Further south and east, the correction was considerably deeper. Bulgaria fell to €153.82/MWh, Greece to €146.57/MWh, Serbia to €131.98/MWh, Albania to €152.48/MWh, Montenegro to €150.06/MWh and North Macedonia to €139.95/MWh. Serbia recorded the lowest regional price, while the Italian benchmark increased to €180.89/MWh, creating an almost €49/MWh gap between the cheapest and most expensive markets.

The scale of the daily correction is more significant than the absolute price level. A simple unweighted basket of HUPX, OPCOM, IBEX, HENEX, BSP, CROPEX, SEEPEX, ALPEX, BELEN and MEMO fell from approximately €163.94/MWh to €152.03/MWh, a decline of around 7.3% in a single session. Albania recorded the largest nominal decline at €25.50/MWh, followed by Serbia at €19.20/MWh, North Macedonia at €14.70/MWh, Bulgaria at €13.90/MWh and Greece at €13.30/MWh. Germany also weakened significantly, falling €17.80/MWh to €148.22/MWh, while Austria declined by €2/MWh to €165.16/MWh. Italy was the exception, gaining €5.40/MWh.

The resulting geographical price structure was considerably wider. HUPX traded at a €13.11/MWh premium to Germany, Serbia was €29.35/MWh below Hungary, and Italy carried a €19.55/MWh premium to HUPX.

The correction should nevertheless not be interpreted as a return to genuinely low regional prices. Hungary’s €161.34/MWh remained roughly 5% above its seven-day average of €153.5/MWh. Romania’s €160.86/MWh was more than 6% above its seven-day average, while Greece, despite one of the largest daily declines, remained almost 13% above its seven-day average of €129.9/MWh. Serbia’s €131.98/MWh was also around 9% above its seven-day average. The session therefore appears to represent a correction from the extreme tightness of the previous several trading days rather than a structural move towards lower prices.

The most important trading signal is visible in the hourly price profiles. HUPX’s peak block averaged just €148.9/MWh, while off-peak power averaged €173.8/MWh, producing an unusual inversion of almost €25/MWh. The Hungarian price reached a daily minimum of €107.7/MWh at hour 14, before climbing to €211.8/MWh at hour 20. Romania showed an almost identical pattern, with peak power at €148/MWh, off-peak at €173.7/MWh, a minimum of €106.1/MWh and an evening maximum of €211.5/MWh. Slovenia displayed a similar inversion, with peak power at €150.3/MWh against €173.5/MWh off-peak.

The shape of the curve is therefore becoming more important than the daily average. Value is increasingly concentrated in the evening ramp, while solar-heavy daytime hours are becoming materially cheaper.

Greece provided the clearest example. HENEX’s base price fell to €146.57/MWh, but its peak block averaged only €119.4/MWh, compared with €173.7/MWh off-peak. The Greek market reached a minimum of just €33/MWh at hour 10, before climbing to €211.2/MWh at hour 20. Bulgaria showed the same pattern, albeit less dramatically, with peak power at €133.9/MWh, off-peak at €173.7/MWh, a daily minimum of €69.1/MWh and a maximum of €211.2/MWh. Croatia remained more closely aligned with Hungary, with peak power at €149.2/MWh and off-peak at €173.5/MWh.

The Mediterranean and Balkan markets are increasingly pricing two different systems within the same delivery day: a heavily supplied solar period followed by a much tighter evening and overnight balance.

The western Balkans were less closely aligned with central European markets but displayed the same underlying structure. Serbia recorded the regional low at €131.98/MWh, with peak power averaging €127.3/MWh, off-peak at €136.7/MWh, a daily minimum of €75.3/MWh and a maximum of €200/MWh. Montenegro averaged €150.06/MWh, but its maximum reached €221.1/MWh. Albania reached €220.6/MWh despite a base price of €152.48/MWh. Albania’s off-peak block averaged €170.1/MWh, more than €35/MWh above its peak value. North Macedonia showed a similar inversion, with peak power at €124.6/MWh and off-peak at €155.3/MWh.

These profiles reinforce the increasing importance of flexibility rather than base-load energy value. Generators and storage assets capable of shifting output into the 19:00–22:00 period are exposed to a fundamentally different price environment from solar-heavy daytime generation.

The physical balance explains much of the downward move. Regional HU+SEE consumption increased to 32,506 MW from 31,360 MW, a day-on-day gain of 1,146 MW, or around 3.7%. Generation, however, recovered more strongly, rising from 29,758 MW to 31,839 MW, an increase of just over 2.08 GW, or approximately 7%.

As supply expanded faster than demand, the region’s net import requirement fell from 1,601 MW to just 667 MW, a reduction of 934 MW. Imports from the core Austria-Slovakia direction declined from 2,044 MW to 1,383 MW, while regional exports towards Italy increased from 450 MW to 915 MW. In a single trading session, SEE therefore required substantially less northern supply while sending more than twice as much electricity westward towards the higher-priced Italian market.

Renewables added another important layer. The 20 August forecast put regional solar production at 8,666 MW, up 1,793 MW from the previous day, while wind generation was forecast at 1,539 MW, an increase of 634 MW. Together, solar and wind were expected to add approximately 2.43 GW of generation day on day.

That increase helps explain the simultaneous combination of higher regional consumption, lower net imports and weaker peak-block prices. The market was not simply responding to falling demand. The region was consuming more electricity while requiring less external supply because generation increased even faster.

Hungary’s balance is particularly revealing. Hungarian consumption declined from 4,437 MW to 4,081 MW, while generation increased from 2,938 MW to 3,077 MW. The country’s net import requirement consequently narrowed from 1,500 MW to 1,004 MW, a reduction of roughly one-third.

The structure varied sharply by trading block. Hungary was marginally a net exporter during the peak block, at 97 MW, but imported an average of 2,105 MW during off-peak hours. Base flows included approximately 786 MW from Romania and 881 MW from Slovakia, while Hungary exported 411 MW to Croatia, 144 MW to Serbia and 352 MW to Slovenia on a base basis.

The daily average therefore masks a system that moves from heavy import dependence overnight to near balance during solar-supported daytime periods.

This also helps explain the sharp widening of the German-Hungarian price spread. HUPX declined, but Germany declined much faster. German base power fell to €148.22/MWh, leaving Hungary €13.11/MWh higher, compared with only around €2/MWh previously. Germany’s intraday profile was even more compressed, with peak power at €123.8/MWh, off-peak at €172.6/MWh and a midday minimum of €63.7/MWh.

The widening Hungarian premium therefore did not reflect a new upward move in Hungary. Instead, it reflected Germany’s more aggressive repricing lower alongside reduced core-to-SEE imports.

Greece provides an even clearer example of the connection between renewables, cross-border flows and hourly price formation. Greek consumption stood at 6,834 MW, generation at 7,629 MW and net exports at 795 MW. The block split was extreme: Greece exported an average of 1,516 MW during peak hours, compared with only 73 MW off-peak.

Its base flow towards Italy increased to approximately 412 MW, while exports to North Macedonia remained around 401 MW. At the Bulgaria border, the direction reversed depending on the trading block. Greece exported strongly during peak hours but became an importer during off-peak periods.

The same hours in which HENEX prices collapsed were therefore the hours when Greek surplus electricity was being pushed into neighbouring markets.

Romania also moved considerably closer to balance. Consumption was almost unchanged at 5,670 MW, compared with 5,693 MW a day earlier, but generation increased from 5,037 MW to 5,533 MW. Net imports consequently fell from 656 MW to just 137 MW.

Romania was actually a 560 MW net exporter during the peak block, while importing 834 MW off-peak, another clear demonstration of the daytime-versus-night-time split. Romanian flows towards Hungary averaged approximately 786 MW on a base basis and rose above 2.1 GW during peak hours, while Romania simultaneously imported substantial volumes from Bulgaria.

OPCOM’s near-perfect convergence with HUPX — €160.86/MWh versus €161.34/MWh — therefore sits on top of an increasingly active transit and balancing position rather than a static national deficit.

Bulgaria remained one of the region’s strongest net exporters, with average exports rising to 1,294 MW, from 1,224 MW on 19 August. Generation reached 5,334 MW, compared with consumption of 4,040 MW.

Base exports included 846 MW towards Romania, 314 MW towards Serbia and 130 MW towards North Macedonia. The Bulgaria-Greece border again revealed a solar-driven hourly reversal. Bulgaria’s daily base position showed exports of 104 MW to Greece, but the peak block saw 456 MW flowing in the opposite direction, while off-peak Bulgaria exported 664 MW southward.

