Monthly trading volumes also strengthened compared with the previous month, rising by 9.6%. The average daily traded volume during June reached 4,572.4 MWh, indicating stronger participation and increased liquidity on the country’s organised electricity market.

The average market-clearing price in June 2026 stood at €93.74/MWh, which was 4.5% higher than in May. The increase reflects broader regional market conditions, with Southeast European electricity prices remaining supported by fuel costs, renewable generation variability and cross-border supply dynamics.

The North Macedonian power exchange recorded a peak price of €60.1/MWh during the month. The development of the local day-ahead market continues to improve price transparency and provide market participants with a more structured platform for electricity trading.

North Macedonia’s electricity exchange was established in May 2023 and has gradually increased its role in the regional power market by supporting greater liquidity, competition and integration with neighbouring electricity markets.

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The solar project is located in Vathylakos, near Thessaloniki, and consists of a fully developed, ready-to-operate photovoltaic plant. Claritas managed the complete project development process, including site acquisition, regulatory approvals, project preparation and the final steps required to bring the facility into commercial operation before transferring ownership to Green Line Energy.

Claritas Investments specialises in the early-stage development of renewable energy projects, while also maintaining activities in technology and electromobility sectors. The company’s main markets include Greece, Romania and Poland, although it continues to evaluate new investment and acquisition opportunities across Europe.

The company is currently advancing a significant renewable energy pipeline in Greece. According to Claritas, its portfolio includes two large-scale solar projects in the Kilkis region of Central Macedonia, with a combined planned capacity of 574 MW. The proceeds from the Vathylakos solar project sale will be directed toward accelerating the development of these larger photovoltaic investments.

The transaction reflects a broader trend in the renewable energy sector, where developers are increasingly monetising smaller operational assets to strengthen their financial capacity and concentrate resources on larger projects with greater strategic importance. For Claritas, the divestment represents a step toward expanding its role in Greece’s utility-scale renewable energy market.

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Between January and June 2026, total natural gas demand reached 43.09 TWh, representing a 15.06% year-on-year increase compared with 37.45 TWh during the same period in 2025. The main contributor to this growth was external demand, as gas exports increased sharply to 8.72 TWh from 2.86 TWh a year earlier. The rise confirms Greece’s growing importance in supplying neighbouring markets through regional interconnections.

Domestic gas consumption remained broadly stable during the period. Gas demand within Greece declined slightly by 0.64% to 34.37 TWh, compared with 34.59 TWh in the first half of 2025. According to DESFA, lower consumption from electricity producers was largely balanced by stronger demand from industrial users, compressed natural gas (CNG) applications and distribution networks. At the same time, gas imports followed the overall market expansion, rising 14.76% year on year to 43.07 TWh.

The Revythoussa LNG terminal continued to be Greece’s leading import gateway, receiving 18.61 TWh of gas, or approximately 43% of total imports. LNG deliveries through the terminal increased by more than 25% compared with the first half of 2025, reinforcing the importance of LNG in Greece’s supply strategy. The Sidirokastro entry point ranked second with 15.47 TWh, followed by Nea Mesimvria with 5.53 TWh. Imports through the Alexandroupoli floating LNG terminal also recorded strong growth, reaching 3.46 TWh, more than three times higher than the previous year.

Electricity generation remained the largest source of domestic gas demand, despite a moderate decline compared with 2025. Gas-fired power producers consumed 22.41 TWh, down from 23.25 TWh in the first half of the previous year, accounting for around 65% of total domestic gas consumption. Meanwhile, distribution networks increased consumption to 8.08 TWh from 7.69 TWh, while industrial users and the CNG sector together raised demand to 3.88 TWh from 3.65 TWh.

The United States remained Greece’s largest LNG supplier during the first half of 2026. US LNG cargoes reached 12.67 TWh, representing around 70% of LNG volumes delivered through Revythoussa. Nigeria supplied 4.16 TWh, while additional LNG volumes arrived from Egypt, Algeria and Mauritania. Overall, 24 LNG shipments delivered 18.18 TWh of gas during the period, compared with 27 cargoes supplying 14.66 TWh in the same period of 2025.

Greece’s LNG infrastructure continued to expand beyond pipeline and terminal activity. DESFA reported further growth in LNG truck-loading operations, with the number of supplied trucks increasing to 537 during the six-month period, compared with 273 a year earlier. Traded LNG volumes doubled to 24,641 cubic metres, while the equivalent energy volume increased from around 0.08 TWh to 0.16 TWh, representing growth of more than 100% year on year.

The first-half 2026 data shows that Greece is becoming increasingly important within the Southeast European gas market. Stronger LNG inflows, rising exports and expanding infrastructure are strengthening the country’s position as a regional energy corridor, while supporting greater flexibility and security of supply across neighbouring markets.

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The regional price cluster was clearly visible across the main day-ahead exchanges. HUPX Hungary settled at €123.62/MWh, down €4.5/MWh compared with the previous day, but the decline was limited despite the sharp reduction in regional import requirements. Romania’s OPCOM closed at €119.97/MWh, Bulgaria’s IBEX at €119.92/MWh, Greece’s HENEX at €120.01/MWh, Croatia at €121.23/MWh, and Slovenia at €122.50/MWh. Together, these markets formed a narrow €120–123/MWh regional price band, reflecting stronger alignment between interconnected SEE markets.

The main price exceptions were Serbia, North Macedonia and Italy. Serbia’s SEEPEX average price was €107.23/MWh, creating a discount of €16.40/MWh compared with HUPX, while North Macedonia recorded the lowest regional price at €103.05/MWh. At the opposite end of the market, Italy remained the regional price leader at €153.73/MWh, maintaining a premium of more than €30/MWh over Hungary. The continued Italian premium remained an important driver of cross-border trading opportunities.

Regional supply-demand conditions improved during the session. Total SEE plus Hungary electricity consumption declined to 31,575 MW, a decrease of 920 MW day on day, while regional net imports dropped to 907 MW, down by 1,639 MW. Imports from the Core European region through Austria and Slovakia also declined sharply to 1,865 MW, a reduction of 1,689 MW. As a result, the traditional advantage of cheaper Core-area electricity for Hungary and SEE weakened. Germany’s price increase to €124.21/MWh brought HUPX almost level with the German market, forcing SEE prices to increasingly reflect regional generation conditions rather than external imports.

Despite lower demand, the generation mix remained supportive of higher prices. Solar production declined by 760 MW to 6,236 MW, while wind generation also decreased to 1,141 MW. Hydro generation improved by 279 MW to 5,362 MW, but this was not enough to offset weaker renewable output. At the same time, coal generation increased by 294 MW to 6,514 MW, while gas-fired generation rose by 236 MW to 4,546 MW. The key market driver was therefore the shift toward more expensive thermal generation as renewable availability weakened.

Intraday price patterns remained strongly shaped by renewable production cycles. HUPX recorded a low of €36.70/MWh during H15, while the evening peak reached €206.10/MWh at H22. Similar solar-driven patterns appeared across Germany, Romania, Bulgaria, Greece, Croatia and Slovenia, with lower prices during midday hours and significant evening ramps. Serbia showed the strongest evening volatility: although its daily average remained relatively low, the market reached €227/MWh at H22, the highest evening spike among the analysed SEE markets.

Italy continued to act as the region’s main price anchor. The Italian national average reached €153.73/MWh, with even the daily minimum remaining high at €136/MWh. This indicates that Italy’s premium was not limited only to evening scarcity but was present throughout much of the trading day. The persistent spread supported the commercial importance of southbound and westbound electricity flows. Montenegro remained a strategically important transit market, with net imports of 113 MW while maintaining average Montenegro-to-Italy flows of 397 MW, increasing to 507 MW during peak hours.

Bulgaria continued to play a stabilising role in the regional market, recording net exports of 1,235 MW. Bulgarian generation reached 4,983 MW, compared with consumption of 3,749 MW, supported by nuclear, coal and solar output. Electricity exports from Bulgaria flowed toward Romania, Serbia, North Macedonia and Greece, helping keep regional prices aligned around the €120/MWh level.

Serbia remained structurally short despite its lower average price. Consumption stood at 3,441 MW, while domestic generation reached 2,975 MW, leaving the country with 466 MW of net imports. Peak imports reached 777 MW, highlighting continued dependence on regional support during tighter hours. The gap between Serbia’s lower daily average and its €227/MWh evening peak shows that the market was not experiencing constant scarcity, but remained vulnerable during periods of reduced solar generation and limited cross-border flexibility.

Hungary also remained dependent on imports, although its balance improved compared with previous sessions. Consumption fell to 4,298 MW, generation reached 3,636 MW, and net imports stood at 662 MW. The Hungarian market displayed a shaped trading profile, with imports during lower-priced hours and stronger commercial positioning during peak periods when regional spreads widened.

Romania moved closer to balance, with consumption at 5,755 MW, generation at 5,481 MW and net imports of 274 MW. Its diverse generation mix, including hydro, nuclear, gas and coal, helped keep prices aligned with the wider SEE cluster. OPCOM’s settlement at €119.97/MWh confirmed that Romania was trading within the regional band rather than establishing a separate premium.

Greece remained almost fully balanced, with consumption of 7,122 MW, generation of 7,093 MW and only 29 MW of net imports. Although gas continued to play an important role in the Greek generation mix, strong renewable availability prevented a larger price divergence. HENEX settled almost exactly alongside Romania and Bulgaria, confirming Greece’s integration into the wider SEE price structure.

Forward markets indicated a more cautious outlook than the spot market. CEGH gas futures increased to €50.03/MWh, while Greek gas rose to €45.01/MWh. Coal prices also strengthened, while EU carbon allowances declined slightly to €79.04/t, not enough to offset fuel-driven support. Hungarian power forwards remained elevated, with Week 29 contracts at €133.50/MWh, Week 30 at €130/MWh, and the 2026 average at €131.50/MWh, suggesting traders continue to price a firm medium-term market environment.

The overall market assessment is that Southeast Europe has moved from a period of extreme heat-driven tightness into a more spread-driven and fuel-sensitive market structure. Lower demand reduced immediate pressure, but weaker solar generation, softer wind output and stronger thermal requirements kept prices supported. The key factor for upcoming sessions will be whether German prices remain elevated. A return of cheaper Core European imports could push HUPX and the eastern SEE markets lower, while continued German strength and Italy’s persistent premium could keep regional prices anchored near €120/MWh despite softer demand.

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The scale of import reliance was significant across several Southeast European markets. Italy recorded 3,706.01 GWh of net imports, followed by Hungary with 1,076.31 GWh, Croatia with 583.90 GWh, Romania with 440.59 GWh and Serbia with 422.97 GWh. These volumes represent more than temporary adjustments and increasingly influence market exposure. In Croatia, net imports accounted for 43.78% of the electricity mix, while Hungary relied on imports for 29.97% and Italy for 17.97%. For large industrial consumers, this creates greater exposure to regional supply conditions, cross-border transmission constraints and neighbouring market price movements.

The growing importance of imports is also changing the way companies approach electricity contracts. Traditional fixed-price agreements may not fully capture the risks associated with suppliers that depend heavily on imported power, volatile day-ahead markets, congestion costs or gas-driven marginal pricing. Industrial buyers are increasingly looking for more transparent and flexible procurement structures that include clear information on supply origin, price exposure, balancing responsibilities, renewable content and carbon attributes.

This development is particularly important for CBAM-exposed industries and companies supplying European markets. Electricity consumption in manufacturing processes is becoming an increasingly important part of customer due diligence, carbon reporting and future competitiveness strategies. Export-oriented companies will require electricity contracts that are not only cost-effective but also traceable, verifiable and financially reliable. Renewable power purchase agreements (PPAs) will need strong metering systems, delivery verification and credible documentation to meet growing expectations from customers, investors and financial institutions.

May’s market data demonstrates why import dependence is becoming a central market theme. Electricity prices remained elevated across several import-reliant countries, with Italy averaging €119.35/MWh, Romania €109.56/MWh, Hungary €106.51/MWh, Croatia €103.58/MWh and Serbia €96.63/MWh. Although imports were not always the only reason for higher prices, they increased exposure to regional volatility and external market conditions.

According to Electricity.Trade, electricity import dependence should increasingly be viewed as a commercial and industrial risk factor rather than only a trading statistic. As Southeast Europe’s power markets become more interconnected, energy-intensive companies will need procurement strategies that combine price hedging, renewable sourcing, cross-border risk management and CBAM-ready documentation. The region is moving away from simple electricity purchasing toward a new model of verified, transparent and strategically managed electricity procurement.

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One of the strongest signals came from SEEPEX, where traded electricity volumes in Serbia reached 566.3 GWh in May, representing a 16.99% increase from April and a 13.31% rise compared with the same month last year. The growth in exchange activity coincided with Serbia becoming a net electricity importer of 422.97 GWh and average day-ahead prices increasing to €96.63/MWh. The combination of tighter domestic supply and rising trading volumes suggests that market participants are relying more heavily on the exchange to manage price risk and secure supply, rather than depending solely on bilateral contracts or balancing mechanisms.

