing stress on regional interconnectors and domestic balancing systems. Curtailment risk is therefore becoming a critical commercial factor for investors and traders alike.

Montenegro’s strategic emphasis on interconnection infrastructure reflects this reality. The second submarine cable project with Italy, combined with the Trans-Balkan Electricity Corridor, is not merely an infrastructure expansion plan. It represents an attempt to position the country at the center of future European electricity flows precisely as cross-border balancing and renewable integration become increasingly valuable.

The same logic applies to Serbia’s transmission position. As renewable penetration rises across Romania, Hungary, Bulgaria and the Western Balkans, Serbia’s role as a balancing and transit node becomes progressively more important. Yet this opportunity also exposes the country to higher volatility. Congestion spreads, balancing costs and negative pricing events are likely to become more frequent as renewable generation grows faster than grid modernization capacity.

This trend could materially reshape project economics throughout the region. Renewable projects located near strong interconnection nodes or high-capacity substations may increasingly outperform isolated generation assets even when pure production profiles appear similar. Grid proximity, export flexibility and balancing access are gradually becoming premium infrastructure characteristics.

Battery storage therefore emerges as one of the most strategically important investment categories in SEE markets. Storage is no longer simply a technical balancing tool. It increasingly functions as a commercial optimization platform capable of protecting renewable projects from curtailment, improving PPA reliability and arbitraging widening volatility inside regional power markets.

The current geopolitical environment further strengthens this trend. Europe’s continuing exposure to gas-market shocks, highlighted once again by the disruption around the Strait of Hormuz, is accelerating efforts to secure more stable regional electricity supply structures. South East Europe’s renewable resources are becoming more strategically valuable because they offer geographic proximity to EU demand centers while reducing dependence on imported LNG.

This creates a new layer of strategic importance for hydropower as well. Countries such as Montenegro and Bosnia and Herzegovina retain balancing advantages through hydro flexibility that become increasingly valuable in a renewable-heavy European market. During periods of renewable oversupply elsewhere in Europe, dispatchable hydro generation and balancing services may generate higher commercial returns than previously assumed.

At the same time, pricing pressure on conventional thermal fleets is likely to intensify. Coal-heavy systems face a growing convergence of negative factors: rising carbon costs, CBAM exposure, aging infrastructure, environmental compliance CAPEX and increasing difficulty securing long-term financing. The economic sustainability of legacy thermal generation across the region is therefore becoming progressively more uncertain.

This tension is especially visible in Serbia, where thermal generation still anchors system stability while renewable expansion accelerates. Policymakers increasingly face a difficult balancing act between preserving affordability, maintaining system reliability and positioning the country competitively within Europe’s evolving low-carbon electricity framework.

The financial sector is already adjusting to these realities. Lenders and institutional investors increasingly differentiate between projects capable of integrating storage, traceability systems and structured offtake arrangements and those relying purely on merchant exposure. Renewable projects aligned with cross-border interconnection strategies and industrial decarbonization demand are likely to attract more favorable financing conditions over the coming years.

The wider implication is that SEE electricity markets are beginning to fragment into multiple value layers simultaneously. Simple baseload generation value is no longer sufficient. Future market competitiveness increasingly depends on a combination of:

• carbon intensity,
• flexibility,
• balancing capability,
• traceability,
• interconnection access,
• and contractual bankability.

That transformation could ultimately redefine the region’s economic role inside Europe. South East Europe may gradually evolve from a relatively low-cost peripheral electricity market into a strategically integrated renewable balancing and export corridor supporting European industrial decarbonization and long-term energy security.

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For South East Europe, the consequences are especially significant because the region sits at the intersection of multiple strategic pressures simultaneously reshaping Europe’s energy system: LNG insecurity, rising electricity demand, decarbonization requirements, CBAM implementation and the urgent need for new transmission corridors connecting renewable-rich regions with industrial demand centers.

This week’s developments revealed how quickly those pressures are converging. Global oil supply disruptions linked to the Hormuz crisis have already removed millions of barrels per day from international markets, while LNG supply losses connected to Qatari export interruptions exposed Europe’s continuing vulnerability to external gas shocks. European gas prices remain roughly double those in the United States and China, forcing policymakers to reconsider earlier assumptions regarding long-term energy security and industrial competitiveness.