That reversal closely mirrors Greece’s very low peak prices and stronger daytime export surplus.

Italy provided the destination for much of the surplus and remained the main premium market. Italy South averaged approximately €180.89/MWh, with peak power at €173/MWh and off-peak at €188.8/MWh. Its minimum price was still €153/MWh, dramatically higher than the daytime lows seen in Germany, Greece, Bulgaria and Serbia.

Even Italy’s cheapest hours therefore retained significant value relative to the weakest periods in SEE and central Europe. The increase in SEE exports towards Italy from 450 MW to 915 MW is consistent with that price signal: available interconnection capacity had a clear economic incentive to move electricity westward.

The forward market reinforced the view that the sell-off was concentrated in prompt electricity rather than being driven by cheaper fuels. Hungarian Week 35 power fell €4.50/MWh to €146.50/MWh, Week 36 declined €1/MWh to €147/MWh, and September fell €2.50/MWh to €156/MWh. The Cal-26 contract, by contrast, edged €0.50/MWh higher to €129/MWh.

Hungarian Week 35 had fallen 8.44% over the preceding trading window shown in the report, compared with only 0.4% for Germany, while Italy gained 2.1%. Hungarian prompt risk has therefore repriced much more aggressively than neighbouring western contracts.

Fuel markets were not sending the same bearish signal. CEGH gas stood at €64.51/MWh, up €0.70/MWh, while the Greek gas marker increased €0.60/MWh to €54.93/MWh. EUA allowances slipped only €0.60/t to €81.71/t. September coal rose $2/t to $124/t, while Q4 coal increased $1/t to $127/t.

At the same time, the Hungarian-German forward spread remained substantial, at €23.50/MWh for Week 35, €25/MWh for Week 36, €24/MWh for September and €20/MWh for Cal-26.

Prompt electricity therefore weakened despite broadly firm fuel inputs, pointing towards weather, renewable generation, cross-border flows and system balance as the dominant drivers of the session rather than a fundamental change in thermal generation economics.

The 20 August trading session leaves SEE with a more complex market structure than the fall in daily averages initially suggests. Base prices corrected across almost every market, regional generation recovered faster than consumption, net imports fell by more than half and exports towards Italy doubled.

Yet the hourly market retained very large scarcity premiums after solar production faded. HUPX moved from €107.7/MWh at its daytime low to €211.8/MWh in the evening, Greece from €33/MWh to €211.2/MWh, while Albania and Montenegro reached evening highs above €220/MWh.

The dominant trading feature is therefore no longer simply whether the regional base price is rising or falling. Increasingly, it is the widening value gap between solar-heavy daytime electricity and the evening ramp, with interconnection capacity determining how efficiently those surpluses and deficits can be redistributed across South-east Europe, Central Europe and Italy.

The post SEE electricity prices fall as stronger generation widens intraday spreads appeared first on Serbia SEE Energy Mining News.

The plant initially reduced reactor output toward approximately 80% of capacity, with the operator warning that additional reductions could be required if river conditions deteriorate further.

Krško’s importance reaches well beyond Slovenia. The plant supplies approximately 20% of Slovenian electricity demand and around 16% of Croatian demand, reflecting the shared ownership and long-standing cross-border role of the nuclear station.

Any sustained reduction therefore affects two national electricity balances simultaneously.

Environmental restrictions are central to the operating decision. The daily average temperature of the Sava after cooling-water mixing is required to remain below 28°C, while separate limits also apply to the permitted increase in river temperature caused by the plant.

During periods of high ambient temperature and low river flow, the amount of heat the river can absorb declines, forcing the plant to reduce generation even when the reactor itself remains technically available.

The constraint is increasingly important because it demonstrates that nuclear generation, although largely insulated from fuel-price and renewable intermittency risk, is not completely independent of weather.

Plants using rivers for cooling can face output restrictions during severe heat and drought conditions, particularly when environmental regulations tightly limit thermal discharge.

The situation at Krško mirrors, in a different technical form, developments at Romania’s Cernavoda nuclear station. Both 680 MW Cernavoda units have been unavailable because exceptionally low Danube flows reduced cooling-water availability.

Romania has responded by restarting nearly 300 MW of coal-fired capacity at Rovinari.

Krško has not faced the same complete shutdown, but its reduction toward 80% removes a meaningful block of low-variable-cost generation from the Slovenian-Croatian market.

At full 730 MW capacity, an output reduction toward 80% implies that roughly one fifth of the plant’s potential generation is temporarily unavailable. The exact lost energy depends on the duration and operating profile of the restriction.

The impact is particularly relevant during hot weather because high temperatures can simultaneously increase air-conditioning demand while reducing cooling capability at thermal and nuclear plants.

This creates a difficult power-market combination: consumption strengthens at precisely the point when some large conventional generators become less able to operate at full capacity.

Solar generation can offset part of the daytime demand increase, but the evening remains more challenging once photovoltaic output falls. Slovenia and Croatia have recently exhibited day-ahead price profiles with sharp evening ramps, underlining the value of dispatchable generation during those hours.

A reduced Krško contribution can therefore increase reliance on imports, hydroelectric production and other thermal generation.

The financial implications depend on market prices and the duration of the derating. Nuclear plants typically have high fixed costs but comparatively low marginal generation costs, meaning electricity not produced during high-price periods can represent economically valuable lost output.

No estimate of lost revenue or the duration of the current restriction has been provided in the information reviewed.

The wider system issue is more structural. Climate conditions capable of simultaneously lowering river flows and increasing water temperatures challenge operating assumptions developed around historical hydrological patterns.

That does not make nuclear generation unreliable, but it increases the importance of cooling-system design, environmental limits and contingency planning in long-term generation adequacy.

Krško remains one of the most important electricity assets shared between two southeastern European countries. Its 730 MW capacity anchors both the Slovenian and Croatian systems, while stable nuclear generation normally helps reduce exposure to volatile wholesale imports.

The current reduction shows that even this low-carbon baseload supply can become weather-sensitive during extreme summer conditions.

Across the Balkans, the same drought episode is now influencing hydro production, nuclear cooling, thermal dispatch, electricity imports and petroleum transport. Krško’s reduced output is another reminder that regional energy security increasingly depends not only on installed capacity but on the physical conditions that allow that capacity to operate.

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Electricity generation between 1 January and 9 August reached approximately 26,906 GWh, an increase of 7.79% year on year. Consumption rose by a slightly slower 6.8% to 25,046 GWh, allowing Bulgaria to maintain a positive balance between domestic output and demand.

The resulting electricity trade surplus reached around 1,860 GWh, compared with 1,511 GWh during the corresponding period of the previous year.

The hydropower sector produced the most dramatic change. Output increased from approximately 1,811 GWh to 3,396 GWh, almost doubling year on year and adding more than 1.5 TWh of electricity to the system.

That increase is important because hydro generation has a disproportionate influence on southeastern European wholesale markets. Unlike solar, reservoir hydro can often be shifted toward higher-value hours, giving it a stronger role in balancing and evening-price formation.

Bulgaria’s improved hydro position has therefore supported not only higher annual electricity production but also the system’s ability to export and respond to volatile regional demand.

Renewable output on both transmission and distribution networks has also increased, further strengthening supply.

Bulgaria has historically occupied an important exporting position in the Balkans because of its combination of nuclear, thermal, hydro and renewable generation. The Kozloduy nuclear power plant provides a large block of baseload production, while coal-fired capacity still plays an important role in balancing the system. Growing solar capacity has increasingly transformed the daytime profile.

The 2026 figures suggest that the country has been able to absorb rising domestic consumption while still expanding its net electricity surplus.

That becomes especially valuable during regional supply disturbances. Romania has recently faced the simultaneous outage of both Cernavoda nuclear units because of low Danube flows, while other Balkan markets have experienced weaker hydrology or higher summer demand.

A country maintaining an exportable surplus can capture higher prices during those periods and provide balancing energy across interconnected markets.

Day-ahead prices nevertheless show that physical surplus does not necessarily translate into permanently cheap electricity. Bulgaria has recently traded almost in line with Hungary, Romania, Slovenia and Croatia during periods of strong regional coupling.

Cross-border prices are increasingly determined by the marginal regional unit and available interconnection capacity rather than by each country’s annual generation balance in isolation.