Trading activity also increased across several other major regional exchanges. Hungary’s HUPX recorded a 6.35% month-on-month increase in traded volume to 2,591.57 GWh, while Italy’s IPEX rose 4.54% to 22,994.12 GWh. Bulgaria’s IBEX posted a 3.51% increase to 2,675.87 GWh, and Greece’s HENEX recorded a more modest 1.60% rise to 3,878.31 GWh. Although these markets play different roles within the regional power system, they all experienced stronger exchange activity during a period of elevated electricity prices and changing cross-border power flows.

Romania and Croatia stood out as exceptions to the broader regional trend. Romania’s OPCOM exchange recorded a 2.48% decline in traded volumes to 1,111.15 GWh, while Croatia’s CROPEX fell 3.97% to 877.24 GWh. Despite lower trading activity, both countries experienced significant increases in wholesale electricity prices, with Romania averaging €109.56/MWh and Croatia €103.58/MWh. These contrasting developments highlight that liquidity growth remains uneven across Southeast Europe, even as price volatility becomes more widespread.

For electricity market participants, exchange liquidity has become a strategic factor rather than simply a trading statistic. Higher liquidity improves hedging opportunities, enhances price transparency, supports more efficient bid-ask spreads and facilitates the development of power purchase agreements (PPAs) and other long-term supply contracts based on reliable market benchmarks. As Southeast European electricity systems become increasingly influenced by renewable generation, cross-border electricity trade and gas-driven marginal pricing, liquid power exchanges are evolving into essential components of regional market infrastructure.

According to Electricity.Trade, May demonstrated that market volatility and exchange liquidity are becoming increasingly interconnected, although progress remains uneven across the region. Serbia, Hungary, Italy, Bulgaria and Greece recorded stronger day-ahead trading activity, while Romania and Croatia highlighted the continuing differences in market depth. The broader trend suggests that Southeast Europe’s electricity markets are becoming more transparent and tradable, but they remain fragmented, creating both new opportunities and additional risks for utilities, traders, industrial consumers and financial market participants.

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Among the region’s largest markets, Serbia recorded one of the strongest month-on-month increases in electricity demand at 4.26%, followed by Italy with 3.29% and Greece with 2.44%. Higher consumption supported elevated electricity prices in these markets, with Serbia’s average wholesale price reaching €96.63/MWh, Italy remaining the region’s highest-priced market at €119.35/MWh, and Greece averaging €88.98/MWh despite strong renewable and hydroelectric generation. In Serbia, rising demand coincided with weaker hydro production and net electricity imports of 422.97 GWh, further tightening market conditions.

In contrast, several other Southeast European markets recorded lower electricity demand while still experiencing higher wholesale prices. Electricity consumption declined by 9.66% in Bulgaria, 7.51% in Hungary, 5.09% in Türkiye, 4.24% in Croatia, and 3.59% in Romania. Nevertheless, Bulgaria’s average electricity price increased 11.08%, Hungary’s rose 10.31%, Croatia recorded a 14.55% increase, and Romania posted the largest rise at 14.66%. Türkiye was the notable exception, with average electricity prices falling to €11.17/MWh as weaker demand coincided with abundant hydro generation and a markedly different market environment.

The May results demonstrate that electricity price formation across Southeast Europe is becoming increasingly regional rather than being determined solely by domestic demand. Markets with declining electricity consumption can still experience higher prices when they depend on imports, remain exposed to natural gas as the marginal fuel, face weaker hydro generation or are closely interconnected with higher-priced neighbouring markets. Croatia illustrates this trend, with lower demand accompanied by net electricity imports of 583.90 GWh and a sharp increase in wholesale prices. Romania experienced a similar situation, where falling demand coincided with a 77.31% decline in nuclear generation, higher gas-fired output and continued reliance on electricity imports.

According to Electricity.Trade, the key lesson from May is that electricity demand must be analysed together with the region’s evolving supply structure. While changes in consumption remain an important market indicator, they no longer consistently determine wholesale price movements. Instead, prices increasingly reflect the combined influence of electricity demand, renewable generation, hydrological conditions, import dependency, cross-border power flows and natural gas prices. As a result, accurate forecasting in Southeast Europe increasingly depends on integrated market models that simultaneously assess electricity load, generation mix, fuel costs and transmission constraints.

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Gas prices continued to play a key role in electricity pricing across several Southeast European markets where gas-fired generation remains an important part of the power mix. Italy relied on natural gas for 34.07% of its electricity generation, making it the region’s most gas-dependent major market and reinforcing its position as the highest-priced electricity market. Greece generated 28.11% of its electricity from gas, while Romania’s gas share reached 11.91%, with gas-fired generation increasing 35.23% compared with April. As a result, elevated gas prices continued to support wholesale electricity prices even as renewable generation expanded across the region.

The gas market in May was shaped by a combination of supply risks and improving LNG availability. According to the report, geopolitical tensions in the Middle East, the need to replenish European gas storage ahead of winter, steady structural demand and weather-related uncertainty all provided upward support for prices. At the same time, strong liquefied natural gas (LNG) imports prevented a more significant price increase. New LNG supplies from producers outside the Gulf region expanded by around 20% year on year, adding nearly 8 bcm of supply and offsetting approximately 90% of the disruption caused by lower Gulf LNG exports.

For electricity traders across Southeast Europe, these conditions created a market in which gas prices remained sufficiently elevated to keep the cost of thermal power generation high, without triggering another energy crisis. This pricing environment helped explain why wholesale electricity prices remained elevated despite stronger renewable output. During May, Italy recorded an average electricity price of €119.35/MWh, Romania reached €109.56/MWh, Hungary averaged €106.51/MWh, while Croatia recorded €103.58/MWh.

The moderation in gas prices during the second half of the month also carried important market implications. Although robust LNG inflows helped ease supply concerns, Europe did not return to a low-cost natural gas environment. According to Electricity.Trade, May demonstrated that natural gas no longer needs to experience dramatic price spikes to shape electricity markets. Instead, relatively stable but elevated gas prices continue to provide a firm price floor for wholesale electricity across Southeast Europe, influencing hedging strategies, power purchase agreement (PPA) pricing, industrial energy procurement and the economics of battery storage and energy arbitrage.

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Hydro generation increased substantially in several markets during May. Greece recorded the strongest month-on-month growth, with hydro output rising 40.80%, followed by Italy with a 12.45% increase and Bulgaria with a 7.30% gain. Improved hydro availability strengthened domestic supply, reduced dependence on thermal generation and supported cross-border electricity exports. Greece emerged as a major net exporter with 874.20 GWh of net exports, while Bulgaria exported 258.65 GWh. Italy remained a net importer, but its electricity imports declined 16.41% to 3,706.01 GWh, supported by stronger hydro and renewable generation.

In contrast, hydro production weakened across several other Southeast European markets. Serbia recorded the sharpest decline, with hydro output falling 31.68%, followed by Hungary at 29.10%, Croatia at 21.17% and Romania at 6.96%. The reduction in hydro generation translated directly into higher import needs. Serbia imported 422.97 GWh of electricity during the month, Croatia’s net imports climbed to 583.90 GWh, Hungary remained heavily dependent on imports with 1,076.31 GWh, while Romania recorded 440.59 GWh of net imports.

Hydropower remains one of the region’s most valuable resources because it provides both electricity generation and system flexibility. Strong hydro output helps reduce reliance on fossil-fuel generation, supports electricity exports and enables power systems to respond efficiently to fluctuations in demand and renewable generation. As solar and wind capacity continues to expand across Southeast Europe, the balancing role of hydroelectric plants becomes increasingly important in maintaining grid stability.

Serbia provides a clear example of this dynamic. Although coal and lignite still accounted for 56.99% of the country’s electricity generation mix in May, weaker hydro production combined with higher electricity demand increased the need for imports. Croatia faced a different challenge, with net imports representing 43.78% of its electricity mix while hydro accounted for 22.83% of generation. The decline in hydro output further increased the country’s reliance on neighbouring electricity markets.

According to Electricity.Trade, the hydrological trends observed in May underline an important structural characteristic of the Southeast European power market. The region is made up of interconnected river basins with highly variable monthly hydrological conditions, meaning changes in water availability can rapidly alter electricity trade flows, price differentials and import requirements. As renewable generation continues to expand, hydro variability is expected to remain one of the most significant drivers of regional electricity market risk and wholesale price dynamics.

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Renewable generation posted solid gains in nearly every analysed market. Bulgaria recorded the largest month-on-month increase at 34.19%, followed by Romania with 26.57%, Greece at 15.88%, Hungary at 9.56%, Italy at 9.22%, Serbia at 2.90%, and Croatia at 0.13%. Türkiye was the only market where renewable output declined, falling 6.70%. Despite this overall expansion in renewable generation, electricity prices moved higher across most interconnected Southeast European markets.

Romania’s average day-ahead electricity price climbed 14.66% to €109.56/MWh, while Croatia recorded a 14.55% increase to €103.58/MWh. Bulgaria’s average price rose 11.08% to €101.07/MWh, Hungary increased 10.31% to €106.51/MWh, and Serbia advanced 5.59% to €96.63/MWh. Greece remained the lowest-priced interconnected European market in the region, although its average still edged up to €88.98/MWh. Italy continued to record the highest average electricity price at €119.35/MWh, remaining broadly stable compared with April but significantly above the level seen a year earlier.

The increase in prices reflects a combination of factors extending beyond renewable generation. While higher wind and solar output can depress prices during periods of strong production, particularly around midday, dispatchable generation remains essential during evening demand peaks and periods of weaker renewable output. In May, hydroelectric generation delivered mixed results, natural gas prices remained sufficiently elevated to continue setting marginal electricity prices, and several markets maintained heavy reliance on imported electricity. Croatia sourced 43.78% of its electricity from net imports, Hungary nearly 29.97%, while imports accounted for 17.97% of Italy’s electricity supply.

According to Electricity.Trade, May’s market performance demonstrates that renewable capacity alone is no longer the decisive factor shaping monthly electricity prices. The effectiveness of renewable energy increasingly depends on the availability of system flexibility, including battery storage, hydroelectric resources, demand response, stronger cross-border interconnections and commercial power purchase agreements (PPAs). As Southeast Europe’s electricity market continues to evolve, these balancing mechanisms are expected to play a much greater role in transforming growing renewable generation into sustained reductions in wholesale electricity prices.

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Crude oil prices recovered modestly toward the end of the week, with the Brent front-month contract closing at $72.12/bbl on Friday, 3 July. The settlement price was almost unchanged from the previous Friday, increasing by only 0.2%, indicating continued stability in the oil market despite ongoing uncertainty.

The relatively stable performance of Brent futures reflected improving conditions around the Strait of Hormuz, where shipping activity continued to normalise after earlier disruptions. At the same time, progress in discussions between the United States and Iran contributed to expectations of lower geopolitical risk, reducing the additional risk premium that had supported oil prices in previous weeks.

Meanwhile, European natural gas markets followed a different trend, with TTF futures moving higher throughout the first week of July. Front-month TTF gas contracts traded on the ICE market increased from €42.57/MWh on Monday, 29 June, reaching a weekly peak of €45.22/MWh on Friday, 3 July. Based on AleaSoft Energy Forecasting’s data analysis, the final settlement was 11% above the previous Friday’s level.

The increase in TTF gas prices was mainly linked to seasonal storage requirements ahead of the winter period. European market participants continued to focus on rebuilding gas inventories, while stronger demand from the power sector in some countries provided additional support. High temperatures combined with lower solar photovoltaic generation increased the need for gas-fired electricity production.

European carbon allowance prices also moved higher during the week, with December 2026 EUA futures traded on the EEX market reaching a weekly low of €78.79/t on Monday, 29 June. After exceeding €80/t during the final session of June, carbon prices remained close to €79.50/t during the first two trading days of July.

By Friday, 3 July, EUA futures reached a weekly maximum of €80.59/t, representing a 0.4% increase compared with the previous Friday. The recovery in carbon prices followed the strengthening trend in TTF gas futures, once again highlighting the close relationship between European gas prices and emissions allowance markets.

Overall, early July energy commodity markets showed a clear split between stable crude oil prices and rising European gas and carbon markets. Reduced geopolitical pressure limited oil price movements, while gas storage needs and electricity sector demand supported higher TTF prices. The increase in gas prices also contributed to stronger EUA values, reinforcing the connection between European energy and carbon markets, AleaSoft reports.

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The French electricity market registered the largest weekly price decline, with average prices dropping by 32%. Spain and Portugal followed with decreases of around 28%, while Germany, Belgium, the Nordic market and the Netherlands recorded declines between 21% and 24%. The British market saw prices fall by approximately 20%, whereas Italy experienced the smallest decline, with prices decreasing by 6.8%, reflecting greater price stability compared with other European markets.

Italy remained the highest-priced electricity market in Europe during the first week of July, despite the weekly correction, with an average price of €134.85/MWh. At the opposite end, the Nordic market recorded the lowest weekly average at €52.91/MWh. Spain and Portugal maintained relatively low price levels, averaging €63.20/MWh and €63.21/MWh, respectively, while prices across the other analysed markets ranged from €78.60/MWh in France to €112.08/MWh in Belgium.

Daily price movements showed continued volatility across European electricity markets during the first week of July. France, Spain, Portugal and the Nordic market recorded daily prices below €50/MWh in several trading sessions. The lowest daily average of the week was registered in the Nordic market on Sunday, 5 July, when prices dropped to €26.95/MWh.