Inside the European Union, the response is becoming increasingly pragmatic. Energy ministers are now openly discussing renewed domestic gas exploration projects in Greece, Romania, Italy and Poland despite years of political resistance to upstream fossil-fuel development. That shift reflects a growing recognition that Europe’s transition strategy cannot rely exclusively on imported LNG and intermittent renewable generation without substantial supporting infrastructure.

South East Europe is emerging as one of the primary beneficiaries of this recalibration.

The region possesses several characteristics now highly valued by European policymakers and infrastructure investors: proximity to EU demand centers, substantial untapped renewable resources, existing hydroelectric balancing capacity and expanding interconnection corridors toward Italy and Central Europe. As a result, SEE is increasingly viewed not as a peripheral electricity market but as a future strategic energy platform capable of supporting European decarbonization and supply security simultaneously.

Montenegro’s evolving role illustrates this transition particularly clearly. The commissioning of the Gvozd wind farm, negotiations over a second submarine cable to Italy and continued development of the Trans-Balkan Electricity Corridor collectively point toward a broader strategic repositioning of the country as an electricity-export gateway between the Western Balkans and the EU.

The economics behind this strategy are becoming increasingly compelling. Europe’s industrial system faces structurally higher gas costs, tighter carbon pricing and rising balancing expenses. Renewable electricity imports from nearby regions therefore become more valuable both economically and strategically. In this environment, countries capable of delivering competitively priced low-carbon electricity into European grids may secure increasingly important geopolitical and financial roles.

This trend is already influencing investment behavior. European institutional lenders are quietly accelerating infrastructure support throughout the region. More than €250 million of EIB-backed investment announced this week for Montenegro reflects a wider EU effort to strengthen strategic infrastructure ahead of potential future integration into European energy systems. Rail modernization, transmission upgrades, port infrastructure and electricity interconnectors are increasingly being treated as interconnected geopolitical investments rather than isolated development projects.

At the same time, the economics of renewable generation inside SEE are improving materially because of global fuel volatility. Wind, solar and storage projects now offer not only decarbonization benefits but also insulation from external gas-market disruptions. This dramatically strengthens the long-term strategic case for regional renewable expansion.

Battery storage plays an increasingly central role in this shift. As European electricity markets experience greater volatility and negative pricing events become more common, storage is evolving from a balancing accessory into core infrastructure. Hybrid solar-storage and wind-storage projects are likely to become dominant investment structures across the region because they provide not only energy generation but also flexibility, balancing support and greater export reliability.

Grid infrastructure may ultimately become the most valuable strategic asset class in the region. The ability to move electricity reliably across borders now matters as much as generation itself. Transmission bottlenecks, curtailment risks and balancing limitations increasingly determine project economics and market competitiveness. This creates strong incentives for accelerated development of high-voltage corridors, interconnectors and digital grid-management systems throughout South East Europe.

The wider industrial implications are equally important. Europe’s manufacturing sector increasingly requires stable access to low-carbon electricity to remain competitive under CBAM and broader decarbonization pressures. South East Europe could therefore evolve into both a renewable electricity exporter and an industrial relocation platform for energy-intensive industries seeking lower operating costs and cleaner electricity sourcing.

Serbia occupies a particularly important position within this transformation. The country combines significant transmission connectivity, growing renewable potential and industrial manufacturing capacity. Yet it also faces mounting pressure to modernize legacy coal-based generation and adapt to Europe’s emerging carbon-linked electricity market structure. Future competitiveness may increasingly depend on how effectively Serbia integrates renewable generation, storage systems, interconnection capacity and compliance infrastructure into a coherent long-term strategy.

The broader market message from this week is increasingly clear. The Hormuz crisis is accelerating trends that were already beginning to reshape Europe’s energy system: regionalization of electricity supply, prioritization of nearby renewable resources, stronger infrastructure integration and rising strategic value of transmission corridors.

South East Europe now finds itself at the center of this transition. The region’s future role may no longer depend simply on whether it can generate enough electricity domestically, but whether it can position itself as a strategically indispensable low-carbon energy bridge between the European Union, the Mediterranean and the wider Eurasian energy landscape.

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The clearest signal emerged this week when Montenegro, Serbia, Bosnia and Herzegovina, North Macedonia and Kosovo jointly asked the European Union to revise parts of the Carbon Border Adjustment Mechanism framework related to electricity exports. Regional governments warned that uncertainty surrounding CBAM implementation is already weakening demand from EU buyers for electricity imports from the Western Balkans, including renewable electricity. The intervention marks one of the first coordinated regional acknowledgements that CBAM is beginning to affect electricity market behavior well before the mechanism reaches its final financial implementation phase.