Bulgaria’s advantage therefore lies in optionality rather than guaranteed low prices. Higher domestic generation gives generators greater ability to export when neighbouring markets pay a premium while reducing the likelihood that Bulgaria itself needs to import during tight periods.

The increase from 1,511 GWh to 1,860 GWh in the trade surplus represents a rise of roughly 349 GWh, even while consumption expanded materially. That indicates that generation growth has been sufficient not merely to keep pace with demand but to improve the external balance.

Hydro will remain the most variable component. The jump from 1,811 GWh to 3,396 GWh is unlikely to repeat mechanically every year, because reservoir and river conditions can change sharply. The additional output should therefore be viewed as a strong 2026 contribution rather than a permanent new baseline.

That distinction matters for investment planning. Solar and wind capacity can structurally increase the country’s renewable generation base, while hydro performance remains partly cyclical.

Bulgaria’s current position nevertheless gives it one of the stronger generation balances in southeastern Europe. Rising domestic demand has not eliminated export capability, nuclear generation remains central to the system, and stronger hydro has provided a large additional energy contribution.

In a region where individual plant outages and weather events can rapidly alter cross-border flows, the ability to maintain a sustained surplus has strategic as well as commercial value.

The post Hydropower recovery pushes Bulgaria deeper into electricity surplus appeared first on Serbia SEE Energy Mining News.

The two companies have signed a memorandum covering the possibility of Transgaz becoming a shareholder in Argent LNG, which is developing a planned 25 million tonne-per-year liquefied natural gas export facility at Port Fourchon in Louisiana.

Argent is targeting first LNG cargoes in 2030, placing the project firmly within the next generation of US export infrastructure rather than the currently operating Gulf Coast facilities.

For Transgaz, the potential transaction is strategically notable because Romania increasingly sees its pipeline network as part of a broader north-south gas corridor serving central and eastern Europe. The commercial concept associated with Argent LNG envisages US gas reaching Romania before moving toward Moldova, Ukraine, Hungary, Austria, Slovakia, the Czech Republic and Germany.

That geography closely mirrors the political and infrastructure logic behind the Vertical Gas Corridor, which is designed to strengthen connections from southern and southeastern European import points toward markets traditionally dependent on east-west gas flows.

Romania occupies a particularly important position within that architecture. It already has domestic gas production, extensive transmission infrastructure and direct connections to several neighbouring markets. The eventual development of the Black Sea’s offshore gas resources could further strengthen its position as both producer and transit state.

An investment in US LNG would add another layer: access to upstream international supply rather than dependence exclusively on pipeline transportation fees.

The proposed 25 million tonnes per year capacity at Port Fourchon is large enough to make Argent a globally significant LNG project if completed. Transgaz has not disclosed the size of any potential shareholding, the amount it could invest, or the commercial rights that might accompany an equity position.

Those details would determine whether participation functions primarily as a strategic minority investment or gives Transgaz access to LNG volumes, capacity rights or long-term commercial arrangements.

The distinction matters financially. Transgaz remains a regulated infrastructure company whose core economics are tied to network investment, transmission tariffs and permitted returns. Moving capital into an LNG export development introduces different construction, commodity, financing and geopolitical risks from those associated with regulated pipeline assets.

At the same time, the potential strategic benefit is clear. Equity participation in an export project can provide a stronger relationship with future gas supply than simply purchasing cargoes through intermediaries after liquefaction capacity has already been allocated.

The timing also reflects the structural changes in Europe’s gas market since the sharp reduction in Russian pipeline flows earlier in the decade. Central and southeastern European countries have invested heavily in interconnectors, LNG-access routes and reverse-flow capability, turning infrastructure that was previously oriented toward Russian imports into a more multidirectional system.

Romania’s location allows it to connect Black Sea supply, LNG imported through regional terminals and flows moving toward Moldova and Ukraine. Transgaz has consequently become an increasingly strategic regional operator rather than a purely domestic transmission company.

The proposed Argent relationship extends that strategy across the Atlantic.

No transaction value, ownership percentage, expected return or final investment decision has been disclosed. The memorandum should therefore be treated as an exploratory agreement rather than a committed acquisition. Development of a large LNG export terminal also requires substantial financing, construction capacity, regulatory approvals and long-term offtake before commercial operation can begin.

The 2030 target leaves several years during which both the US project and European gas demand could change significantly.

Yet the direction of travel is important. Transgaz is evaluating whether security of supply and regional transit relevance justify placing capital directly into the infrastructure that would produce future LNG cargoes.

That represents a much broader concept of gas-network strategy than simply building pipelines inside Romania. It links domestic transmission assets to a potential US liquefaction project and positions Romania as one of the entry points through which Atlantic LNG could move toward some of Europe’s most supply-sensitive markets.

The post Transgaz explores US LNG equity investment as Romania expands regional gas ambitions appeared first on Serbia SEE Energy Mining News.

The photovoltaic development represents an investment of approximately €100 million and marks Entek’s first renewable-generation investment in Romania. The company is part of Turkey’s Koç Group, one of the country’s largest industrial conglomerates, adding another well-capitalised strategic investor to Romania’s rapidly expanding renewable market.

The financing structure is significant because the €71.4 million facility covers a substantial share of the disclosed project cost, illustrating the willingness of Romanian banks to provide large-scale debt for utility-scale solar assets. The remaining capital requirement would need to be covered through sponsor equity or other financing, although the precise capital structure has not been disclosed.

At 205 MWm, Niculesti belongs to the larger generation of Romanian photovoltaic projects rather than the smaller merchant solar plants that characterised the market’s earlier development phase. Projects of this scale increasingly depend on the combination of bankability, network access, credible construction counterparties and a route to market that can withstand growing solar-price cannibalisation.

Romania has become one of southeastern Europe’s most active renewable-development markets, driven by a large electricity system, comparatively strong interconnection with neighbouring countries and a growing pipeline of wind, solar and battery projects. Yet the market is also moving into a more complicated phase. Additional solar capacity increases daytime electricity supply, which can compress wholesale prices during peak photovoltaic production hours while leaving evening prices considerably higher.

That changing intraday profile is already visible in Romanian and regional day-ahead trading. Midday electricity prices can fall sharply relative to evening levels as solar output rises, creating stronger incentives for storage, hybridisation and more sophisticated offtake structures.

Niculesti therefore enters a market in which obtaining grid access is no longer sufficient on its own. The revenue profile of a 205 MWm solar project will increasingly depend on the price captured during actual generation hours rather than the headline annual baseload price.

The presence of Banca Transilvania as lender nevertheless demonstrates continued confidence in the sector. Domestic bank participation is especially important because renewable expansion across southeastern Europe cannot rely entirely on multilateral development banks or foreign infrastructure funds. A scalable domestic debt market can reduce financing friction and provide developers with an alternative to more complex international project-finance structures.

Entek’s ownership also matters. As a member of Koç Group, the company brings an industrial balance sheet and a longer-term strategic perspective that differs from purely financial developers seeking to build and sell projects rapidly after construction. Its entrance into Romania may therefore signal broader Turkish interest in the country’s power market, particularly as interconnection, manufacturing relationships and energy trade deepen across southeastern Europe.

The project’s approximately €100 million total investment corresponds to a large new capital deployment into Dambovita county, while the €71.4 million bank facility makes the transaction one of the more visible examples of commercial-bank support for Romanian solar development.

No specific power-purchase agreement, contract-for-difference exposure, merchant share, operating-cost assumptions or expected equity return was disclosed in the information reviewed. Without those variables, project-level returns cannot be calculated reliably. The financing itself, however, indicates that lenders have obtained sufficient comfort around construction, ownership and expected cash generation to support debt representing a majority of the disclosed investment cost.

The next test for projects such as Niculesti will be integration rather than construction alone. Romania is simultaneously adding large volumes of photovoltaic capacity and accelerating battery-storage investment. Winners Holding and Finas Group, for example, are developing an operational and near-term battery portfolio that is expected to reach 310 MWh, illustrating how rapidly flexibility assets are beginning to accompany renewable expansion.

That relationship will become increasingly important. As solar capacity rises, the marginal value of additional midday generation can decline even while evening scarcity remains pronounced. Developers capable of combining renewable output with storage, flexible offtake or structured hedging will be better positioned than projects exposed entirely to spot-market daytime prices.

Entek’s first Romanian investment therefore arrives at an important transition point. Romania still offers considerable room for renewable growth, but the market is moving from a simple capacity-expansion phase toward one in which financing quality, grid position and captured-price optimisation increasingly determine project economics.