Despite the broader downward trend, several markets experienced periods of elevated prices, especially at the beginning of the week. Daily prices exceeded €100/MWh in most analysed markets, although Spain, Portugal and the Nordic region remained below this level. The most significant price surge occurred on Tuesday, 30 June, when the Belgian and Dutch markets exceeded €200/MWh, with Belgium reaching the week’s highest daily average at €210.96/MWh.

The main factors behind the price decline were reduced electricity demand after the heatwave and stronger wind generation across Europe. Increased wind output improved renewable electricity availability and lowered dependence on more expensive thermal generation. However, weaker solar photovoltaic production in Germany, France, Spain and Italy limited the downward pressure on prices, preventing a stronger correction in some markets.

Italy and Belgium remained among Europe’s most expensive electricity markets, even after the weekly decline, while the Nordic market continued to record the lowest prices due to its traditional market structure and strong hydroelectric generation base. The differences between regional price levels reflected variations in generation mixes, renewable availability and cross-border market conditions.

According to AleaSoft Energy Forecasting, electricity prices are expected to increase in most European markets during the second week of July. The expected rise is linked to higher electricity demand and lower wind generation forecasts, while natural gas price developments will continue to influence wholesale electricity market trends across Europe, AleaSoft reports.

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Portugal remained the exception to the broader European downward trend, as electricity demand increased by 7.0% week on week. The Portuguese market continued its upward trajectory, marking the fourth consecutive week of demand growth, driven by persistently warm weather conditions and higher consumption needs.

Temperature patterns played a key role in shaping electricity demand across Europe. Belgium experienced the strongest cooling effect, with average temperatures falling by 8.1°C during the week. France followed with a 6.1°C decrease, while Germany and Great Britain recorded declines of 5.9°C and 5.2°C, respectively. Temperature reductions were more limited in Italy and Spain, where averages dropped by 0.9°C and 0.3°C. Meanwhile, Portugal recorded the only increase in average temperatures, rising by 1.6°C compared with the previous week.

The cooler weather contributed to lower electricity consumption in most European markets, reversing the demand pressure created by earlier heatwave conditions. During the second half of June, high temperatures affected France, Italy, Belgium and Germany, while Great Britain experienced a significant heat event between 24 and 28 June. As temperatures moderated during the week of June 29, cooling demand declined, leading to lower overall electricity consumption.

Portugal developed a different market dynamic, with warmer conditions supporting increased electricity usage. The country’s higher temperatures helped sustain demand growth, contrasting with the declining consumption trend observed across most other European electricity markets and demonstrating the continued importance of weather factors in short-term power market movements.

According to AleaSoft Energy Forecasting, electricity demand during the second week of July is expected to increase in Great Britain, France, Belgium and Spain. In contrast, consumption is forecast to decline in Portugal, Germany and Italy, reflecting changing weather conditions and evolving electricity demand patterns across European markets, AleaSoft reports.

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Germany recorded the largest reduction in solar photovoltaic generation, with output falling by 24% week on week. France followed with a 9.8% decline, while Italy registered the smallest decrease at 1.1%, marking its second consecutive week of lower solar production. Despite the weekly declines, several markets achieved notable milestones, highlighting the continued expansion of solar generation capacity across Europe.

Portugal and Italy reached new solar photovoltaic production records during the period. Portugal achieved an all-time daily record on 30 June, producing 35 GWh of solar electricity. Italy reached its highest-ever solar output on 4 July, with production reaching 164 GWh. Spain also recorded a significant milestone, achieving its highest solar photovoltaic generation for a July day on 5 July, with output reaching 249 GWh.

For the week beginning 6 July, forecasts from AleaSoft Energy Forecasting indicated that solar generation is expected to increase in Italy and Germany, while Spain is forecast to experience a decline in photovoltaic production.

Wind power generation increased across all major European electricity markets during the same period, reversing the mixed trends seen in previous weeks. Germany recorded the strongest growth, with wind generation surging by 156% compared with the previous week. France registered the smallest increase at 9.1%, while Portugal, Spain and Italy recorded significant rises of 62%, 70% and 122%, respectively.

The growth in wind generation reflected improved weather conditions across several markets. France, Portugal and Spain continued their upward trend for the second consecutive week, while Germany and Italy recovered after experiencing declines during the previous two weeks.

Spain and Portugal achieved new July wind generation records on 2 July. Spain produced 252 GWh of wind electricity, marking its highest daily output for a July day in the last four years. Portugal reached 66 GWh, its strongest July daily wind generation level in the last five years.

Looking ahead to the week of 6 July, AleaSoft Energy Forecasting’s wind energy projections point to further growth in the German electricity market, while declines are expected in France, Italy and the Iberian Peninsula. The latest trends highlight the increasing influence of renewable generation variability on European electricity markets, with solar and wind output continuing to shape price dynamics and trading opportunities across the region, AleaSoft reports.

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Despite higher prices, trading activity on the day-ahead market declined. Total traded volume in June 2026 amounted to 0.89 million MWh, which was 20.05% lower than in May and 23.38% below the level recorded in June 2025. The average traded volume during the month stood at 1,233.8 MWh per hour, indicating reduced market participation compared with previous periods.

The total value of transactions on the OPCOM day-ahead market reached €117.7 million in June 2026. This was 11.56% higher than in June 2025, when transaction value amounted to €105.5 million, but represented a 2.19% decline compared with May’s €120.3 million. The increase compared with the previous year was primarily driven by significantly higher electricity prices despite lower traded volumes.

The day-ahead market accounted for 26.71% of Romania’s forecasted net electricity consumption in June 2026, confirming its continued importance as a key platform for wholesale electricity trading and price formation in the country.

Activity on the intraday market also decreased during the month. Total traded volume reached 117,391.6 MWh, representing a 41.3% decline compared with June 2025 and a 13.43% decrease compared with May 2026. The reduction in intraday activity reflects weaker short-term trading volumes despite the continued need for market participants to manage renewable generation variability, demand changes and balancing requirements.

The June results show that Romania’s electricity market faced a combination of higher prices and lower liquidity, with increased wholesale costs supported by regional market conditions while trading volumes weakened. Nevertheless, OPCOM continued to play a central role in Romania’s electricity market by providing a key reference point for day-ahead and intraday price formation in Southeast Europe.

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The average HUPX day-ahead peak price increased even more significantly, reaching €90.2/MWh in June, which was 45.1% higher than in the previous month. The stronger peak-hour pricing indicates increased value during periods of higher demand and tighter supply conditions.

Despite higher prices, trading activity on the HUPX day-ahead market declined. Total traded volume reached 2.38 million MWh in June 2026, down 8.1% compared with May’s 2.59 million MWh and 16.2% lower than the 2.84 million MWh recorded in June 2025. The decline in volumes suggests that market participants were more selective despite the elevated price environment.

Activity on the intraday continuous market moved in the opposite direction, with traded volume increasing to 1,143,415 MWh in June 2026, representing an 11.2% rise compared with the previous month. The growth highlights the increasing importance of short-term trading flexibility as market participants respond more actively to hourly changes in renewable generation, demand patterns and cross-border conditions.

The number of market participants on HUPX continued to expand. In June 2026, the day-ahead market had 130 registered members, six more than in May, while the intraday continuous market counted 125 registered members.

The June results confirm HUPX’s continued importance as a key regional electricity trading platform. Higher prices, stronger peak-hour volatility, growing intraday activity and an expanding participant base underline Hungary’s role as an important hub connecting Central European and Southeast European power markets.

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The decision secures access to the high-voltage electricity network for future offshore wind projects and confirms the marine areas that will be included in the initial rollout. The reserved grid capacity will be allocated exclusively to offshore wind developments, providing the necessary infrastructure support for Greece’s planned expansion of renewable energy generation.

Although the government’s first offshore wind phase targets around 1.9 GW of installed capacity, additional transmission capacity has been reserved to provide flexibility during project implementation. The additional margin will allow developers to adjust project designs, modify technical solutions or accommodate changes that may emerge during the development process.

The largest share of the reserved capacity, 600 MW, has been allocated to pilot offshore wind projects near Alexandroupoli, which are being developed by PPC, TERNA Energy and Motor Oil. The remaining capacity will be made available through future competitive tenders covering six offshore wind zones, including areas south of Rhodes, Agioi Apostoloi off Evia, Zakros in Crete, Donousa, Gyaros and the Gulf of Patras. The Gulf of Patras zone replaces the previously planned offshore wind area near Elounda in Crete.

The latest decision follows the establishment of a special purpose vehicle by the Hellenic Hydrocarbons and Energy Resources Management Company (EDEYEP), which will oversee offshore and seabed surveys required before concession tenders can begin. The company is expected to bring additional partners into the initiative, including electricity transmission system operator ADMIE, financial institutions and representatives from the energy sector.

The start of the offshore survey campaign has been delayed until the autumn as preparations continue. Once the necessary studies are completed and the National Offshore Wind Program receives final approval, Greece is expected to launch its first concession tenders for offshore wind development.

The expansion of offshore wind capacity represents a key element of Greece’s renewable energy strategy, supporting the country’s decarbonisation targets, increasing clean electricity generation and strengthening its role as a regional energy hub in Southeast Europe. The successful implementation of the program could position Greece as one of the leading offshore wind markets in the Eastern Mediterranean.

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Electricity consumption also recorded growth during the period, rising by 6.82% year on year to 21.4 TWh. Despite stronger domestic demand, Bulgaria maintained its position as a net electricity exporter, with net exports reaching 866.6 GWh in the first half of 2026.

The structure of electricity generation continued to shift, with baseload power plants, including coal-fired and nuclear facilities, producing a combined 14.14 TWh of electricity. This represented a 10.6% decline compared with the same period in 2025, reflecting lower output from traditional generation sources.

At the same time, renewable energy sources (RES) continued to gain importance in Bulgaria’s electricity system. RES generation connected to the transmission network increased by 12.89% to 2,216.9 GWh, while renewable production within the distribution network rose by 3.9% to 2,127.3 GWh.

The latest figures highlight the ongoing transformation of Bulgaria’s power sector, with renewable energy playing a larger role in the national generation mix while conventional baseload production gradually declines. Despite higher electricity consumption, the country’s increased generation capacity and growing renewable contribution allowed Bulgaria to preserve a positive export balance and strengthen its role as a regional electricity supplier.

Bulgaria’s 2026 performance reflects the impact of expanding renewable capacity, continued importance of nuclear generation and changing market dynamics across Southeast Europe, where flexible and low-carbon electricity sources are becoming increasingly important for both domestic supply security and cross-border trade.

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The latest auction results represent an important step for the corridor’s development, as they were the first conducted under a revised commercial framework that introduced lower transmission tariffs and additional discounts across selected sections of the route. These changes have improved the competitiveness of gas transportation toward Ukraine, making the corridor the fourth-most cost-effective import route into the Ukrainian market. However, market participants noted that further incentives could still be required to stimulate additional demand and secure wider long-term commitments.

According to Greek gas transmission system operator DESFA, the auction outcome supports Greece’s ambition to become a regional natural gas hub and expand its role in supplying energy markets across Southeast and Eastern Europe. The strongest demand was recorded at the Sidirokastro interconnection point on the Greece-Bulgaria border, which has become a key gateway for northbound gas flows.

Approximately 46% of the available export capacity for the 2026/2027–2029/2030 gas years was booked at Sidirokastro, while around 26% of capacity was reserved for the 2030/2031 gas year. Market participants also secured long-term transport rights extending into future periods, with reservations reaching as far as the 2040/2041 gas year, highlighting expectations of sustained demand for the corridor.

Several major Greek energy companies participated in the capacity allocations. Atlantic SEE LNG Trade, a joint venture between Aktor Group and DEPA Trade, secured around 13,000 MWh per day, equivalent to approximately 4.7 TWh annually. Metlen booked an additional 20,000 MWh per day of capacity. The total export capacity offered at Sidirokastro reached 100 GWh per day, with auction demand broadly matching market expectations.

The strong booking activity reflects the growing interest of Greek energy companies in using LNG supplies from Greece to serve markets in Southeast Europe, Eastern Europe and Ukraine. The corridor is increasingly viewed as an important component of European energy security, diversification of gas supply sources and reduction of dependence on traditional routes.

At the same time, European transmission system operators and the European Commission continue to assess ways to make long-term capacity reservations more flexible. Additional adjustments to market rules could help attract more participants, increase liquidity and unlock further commercial potential along the Greece-Ukraine gas corridor.

The latest auction results confirm that the Vertical Gas Corridor is moving from a strategic concept toward a commercially active energy infrastructure route, strengthening Greece’s position as a gateway for LNG flows and improving supply flexibility for European markets facing ongoing energy security challenges.

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The price increase was driven by a combination of market fundamentals rather than higher temperatures alone. Although the regional average temperature declined by 2.3°C to 20.7°C, forecast electricity demand increased by 768 MW to 32,667 MW, reflecting a return to normal weekday consumption patterns. At the same time, forecast solar generation fell by 807 MW to 5,752 MW, while wind generation improved by 336 MW to 1,517 MW. The reduction in solar output increased reliance on imports and dispatchable generation, particularly during morning and evening hours, reinforcing tighter market conditions across much of Southeast Europe.