Behind the diplomatic language lies a much deeper structural issue for the region’s energy sector. For decades, SEE electricity markets largely operated on a merchant-trading logic driven by price spreads, hydrology, coal generation availability and cross-border congestion. The next market phase appears fundamentally different. European industrial buyers increasingly require proof that imported electricity is connected to renewable generation, supported by Guarantees of Origin, contractual PPAs and increasingly sophisticated traceability frameworks.

This transition has major implications for Serbia in particular, where electricity exports historically benefited from relatively low production costs tied to lignite-based generation and legacy thermal infrastructure. Under the emerging CBAM structure, however, carbon exposure increasingly becomes a commercial liability rather than merely a future environmental obligation. Electricity generated from high-emission portfolios risks becoming progressively less attractive for EU counterparties seeking to reduce embedded carbon exposure inside industrial supply chains.

That dynamic is beginning to alter the relative attractiveness of renewable projects throughout the region. Wind, solar and storage assets are increasingly viewed not only as generation facilities but as strategic compliance infrastructure capable of producing auditable low-carbon electricity products for European markets. In practice, this means that renewable projects with structured PPAs, verified physical delivery pathways and strong Guarantees of Origin systems may command materially stronger financing conditions than conventional merchant renewable assets.

The shift is especially relevant for industrial exporters operating in Serbia and Montenegro. Companies in steel, aluminum processing, chemicals, fertilizers and advanced manufacturing sectors face rising pressure from European customers to demonstrate lower embedded emissions across supply chains. Electricity sourcing is therefore becoming a central commercial issue rather than merely a procurement function. The growing importance of renewable-backed electricity contracts introduces a new relationship between power markets, industrial competitiveness and project finance.

Regional transmission infrastructure is emerging as another critical factor in this transformation. Montenegro’s accelerated positioning as an electricity corridor toward Italy illustrates the wider strategic logic now shaping SEE markets. The commissioning of the Gvozd wind farm, progress on the Trans-Balkan Electricity Corridor and negotiations with Terna regarding a second submarine cable to Italy collectively indicate that the region is increasingly viewed as a future low-carbon export platform for European electricity demand.

That strategy becomes even more important in the context of Europe’s widening energy-security concerns. The continuing disruption around the Strait of Hormuz and LNG supply volatility have reinforced Europe’s vulnerability to imported fossil fuels, indirectly strengthening the strategic value of domestically connected renewable electricity from nearby regions. South East Europe therefore finds itself in an unusually advantageous position: geographically close to European demand centers while simultaneously possessing significant untapped renewable generation potential.

The implications extend beyond generation itself. Grid access, balancing capability and storage integration are rapidly becoming decisive economic differentiators. Projects located near strong transmission corridors or interconnection points may enjoy significantly higher long-term value than isolated generation assets unable to provide flexible delivery or export reliability. Battery storage integration, once viewed primarily as a balancing technology, is increasingly evolving into a strategic commercial tool enabling renewable generators to offer more stable and contractually reliable supply structures to industrial buyers.

The region’s request that the EU formally recognize PPAs and Guarantees of Origin as proof of electricity origin also reveals another important market trend: the emergence of “qualified electricity” as a premium export category. Electricity accompanied by auditable documentation, verified renewable sourcing and contractual transparency may gradually develop a separate commercial value layer above simple wholesale pricing.

That creates a growing role for engineering-grade verification systems, MRV frameworks and compliance infrastructure. Electricity trading is becoming increasingly intertwined with carbon accounting, project documentation and auditability requirements. Developers capable of integrating these systems early may secure significant competitive advantages as the market evolves.

Financial institutions are already beginning to adapt to these changes. Renewable projects aligned with EU decarbonization objectives, regional interconnection strategies and industrial decarbonization demand are increasingly perceived as lower-risk infrastructure investments. The combination of CBAM pressure, European industrial decarbonization and persistent energy-security concerns may therefore accelerate capital flows into SEE renewable infrastructure over the next several years.

For governments across the Western Balkans, the challenge will be balancing industrial competitiveness, household affordability and decarbonization requirements simultaneously. Electricity prices in the region remain politically sensitive, while infrastructure investment needs continue rising sharply. Yet the broader market direction now appears increasingly irreversible. Electricity in South East Europe is gradually transforming from a relatively commoditized regional product into a strategically verified industrial input tied directly to European carbon policy and supply-chain restructuring.