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The wind farm generated approximately 26 GWh during its first three months of operation, electricity that EPCG valued at roughly €2.43 million using prevailing Montenegrin market prices. More important than the revenue number alone is the contribution to EPCG’s physical balance. The company estimates that Gvozd reduced its electricity deficit by around 8.5% during the period, demonstrating the value of adding non-hydro renewable generation to a system still strongly influenced by rainfall, reservoir levels and the operating availability of large thermal assets.

Gvozd has an expected annual generation target of around 150 GWh. At that level, the project becomes material relative to Montenegro’s domestic electricity market, particularly during periods when poor hydrological conditions reduce output from EPCG’s hydroelectric portfolio. Wind does not remove Montenegro’s exposure to weather, but it diversifies that exposure: low reservoir levels and weak river inflows do not necessarily coincide with weak wind conditions, giving EPCG a broader generation mix than it had when hydro and lignite dominated its production profile.

The timing is particularly relevant. The summer of 2026 has again demonstrated the vulnerability of southeastern European electricity systems to hydrological stress. Low river flows have affected hydroelectric production across the region and, in Romania, have also contributed to the shutdown of nuclear generation because of cooling-water restrictions. Montenegro’s power balance has faced the same broader pressure from hot weather, higher seasonal consumption and constrained hydro conditions.

Gvozd therefore represents more than incremental renewable capacity. The project is becoming a hedge against the part of EPCG’s portfolio that is most sensitive to drought.

The utility is already preparing an expansion. Gvozd II, with planned capacity of 21 MW, is being developed under a €26 million contract with Nordex. Completion of the second phase would increase the combined complex to approximately 75.6 MW, with expected annual electricity generation exceeding 210 GWh.

The disclosed contract value implies that the extension is not a marginal addition to the existing project but a meaningful capital programme in its own right. Once both phases are operating, the Gvozd complex would provide EPCG with a larger block of predictable long-term renewable capacity without requiring fuel purchases and without creating the same hydrological exposure as the company’s hydro assets.

The commercial value of the project will nevertheless depend heavily on the timing of production. Wind generation has a materially different system profile from solar. It can produce during evening and overnight periods when photovoltaic output disappears, giving it potentially greater value during the evening scarcity hours that have repeatedly driven Balkan day-ahead prices above midday levels this summer.

That characteristic matters in a market where daily average electricity prices can mask very wide hourly spreads. During the regional trading session for 19 August, several southeastern European markets recorded evening prices above €210/MWh, while some midday hours were close to or below €100/MWh. Wind generation available during those higher-priced periods can therefore carry significantly more system and commercial value than the same amount of energy produced during the solar-heavy middle of the day.

EPCG has not disclosed project-level operating costs, financing structure or expected equity returns for the enlarged Gvozd complex in the information reviewed, making a reliable project IRR impossible to establish from the disclosed figures alone. The strategic value, however, is already visible in the reduction of the utility’s summer energy deficit.

The combination of 54.6 MW already operating, another 21 MW planned, and annual generation potentially rising above 210 GWh gives Montenegro one of its clearest examples of renewable investment directly improving the incumbent utility’s wholesale-market position rather than simply adding capacity to the national generation statistics.

As EPCG continues to develop solar, wind and storage projects, the significance of Gvozd is likely to lie increasingly in portfolio economics. Every additional megawatt-hour produced domestically during periods of weak hydro generation reduces the volume that must be purchased from neighbouring markets, where Montenegro can quickly become exposed to prices above its domestic production cost. The first operating months suggest that Gvozd is already beginning to perform that role.

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The HUPX Hungarian base price settled at €167.99/MWh, up €3.5/MWh from the previous session. Romania’s OPCOM reached €168.04/MWh, only €0.06/MWh above HUPX, while Bulgaria’s IBEX settled at €167.72/MWh, Slovenia’s BSP at €167.94/MWh and Croatia’s CROPEX at €167.91/MWh. The five markets were separated by just €0.33/MWh, creating an exceptionally tight central SEE price zone.

Germany remained slightly cheaper at €166.03/MWh, while Austria stood at €167.21/MWh. Italy continued to trade higher at €175.49/MWh, maintaining a premium of €7.50/MWh over HUPX. Greece rose by €6.2/MWh to €159.88/MWh, leaving it below the central cluster. The overall picture was therefore one of strong central convergence, positioned between cheaper southern Balkan markets and more expensive Italian and Albanian markets.

Across Hungary and the nine SEE exchanges included in the comparison, the unweighted average base price was approximately €163.93/MWh. The highest-to-lowest spread nevertheless reached €26.83/MWh, largely because Albania reached €178.03/MWh while Serbia remained at €151.20/MWh. This dispersion highlights the continuing difference between the tightly coupled central markets and the more volatile peripheral Balkan systems.

The strongest daily increases were recorded in the peripheral markets. Albania gained €25.4/MWh, North Macedonia increased by €19.2/MWh and Serbia by €18.2/MWh. Montenegro rose by a more modest €1.4/MWh to €156.01/MWh. Serbia remained €16.79/MWh below HUPX, North Macedonia was €13.38/MWh lower and Montenegro €11.98/MWh lower. Albania, meanwhile, carried a €10.04/MWh premium over Hungary.

The physical balance points to stronger demand as one of the main drivers of the move. Forecast regional electricity consumption increased to 32,004 MW, up 1,246 MW from the previous day. At the same time, the Hungary-SEE system shifted sharply toward imports, with net imports reaching 1,720 MW compared with approximately -36 MW a day earlier. Flows from the CORE region, mainly Austria and Slovakia toward Hungary and Slovenia, jumped to 2,298 MW, an increase of 1,825 MW.

The shift in cross-border flows is particularly significant because it shows that the region was relying much more heavily on northern imports to cover stronger consumption. At the same time, around 580 MW was flowing toward Italy, meaning the Hungary-SEE area could remain a net importer while still exporting electricity toward the higher-priced Italian market. This configuration helped keep HUPX closely aligned with Austria and Romania while remaining below Italy.

Renewable forecasts added another important dimension. Solar output was expected to increase by 1,266 MW to 7,866 MW, while wind generation was forecast to decline by 1,169 MW to just 673 MW. Although the two changes were broadly neutral in average megawatt terms, their timing was very different. Additional solar generation was concentrated during daylight hours, while the loss of wind generation affected a much wider part of the day and became particularly important after sunset.

The hourly price curves clearly reflected this shift. HUPX reached a daily minimum of €127.5/MWh at H14 before climbing to a maximum of €214.6/MWh at H21. The base price was €168/MWh, while the conventional peak block averaged €158.3/MWh and off-peak hours averaged €177.7/MWh. The apparent inversion is explained by the strong evening spike: H21 falls outside the standard daytime peak block, and the disappearance of solar generation coincided with higher evening demand.

A similar pattern appeared across the central markets. Romania fell to €127.5/MWh and peaked at €214.7/MWh at H21, while Slovenia moved between €127.8/MWh and €209.4/MWh, also reaching its high at H21. Bulgaria reached €214.4/MWh at H21 and Austria €209.9/MWh, while Croatia peaked slightly earlier at H20 at €217.3/MWh. Greece recorded a deeper daytime trough of €100.1/MWh at H10 before rising to €214.4/MWh at H21.

The hourly profiles therefore point to a market where evening scarcity is becoming more important than the baseload price itself. Strong solar generation suppresses prices during the middle of the day, but the market becomes considerably tighter once solar production disappears. The transition from high renewable output to evening demand is consequently one of the key trading signals in the current regional market.

The southern Balkan markets showed an even sharper version of the same pattern. Serbia’s SEEPEX price reached €151.20/MWh, with an intraday low of €103.1/MWh at H12 and a maximum of €215/MWh at H20. Montenegro averaged €156.01/MWh, falling to €100.1/MWh before reaching €220/MWh at H20. North Macedonia averaged €154.6/MWh, with a minimum of €90/MWh and a maximum of €226.3/MWh at H21.

Albania remained the most expensive market in the regional comparison. Its base price reached €178.03/MWh, while the off-peak block averaged €207.9/MWh and the daily maximum reached €250/MWh at H21. Prices nevertheless fell as low as €93.6/MWh during the day, demonstrating that the high average was driven primarily by a very strong evening ramp rather than by uniformly elevated prices throughout the session.

The resulting intraday spreads were substantial. Albania recorded a difference of more than €156/MWh between its minimum and maximum prices, while Serbia saw a spread of roughly €112/MWh and North Macedonia more than €136/MWh. Such volatility increases the potential value of flexible resources including hydropower, battery storage and demand response, as well as available cross-border capacity.