Market pricing continued to reflect a pronounced duck-curve pattern. On HUPX, the baseload price settled at €128.17/MWh, while the peak block averaged €102.2/MWh and the off-peak block reached €154.1/MWh. This unusual price structure illustrates how abundant solar generation suppresses daytime prices, while reduced renewable output outside solar hours increases the value of flexible resources such as battery storage, hydropower, gas-fired generation and cross-border electricity trading.

Cross-border flows further highlighted the region’s growing dependence on international electricity markets. Southeast Europe recorded net imports of 2,352 MW, with 3,537 MW imported from the Austria-Slovakia corridor, while simultaneously exporting 1,066 MW to Italy. The Italian market maintained a premium of €18.26/MWh over Hungary, continuing to attract electricity flows despite the region’s reliance on imports from Central Europe. This demonstrates the increasingly important role of transmission capacity and interconnector availability in regional price formation.

Hungary remained the central pricing hub within the region. The country imported 1,277 MW of electricity as domestic generation of 3,383 MW fell short of consumption of 4,660 MW. Supported primarily by Paks nuclear generation, solar production and imports, Hungary continued to influence regional pricing. Although the premium over the German market narrowed, HUPX still traded €29.21/MWh above Germany, preserving the commercial attractiveness of electricity flows from Central Europe.

Serbia stood out as the day’s principal market outlier. While most neighbouring markets experienced strong price increases, SEEPEX declined by €3.9/MWh to €104.08/MWh. Domestic consumption remained stable at 3,560 MW, while generation reached 3,136 MW, leaving Serbia a net importer of 425 MW. Coal-fired generation continued to dominate the supply mix with 2,578 MW, complemented by 693 MW of hydropower, while wind generation remained minimal at only 18 MW. Despite offering the lowest prices in the region, Serbia’s discount did not translate into significantly higher exports because cross-border transmission constraints and commercial flow patterns limited arbitrage opportunities.

Bulgaria maintained its position as the region’s strongest electricity exporter. The country exported 1,303 MW, supported by generation of 5,129 MW against domestic demand of 3,826 MW. Nuclear generation remained the backbone of the system at approximately 1,886 MW, while solar output also made a substantial contribution. As a result, IBEX closed at €117.80/MWh, remaining below Hungarian and Romanian prices despite a strong €14.8/MWh daily increase. Romania, meanwhile, traded almost identically to Hungary at €127.09/MWh while importing 589 MW, with nuclear, hydropower, gas and solar generation all contributing to the supply mix.

Croatia and Slovenia also traded close to Hungarian price levels due to continued import dependence. CROPEX reached €127.08/MWh, with Croatia importing 1,064 MW, while BSP Slovenia settled at €128.40/MWh as Slovenia imported 390 MW. Montenegro also recorded a notable increase, with prices rising to €117.54/MWh, up €23.7/MWh from the previous day. Although Montenegro remained a net importer by 132 MW, it continued to facilitate commercial electricity exports toward Italy through the undersea interconnector, reinforcing its strategic role as a regional transit market.

Forward markets presented a more balanced outlook than the spot market. The HU Week 29 contract declined to €130.50/MWh, down €1.5/MWh on the day and 9.38% over the previous week. In contrast, the HU Q4 Base contract increased to €145/MWh, while the HU Cal-27 contract stood at €114/MWh, indicating that market participants continue to assign a higher risk premium to the winter delivery period despite short-term price volatility. In fuel markets, CEGH natural gas strengthened to €47.39/MWh, while EU Emissions Allowances (EUA) eased to €80.19/t, leaving fuel and carbon costs supportive of wholesale electricity prices without generating additional upward pressure.

Overall, the trading session confirmed that Southeast Europe continues to operate as a collection of interconnected but distinct electricity markets rather than a single uniform region. Italy remained the premium destination for electricity exports, Hungary continued to act as the region’s principal pricing and import hub, Bulgaria strengthened its position as the leading exporter, while Serbia remained the lowest-priced market despite ongoing import dependence. Looking ahead, market direction is likely to depend less on average temperatures and more on hourly renewable generation, cross-border transmission availability, Central European import flows, and whether Serbia’s discounted pricing can translate into stronger regional electricity exports.

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This shift is increasing the importance of battery storage as a trading tool, rather than simply a component of the energy transition. Renewable generation expanded across most Southeast European markets in May, with Bulgaria recording a 34.19% increase, Romania 26.57%, Greece 15.88%, Hungary 9.56%, Italy 9.22%, Serbia 2.90% and Croatia 0.13%. As solar and wind penetration grows, these resources are reshaping intraday market behaviour. Lower-cost renewable electricity is increasingly concentrated in midday hours, while evening periods remain supported by demand peaks, reduced solar availability and the need for flexible generation.

The regional market data also highlights why storage opportunities vary significantly between countries. Greece, with 57.19% renewables in its May electricity mix, became a major electricity exporter as strong renewable and hydro output supported cross-border flows. Bulgaria combined 29.35% renewables with 32.59% nuclear generation, creating a system with both baseload stability and increasing renewable-driven price variation. Serbia remained heavily dependent on coal and lignite, accounting for 56.99% of its generation mix, but weaker hydropower and stronger demand increased reliance on imports. Croatia faced even greater external dependence, with net imports representing 43.78% of its electricity mix. These different market structures create unique trading opportunities based on renewable availability, hydro conditions, import exposure and gas-related marginal pricing.

The natural gas market continues to influence regional electricity spreads. TTF front-month gas futures averaged €47.26/MWh in May and generally traded within the €44–50/MWh range, keeping gas-fired generation costs high enough to support evening electricity prices. Even when renewable generation pushes daytime prices lower, gas-linked marginal costs continue to provide a price floor during periods of tighter supply and higher demand.

Overall, May 2026 marks an important shift in Southeast European power trading strategy. The market opportunity is increasingly moving beyond simple cross-border price differences and toward managing the daily electricity curve. Battery storage, pumped hydro, flexible industrial demand, virtual PPAs and advanced intraday trading strategies are expected to become increasingly valuable as SEE markets integrate more renewable energy while continuing to price scarcity during non-solar hours.

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The key market signal was Croatia’s growing reliance on imported electricity. Net imports reached 583.90 GWh in May, increasing 20.59% from April and representing 43.78% of the country’s electricity mix. Domestic generation consisted of 33.19% renewables, 22.83% hydropower and only 0.19% natural gas, leaving Croatia with limited thermal flexibility. With imports accounting for the largest share of supply, Croatian price formation became increasingly dependent on regional availability, cross-border capacity and neighbouring market conditions.

Croatia’s cross-border flows reflected its strategic position between Central Europe and the Western Balkans. The country imported electricity from Hungary and Slovenia, while exporting to Bosnia and Herzegovina and Serbia. This trading pattern shows Croatia functioning as a link between more liquid Central European markets and Balkan power systems. At the same time, the high level of imports increases exposure to transmission constraints, weather-driven generation changes and the availability of surplus electricity in neighbouring countries.

Hydropower conditions added further pressure to the Croatian market in May. Hydro generation declined by 21.17% compared with April, reducing one of the country’s most important sources of flexibility. Renewable output remained almost unchanged, increasing by only 0.13%, meaning Croatia did not experience the same renewable generation growth seen in markets such as Bulgaria, Romania and Greece. The combination of weaker hydro availability, limited thermal capacity and higher import needs contributed to the sharp increase in wholesale prices.

For electricity traders, Croatia is becoming a market where import requirements, cross-border spreads and liquidity conditions must be assessed together. While CROPEX continues to show long-term market growth through higher annual trading volumes, the monthly decline in activity during a period of elevated prices highlights the need for deeper liquidity. Electricity.Trade’s analysis positions Croatia as a premium-risk electricity market — one that benefits from strong regional connections but remains highly exposed when neighbouring supply tightens, making it an increasingly important market for monitoring the Hungary-Slovenia-Western Balkans trading corridor.

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Bulgaria recorded 258.65 GWh of net electricity exports in May, sending power to Romania and Serbia while importing from North Macedonia, Türkiye and Greece. This trading pattern demonstrates Bulgaria’s position as a regional balancing hub, both absorbing available lower-cost electricity from neighbouring systems and supplying markets facing tighter domestic conditions. The country effectively operated as a connection point between the Greek and Turkish markets and the northern Balkan systems of Romania and Serbia.

The structure of Bulgaria’s generation mix was central to its market performance. Electricity production consisted of 32.59% nuclear, 29.35% renewables, 17.58% hydropower, 15.51% coal and lignite, and 4.97% natural gas. Renewable generation increased by 34.19% compared with April, marking the strongest monthly growth among the analysed Southeast European markets. Hydropower output also improved by 7.30%, while coal and lignite generation declined by 17.81% and gas-fired production fell by 28.10%. The combination shows that Bulgaria was able to support exports even with lower thermal generation, relying instead on nuclear, renewable and hydro resources.

Liquidity on the IBEX exchange also continued to strengthen. Monthly traded volume reached 2,675.87 GWh, increasing 3.51% month on month and 15.99% year on year. Higher exchange activity alongside stronger export performance reinforces Bulgaria’s importance as both a physical electricity flow market and a regional price reference point. Growing liquidity improves market transparency and provides traders with better tools for managing Balkan electricity exposures.

Overall, Bulgaria’s May 2026 performance reflects the strength of a diversified electricity system. Nuclear generation provides a stable foundation, renewables deliver increasing volumes of low-marginal-cost electricity, hydropower improves flexibility, and lower reliance on gas reduces exposure to fuel price volatility. Electricity.Trade’s analysis positions Bulgaria as one of Southeast Europe’s most strategically important power markets — a country with strong interconnections, a balanced generation portfolio and sufficient market liquidity to influence regional electricity trading dynamics.

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Greece recorded 874.20 GWh of net electricity exports during May. The country imported electricity from Albania and Türkiye, while exporting to North Macedonia and Bulgaria, with no recorded electricity trade with Italy. The largest cross-border flow was directed to Bulgaria, where exports reached 666.23 GWh, underscoring Greece’s increasingly important role in supplying neighbouring Southeast European markets.

The country’s generation mix played a decisive role in supporting these exports. Electricity production consisted of 57.19% renewables, 28.11% natural gas, 8.42% hydropower and 4.29% coal and lignite. Renewable generation increased by 15.88%, while hydropower output surged by 40.80% to 408.78 GWh, benefiting from improved precipitation. Electricity demand also rose by 2.44%, indicating that Greece’s export surplus was driven by stronger domestic generation rather than weaker consumption. The combination of abundant renewable and hydro production enabled the country to meet higher domestic demand while maintaining significant electricity exports.

For electricity traders, Greece’s market performance illustrates the growing value of renewable-rich systems supported by flexible hydropower resources. Competitive wholesale prices allowed Greek electricity to flow into neighbouring markets, particularly Bulgaria, while natural gas continued to provide balancing capacity without dominating the generation mix. This market structure creates favourable conditions for cross-border and intraday trading, with renewable output influencing hourly price patterns and hydropower providing additional operational flexibility.

Overall, May 2026 demonstrated that Greece’s energy transition is increasingly reflected in regional electricity trade. High renewable penetration is no longer only a measure of decarbonization but also a key driver of cross-border market dynamics. Strong renewable and hydropower output enabled Greece to become a major exporter, reshaping electricity flows across the Balkans and creating attractive trading opportunities along the Greek-Bulgarian and Greek-North Macedonian interconnection corridors.

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Hungary remained heavily dependent on imported electricity throughout the month. Net imports totaled 1,076.31 GWh, increasing by 38.70 GWh compared with April. Electricity was imported from Austria, Croatia, Romania, Serbia and Slovakia, while exports were directed solely to Ukraine. This trading pattern highlights Hungary’s dual function as both a domestic balancing market and a strategic transit corridor linking multiple electricity price zones, generation portfolios and regional supply chains.

The country’s generation mix continued to support its strategic market position. In May, electricity supply consisted of 29.97% net imports, 29.65% renewables, 28.92% nuclear generation, 2.54% coal and lignite, 0.19% hydropower and other smaller energy sources. While nuclear power provides a stable baseload, the limited contribution from hydropower and the significant share of imported electricity leave the market highly dependent on cross-border transmission capacity. Renewable generation increased by 9.56%, even as electricity demand declined by 7.51%, indicating that higher wholesale prices were driven more by regional market conditions and import costs than by domestic consumption.

Hungary’s geographical position continues to make it one of the region’s most influential electricity trading markets. By connecting the core Central European markets with Romania, Serbia, Croatia and Ukraine, the country plays a critical role in cross-border electricity flows and regional price formation. As a result, HUPX remains an important benchmark for spread trading, congestion analysis and forward hedging strategies across Southeast Europe, with price movements often reflecting both Central European supply conditions and Balkan import demand.

Overall, May 2026 highlighted Hungary’s growing importance as a regional flexibility and liquidity hub. A power system built on stable nuclear generation, expanding renewable capacity and substantial electricity imports requires efficient balancing resources, storage capacity, strong interconnections and responsive trading strategies. The continued growth in HUPX trading volumes and Hungary’s central role in regional electricity flows underscore its increasing influence on Southeast European market integration, while also illustrating the ongoing importance of cross-border capacity and supply security in regional price formation.