The result is that the next phase of SEE electricity markets may be defined less by simple megawatt expansion and more by who can deliver traceable, contractually bankable and CBAM-compatible renewable electricity into European industrial systems most efficiently.

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The deal follows a previous agreement signed last year covering replacement motors for feedwater pump systems, further extending cooperation between Končar and the Krško facility.

Under the new contract, Končar will manufacture reserve motors for cooling tower pumps with a capacity of 2,000 kW, replacing equipment originally produced by Končar itself. The agreement also includes new motors for circulating water pumps rated at 1,471 kW, which will replace units initially supplied by Westinghouse Electric Company.

The cooperation further strengthens Končar’s long-standing presence in the Slovenian energy sector. Over previous decades, the company has contributed to multiple hydropower projects in Slovenia, including HPP Boštanj, HPP Blanca, HPP Brežice, as well as modernization works at HPP Zlatoličje, HPP Doblar and HPP Plave. Earlier this year, Končar also signed a contract to upgrade the control system at HPP Boštanj.

Končar Group currently exports products and services to around 140 countries worldwide, generating approximately €1.3 billion in revenue last year, with net profit exceeding €220 million. International markets account for about 68% of total sales, reflecting its strong export orientation.

The company also reported strong momentum in 2026, securing around €585 million in new orders in the first quarter alone. Export activities now represent more than 72% of total revenues, underscoring continued growth in foreign markets and large-scale energy infrastructure projects.

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The wind farm, located in Galați County, was developed by Swedish renewable energy company OX2 for Nala Renewables, a joint venture backed by commodity trading firm Trafigura and IFM Investors.

Project partners confirmed that the commissioning of the Frumușița substation marks a key stage in the project’s completion, allowing future electricity exports into Romania’s national transmission grid. Full commercial operation is expected within the coming months. The facility has an installed capacity of 99.2 MW and consists of 16 Vestas V162-6.2 MW turbines, positioning it among the significant new wind developments in the region.

Once fully operational, the wind farm is expected to generate approximately 312 GWh of electricity annually, sufficient to supply around 51,000 households. Developers also estimate that the project will reduce CO₂ emissions by about 150,000 tons per year, reinforcing its role in Romania’s ongoing energy transition.

Construction began in late 2024 after Nala Renewables acquired the project from OX2 earlier that year. Under the agreement, OX2 remained responsible for construction and operational delivery, while Nala Renewables retained investment oversight. The transaction also included a 12-year power purchase agreement (PPA) with a multinational corporate offtaker, providing long-term revenue stability.

Financing for the project was secured through Erste Group and its Romanian subsidiary Banca Comercială Română, highlighting continued strong bank appetite for utility-scale renewable assets in Central and Eastern Europe.

Green Breeze Wind Farm represents the first fully completed renewable energy project by OX2 in Romania, where the company is simultaneously developing a broader pipeline of projects totaling approximately 1,100 MW, signaling continued expansion of wind capacity in the country.

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The company expects the new installation to enter commercial operation by the end of 2026. Once completed, the facility is projected to produce more than 7 million cubic meters of biomethane annually, enough to supply the yearly natural gas demand of approximately 8,500 households. According to MOL, the development will represent the group’s first biomethane production project and only the third operational biomethane plant currently active in Hungary.

The existing Szarvas facility already converts large volumes of organic waste into biogas using materials such as manure, slurry, agricultural residues and waste from the food-processing industry. Under the planned expansion, the produced biogas will undergo additional upgrading processes designed to remove carbon dioxide and other impurities, converting it into grid-quality biomethane suitable for injection into the national gas infrastructure.

MOL acquired the Szarvas site in 2023 as part of its broader strategy focused on renewable energy and circular economy solutions. The facility currently operates gas engines with installed generation capacity of around 4 MW and produces nearly 24 GWh of electricity annually.

The company stated that the plant processes substantial quantities of organic waste each year, including more than 40,000 tons originating from regional meat production, approximately 53,000 tons of livestock and meat-processing by-products, as well as roughly 18,000 tons of agricultural raw materials. These feedstocks currently generate close to 12 million cubic meters of biogas per year.

MOL added that the operational experience gained through the Szarvas biomethane project will support the company in evaluating future acquisitions and potential greenfield investments within the rapidly expanding renewable gas sector.

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The group reported an adjusted EBITDA of approximately €700 million for the first quarter of 2026, compared with around €500 million during the same period last year. Adjusted net profit attributable to minority interests also recorded a strong increase, rising to nearly €200 million, up from €100 million in the first quarter of 2025.