Romania faced an additional supply-side challenge as both 680 MW units at the Cernavoda nuclear plant remained unavailable because low Danube flows had reduced cooling-water availability. The outage removed approximately 1.36 GW of nuclear capacity. Romania responded by restarting almost 300 MW at Unit 4 of the Rovinari coal plant, while renewable generation and imports continued to support the system.

Despite the significant nuclear outage, OPCOM remained almost perfectly aligned with HUPX. Romania therefore avoided the large price premium that might otherwise have been expected from the loss of both Cernavoda reactors. Replacement thermal generation, renewable output and access to neighbouring markets appear to have prevented a major local price dislocation. Nevertheless, the evening peak above €214/MWh showed that post-solar supply remained tight.

The forward market was firmer but considerably less stressed than the day-ahead segment. Hungarian Week 35 power traded at €151/MWh, Week 36 at €148/MWh, September 2026 at €158.5/MWh and Calendar 2026 at €128.5/MWh. These contracts gained between €0.5/MWh and €2/MWh on the day. HUPX day-ahead therefore remained almost €17/MWh above Week 35 and €9.49/MWh above September, indicating a clear prompt premium.

Fuel and carbon markets provided some additional support. CEGH gas rose to €63.77/MWh, while EU allowances reached €82.31/t. September and fourth-quarter gas forwards stood at €65/MWh, increasing by €2/MWh and €1.5/MWh respectively. API-2 coal was priced at $122/t for September and $126/t for Q4. Greek gas moved in the opposite direction, falling to €54.36/MWh. Overall, the fuel complex was supportive, but the size of the electricity premium suggests that the move was driven primarily by power-system conditions rather than fuel costs.

For traders, the most important feature of 19 August is therefore the distinction between baseload convergence and hourly scarcity. Hungary, Romania, Bulgaria, Slovenia and Croatia offered very limited geographical base-price differentiation, with all five markets clustered within €0.33/MWh. Greater opportunities and risks remained in the peripheral spreads, particularly Albania against HUPX and the discounted Serbia-Montenegro-North Macedonia group.

The physical system reinforced this structure. Demand increased by more than 1.2 GW, wind generation fell by almost 1.17 GW and northern imports increased by more than 1.8 GW. Stronger solar generation kept midday prices under control, but its disappearance exposed the system to much higher evening prices. The repeated €210-€226/MWh evening peaks, together with Albania’s €250/MWh maximum, show where marginal capacity was being valued.

The regional market is therefore pricing the current tightness primarily as a short-term balancing and shape problem, rather than as a broad repricing of the entire forward curve. Central SEE markets are increasingly capable of moving together under favourable cross-border conditions, but the sharp evening ramps and persistent peripheral spreads show that regional convergence remains incomplete. For the coming sessions, the key variables will be the evolution of demand, wind availability, solar output after sunset, northern imports and the ability of flexible generation and storage to cover the evening ramp.

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The average household electricity bill reached €42.36 in July 2026, an increase of 25.3% from €33.80 in June. The average was also 5.4% higher year on year, compared with €40.19 in July 2025. 

The national figure concealed substantial differences between municipalities. Pljevlja recorded the lowest average monthly bill at €21.40, while Ulcinj was at the opposite end of the range with an average of €69.60.

Despite the increase in the national average, more than half of households remained in the lowest billing bracket. Around 55.6% will pay less than €30, while 19.74% face bills between €30 and €50. Another 17.38% will pay between €50 and €100, and 7.28% will receive bills above €100.

Payment discounts continue to play a significant role in the retail market. A total of 133,660 regularly paying customers qualified for a discount, equivalent to around 32.1% of Montenegro’s consumers.

The rise in bills coincided with a substantial increase in electricity use. EPCG said households consumed 147.8 million kWh during July, 23.94% more than in June and 2.75% more than in July 2025.

The figures point to a pronounced seasonal effect. Monthly household consumption rose at almost the same pace as the average bill, while the relatively modest year-on-year consumption increase was accompanied by a larger increase in the average payment. Ulcinj’s substantially higher average bill also highlights the pronounced geographical variation in summer electricity demand across Montenegro’s coastal and northern municipalities.

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The larger installation will have 20 MW of capacity and will be constructed near the Bitola thermal power complex in southern North Macedonia. The contract is valued at €15.65 million.

A second 10 MW plant will be built at Oslomej, using land previously associated with coal mining. That contract is worth €12 million, putting the combined value of the two awards at €27.65 million. 

The agreements were signed in late June, according to contract-award information cited from the European Bank for Reconstruction and Development. POWERCHINA Jiangxi Electric Power Construction will be responsible for construction and operation, with completion scheduled by 13 August 2027.

Once both plants are operating, they are expected to reduce carbon dioxide emissions by approximately 33,000 tonnes annually. The EBRD is supporting the wider programme through a €25 million loan approved in 2021.

Oslomej is already becoming one of the most visible locations in North Macedonia’s transition away from coal. ESM placed its first 10 MW solar plant there into trial operation in 2022 and has outlined plans for another 100 MW of photovoltaic capacity.

Private developers are also involved. Agreements signed by the government in 2021 with Bulgaria’s Solarpro Holding and Turkey’s Fortis Energy Electric cover a further 100 MW of solar development at the former Oslomej mine. 

The newly awarded projects therefore form part of a considerably larger repurposing programme rather than isolated solar installations. Oslomej in particular is evolving from a coal-production site into a mixed portfolio of state-backed and privately developed photovoltaic assets, while Bitola is beginning a similar diversification process alongside its existing thermal infrastructure.

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Mayor Gergely Karacsony has presented the opportunity as unusually large relative to the capital’s electricity requirements. He said Budapest’s theoretical rooftop solar potential could be equivalent to roughly 2.5 times the electricity generation of the Paks nuclear power plant and, if fully exploited, could produce enough electricity to match the annual consumption of the city’s households.

Karacsony also estimated that full development could reduce carbon dioxide emissions by almost 500,000 tonnes. These figures represent the municipality’s assessment of technical potential rather than an announced construction programme. 

Budapest has already spent several years mapping the opportunity. The municipality prepared a solar-potential map and subsequently launched the Powered by the Sun programme to encourage greater rooftop photovoltaic deployment.

Moving from theoretical rooftop potential to investable projects remains dependent on national policy. Karacsony said the central government would need to establish appropriate financial and regulatory conditions, while the city could coordinate implementation and private companies could provide capital and technology.

Grid rules are a central constraint. Restrictions affecting the ability of newly installed solar systems to feed electricity into the network have, according to the mayor, effectively stopped further expansion in some cases. Relaxing those restrictions could reopen development opportunities.

The Hungarian government’s more recent energy-development strategy gives solar a larger role, which Budapest sees as a possible basis for cooperation between national and municipal authorities.

Storage is an important part of the concept. The city is not simply proposing additional photovoltaic generation but a combination of rooftop solar and batteries capable of covering a larger share of local electricity needs while reducing dependence on supply from outside Budapest. The scale of the identified roof area is significant; the investment case will ultimately depend on grid access, regulation and the financing structures made available to property owners and private developers.

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The distribution operator had proposed approximately €5.9 billion of expenditure, an increase of 35.2% compared with the amount approved under its previous 2024–2028 programme. A substantial share of the proposed increase was intended to address ageing infrastructure, particularly through replacement and refurbishment of existing network assets.

RAAEY acknowledged that higher material prices, project modifications and delays had contributed to rising costs. It also criticised repeated postponements, including delays affecting priority investments, and called for more credible implementation schedules. 

The pressure on network investment can already be seen in connection costs. DEDDIE spent €140.5 million connecting electricity users in 2025, compared with €101 million in 2023, even though it completed approximately 3,000 fewer connections.

The amount of new network required nevertheless increased from 1,139 kilometres to 1,311 kilometres, while contractor prices rose by 42% between 2022 and 2025. The combination of higher unit costs and greater network requirements is making expansion more capital-intensive even where the number of completed customer connections is lower.

RAAEY did not accept the investment plan in full. Shore-power projects at Igoumenitsa, Rafina and Kyllini were excluded, along with a low-voltage monitoring system, the proposed Mount Athos electrification project and an artificial-intelligence and knowledge infrastructure programme.

Several major spending envelopes were also reduced. Funding for customer connections was lowered from €800 million to €760 million, expenditure on network variants from €150 million to €115 million, and the smart-meter programme from €1.6 billion to €1.46 billion.