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The scale of the price differential created one of the widest spreads in Southeast Europe. Türkiye traded nearly €90/MWh below Bulgaria, around €78/MWh below Greece and more than €108/MWh below Italy, presenting what would typically be viewed as a strong arbitrage opportunity. However, the ability to capitalize on such price differences remains constrained by limited interconnection capacity, transmission rights, market coupling arrangements and balancing requirements. As a result, Türkiye’s exceptionally low prices generated a clear economic signal, but only a limited portion of that value could be transferred to neighbouring European markets.

The country’s generation mix played a major role in shaping this outcome. Electricity production in May was led by 50.31% hydropower, followed by 19.68% renewables, 18.41% coal and lignite, 11.35% natural gas and 0.25% oil. Electricity demand declined by 5.09% compared with April, while renewable generation fell by 6.70%. The decisive factor behind the price decline was the combination of lower demand and abundant hydropower generation, as hydro-rich systems are capable of pushing wholesale prices significantly lower when reservoir conditions are favourable and dispatch patterns align with domestic market dynamics.

Türkiye remained a net electricity exporter during the month, recording 255.00 GWh of net exports. Power exports reached 26.87 GWh to Greece, 44.01 GWh to Bulgaria and 184.12 GWh to Georgia. Although these cross-border flows supported regional trade, their volume was insufficient to significantly reduce the substantial price gap between Türkiye and neighbouring Southeast European markets, highlighting the limited degree of market integration.

Overall, May 2026 demonstrated that Türkiye’s exceptionally low electricity prices were driven not only by favourable generation conditions but also by the country’s relatively limited integration with the broader European power market. The sharp decline underscored the importance of cross-border interconnection capacity, regional market integration and efficient transmission infrastructure. Without stronger physical and regulatory links, even extreme price spreads remain only partially tradable, leaving Türkiye’s hydro-driven low-price environment largely isolated from the pricing dynamics of EU-linked electricity markets.

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Italy also maintained its position as the region’s largest and most liquid electricity market. Trading volumes on the IPEX exchange reached 22,994.12 GWh in May, increasing 4.54% month on month and 8.30% year on year. This high level of liquidity continued to shape forward market expectations, influence cross-border trading strategies and support Italy’s role in determining the value of electricity flows across neighbouring countries.

The market’s underlying fundamentals remained equally significant. Italy’s electricity generation mix consisted of 41.61% renewables, 34.07% natural gas, 16.24% hydropower and 17.97% net electricity imports. Renewable generation rose by 9.22%, while hydropower output increased by 12.45%, helping meet electricity demand that expanded by 3.29% during the month. Even so, Italy remained a major net importer, bringing in 3,706.01 GWh of electricity, although net imports declined 16.41% compared with April as stronger domestic renewable and hydro production reduced the need for external supply.

Cross-border trade continued to play a crucial role in the Italian market. The country imported electricity primarily from France, Switzerland, Austria and Montenegro, while exporting to Greece, Malta and Slovenia. This trading pattern highlights Italy’s close integration with both Central European and Balkan power systems. While improved renewable generation helped ease import requirements, the country’s gas-dependent generation fleet continued to expose electricity prices to fuel market fluctuations, making interconnector capacity and effective cross-border trading strategies increasingly important.

Overall, May 2026 demonstrated that Italy’s market strength was driven not by a new price surge but by its persistent premium status. Stable prices at a high level confirmed that Italy remains the region’s key pricing benchmark, rewarding flexible generation, efficient import strategies and access to interconnection capacity. As several neighbouring Southeast European markets also traded above €100/MWh, Italy retained the highest price range and reinforced its role as the principal reference market for regional arbitrage opportunities.

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The facility integrates a 63 MW solar photovoltaic plant with a battery energy storage system (BESS) featuring 10 MW of power capacity and 21 MWh of storage capacity. The combination of renewable generation and storage allows the project to retain part of its electricity output and release it during periods of higher demand, improving grid flexibility, operational efficiency, and system stability.

MORE expects the Stalpu 2 hybrid project to generate approximately 76 GWh of electricity annually, enough to supply around 32,000 households. The company estimates that the renewable facility will help reduce more than 26,000 tonnes of CO₂ emissions each year, supporting Romania’s decarbonisation objectives and the wider energy transition in Southeast Europe.

The commissioning of Stalpu 2 represents a major milestone for MORE’s international expansion strategy, as it marks the company’s entry into the Romanian renewable-energy market and its first step beyond Greece. The project also highlights the growing importance of hybrid renewable assets, where solar generation and storage are combined to address intermittency challenges and create additional value in increasingly flexible electricity markets.

With renewable capacity expanding across the region, projects such as Stalpu 2 demonstrate the shift toward a new generation of energy investments focused not only on producing clean electricity, but also on improving market integration, grid resilience, and long-term energy security.

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The reactor, operated by Nuclearelectrica, was disconnected from the grid on 10 May for a planned maintenance programme lasting approximately two months. The works included preventive and corrective maintenance, mandatory safety inspections, equipment testing, and modernization activities on selected plant systems to ensure continued reliable operation.

According to Nuclearelectrica, all maintenance activities were completed in accordance with approved technical procedures and fully complied with nuclear safety standards and environmental protection requirements. The successful return of the unit confirms the importance of nuclear generation as a stable source of low-carbon electricity in Romania’s energy mix.

The restart of Cernavoda Unit 1 is expected to significantly improve the balance of Romania’s electricity system, especially during evening peak hours when solar generation decreases while electricity demand remains elevated. The additional 700 MW of available capacity should help reduce reliance on imports and provide greater stability during tighter market conditions.

Commissioned in 1996, Unit 1 has produced more than 149 million MWh of electricity throughout its operational lifetime. Nuclearelectrica estimates that the reactor’s generation has avoided approximately 145 million tonnes of CO₂ emissions, while maintaining a capacity factor above 90%, placing it among the highest-performing nuclear reactors globally.

Nuclearelectrica currently operates two 700 MW CANDU reactors at Cernavoda Nuclear Power Plant and also owns the Nuclear Fuel Factory in Pitesti, which manufactures fuel bundles for CANDU 6 reactors. The company’s nuclear assets remain a key pillar of Romania’s energy strategy, supporting security of supply, decarbonisation targets, and electricity-market stability across Southeast Europe.

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During the extreme heat, Paks gradually reduced its output in coordination with Hungary’s electricity transmission system operator MAVIR to comply with regulations governing the temperature of cooling water discharged into the Danube. The nuclear plant, with an installed capacity of 2,000 MW, relies on river water to cool its reactors before returning the water downstream.

Hungarian regulations require discharged cooling water to remain below 30°C within 500 metres of the outlet point. Under exceptional circumstances, the limit may be temporarily increased to 31.5°C if the energy minister determines that such a measure is necessary to protect security of electricity supply.

The Hungarian government said earlier that the electricity system remained stable throughout the heatwave, while continuous monitoring showed no indication that higher river temperatures had created a threat to the Danube ecosystem. The temporary production reduction at Paks was therefore managed as a precautionary operational measure rather than a wider system-security issue.

With temperatures now declining, the nuclear facility has begun gradually increasing generation levels. Weather forecasts indicate more moderate conditions in the coming days, with daytime temperatures expected around 30°C, alongside periods of rain and thunderstorms that should further improve cooling conditions.

The restoration of Paks output will provide additional stability to Hungary’s electricity system, reducing pressure on imports and strengthening supply availability as regional power markets continue to face volatility during periods of high demand and weather-related constraints.

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Trading activity was distributed across both market segments, with 986,130.5 MWh traded on the day-ahead market and 327,879.7 MWh on the intraday market. The average daily day-ahead traded volume reached 32,871 MWh, highlighting the growing importance of transparent exchange-based trading for Croatian market participants and the wider Southeast European electricity market.

Higher liquidity was accompanied by stronger price levels throughout the month. The average day-ahead baseload price increased to €115.90/MWh, representing an 11.9% rise compared with May. Peak-hour prices experienced a much sharper increase, with the average peak price reaching €250.97/MWh, a 286% monthly increase, reflecting significant pressure during periods of elevated demand and tighter supply conditions.

The intraday market followed a similar trend, with the average traded price reaching €120.34/MWh, up 12.6% compared with the previous month. The combination of rising volumes and higher prices points to a market environment where short-term flexibility, balancing capability, and efficient trading strategies are becoming increasingly valuable.

CROPEX was established on 11 March 2016 through cooperation with Nord Pool, one of Europe’s leading electricity exchanges, and is jointly owned by the Croatian Transmission System Operator (HOPS) and the Croatian Energy Market Operator (HROTE). The exchange expanded its market offering with the launch of the intraday market in April 2017, providing participants with additional tools to manage short-term electricity positions.

A key step in Croatia’s market integration was achieved on 19 June 2018, when the CROPEX day-ahead market was successfully coupled with the Multi-Regional Coupling (MRC) markets through the Croatia-Slovenia interconnection. This integration improved cross-border trading opportunities and strengthened Croatia’s connection with the broader European electricity market.

As renewable generation continues to expand and regional electricity flows become more dynamic, CROPEX is expected to play an increasingly important role in supporting market liquidity, price transparency, cross-border integration, and the efficient development of Southeast Europe’s electricity market.

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Average daily traded volume on the day-ahead market reached 90,266.5 MWh during June. While trading activity increased, average baseload prices recorded a moderate decline, falling to €98.08/MWh from €101.07/MWh in May, a decrease of approximately 3%. However, average peak prices moved higher, increasing by 6% to €64.88/MWh, highlighting continued pressure during periods of higher demand and tighter system conditions.

Market liquidity continued to improve, with 155 registered participants active on the IBEX day-ahead market in June, one more than in the previous month. The steady increase in market participation indicates growing confidence in exchange-based electricity trading and strengthens IBEX’s role as an important platform for price discovery and market transparency in Southeast Europe.

Trading activity on the intraday continuous market remained substantial, with total volumes reaching 673,371.5 MWh. Although this was 9% lower compared with May, the market maintained solid liquidity, while the average weighted intraday price declined slightly by 1% to €88.51/MWh.

June results underline the continued development of Bulgaria’s organized electricity market, supported by higher trading volumes, stronger market participation, and deeper regional integration. As renewable generation increases and cross-border electricity exchanges become increasingly important, IBEX is expected to play a growing role in improving market efficiency, price transparency, and investment signals across Southeast Europe.

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The traded volume was distributed across both ALPEX bidding zones, with 108.7 GWh traded in the Kosovo zone and 136.1 GWh in the Albania zone. Both markets recorded an average clearing price of €91.55/MWh, reflecting the increasing role of transparent market-based price signals in the regional electricity system and the gradual strengthening of power-market integration in Southeast Europe.

The financial value of transactions on ALPEX reached approximately €32.5 million during June 2026, marking a 10% increase compared with the same month of the previous year. The higher transaction value reflects stronger market participation, increased trading activity, and the growing importance of centralized electricity exchanges in improving liquidity and price discovery.

ALPEX was established in October 2020 through cooperation between Albania’s transmission system operator OST and Kosovo’s transmission operator KOSTT. The exchange was created to support the development of a more efficient and competitive regional electricity market. Its first day-ahead auction for the Albanian bidding zone was launched in April 2023, representing a major milestone in the development of organized power trading in the region.

The exchange currently includes 36 registered market participants operating across the Albania and Kosovo bidding zones. As renewable-energy capacity expands and cross-border electricity flows become increasingly important, ALPEX is expected to play a larger role in improving market transparency, investment signals, and regional electricity trading efficiency across Southeast Europe.

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Most Southeast European markets remained closely grouped around €102–108/MWh, while Italy National continued to stand significantly above the region at €142.36/MWh. At the same time, Germany declined to €72.80/MWh, expanding the HUPX-Germany spread to €34.04/MWh. This spread became the most important market signal of the day: Central Europe benefited from weaker prices, but Hungary and SEE maintained a premium because regional systems still required imports and because part of the available supply was attracted toward Italy’s higher-priced market.

Hungary’s HUPX settled at €106.85/MWh, falling by €9.6/MWh compared with the previous session, but it remained well above German levels. Most regional hubs followed a similar pattern, with OPCOM (Romania) at €103.81/MWh, IBEX (Bulgaria) at €103.03/MWh, HENEX (Greece) at €103.51/MWh, BSP (Slovenia) at €103.11/MWh, CROPEX (Croatia) at €102.34/MWh, and ALPEX (Albania) at €103.56/MWh. Serbia and North Macedonia were the main upward outliers within SEE, with SEEPEX at €108.01/MWh and MEMO at €108.84/MWh, while Montenegro moved in the opposite direction, falling sharply to €93.85/MWh.

The physical market balance explains why prices did not converge toward Germany’s lower levels. Regional consumption increased to 32,075 MW, rising by 1,604 MW day on day, while total net imports climbed to 1,979 MW, an increase of 556 MW. Imports from the core European direction also strengthened, with Austria and Slovakia supplying 3,244 MW, up 549 MW from the previous day.

Lower Central European prices therefore helped support the SEE-Hungary system, but they were not enough to eliminate the regional premium. The market remained dependent on external supply, while internal flows continued to redistribute electricity toward higher-value destinations.

The strongest commercial signal came from Italy’s continued price premium. Even as the wider HU+SEE region remained a net importer, scheduled flows still moved 1,083 MW toward Italy, where prices reached €142.36/MWh. This created a familiar regional trading pattern: Central Europe supplied electricity into Hungary and Slovenia, while available capacity was redirected toward southern and western markets where prices were higher.