According to the company, the improved results were primarily supported by the contribution of projects developed over recent years, together with favorable weather conditions that boosted both hydropower and wind generation output during the quarter. The combination of higher renewable production and stronger operational performance significantly strengthened the company’s earnings profile.

Investment activity remained highly intensive throughout the quarter, with PPC allocating roughly €500 million during the first three months of the year. Around 82% of total capital spending was directed toward renewable energy developments, flexible generation assets and the modernization of electricity distribution networks, fully aligned with the group’s long-term strategic transformation plan.

By the end of March, PPC’s installed renewable energy portfolio had reached 7.2 GW, accounting for nearly 60% of the company’s total generation capacity. At the same time, the group continued expanding its future development pipeline, which currently includes approximately 6.7 GW of renewable projects that are either under construction, preparing for construction or participating in tender procedures.

Despite the elevated level of investment spending, PPC maintained its financial indicators within targeted limits. Net debt stood at approximately €6.9 billion at the end of the quarter, while the company’s leverage ratio remained at 3.0x, comfortably below its internal ceiling of 3.5x.

The company also reaffirmed its guidance for the full 2026 financial year, maintaining targets of €2.4 billion in adjusted EBITDA and approximately €700 million in adjusted net income after minority interests. PPC additionally confirmed plans to distribute a dividend of €0.8 per share.

Commenting on the quarterly results, CEO Georgios Stassis stated that the group had entered 2026 with strong operational momentum, emphasizing the stability of PPC’s integrated business model and the company’s continued transition toward cleaner and more flexible energy production.

He added that PPC intends to continue disciplined investments in renewable energy, network infrastructure and flexible generation technologies as the company advances its long-term strategic objectives and strengthens its role in the energy transition across Central and Southeastern Europe.

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The most important market signal of the day was the extreme decoupling between SEEPEX Serbia and the broader HUPX-linked regional complex. Serbian day-ahead prices collapsed to €65.79/MWh, down almost €49.5/MWh day-on-day, making Serbia the lowest-priced market in the region by a very wide margin. Montenegro followed at €93.41/MWh, while North Macedonia traded at €83.18/MWh and Albania at €90.11/MWh. By contrast, Slovenia, Croatia, Romania and Hungary remained tightly coupled around the €117–120/MWh range.  

This pricing fragmentation reflects a temporary but important structural divergence in regional power balances. Serbia benefited from significantly stronger domestic generation and lower import dependency, while northern and core-linked markets remained exposed to tighter coupling with Italian and Central European pricing. The report shows total regional imports collapsing to only 167 MW, down nearly 950 MW versus the previous day, indicating a substantial reduction in external balancing needs across the SEE region.  

The generation mix explains much of the move. Regional hydro output remained strong at 6,404 MW, accounting for around 24% of the power mix, while coal generation increased to 4,876 MW and gas-fired generation rose to 3,736 MW. At the same time, wind production collapsed by almost 1,800 MW day-on-day, falling to 1,897 MW.  

Normally, such a sharp wind decline would support higher prices across SEE markets. Instead, the combination of stronger hydro availability, reduced imports and softer demand offset the loss of wind generation. Regional consumption increased modestly to 28,694 MW, but remained manageable within the existing thermal-hydro mix.  

The Serbian market displayed the clearest example of local balancing pressure overwhelming regional pricing convergence. SEEPEX hourly prices remained heavily discounted through most of the day, with a minimum price of €30/MWh and peak values only reaching €121.1/MWh.   The Serbian spread versus HUPX widened dramatically, creating one of the strongest arbitrage signals seen in recent weeks across the Balkan corridor.

Cross-border commercial flow data also confirmed persistent export orientation from several SEE markets toward neighboring deficit systems. Hungary maintained strong exports toward Croatia and Austria, while Romania exported heavily toward Hungary. Greece remained structurally import-dependent from Bulgaria, with average commercial flows from Bulgaria into Greece reaching approximately 987 MW in base load terms over the previous seven days.  

Another major driver remained Italian pricing strength. Italy traded at €136.36/MWh, retaining its position as the highest-priced market in the monitored region.   This continued to support northwestern SEE markets such as Slovenia and Croatia through coupled flow dynamics and export economics into the Italian system.