The regulator’s intervention leaves Greece with a large distribution investment requirement but a more constrained capital programme. Rising construction costs, ageing assets and growing connection requirements remain intact; the pressure now shifts toward execution discipline and the operator’s ability to deliver the approved projects without repeating the delays identified under earlier plans.

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According to the material cited in the newsletter, preliminary investigations indicated that incidents associated with the electricity network may have been linked to around 75% of the area burned by wildfires this year. That assessment contrasts sharply with distribution operator DEDDIE’s earlier position that its infrastructure was responsible for only about 1% of forest fires in 2025.

Recent fires in Attica, Crete and Arta have brought the issue back into focus, particularly the effectiveness of inspection programs and vegetation clearance around electricity infrastructure. 

The operational challenge is substantial. DEDDIE manages almost 254,000 kilometres of network and more than 167,000 substations, serving around 7.67 million users. At the same time, more than 9.1 GW of renewable capacity has been connected to the system, increasing the volume and complexity of infrastructure requiring monitoring and maintenance.

Technicians have raised concerns about incomplete information covering the location, age and physical condition of some assets, as well as weaknesses in outsourced inspection and vegetation-clearance activities. Staffing has also emerged as a constraint, with the technical workforce estimated at around 3,000, significantly below historical levels.

Wholesale conversion of overhead networks to underground cables is not regarded as economically realistic. Underground systems can cost as much as five times more than overhead lines. The alternative being discussed is a more targeted approach: undergrounding in particularly high-risk locations, greater use of insulated conductors, automated fault-isolation equipment, drones, sensors and more intensive preventive maintenance.

DEDDIE already has an investment programme running through 2030, but regulator RAAEY has criticised delays in maintenance and questioned elements of planned expenditure. That puts the emphasis increasingly on capital allocation rather than simply capital volume. The central issue is whether available investment is being directed quickly enough toward the parts of the Greek distribution network most exposed to weather, vegetation, equipment failure and wildfire risk.

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The procurement forms part of UNDP’s GED project and covers the supply, delivery and installation of all six photovoltaic systems, together with the works required to make the installations operational.

Prospective contractors have until 31 August to submit bids. The contract is being awarded through a request-for-quotation procedure using UNDP’s Quantum procurement platform, with companies that are not already registered required to join the supplier system before participating. 

The tender is notable for what has not yet been disclosed. UNDP’s initial notice does not identify the locations of the six installations, their individual or combined generating capacities, or an estimated procurement value. Those omissions make it impossible at this stage to assess the projects on a cost-per-megawatt basis or determine their likely contribution to Bosnia and Herzegovina’s electricity supply.

UNDP has advised interested companies to subscribe to procurement notifications so they receive subsequent amendments or additional technical information.

For contractors, the tender therefore represents an identifiable near-term procurement opportunity, but one for which significant commercial and engineering details remain outstanding. Capacity, site characteristics and project value will ultimately determine whether the six installations amount to a collection of relatively small public-sector systems or a more material addition to Bosnia and Herzegovina’s distributed solar portfolio.

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Hungary’s HUPX day-ahead baseload settled at €164.47/MWh, down €19.4/MWh, or around 10.6%, from Monday. Romania’s OPCOM cleared at €164.17/MWh, Croatia at €164.23/MWh, Germany at €163.93/MWh, Slovenia at €165.68/MWh and Austria at €166.08/MWh. The six markets therefore averaged approximately €164.76/MWh, with only €2.15/MWh separating the lowest and highest prices.

The degree of convergence was particularly clear in Hungary’s cross-border spreads. HUPX traded just €0.54/MWh above Germany, €0.30/MWh above Romania and €0.24/MWh above Croatia, while Slovenia carried a premium of slightly more than €1.20/MWh over Hungary. The narrow spreads indicate that Tuesday’s market behaved increasingly like an integrated central European power system, rather than a group of separately priced national markets.

Further south, however, the price picture remained markedly different. Serbia’s SEEPEX recorded the lowest regional baseload price at €133.02/MWh, despite rising €4.8/MWh from Monday. North Macedonia followed at €135.38/MWh, down almost €16/MWh. Albania rose €8.3/MWh to €152.60/MWh, Greece edged up €0.3/MWh to €153.72/MWh, while Montenegro declined €13.6/MWh to €154.65/MWh. Italy remained the regional premium market at around €172.64/MWh, leaving a €39.6/MWh gap between Italy and Serbia.

The result was a clear two-tier regional structure. Hungary, Romania, Croatia, Slovenia, Austria and Germany formed a closely clustered group around €164–166/MWh, while Serbia and North Macedonia remained heavily discounted. HUPX traded approximately €31.45/MWh above Serbia and €29.08/MWh above North Macedonia, compared with premiums of €10.75/MWh over Greece and €11.87/MWh over Albania. Italy maintained an €8.17/MWh premium over Hungary.

Hourly profiles provided an even stronger indication of the market’s underlying dynamics. Conventional peak and off-peak relationships remained inverted across several markets, reflecting the impact of solar generation during daytime hours. In Hungary, the peak block averaged €153.8/MWh against €175.1/MWh for off-peak hours. Germany showed a similar pattern at €153.8/MWh and €174.1/MWh, respectively, while Romania recorded €153.9/MWh for peak and €174.4/MWh for off-peak.

The inversion became even more pronounced in southern markets. Greece recorded a €133.1/MWh peak average compared with €174.3/MWh off-peak, producing a spread of more than €41/MWh. Serbia averaged €115/MWh during peak hours against €151.1/MWh off-peak, while North Macedonia stood at €122.5/MWh and €148.3/MWh. Italy recorded €159.1/MWh for peak and €188.2/MWh for off-peak.

The hourly curves underline the growing separation between solar-heavy afternoon hours and the evening ramp. HUPX reached a low of €131.3/MWh in hour 14 before climbing to €208.6/MWh in hour 21. Romania recorded the same €208.6/MWh maximum, while Greece fell as low as €66.3/MWh in hour 15 before reaching €208.6/MWh in hour 21. Italy showed the strongest evening scarcity signal, with its national price peaking at €251.7/MWh in hour 21.

Serbia provided a particularly clear example of why a low daily average does not necessarily indicate a lack of scarcity. SEEPEX dropped to just €56.9/MWh at its minimum, but surged to €224.3/MWh in hour 21, exceeding the Hungarian maximum. North Macedonia ranged between €70/MWh and €200/MWh, while Montenegro moved from €130/MWh to €217.1/MWh. The data show that the regional market’s risk is increasingly concentrated in specific evening hours rather than reflected in the daily baseload average.

Fundamentals were mixed rather than uniformly bearish. Average regional consumption was forecast at 31.495 GW, up 708 MW from Monday, even as the regional temperature indicator declined 1.2°C to 23.3°C. Hungarian demand fell by 259 MW to 4.48 GW, while Greece added 345 MW and Romania and Bulgaria together increased demand by approximately 920 MW.

Renewable availability provided the stronger bearish influence. The regional solar forecast increased by 918 MW to around 7.895 GW, while wind availability declined by 179 MW to 1.248 GW. Tuesday’s price correction was therefore not driven by weaker demand alone. Instead, higher solar output and changing physical flows helped absorb stronger weekday consumption and pushed daytime prices lower.

Net regional imports fell to only 436 MW, down 555 MW from the previous session. Imports from the Austria-Slovakia core declined by 462 MW to 948 MW, while exports towards Italy increased to around 513 MW from 403 MW. The stronger convergence between HUPX and Germany therefore occurred despite lower overall imports from the western core, suggesting that Tuesday’s price alignment was not simply the result of heavy west-to-east power flows.

Country-level balances revealed a pronounced northbound flow pattern. Bulgaria remained one of the region’s strongest surplus systems, with forecast generation of approximately 5.37 GW against consumption of 3.90 GW, leaving net exports of around 1.47 GW. The Bulgaria-Romania base flow was approximately 1.15 GW, while around 385 MW moved towards Serbia and another 160 MW towards North Macedonia.

Romania was almost balanced at system level, with generation of around 5.59 GW versus consumption of 5.60 GW, but continued to function as an important transit market. Average base flows from Romania into Hungary reached approximately 1.19 GW and increased to 2.27 GW during peak hours. The combination of Bulgarian surplus and Romanian northbound flows helped keep the central SEE markets closely aligned even as imports from Austria and Slovakia declined.