Montenegro provided the clearest example of this cross-border optimisation. Although BELEN cleared at €93.85/MWh, commercial schedules showed exports toward Italy of 425 MW during base hours and 438 MW during peak hours, while Montenegro remained a net importer overall at 160 MW. The market dynamic was therefore not driven by domestic oversupply, but by the ability to exploit regional price differences through interconnection capacity.

Serbia remained one of the tighter markets in SEE. SEEPEX increased by €10.2/MWh to €108.01/MWh, placing Serbia above Hungary, Romania, Bulgaria, Greece, Croatia, Slovenia, and Albania. The country recorded 3,476 MW of consumption, 2,974 MW of generation, and 502 MW of net imports. The pressure was particularly visible during peak hours, when Serbia’s commercial balance reached -785 MW, compared with -219 MW during off-peak periods.

Serbia imported electricity from Bosnia and Herzegovina, Croatia, Hungary, Bulgaria, and North Macedonia, while exporting toward Romania and Montenegro. This structure explains why SEEPEX maintained a premium: Serbia was not simply following the regional price trend but reflecting its own peak-hour adequacy constraints.

Hungary showed a similar structural imbalance. Consumption reached 4,662 MW, while domestic generation stood at 3,695 MW, leaving the country with 967 MW of net imports. The market relied heavily on Austrian and Slovak flows, while still supporting exports toward Croatia, Slovenia, and Romania during certain periods. As a result, HUPX remained a regional balancing hub rather than simply following German market weakness.

Romania’s decline to €103.81/MWh was supported by the return of Cernavoda Unit 1, which restored approximately 700 MW of nuclear capacity following scheduled maintenance. The additional nuclear output improved supply conditions, particularly during evening periods when solar generation declines. However, Romania still recorded 596 MW of net imports, indicating that the market had become less tight rather than fully oversupplied.

Bulgaria continued to act as the region’s main supply contributor. The country recorded 5,074 MW of generation against 3,809 MW of consumption, creating 1,266 MW of net exports. Electricity flowed toward Romania, Serbia, North Macedonia, and Greece, reinforcing Bulgaria’s role as a regional balancing supplier when nuclear and renewable output are available. Despite this surplus position, IBEX remained close to regional prices because interconnectors absorbed much of the available generation.

Greece traded near the regional average at €103.51/MWh despite strong solar production and flexible gas generation. The country recorded 7,192 MW of consumption and 7,274 MW of generation, with limited base exports of 82 MW but stronger peak exports of 630 MW. Greece exported toward North Macedonia, Albania, and Italy while importing from Bulgaria, creating a balanced regional position that kept HENEX closely aligned with neighboring markets.

Forward markets showed a more optimistic outlook than the immediate spot environment. Hungarian Week 29 prices declined to €132/MWh, down €14/MWh, while Week 30 fell to €126/MWh, down €7.5/MWh. The Hungarian Week 29 premium over Germany narrowed to €19.5/MWh, suggesting expectations of reduced short-term pressure. Fuel markets also softened, with CEGH gas at €45.71/MWh, Greek gas at €42.87/MWh, and lower coal forwards, although EU carbon allowances increased to €81.79/t.

The forward curve therefore suggests some relief from current tightness, but not a complete return to normal conditions. The market continues to price structural differences between Germany, Hungary, SEE, and Italy.

The overall trading message is clear: SEE spot prices softened, but the region’s structural premium remains intact. Hungary continued to trade above Germany, Serbia faced tighter domestic conditions, and Italy maintained the strongest price signal in the region. For traders, the most important spreads remain Germany versus Hungary, SEE versus Italy, and Serbia versus the regional cluster.

For generators and investors, the value opportunity is increasingly concentrated in flexibility during high-value hours. Hydro, gas, batteries, demand response, and cross-border capacity will continue to gain importance as markets move away from simple baseload pricing toward a system where timing, location, and operational flexibility determine revenue value.

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The challenge is straightforward: renewable development is accelerating faster than grid infrastructure expansion. Solar and wind projects may secure land rights, obtain permits, and order equipment, yet still face uncertainty over connection dates, energisation approvals, or available transmission capacity. When grid access is delayed, the entire financial structure of a project changes. Revenue generation is postponed, financing costs increase, equity remains committed for longer periods, and expected returns decline.

A 12–18 month delay in grid connection can have a greater impact on project economics than a moderate increase in construction costs. The consequences extend across the entire financial model. Debt repayments may begin before commercial operations start, interest during construction can rise, EPC schedules may be disrupted, and contractual commitments under PPAs may become harder to meet. For lenders, these delays can trigger the need for additional protections, renegotiations, or restructuring discussions. For equity investors, prolonged uncertainty increases risk and can raise the required return on future investments.

Beyond connection delays, curtailment risk represents another major hidden cost. A renewable project being connected to the grid does not automatically mean it can operate at full output whenever electricity is produced. If transmission infrastructure cannot absorb high levels of renewable generation, projects may be forced to reduce output, directly lowering revenues. Solar assets are particularly vulnerable during periods of strong midday production, while wind projects often face challenges in areas with excellent renewable resources but limited grid capacity.

These realities are changing how financial institutions evaluate renewable projects. A project with slightly lower generation potential but secure grid access may be considered more attractive than a high-yield project located in a congested network area. As a result, grid studies, connection agreements, transmission-system operator (TSO) communication, curtailment scenarios, and realistic commissioning schedules are becoming essential components of project-finance assessments.

For governments and energy policymakers, grid limitations represent a broader challenge for the energy transition. Delayed network upgrades increase project costs, reduce investor confidence, slow renewable deployment, and limit the ability of industries to access reliable low-carbon electricity. This can directly affect regional competitiveness, especially as European customers increasingly demand cleaner supply chains and lower embedded emissions.

For developers, the response must be a stronger focus on project preparation and risk management. Bankable renewable projects increasingly require detailed grid-risk assessments, realistic energisation strategies, commissioning plans, curtailment modelling, potential storage solutions, and clearly defined responsibilities between developers, EPC contractors, TSOs, and technical advisers.

Southeast Europe continues to offer significant renewable-energy potential, but future investment will increasingly flow toward projects where grid challenges are identified, quantified, and actively managed. Grid access is no longer a secondary technical consideration added after project development. It has become a core financial variable that directly influences cost of capital, investment decisions, and long-term project value.

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Recent electricity-market trends across SEE demonstrate why this shift is accelerating. Regional power prices remain volatile, renewable generation is expanding unevenly, and gas-fired generation continues to influence prices during periods of supply pressure. For industrial exporters, electricity can no longer be viewed only as a production cost. It is becoming part of the product’s embedded-emissions profile, directly affecting competitiveness and commercial credibility in EU markets.

A CBAM-ready electricity strategy requires far more than purchasing renewable-energy certificates. Companies need a structured and auditable procurement approach that demonstrates where electricity comes from, how it is measured, and how it is connected to production processes. This includes reliable generation data, appropriate metering systems, contractual delivery arrangements, guarantees of origin where relevant, time-based matching requirements where applicable, and integration with the company’s Monitoring, Reporting and Verification (MRV) framework. Renewable suppliers must also be capable of providing transparent settlement records, operational data, and technical documentation that can withstand external verification.

For renewable-energy developers, this creates a new and potentially valuable offtake opportunity. Solar, wind, and hydro projects that can deliver verified low-carbon electricity may become more attractive partners for industrial consumers than projects selling into the open market without additional documentation. This can support stronger long-term PPAs, improve revenue visibility, strengthen credit quality, and enhance access to project financing.

For industrial companies, the advantages extend beyond regulatory compliance. Verified renewable electricity can help protect relationships with EU customers, reduce exposure to future carbon-related costs, and improve the market positioning of exported products. In industries where margins are under pressure and supply chains are increasingly evaluated through sustainability criteria, credible carbon documentation can become a significant commercial advantage.

Serbia represents a particularly important example of this transition. The country has a large industrial base connected to EU markets, while its electricity system remains relatively carbon-intensive due to continued reliance on lignite generation. A Serbian manufacturer that secures verified renewable electricity from a domestic renewable project could strengthen its CBAM reporting position and improve its competitiveness—but only if the procurement structure is transparent, measurable, and fully auditable.

This is where project finance and corporate finance increasingly intersect. Banks may view CBAM-linked PPAs more positively when they are supported by reliable industrial offtakers, transparent measurement systems, and long-term demand visibility. Renewable developers can use these agreements to improve debt capacity and reduce merchant-market exposure. Industrial exporters, meanwhile, can use renewable electricity procurement as a tool for managing customer risk and strengthening supply-chain resilience.

CBAM-ready electricity is therefore becoming more than an environmental attribute. It is evolving into a commercial and financial instrument that connects renewable-energy development with industrial competitiveness. In Southeast Europe, projects capable of delivering not only clean electricity but also credible documentation and verifiable emissions benefits are likely to gain a growing advantage in both energy markets and export markets.

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The traditional approach viewed batteries mainly as an additional investment that became attractive when supported by subsidies or specific incentive schemes. That model is changing. Storage is increasingly being evaluated as a commercial market asset capable of capturing price differences between periods of abundant renewable generation and periods of higher demand. Beyond price arbitrage, batteries can reduce curtailment, improve grid flexibility, provide balancing services, and strengthen the financial performance of renewable-energy projects.

For solar developers, storage is becoming an important tool for managing capture-price risk. Without a battery, solar projects typically sell electricity during the same midday hours when overall solar production is highest and market prices are under pressure. As solar penetration increases, this can significantly reduce project revenues. A co-located battery allows developers to shift part of their generation into evening periods when electricity prices are often higher. This can improve PPA structures, reduce exposure to merchant-market volatility, and strengthen the project’s ability to secure financing.

The role of storage for wind projects is different but equally important. Wind generation is not exposed to the same level of midday price compression as solar, but it carries greater uncertainty due to changing weather patterns and forecasting challenges. Batteries can help smooth production profiles, reduce imbalance costs, and provide additional grid-support services. This improves the commercial reliability of wind assets, particularly in markets where balancing requirements are becoming stricter.

For electricity-system operators, storage represents an important flexibility resource as renewable deployment accelerates. Across SEE, renewable development pipelines are expanding faster than grid infrastructure in some regions, creating challenges related to congestion and system balancing. While batteries cannot replace the need for major transmission investment, they can help manage short-term constraints, reduce ramping pressures, and provide local flexibility where it is most needed.

The main challenge for storage financing remains revenue certainty. Unlike traditional generation assets, battery projects often rely on multiple revenue streams, including energy arbitrage, balancing services, ancillary markets, capacity mechanisms, and congestion management. However, regulatory frameworks across SEE remain at different stages of development, and some markets still lack clear long-term visibility for these income sources. As a result, lenders will increasingly prioritize projects with contracted revenues, reliable market data, proven technology performance, and conservative financial assumptions.

Storage could also become increasingly important for industrial electricity consumers. Companies seeking renewable power are not only interested in low-cost daytime electricity; they increasingly require reliable and predictable supply profiles. Batteries can help transform intermittent renewable generation into a more valuable commercial product by providing firmer delivery, improving energy security, and supporting compliance requirements for CBAM-exposed exporters that need transparent documentation of electricity sourcing and emissions performance.

The strategic direction for Southeast Europe is becoming increasingly clear: the region does not only need more renewable megawatts—it needs more flexible and controllable megawatts. Battery storage is emerging as the technology that can bridge the gap between renewable growth and market integration, allowing solar and wind expansion to translate into greater system reliability, stronger investment value, and more resilient electricity markets.

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Italy’s structural market position explains much of this premium. The country combines strong electricity demand, limited domestic flexibility, continued reliance on gas-fired generation, and significant dependence on imports. During periods of weaker hydro or wind generation, the Italian market becomes even tighter, causing the price gap with neighboring countries to expand. These effects do not remain isolated within Italy; they influence electricity flows, trading strategies, and investment decisions across Slovenia, Croatia, Greece, and the Western Balkans.

For energy investors in Southeast Europe, Italy’s price premium creates several strategic opportunities. Renewable projects with export potential can capture additional value when interconnectors allow electricity flows toward higher-priced markets. Battery storage assets can benefit from increased volatility by shifting energy into higher-value periods. At the same time, investments in interconnectors, transmission upgrades, and grid reinforcement become increasingly important because they determine whether regional price differences can be converted into actual commercial opportunities.

Croatia is particularly exposed to these dynamics due to its Adriatic location and connections with both Central European markets and Italy. During periods of higher domestic demand or reduced local generation, Croatian electricity prices can quickly move closer to Italian levels as import dependence increases. Serbia and Bosnia and Herzegovina, while not directly integrated into the same market structure, may also benefit from regional export opportunities when domestic supply conditions allow. Greece can occasionally move in the opposite direction due to strong solar production and export availability, but Italy remains a key reference market for Mediterranean electricity trading.

However, the investment case is not based solely on merchant price opportunities. Lenders and institutional investors will increasingly focus on whether assets can capture volatility through reliable and diversified revenue streams rather than relying only on uncertain market spreads. Projects with strong financing potential are likely to combine long-term contracts, corporate PPAs, balancing-market participation, storage integration, and realistic assumptions regarding cross-border electricity flows.