Forward markets meanwhile remained relatively stable despite the sharp spot volatility. Hungarian week-ahead baseload contracts traded around €117/MWh, while calendar 2026 power remained above €112/MWh. EUA carbon prices stayed elevated at around €75/t, while CEGH gas traded near €49/MWh.   This indicates traders still view the current spot weakness in Serbia and parts of the Balkans as temporary rather than structural.

The underlying thermal system remains active. Activated thermal generation capacity across the region stayed elevated through the week, while Danube hydrology conditions improved materially, supporting hydro dispatch flexibility.   This combination is increasingly important for balancing growing renewable penetration across SEE markets, particularly as solar generation continues expanding rapidly across Hungary, Romania, Greece and Serbia.

From a structural market perspective, the data again highlights the growing fragmentation inside SEE electricity pricing after the introduction of negative-price capable market structures earlier in 2026. While the region remains increasingly interconnected physically, local renewable surpluses, hydro variability and transmission bottlenecks are creating wider temporary pricing dislocations between neighboring markets.

This is particularly important for battery storage developers, cross-border traders and industrial offtakers. The spread between Serbia at €65.79/MWh and Italy at €136.36/MWh represents an intraregional differential exceeding €70/MWh in a single trading session.   Such spreads materially improve the economics of cross-border balancing assets, storage arbitrage and flexible industrial demand management.

The investment and infrastructure news flow across the region also reinforced the accelerating buildout of renewable and grid infrastructure. Kosovo’s 72 MW Zatriq wind farm is approaching commissioning, Romania’s 99 MW Green Breeze wind project entered final commissioning, while Turkey continues expanding both wind generation and underground gas storage capacity.  

At the same time, Serbia’s EPS reported a quarterly profit of €129 million, supported by stronger hydrology, higher coal production and reduced debt levels.   That combination reinforces the importance of legacy thermal-hydro systems in stabilizing SEE markets during periods of renewable volatility.

The daily data points to a market increasingly shaped by short-duration renewable swings, hydro conditions and congestion-driven fragmentation rather than purely fuel-driven pricing logic. The widening divergence between local Balkan pricing and core European markets is becoming one of the defining structural characteristics of SEE electricity trading in 2026.  

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This changes the role of PPAs fundamentally.

A power purchase agreement is no longer only a revenue hedge between a renewable generator and an electricity consumer. Under CBAM conditions, the PPA increasingly becomes part of an industrial exporter’s carbon strategy, financing strategy and long-term competitiveness model.

For banks, this creates a major shift in renewable project bankability.

CBAM turns renewable electricity into industrial compliance infrastructure

Industrial exporters across Europe increasingly face pressure to demonstrate lower embedded emissions in products entering the EU market. For steel, aluminum, fertilizers, chemicals, cement and energy-intensive manufacturing, electricity sourcing now directly influences carbon exposure.

As a result, renewable electricity gains a second value layer beyond the visible wholesale price.

The first layer remains the energy value itself — the €/MWh received from the market or contracted through a PPA.

The second layer is the carbon-adjusted industrial value attached to verifiable low-carbon electricity.

This second layer is becoming increasingly important for exporters trying to reduce CBAM exposure.

Banks understand this dynamic.

A renewable project supplying electricity to an industrial exporter under a long-term structured PPA may therefore become materially more bankable than a standalone merchant project exposed entirely to wholesale volatility.

The reason is that the renewable asset is no longer only selling electricity. It is helping preserve industrial export competitiveness.

Why PPAs are becoming more valuable to banks

Historically, banks evaluated PPAs primarily through:

• Counterparty strength
• Contract tenor
• Price stability
• Curtailment exposure
• Balancing risk
• Grid connection reliability
• Settlement structures

Those variables remain critical, but CBAM introduces additional considerations.

Banks increasingly ask:

• Does the PPA help reduce industrial carbon exposure?
• Can the electricity sourcing withstand verification scrutiny?
• Is the supply physically credible?
• Can emissions reductions be documented?
• Does the industrial buyer remain competitive under CBAM?

This changes lender perception of renewable assets.

A wind or solar project linked to a strong industrial exporter with CBAM-sensitive operations may achieve superior financing conditions because the offtake relationship becomes strategically important for both sides.

Physical PPAs become more important than pure financial structures

CBAM also strengthens the importance of physically connected electricity structures.

European regulators and industrial buyers increasingly focus on:

• Traceable electricity sourcing
• Metering systems
• Physical delivery logic
• Hourly or granular matching
• Grid connection evidence
• Auditable emissions calculations

This means purely synthetic green claims may become less valuable than physically demonstrable renewable supply arrangements.