Hungary remained structurally short, with consumption forecast at 4.48 GW against generation of approximately 2.89 GW, implying net imports of around 1.59 GW. That deficit was nevertheless smaller than Monday’s estimated 2.09 GW. Slovakia remained an important source with approximately 796 MW on a base basis, while Hungary also exported electricity towards Croatia and Slovenia during parts of the day. The highly variable Austria-Hungary flow profile, which switched between imports and exports, showed that the almost negligible daily HUPX-Germany spread concealed significant intraday congestion and flow reversals.

Bulgaria’s strong surplus contrasted with Serbia’s relatively balanced system. Serbian generation was forecast at around 3.48 GW, compared with consumption of 3.53 GW, leaving an average net import requirement of only about 59 MW. Despite this near balance, Serbian electricity traded more than €31/MWh below Hungary. Strong imports from Bulgaria and North Macedonia combined with exports on other borders created a complex hourly flow pattern that kept the daily average depressed even though Serbia recorded an evening price above HUPX.

Greece remained a significant exporter despite trading below the northern European cluster. Generation was forecast at 7.42 GW against consumption of around 6.50 GW, leaving exports of approximately 919 MW. Although that was substantially below Monday’s 1.55 GW, Greek electricity continued flowing towards Bulgaria, Albania, North Macedonia and Italy during significant parts of the day. The move from a €66.3/MWh afternoon low to a €208.6/MWh evening high demonstrates how strongly hourly renewable availability is shaping the Greek market.

The prompt power correction was also reflected in Hungary’s forward curve. Week 35 fell €10/MWh to €150.50/MWh, while Week 36 declined €13.50/MWh to €147/MWh. September 2026 dropped €4/MWh to €157.50/MWh, while Calendar 2026 remained unchanged at €126.50/MWh. The concentration of losses at the front of the curve suggests that traders were primarily unwinding part of the short-term risk premium accumulated during Monday’s price spike rather than materially repricing the longer-term Hungarian power balance.

Hungarian-German forward spreads narrowed accordingly. The Week 35 premium contracted by €9/MWh to €22.50/MWh, Week 36 narrowed €4.50/MWh to €25.50/MWh, and September decreased €1/MWh to €25.50/MWh. The Calendar 2026 spread remained at €20/MWh. Hungary’s front-end power prices therefore weakened both in absolute terms and relative to Germany.

Fuel markets provided a less bearish signal. CEGH gas increased €1/MWh to €63.16/MWh, while the Greek gas indicator rose €0.60/MWh to €55.58/MWh. EU allowances edged down €0.20/t to €81.58/t. September gas forwards were unchanged at €63/MWh, while Q4 increased €0.50/MWh to €63.50/MWh. The divergence between firmer gas prices and weaker prompt electricity indicates that Tuesday’s correction was driven primarily by regional power fundamentals, renewable generation and cross-border positioning, rather than a broad decline in thermal fuel costs.

The weather outlook suggests that the bearish pressure may not persist uniformly. The regional temperature forecast excluding Greece rises from 23.3°C on Tuesday to 23.9°C on Wednesday, then accelerates to 26.7°C on Thursday and 27.6°C on Friday. Hungary is forecast to warm from 21.1°C to around 26.4–26.5°C later in the week, while Romania, Serbia, Greece and Montenegro are also expected to experience significantly higher temperatures.

The warming trend points towards renewed cooling demand just as the market is demonstrating that its most expensive periods are increasingly concentrated after the solar ramp-down. Tuesday’s decline in baseload prices has removed part of the premium built into the Hungarian front end, but the underlying hourly structure remains tight. Prices above €200/MWh appeared across much of the region, Italy exceeded €250/MWh and even discounted Serbia reached more than €224/MWh. The next sessions are therefore likely to be shaped less by the daily baseload average and more by the interaction between daytime renewable price compression, evening thermal flexibility and cross-border transmission capacity.

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The lower tax rate took effect on 16 August and is scheduled to remain in place until the end of the month.

The government reduced the duty by €106.60 per 1,000 litres, bringing it to €426.20/1,000 litres, equivalent to €504.50/tonne.

The measure followed a significant deterioration in diesel-market conditions. During the relevant monitoring period, Platts diesel quotations rose 34.13%, while the average Romanian retail price of standard diesel increased 23.01%.

Rather than adopting a permanent tax reduction, Romania is using a mechanism established under Law No. 162/2026, which allows the government to adjust fuel excise duties temporarily when defined market thresholds are triggered.

The framework gives policymakers a way to respond to sudden international fuel-price shocks while limiting the longer-term effect on tax revenues.

Market conditions will be reassessed every two weeks, giving the government the option to change or withdraw the reduction as wholesale and retail pricing evolves.

The intervention is relevant beyond motorists because diesel costs feed directly into freight, logistics, agriculture and other fuel-intensive sectors.

Romanian transport companies are particularly exposed to changes in diesel prices, and sustained increases can eventually feed into the cost of goods moved through domestic and regional supply chains.

The temporary reduction therefore serves both as a consumer-relief measure and an attempt to contain secondary inflationary pressure.

The design of the intervention is deliberately short-term. By restricting lower excise duties to periods of unusually high market prices rather than permanently changing the tax structure, the government is attempting to balance relief for consumers and companies against the fiscal importance of fuel taxation.

The next two-week market review will determine whether price conditions continue to justify the lower rate. 

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Electricity consumption reached 24.11 TWh between January and June, down 3.3% year on year, according to the National Institute for Statistics.

Industrial demand proved comparatively resilient, declining only 0.6% to 18.61 TWh.

Household consumption fell much more sharply, dropping 11.8% to 5.31 TWh, while electricity used for public lighting declined 4.6% to approximately 191.3 GWh.

Generation moved in the opposite direction. Romanian power production increased 5.2% to 26.23 TWh, improving the system’s underlying supply-demand balance.

The strongest increase came from hydropower, where production rose 17.9% to 7.5 TWh.

Solar production, including prosumers, registered an even larger percentage increase, climbing 42.1% to 3.26 TWh. Wind generation increased 9% to 3.27 TWh.

Those gains more than compensated for weaker conventional production in several segments.

Thermal generation declined 5.9% to 7.68 TWh, while electricity production at the Cernavoda nuclear plant fell 11.7% to 4.53 TWh.

Cross-border volumes reflected the stronger domestic generation environment. Romanian electricity exports rose 11.4% to 7.69 TWh, while imports fell 9.8% to 8.46 TWh.

Romania therefore remained a net importer over the six-month period, but the gap between imports and exports narrowed materially as renewable and hydro production strengthened.

The composition of the change is important for the regional market. Romania is one of southeast Europe’s largest electricity systems and a key transit market between Bulgaria, Hungary, Serbia, Ukraine and Moldova. Higher Romanian renewable output can consequently influence price formation and cross-border flows well beyond the domestic market.

Primary-energy production moved differently from electricity generation. The source reports total primary energy-resource production of 7,929.6 million tonnes of oil equivalent, down 2.6% year on year. It reports coal production at 742.3 million tonnes of oil equivalent, a decline of 17.9%; oil at 1,160.7 million tonnes, down 7.2%; and natural gas at 3,710.3 million tonnes, down 0.6%.

The first-half figures therefore show an electricity system increasingly supported by hydro, wind and particularly solar generation while underlying domestic electricity consumption remains below 2025 levels. 

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The timetable depends on completion of engineering, permitting, corporate structuring and financing work, meaning the project has not yet reached a final construction-ready stage.

EPCG and Masdar intend to hold 50% each in a new joint company that will develop projects included in their cooperation framework.

The partnership was formalised through a joint investment agreement in April 2026 and expanded in July through development agreements covering the Krupac and Stedim solar projects. A separate framework agreement also covers cooperation in hydropower.

The immediate corporate step is the signing of a shareholders’ agreement and formal establishment of the joint venture. EPCG and Masdar would then define individual project schedules and determine financing structures.

Funding is expected to be organised through the joint company and could include conventional project-finance structures or alternative financing models.

EPCG board president Milutin Djukanovic said the first solar development could enter construction in 2027, provided the remaining technical, administrative and financial work proceeds according to plan.

The cooperation sits within a broader government-to-government energy relationship between Montenegro and the United Arab Emirates. The two countries initiated an energy cooperation agreement in November 2025, which Montenegro’s parliament ratified in March 2026.

The significance of the partnership extends beyond the first solar plants.

EPCG and Masdar are also studying pumped-storage hydropower, which could provide balancing capacity and flexibility as Montenegro adds more intermittent solar generation.