Export-oriented renewable projects must also address important regulatory and infrastructure risks. Available interconnector capacity, market-coupling arrangements, congestion management, balancing rules, and transmission access will determine whether Italy’s price premium translates into actual project revenues or remains only a theoretical market indicator.

The same trend is relevant for industrial electricity consumers across the region. Italy’s high prices demonstrate why electricity procurement is becoming increasingly strategic for companies exposed to international competition, carbon costs, and supply-chain decarbonisation requirements. Premium-priced export markets can attract regional electricity supply, particularly during periods of system stress.

Italy should therefore be viewed as more than simply a neighboring high-cost electricity market. It represents a regional valuation benchmark for Southeast European energy assets. As long as Italy remains structurally constrained and maintains a significant price premium, renewable projects, storage facilities, and grid investments with credible export capability will retain strategic importance across the region.

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Historically, renewable-energy financing has relied on relatively straightforward assumptions based on expected annual production, average market prices, and a limited range of downside scenarios. That framework is becoming increasingly inadequate in modern power markets. A solar project may generate exactly as forecast yet still underperform financially if midday electricity prices fall due to rising solar penetration. Likewise, a wind project may benefit from generation during higher-priced periods but face greater uncertainty related to weather conditions, forecasting accuracy, and balancing costs. In addition, projects located in congested areas of the grid may encounter curtailment risks regardless of the quality of the underlying renewable resource.

As a result, lenders are placing greater emphasis on granular revenue modelling. Modern project assessments increasingly require detailed hourly price forecasts, capture-price analysis, curtailment sensitivity testing, balancing-cost assumptions, and realistic evaluations of grid-connection risks. Debt-service coverage ratios (DSCRs) can no longer be evaluated solely against lower average market prices. They must also be stress-tested against scenarios in which realized revenues decline because electricity is produced during periods of weaker market pricing.

The same shift applies to the assessment of merchant exposure. Many renewable projects benefit from long-term Power Purchase Agreements (PPAs) during their initial operating years, providing predictable cash flows and supporting debt financing. However, lenders are increasingly focused on what happens after those contracts expire. Merchant-price assumptions, refinancing prospects, storage integration opportunities, future grid conditions, and the potential to secure new corporate offtake agreements are becoming critical components of credit analysis. A project’s long-term value is no longer defined only by its current contract structure but by its ability to remain competitive in a changing market environment.

At the same time, grid risk has emerged as a major financing variable. Delays in obtaining grid access or completing network upgrades can significantly affect project economics. A postponed connection can increase interest costs during construction, extend the period of equity exposure, delay revenue generation, and reduce overall project returns. Even when a project remains technically viable, a grid-connection delay of 12 to 18 months can materially weaken its financial profile. This challenge is becoming increasingly relevant across SEE, where renewable-development pipelines are often larger than the available transmission and distribution capacity.

The introduction of CBAM-related pressures adds another layer of complexity. Industrial exporters seeking to maintain competitiveness in European markets are increasingly interested in securing documented renewable electricity that supports lower embedded emissions. This creates opportunities for stronger and potentially more valuable PPAs. However, these opportunities depend on the ability of renewable projects to provide verified generation data, reliable metering, guarantees of origin where applicable, and integration with the buyer’s monitoring, reporting, and verification (MRV) systems.

Consequently, the role of lenders is evolving alongside the market. Financing renewable-energy projects in Southeast Europe is no longer focused solely on technology performance, resource assessments, and construction execution. Increasingly, it is about market integration, grid accessibility, contract quality, revenue visibility, and data transparency. Projects supported by robust documentation, credible hourly revenue modelling, and realistic assumptions regarding market and grid conditions are likely to secure more attractive financing terms. Conversely, projects that depend on overly optimistic price forecasts or simplified market assumptions may find it increasingly difficult to attract competitive debt and equity capital.

As renewable penetration continues to rise across the region, the most successful projects will be those that demonstrate not only strong generation potential but also a clear ability to navigate the realities of modern electricity markets. In today’s SEE power sector, financing decisions are increasingly driven by when electricity is generated, how it reaches the market, and how reliably revenues can be captured over the long term.

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The importance of hydro extends far beyond its share of electricity production. Hydropower assets provide essential flexibility, balancing services, operating reserves, and price stability. Unlike many conventional thermal plants, hydro facilities can respond rapidly to changing demand and generation conditions, making them indispensable for integrating growing volumes of wind and solar power. When hydro availability weakens, electricity systems become more exposed to gas-fired generation, coal plants, cross-border imports, and periods of peak-hour scarcity.

Week 25 offered a clear illustration of these dynamics. In Romania, electricity demand declined, yet market prices increased because weaker hydro generation reduced supply flexibility while regional market coupling pushed prices on OPCOM higher. In contrast, Serbia benefited from stronger hydro output, allowing the system to move into an export position and helping to ease domestic market pressures. These contrasting outcomes demonstrate that hydrological conditions can be a stronger driver of national electricity prices than demand trends alone.

Hydro variability also has important implications for the economics of renewable-energy projects. Solar and wind assets depend on the broader system’s ability to absorb and balance variable generation. During periods of strong hydro availability, balancing costs are often lower, system flexibility improves, and curtailment risks can decline. However, when hydro generation weakens, the system requires additional thermal flexibility, increasing market volatility and altering the revenue environment for renewable assets. This directly affects merchant revenues, PPA pricing, financing assumptions, and the risk assessments used by lenders and investors.

The growing impact of climate variability makes this issue even more significant. Hydropower systems across Southeast Europe are highly dependent on rainfall patterns, snowpack levels, river flows, and exposure to seasonal droughts. A region that relies heavily on hydro for balancing and flexibility cannot afford to overlook hydrological risks in market analysis. Long-term electricity-price forecasts must incorporate wet-year, normal-year, and dry-year scenarios, rather than focusing solely on fuel prices, carbon costs, or demand growth projections.

For utilities, hydro assets are increasingly becoming strategic balance-sheet resources. During wet periods, strong hydro output can reduce fuel consumption, lower operating costs, strengthen export opportunities, and support profitability. During dry periods, however, utilities may be forced to increase imports, operate more gas- and coal-fired generation, and absorb higher balancing costs. These shifts can influence earnings performance, working-capital requirements, and even create additional pressure on regulated electricity tariffs.

For investors in battery storage and other flexible technologies, hydro volatility creates a growing commercial opportunity. When hydro resources are constrained, batteries become more valuable because they can provide many of the balancing and ramping services that hydro would normally deliver. As renewable penetration increases and weather-driven hydro variability becomes more pronounced, the value of flexible assets is likely to grow further.

Hydropower remains one of Southeast Europe’s greatest energy advantages, providing flexibility and supporting system reliability across the region. However, it should no longer be viewed as a guaranteed source of stability. Hydro is fundamentally a weather-dependent asset, and its variability is increasingly shaping electricity prices, market dynamics, investment decisions, and energy-security outcomes. Week 25 reinforced a key reality for the region: hydro is not merely a buffer against volatility—it is now one of the most important drivers of it.

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For investors, lenders and energy planners, this distinction is increasingly important. Wind and solar differ in their generation patterns, exposure to market prices, curtailment risks and overall contribution to system reliability. Viewing renewable capacity as a single homogeneous category can lead to inaccurate assumptions and weaker investment decisions.

Solar generation is concentrated during daylight hours and is becoming increasingly exposed to capture-price compression as more capacity enters the market. As large volumes of solar power are produced simultaneously, midday electricity prices tend to decline, reducing the realized revenues earned by solar projects. Wind generation follows a different profile. It can produce electricity during evening and overnight periods when market prices are often higher, potentially allowing wind assets to capture greater value. However, wind output is more dependent on weather conditions and can weaken across large geographic areas at the same time, creating its own set of risks.

The market dynamics observed during Week 25 illustrated this challenge clearly. Despite stronger solar production, several SEE markets still required increased thermal generation because wind and hydro resources did not provide sufficient non-solar or flexible output. As a result, electricity prices in a number of markets remained elevated even as natural gas prices moved lower.

From a project-finance perspective, wind assets require their own dedicated analytical framework. Revenue forecasts should be based on technology-specific hourly production patterns, capture-price expectations, balancing costs and forecasting assumptions. A wind farm in Serbia, Croatia or Romania cannot be evaluated using the same commercial model as a solar project in Greece or Bulgaria. While wind projects may benefit from stronger capture prices during certain periods, they are also exposed to greater production variability and forecasting uncertainty.

Grid access and location remain equally important considerations. Many of the region’s strongest wind resources are located in areas where transmission infrastructure is weaker or less developed. This can increase connection costs, curtailment exposure and project-delivery risks. Consequently, a wind project with exceptional resource quality but uncertain grid availability may be less attractive from a financing perspective than a lower-yield project with secure grid access and a reliable long-term offtake agreement.

The policy implications extend beyond individual projects. Southeast Europe requires a balanced expansion of both wind and solar generation, supported by investments in storage, forecasting capabilities, transmission networks and system flexibility. A renewable-growth strategy dominated by solar can intensify midday price compression while increasing evening supply shortages. Conversely, rapid wind deployment without adequate grid reinforcement can create balancing challenges and network congestion.

Renewable technologies should therefore be evaluated as a diversified portfolio rather than as a single category. Solar, wind, hydro and storage each provide distinct commercial and system value, and their contributions to market stability differ significantly. Week 25 demonstrated that these differences are not theoretical—they are reflected directly in electricity prices, system operations and investment outcomes across the region.

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This development highlights a central challenge for solar project finance. A solar asset may achieve strong annual generation volumes, but its financial performance ultimately depends on the price available during the hours when it produces electricity. As solar penetration increases, midday market prices often decline because a large number of projects generate power simultaneously. This phenomenon can significantly reduce the realized price captured by solar producers compared with the average day-ahead market price.

For lenders and investors, this issue has direct implications. Debt sizing and project valuation can no longer rely solely on annual generation forecasts and average market prices. Financial assessments must incorporate hourly production profiles, merchant capture-price assumptions, curtailment risks, balancing costs, and downside market scenarios. A solar project that appears highly bankable under a relatively stable price environment may become considerably less attractive if midday price compression accelerates beyond expectations.

Greece and Bulgaria are among the first SEE markets to illustrate this transition. Strong solar production contributed to lower weekly electricity prices and increased export availability, delivering benefits for consumers and supporting regional system adequacy. However, these same developments also signal the early stages of more pronounced solar-price cannibalization, where an expanding fleet of solar assets increasingly competes within the same generation window. As installed solar capacity continues to grow, the pressure on captured revenues is likely to intensify.

Energy storage is emerging as one of the most effective tools for addressing this challenge. Co-located battery systems allow a portion of solar generation to be shifted into higher-value evening periods, helping to reduce curtailment and improve revenue stability. Storage can also unlock additional income streams through balancing services, ancillary services, and congestion management, where market frameworks permit. From a financing perspective, storage can strengthen a project’s risk profile, provided that revenue-stacking assumptions are realistic and supported by credible contractual arrangements.

Corporate Power Purchase Agreements (PPAs) represent another important solution, particularly for industrial consumers facing pressures related to CBAM compliance, electricity-price volatility, and supply-chain decarbonization requirements. However, PPA structures are also evolving. Traditional pay-as-produced solar agreements may transfer significant shape risk to buyers. Increasingly, market participants are exploring more sophisticated arrangements that include firming mechanisms, hourly matching requirements, guarantees of origin, balancing services, and documentation that supports embedded-emissions reporting.

Solar energy remains one of the most attractive investment opportunities in Southeast Europe, but the market is entering a more complex phase of development. Future success will depend less on installed capacity alone and more on factors such as grid access, realistic capture-price modelling, storage integration, and the strength of offtake arrangements. In modern solar finance, the critical question is no longer simply how much electricity a project generates. It is when that electricity is produced, where it enters the system, and at what realized price it can ultimately be sold.

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Including Slovenia’s share of output from the Krško nuclear power plant, domestic facilities produced a total of 10,948 GWh of electricity. Over the same period, total electricity consumption—including grid losses—reached 13,228 GWh, leaving the country partially dependent on imports to meet demand.

Electricity production declined compared with the previous year, primarily due to weaker hydrological conditions that reduced output from hydropower plants. Additional pressure came from planned maintenance at Krško, which was offline for most of October. At the same time, operations at TEŠ Unit 6 (Šoštanj Thermal Power Plant) were largely dictated by district heating needs, limiting flexibility in electricity generation.

Despite these constraints, renewable energy remained the dominant source in Slovenia’s electricity mix, accounting for 51.8% of total generation. Nuclear energy contributed 23.8%, while fossil fuel-based generation made up the remaining 24.4%.

Hydropower experienced a significant decline, falling to 4,222 GWh from 5,450 GWh in 2024, reflecting unfavorable water conditions. As a result, total renewable output dropped by 13.3% year-on-year to 6,035 GWh. In contrast, solar power continued its rapid expansion, with photovoltaic generation rising to 1,606 GWh, up from 1,282 GWh a year earlier—an increase of roughly 25%.

Energy Agency Director Duška Godina noted that the results demonstrate continued progress in expanding low-carbon electricity sources. However, she also emphasized that fluctuating weather patterns and broader geopolitical uncertainties continue to test the resilience of Slovenia’s energy system, underlining the need for sustained investment in its long-term energy transition.