For SEE markets, this is especially important because the region remains heavily interconnected with coal-based electricity systems.

Industrial exporters in Serbia, Montenegro, Bosnia and neighboring markets increasingly require evidence that renewable electricity is genuinely linked to operations rather than simply purchased through detached certificates.

This favors renewable projects capable of integrating:

• Dedicated industrial offtake
• Private-wire structures
• Industrial parks
• Direct balancing arrangements
• Battery-supported delivery stability

Battery storage changes renewable bankability under CBAM

Battery storage becomes critically important in this environment because CBAM increases the value of operational flexibility.

The old merchant renewable model relied heavily on high capture prices and stable spread economics.

However, from 2026 onward, SEE electricity markets increasingly face:

• Negative prices
• Solar cannibalization
• Volatility spikes
• Congestion
• Cross-border flow instability
• Carbon-adjusted export pressure

This is already visible through SEEPEX negative-price implementation beginning in May 2026.

In that environment, BESS becomes more than an arbitrage tool.

Storage helps renewable assets provide:

• Stable industrial delivery
• Peak-hour optimization
• Carbon-efficient balancing
• Curtailment reduction
• Intraday flexibility
• Grid-support services
• Improved renewable capture pricing

For banks, hybrid wind-solar-BESS projects increasingly appear structurally stronger than standalone intermittent generation because they improve operational predictability.

CBAM quietly favors hybrid renewable structures

The market is therefore moving toward hybrid structures where:

• Wind provides higher capacity-factor stability
• Solar provides low daytime marginal cost
• Battery storage manages volatility and delivery quality
• PPAs anchor industrial revenues

This combination increasingly aligns with what lenders seek:

• Long-term contracted cash flow
• Reduced merchant exposure
• Industrial strategic relevance
• Carbon-transition alignment
• Lower curtailment risk
• Improved DSCR stability

In SEE, this trend could become especially powerful because industrial exporters simultaneously need:

• Lower-carbon electricity
• Stable long-term pricing
• Protection from EU carbon costs
• Reliable physical delivery

Banks financing such projects may therefore view CBAM-linked industrial PPAs as quasi-infrastructure relationships rather than simple commercial power contracts.

Wind gains strategic importance in SEE

CBAM may particularly strengthen the strategic position of wind projects across Serbia, Montenegro and the wider Balkans.

Wind offers several advantages in this environment:

• Higher annual capacity factors
• Better winter production correlation
• Reduced daytime solar cannibalization
• Lower seasonal volatility
• Stronger nighttime delivery capability
• Better alignment with industrial baseload demand

When integrated with BESS and industrial PPAs, wind projects may become highly attractive financing candidates for banks seeking resilient low-carbon infrastructure exposure.

Projects such as large-scale Serbian and Montenegrin wind developments therefore increasingly sit at the intersection of:

• Energy transition
• Industrial competitiveness
• CBAM mitigation
• Export resilience
• Grid modernization

CBAM creates a new renewable revenue layer

Perhaps the most important market shift is that renewable electricity increasingly carries hidden strategic value.

The market no longer prices only electricity generation.

It increasingly prices:

• Carbon competitiveness
• Industrial decarbonisation capability
• Verification readiness
• Export resilience
• Supply-chain positioning

A renewable project supporting a CBAM-sensitive industrial exporter may therefore possess stronger long-term economics than merchant pricing alone suggests.

Banks are beginning to recognize this.

The next financing cycle in SEE will likely be CBAM-driven

For South East Europe, this may become one of the largest infrastructure financing trends of the decade.

The region simultaneously faces:

• Coal-heavy electricity systems
• Growing renewable buildout
• EU integration pressure
• Industrial export dependence
• Grid congestion
• Negative price emergence
• Need for storage
• CBAM-adjusted trade exposure

That combination naturally pushes capital toward:

• Wind
• Solar
• Battery storage
• Industrial PPAs
• Grid reinforcement
• Flexible balancing systems

The result is that renewable projects are no longer financed only because they are green.

Increasingly, they are financed because they help preserve industrial competitiveness inside Europe’s carbon-adjusted economic system.

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The first market signal is already visible. Energy Community’s Q1 2026 CBAM monitoring showed that commercial electricity flows between the EU and WB6 contracted by roughly 25% year on year, with traders appearing to prefer routes less exposed to CBAM friction. That means CBAM is not a future theoretical tax; it is already influencing route selection, interconnector utilisation and cross-border optimisation.  

For SEE traders, this creates five structural trends.

First, coal-heavy baseload exports lose optionality. Serbian, Bosnian, Montenegrin and North Macedonian thermal output can still trade regionally, but EU-bound exports face a carbon discount. The old model of exporting surplus lignite generation into higher-priced EU hours becomes weaker because the carbon adjustment eats into the spread. Serbia’s export economics are especially exposed because CBAM arrived at the same time as SEEPEX introduced negative prices from 5 May 2026, with day-ahead prices allowed down to -€500/MWh and intraday prices to -€9,999/MWh.  

Second, hydro, wind and solar gain trading value beyond the energy price. Low-carbon MWh increasingly carry a compliance premium when tied to industrial offtake, CBAM-sensitive exporters, or EU buyers needing cleaner supply chains. This is why Albania’s and Greece’s hydro-linked flows became more relevant in Q1 2026, while alternative corridors outside CBAM friction became more attractive.  

Third, electricity PPAs become CBAM instruments. For industrial exporters in steel, aluminium, fertilizers, cement and processing, a PPA is no longer only a hedge against wholesale prices. It becomes a documentable carbon-risk hedge if backed by metering, physical delivery logic, hourly matching and reliable emissions accounting. This strengthens the bankability of wind, solar, BESS and hybrid projects across Serbia, Montenegro, Bosnia and North Macedonia.

Fourth, domestic carbon pricing becomes a trading variable. Montenegro illustrates the issue clearly. EPCG has warned that CBAM costs could reach about €191 million annually, while reports linked CBAM pressure to around €13 million in Q1 2026 impact. Montenegro’s exposure is concentrated because electricity accounts for a very large share of exports and TE Pljevlja remains central to generation.  

Fifth, negative prices and CBAM together accelerate flexibility economics. Negative prices punish inflexible generation in oversupply hours, while CBAM punishes high-carbon exports in EU-bound hours. Together they increase the value of battery storage, hydro flexibility, demand response, intraday optimisation and balancing services. Traders will increasingly make money from hourly positioning, congestion, imbalance management and carbon-aware routing rather than simple baseload exports.

The strategic market result is clear: SEE power is moving into a two-price world. One price is the visible wholesale price. The second is the embedded carbon value or penalty attached to the MWh. From 2026 onward, traders, utilities and banks that ignore the second price will misread spreads, overvalue coal-backed exports and underestimate the bankability premium of clean, traceable electricity.

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The trial program will run from June to September 2026, while customer registration is open between 7 and 20 May. Participation is limited to the first 5,000 eligible customers. According to the company, households included in the scheme could benefit from approximately 70 hours of zero-cost electricity per month during the four-month pilot period.

The initiative is designed to demonstrate the benefits of integrating renewable energy and digitalized power systems. PPC Energie stated that the project aims to help consumers adjust their usage patterns to periods when solar generation is at its highest, potentially reducing overall electricity costs. Only customers equipped with smart meters connected to the company’s digital metering infrastructure will be eligible. Participants will receive advance notifications about free electricity intervals via email and through the myPPC mobile application, at least 12 hours before each time window begins.

The supplier emphasized that the pilot does not change existing electricity contracts, tariff structures, or supply conditions. Instead, customers will receive a commercial bonus on their monthly bills corresponding to electricity consumed during designated free periods.

The system automatically calculates the discount based on meter data transmitted by regional distribution operators. PPC Energie noted that the program could encourage households to run energy-intensive appliances or charge electric vehicles during hours of high solar output.

According to Ionuț Duna, General Manager of PPC Energie, the initiative is intended to familiarize customers with the advantages of solar generation and highlight the growing importance of smart energy infrastructure in optimizing electricity demand.

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The lowest average monthly consumption was recorded in the municipality of Žabljak, at €20.2, while the highest was in Kotor, where the average bill reached €37.3.

Around 63.47% of households will pay less than €30 for electricity consumed in April, while 18.13% will pay between €30 and €50, 14.44% between €50 and €100, and 3.97% of customers will receive bills exceeding €100.

A total of 163,271 regularly paying customers were granted discounts, representing approximately 39.5% of all electricity consumers in Montenegro.

Montenegro’s power utility EPCG also reported that households consumed 112.5 million kWh in April 2026, which is 4.29% lower compared to April 2025 and 20.54% lower than in the previous month.

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