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The project will consist of four wind turbines, each rated at 7.2 MW, featuring rotor diameters of around 170 metres and a maximum height of approximately 215 metres. The permit currently covers only the wind farm infrastructure itself, while a separate approval process is still required for the grid connection, which is necessary before the project can be fully commissioned and begin operation.

The Bana wind farm represents the first concrete step in a much larger development pipeline led by Green Energy Investhor. The company’s broader programme spans three Hungarian counties—Győr-Moson-Sopron, Komárom-Esztergom, and Vas—and includes planned projects across 16 municipalities.

According to CEO Antal Ritter, the approval marks the end of several years of development work and the beginning of the execution phase of the company’s wind expansion strategy. If fully realized, the portfolio would include around 70 wind turbines, generating approximately 1,200 GWh of electricity annually, significantly increasing Hungary’s installed wind capacity.

However, the company still faces additional regulatory steps before construction can proceed on a larger scale. These include further permitting processes and network connection approvals, which remain essential for integrating the new capacity into the national grid.

The investment programme is designed to strengthen Hungary’s domestic renewable energy supply and reduce dependence on imported electricity. It is also expected to complement the country’s rapidly expanding solar generation fleet, as wind power provides output under different weather conditions and helps improve overall system flexibility and balance.

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Since the onset of the heatwave, peak demand has risen from typical summer levels of 6,000–6,500 MW to around 9,000 MW, forcing nearly all available dispatchable generation units to remain in operation to maintain system stability.

Natural gas-fired plants have been running continuously since 24 June, while PPC’s lignite unit Ptolemaida V has also been activated, particularly during evening hours when solar output drops and the system must rely on flexible thermal generation to meet demand. The situation underscores the ongoing challenge of balancing a grid that is increasingly dominated by solar generation during the day but still dependent on conventional plants during peak and ramping periods.

As photovoltaic production declines after sunset, wind generation becomes a critical balancing factor. Strong wind output reduces the need for gas and lignite plants, while weaker conditions increase their operational role in covering the evening demand gap. This interaction highlights the growing importance of weather variability in shaping short-term system stability.

The heatwave affecting much of Europe has also reinforced the need for sufficient reserve capacity. Greece’s transmission system operator ADMIE has stated that available generation is adequate even if peak demand approaches 10,000 MW, suggesting that the system remains secure under current stress conditions.

Nearly the entire gas-fired fleet is expected to remain online throughout the summer, with only one unit currently offline due to technical maintenance. ADMIE has also reportedly requested that PPC keep the lignite plant Ptolemaida V available at least through the end of the 2026/27 winter season, reflecting continued reliance on dispatchable thermal capacity.

Hydropower is providing additional system flexibility. Reservoir levels at PPC facilities are estimated to be 20–25% higher than last year, offering a stronger buffer for peak demand periods and improving the system’s ability to respond to short-term fluctuations in both demand and renewable output.

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The new special purpose vehicle (SPV) has been created by the Hellenic Hydrocarbons and Energy Resources Management Company (EDEYEP) and will be responsible for conducting wind measurements, marine studies, and seabed analysis across selected offshore zones. These studies are essential for determining the technical feasibility of future offshore wind projects.

At this stage, EDEYEP is the sole shareholder, but the ownership structure is expected to expand as the program advances. Future participation may include the electricity transmission system operator ADMIE, financial institutions, and private sector developers involved in Greece’s National Offshore Wind Programme, including companies such as Hellenic Cables.

The initial survey campaign will focus on offshore areas near Evia, Gyaros, eastern Crete, and Rhodes, which together are estimated to have the potential to support around 1.3 GW of offshore wind capacity. Pilot projects planned near Alexandroupoli are not included in this phase of development.

A key driver behind the creation of the SPV is compliance with the requirements of Greece’s Recovery and Resilience Facility (RRF), which set a deadline of 30 June for its establishment. While the corporate structure is still evolving, authorities emphasize that securing funding for the survey work is the immediate priority, as completing the technical studies on time is critical for keeping the broader offshore wind roadmap on track.

The launch of the SPV is being seen as one of the clearest signals yet that Greece’s offshore wind strategy is moving from planning into an early implementation phase. However, investors are still calling for a more detailed and transparent timeline for both the survey campaign and the subsequent development stages, including licensing and project execution.

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The project, implemented on the roof of the local Volunteer Fire Department building, is based on a jointly financed solar photovoltaic installation that began producing electricity on 1 June. From July onward, the generated electricity is being shared among 17 participating members, including households, a small business, and the fire department itself. The allocated energy is directly reflected on participants’ electricity bills, reducing their individual consumption costs.

Instead of installing separate rooftop systems, the community chose a collective model in which members co-invested in a single installation and share both the energy output and financial benefits. According to the Regional Energy and Climate Agency of Northwest Croatia (REGEA), this makes Spickovina the first fully functioning example of a legally enabled energy community operating in Croatia.

Although Croatia introduced the legal framework for energy communities several years ago, implementation had been limited. The Spickovina project—developed under the European SHAREs programme—is the first to move beyond theory into a working, real-world structure for local energy sharing. REGEA managed the technical design, administrative process, and community coordination, while the City of Zabok provided financial and organizational support.

The initiative is already expanding into a second phase. Through the EU-funded ENERCOM Facility (LIFE programme), the community secured €45,000 to develop a long-term business plan. Additional support will come from the Citizen-Led Renovation programme, which will help members assess further efficiency upgrades, including insulation improvements, window replacements, heating system modernization, and potential heat pump installations.

REGEA highlighted the project as a replicable model for other municipalities in Croatia, suggesting that Spickovina could serve as a blueprint for future community-based renewable energy schemes across the country.

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The strongest benchmark signal came from Hungary, where HUPX settled at €116.43/MWh, rising by €44.1/MWh day-on-day. Romania followed almost exactly at €116.29/MWh, while Slovenia and Croatia converged tightly around the same level at €116.22/MWh and €115.71/MWh, confirming a re-established Central Eastern European pricing cluster. These markets effectively traded as a single coupled zone for much of the session, with only marginal divergence between them.

Further south, Montenegro stood out as the most volatile mover. BELEN surged to €133.23/MWh, an increase of €74.6/MWh, making it the most expensive SEE market outside Italy. At the top of the regional structure, Italy reached €144.03/MWh, maintaining its role as the dominant regional price premium hub and continuing to pull south-eastern flows toward the Adriatic basin.

At the other end of the spectrum, Serbia traded at €97.84/MWh, remaining significantly below the Hungarian benchmark (by €18.59/MWh) and well under Italian levels (by more than €46/MWh). North Macedonia was the regional low at €90.94/MWh. Importantly, Serbia’s discount was not the result of surplus generation. Instead, it reflected a more complex structure of hourly scarcity, cross-border constraints, and segmented market dynamics, as the country remained a net importer despite lower prices.

The fundamental driver of the price rebound was a sharp recovery in regional consumption. Total HU+SEE demand increased to 30,779 MW, up by 3,332 MW compared to Sunday. At the same time, total net imports fell from 2,006 MW to 1,294 MW, meaning that a larger share of demand was met through domestic generation and internal redispatch rather than additional external supply.

Cross-border flows confirmed the system’s dual orientation. Imports from the CORE region remained significant, with AT+SK → HU+SEE flows at 2,477 MW, while the region continued to export toward Italy at 1,089 MW. This created a structural pattern where SEE and Hungary simultaneously relied on north-western imports while supplying higher-priced demand in Italy. The result is a two-directional balancing system, where flows are dictated more by price differentials than by simple regional surplus or deficit positions.

The most important market signal was not the daily average, but the intraday price shape. In Hungary, prices ranged from a low of €37.2/MWh at H11 to a peak of €215.2/MWh at H21. Romania showed a nearly identical structure, moving from €36.7/MWh at H11 to €212.6/MWh at H21. Serbia also displayed strong volatility, with a low of €23/MWh at H12 and a peak of €150.1/MWh at H21.

This pattern reflects a classic summer solar profile: midday oversupply from photovoltaic generation suppresses prices, while the evening ramp—when solar output falls but cooling demand persists—creates acute scarcity. The fact that Hungary’s off-peak average (€144.6/MWh) exceeded its peak average (€88.3/MWh) highlights a structural shift: traditional peak/off-peak definitions are losing relevance, replaced by a sharper evening-only scarcity window.

For flexibility assets, the signal was particularly strong. Intraday spreads reached approximately €178/MWh in Hungary, €176/MWh in Romania, and €127/MWh in Serbia, creating clear arbitrage opportunities for battery storage, demand response, and flexible generation targeting the H20–H22 ramp period.

Country balance data confirms a highly fragmented system rather than a unified regional block. Bulgaria remained the strongest exporter (1,393 MW net exports), supported by robust generation of 5,323 MW against consumption of 3,931 MW. Greece also stayed in export mode with 618 MW net exports, while Bosnia and Herzegovina exported 355 MW.

On the import side, Croatia (1,015 MW), Hungary (861 MW), Romania (588 MW), Serbia (545 MW), Slovenia (285 MW), Montenegro (217 MW), and Albania (120 MW) all remained net importers. The result is a hybrid regional structure, where Bulgaria and Greece provide export liquidity while Central and Western SEE markets rely on cross-border balancing.

Serbia’s position is particularly instructive. Despite a relatively low price, it remained a 545 MW net importer, with generation at 2,807 MW versus consumption of 3,352 MW. Flow patterns show Serbia importing from multiple neighbors while simultaneously exporting into selected directions, confirming its role as a transit and balancing node rather than a purely surplus or deficit market.

Montenegro also illustrates how corridor dynamics shape pricing. With only 209 MW of generation and 426 MW of consumption, it remained structurally short domestically. However, strong export flows toward Italy—432 MW on base and 458 MW on peak—positioned it as a physical bridge into the Italian premium market, explaining its elevated clearing price despite net import conditions.

The forward curve reinforces the short-term tightening narrative. Hungarian week-ahead contracts remained elevated, with Week 28 at €110/MWh and Week 29 at €146/MWh, while the HU-DE spread for Week 29 reached €30.5/MWh, indicating continued expectations of regional premium pricing.

On the fuel side, gas remained stable rather than volatile, with CEGH at €45.90/MWh and Greek gas at €43.75/MWh, while EUA carbon prices hovered around €80.6/t. This confirms that the day’s price action was driven primarily by load recovery, cross-border flows, and intraday flexibility constraints, rather than fuel or carbon shocks.

The broader conclusion from 6 July is clear. The SEE power system is increasingly defined by hourly scarcity rather than average conditions. Italy remains the premium sink, Montenegro acts as a corridor-linked volatility hub, Serbia reflects segmented import-based pricing despite lower averages, and Hungary continues to function as the central convergence benchmark.

Across the region, pricing is no longer determined by baseload fundamentals alone. Instead, it is shaped by the interaction between solar-driven midday compression and evening ramp scarcity, where flexibility—not volume—defines market value.

The post SEE power prices reprice higher as Monday demand returns and Italy pulls regional flows appeared first on Serbia SEE Energy Mining News.

This creates a market environment that is best described as price relief without structural reassurance. Lower spot prices improve immediate economics, but they do not eliminate the medium-term uncertainty tied to seasonal balancing. Storage remains the central stabilizing mechanism in the European gas system. When inventories are high, the market is better equipped to absorb demand spikes, supply disruptions, and LNG competition. When inventories are comparatively low, the system must rebuild confidence during the injection season, which keeps forward curves sensitive even in periods of weak demand.

Within Southeast Europe, the impact of storage conditions is uneven across countries. Italy remains one of the most exposed markets due to its large consumption base and continued reliance on both LNG and pipeline imports. Hungary plays a critical balancing role thanks to its significant storage capacity and strong integration with Central European gas flows. Croatia, through its Krk LNG terminal, provides an important diversification point for regional supply security. Greece increasingly acts as a flexible LNG-supported hub with growing regional relevance. In contrast, Serbia remains more dependent on long-term pipeline arrangements, giving it a different and more constrained flexibility profile compared with EU-connected markets.

The importance of gas fundamentals is further reinforced through the electricity sector. Even with expanding renewable generation across SEE, gas-fired power plants remain essential for system balancing, particularly during peak and evening hours. Week 25 showed that gas generation can increase significantly when hydro output weakens, wind production drops, or demand rises. This confirms that gas security remains closely tied to electricity system security, especially in stress periods.

For industrial consumers, the current lower TTF environment offers short-term procurement relief, but it does not justify a reduction in forward risk awareness. The key issue is not only today’s price level, but whether storage capacity, LNG availability, and cross-border pipeline flexibility are sufficient to ensure stability during the winter period. As a result, hedging strategies must continue to reflect seasonal risk rather than relying solely on spot market conditions.

For policymakers and system operators, the message is equally clear. Even in a transitioning energy system, gas infrastructure remains strategically critical. Storage facilities, LNG terminals, interconnectors, and efficient balancing frameworks continue to shape not only gas markets but also electricity price formation and broader energy security. While these assets may appear less visible than new renewable generation, they remain fundamental to maintaining price stability and managing volatility.

Overall, SEE gas markets are currently characterized by a dual reality: lower prices in the short term, but weaker comfort in the system balance. The summer price signal has improved, but the underlying winter risk has not disappeared.

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Between June 29, 2026 and July 5, 2026, 96 articles were published.

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