The pairing of solar and storage is strategically important for EPCG because the company is seeking to diversify a generation portfolio still strongly influenced by hydrology and thermal production.

Additional solar capacity could improve Montenegro’s daytime electricity balance and reduce imports, but rapid expansion without flexible capacity would increase the challenge of managing production during high-output hours and supplying demand once solar generation falls.

Pumped storage could address part of that problem by shifting energy across the day while providing system-balancing services.

The partnership also gives EPCG access to Masdar’s project-development and operating expertise while retaining equal domestic ownership of the venture. Domestic engineers and specialists are expected to participate in development.

The 50:50 structure, potential use of project finance and inclusion of both renewable generation and storage make the EPCG-Masdar partnership materially broader than a straightforward equipment procurement arrangement. It is being structured as a platform capable of developing multiple Montenegrin electricity assets over time.

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Distribution system operator CEDIS said consumption exceeded the previous record, established exactly a year earlier, by 113 MWh.

The record was reached under difficult operating conditions around Herceg Novi, where wildfires created significant problems for the distribution network.

CEDIS temporarily disconnected two 35 kV transmission connections, including the Herceg Novi-Topla line.

The disruption on the Herceg Novi-Kumbor connection was considerably longer. Around 10,800 customers were affected, with the average interruption lasting 238 minutes.

Efforts to reroute electricity through alternative sections of the network subsequently created additional technical difficulties and further outages.

Despite those interruptions, total energy delivered during the day still exceeded the previous national record, indicating that underlying demand would have been even higher without the supply disruptions.

The result highlights the intensity of Montenegro’s summer electricity-demand profile. Tourism, air-conditioning and high coastal occupancy can push consumption sharply higher during the peak holiday period, creating a seasonal system challenge very different from the traditional winter load profile of some continental Balkan markets.

The record is particularly relevant because Montenegro has historically relied on imported electricity during periods when domestic generation cannot cover demand.

High summer consumption therefore affects not only CEDIS’s distribution network but also EPCG’s generation position and Montenegro’s exposure to regional day-ahead and cross-border electricity prices.

Wildfire risk adds another layer to that exposure. Extreme heat can simultaneously increase electricity demand and threaten transmission and distribution infrastructure, creating conditions in which the system requires more power at the same time as parts of the network become harder to operate.

The 12,218 MWh record demonstrates that this combination is no longer theoretical. Montenegro experienced record consumption while significant local network assets were already under operational stress. 

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Transmission system operator HOPS recorded 64 GWh of electricity withdrawn from the transmission network over the full day.

Actual nationwide consumption was higher because the transmission figures exclude electricity generated and consumed directly behind the meter, particularly from household and commercial solar installations.

Croatia now has around 600 MW of residential rooftop solar, according to the report. That capacity increasingly suppresses visible network demand during daylight hours, creating a growing difference between underlying electricity consumption and demand measured directly at transmission level.

The result is a more pronounced daily load shape. Solar generation reduces the amount of centrally supplied electricity required during sunny hours, but that output falls rapidly towards evening just as air-conditioning and residential demand can remain elevated.

Croatia’s new system record occurring between 20:00 and 21:00 is therefore significant. It demonstrates that the highest stress on the transmission system can increasingly occur after solar production has declined rather than during the hottest part of the afternoon.

The Croatian record contrasts with neighbouring Slovenia, where the highest hourly transmission load of 2,300 MW was recorded between 08:00 and 09:00 on 8 January 2026 during an exceptionally cold period.

The two markets consequently face different seasonal demand extremes. Slovenia’s record reflects winter heating and cold-weather conditions, while Croatia’s was established during the summer holiday and cooling-demand season.

The difference also has trading implications. Croatia’s combination of tourism-driven summer consumption and a growing distributed solar base can produce relatively comfortable daytime balances followed by materially tighter evening conditions. Those intraday changes become increasingly relevant for cross-border flows with Slovenia, Hungary, Bosnia and Herzegovina and Serbia.

The 3.4 GW record also illustrates why installed behind-the-meter solar cannot be assessed solely by its contribution to annual energy production. As rooftop penetration rises, its influence on network demand, peak timing and flexibility requirements becomes just as important as the amount of electricity produced. 

The post Croatia records 3.4 GW summer evening demand peak as rooftop solar reshapes load profile appeared first on Serbia SEE Energy Mining News.

Kozloduy has continued operating according to its planned production schedule, but technical teams are examining options to secure adequate water supplies should river levels decline further.

Attention is focused particularly on the plant’s riverside pumping station. Specialists are assessing ways to improve pump performance and reinforce associated hydraulic infrastructure so that sufficient water can continue to reach the site under more difficult hydrological conditions.

Cooling arrangements for the operating reactor units and spent-fuel storage are also being monitored. Plant personnel are considering preventive measures that could be activated should existing water-supply arrangements become insufficient.

The Bulgarian Energy Ministry has established a dedicated task force to coordinate the institutions involved and provide support to Kozloduy’s technical teams. Additional contingency measures are being prepared in advance, allowing them to be implemented more rapidly should conditions on the Danube deteriorate.

The issue has implications beyond Bulgaria because Kozloduy is the country’s largest electricity producer and one of southeast Europe’s most important sources of nuclear baseload generation.

Any material reduction in output would affect Bulgaria’s domestic balance while potentially reducing electricity available for export to neighbouring systems. Bulgaria has remained a significant regional exporter during 2026, making the availability of Kozloduy particularly important during periods of elevated summer consumption.

Authorities are consequently discussing the hydrological situation with neighbouring countries and European institutions.

The immediate issue remains operational rather than a confirmed loss of production: the plant is maintaining its scheduled generation. But the preparation of additional safeguards demonstrates the growing intersection between hydrological conditions and assets traditionally regarded as firm thermal or nuclear capacity.

Low river levels can affect hydroelectric production directly, but sustained drought can also constrain power stations dependent on rivers for cooling. That increases the system value of water availability across several different generation technologies and makes prolonged low-Danube conditions a regional electricity-market variable rather than solely a Bulgarian operational issue. 

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Electricity production between 1 January and 16 August reached 27.86 TWh, up 8.34% year on year, according to Bulgarian transmission system operator ESO.

Domestic electricity consumption also increased, rising 6.91% to 25.78 TWh over the same period. Generation nevertheless remained above consumption, leaving Bulgaria with net electricity exports of approximately 2.07 TWh.

That surplus continues to support Bulgaria’s role as one of the more important exporting systems in southeast Europe, particularly during periods when neighbouring markets require additional baseload or daytime supply.

The composition of generation is changing, however. Coal and nuclear plants together produced 17.32 TWh, a decline of 6% from the corresponding 2025 period.

Renewable generation moved in the opposite direction. Renewable electricity connected to the transmission network increased 18.25% to 3,109.2 GWh, while renewable generation within distribution networks rose 7.17% to 2,853.8 GWh.

The figures point to a Bulgarian market where higher total output is increasingly being supported by renewable capacity rather than additional conventional baseload generation. This changes not only the annual generation mix but also the shape of the power system during individual hours.

Higher solar output, in particular, can strengthen daytime export capability while simultaneously increasing the requirement for dispatchable capacity, storage and cross-border trading during the evening ramp. Bulgaria’s substantial nuclear fleet remains an important stabilising element within that transition because it provides a large block of relatively predictable baseload generation beneath increasingly variable renewable production.

The 2.07 TWh net export position accumulated through mid-August demonstrates that rising domestic consumption has so far not eliminated Bulgaria’s regional supply surplus. The durability of that position will increasingly depend on renewable availability, nuclear generation, hydrology and the operating profile of the country’s coal fleet as the generation mix continues to shift. 

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Large Bosnian hydropower plants produced an average of around 5.3 TWh/year over the past eight years, according to an analysis by energy expert Zijad Bajramovic cited in the report. Actual production can diverge sharply from that level depending on rainfall and river flows.

The scale of that variation is illustrated by the difference between 2023 and 2020.

Strong hydrology in 2023 lifted hydropower production to 6.4 TWh, around 21% above the eight-year average. That resulted in approximately 1.1 TWh of additional hydroelectricity, reducing the requirement for thermal generation and imports while increasing the volume available for export.

Using an assumed wholesale power value of €100/MWh, that incremental generation would have been worth around €110mn.

The opposite occurred in dry 2020, when hydro output fell to 4.3 TWh, around 19% below average. The resulting production deficit of approximately 1 TWh would represent about €100mn at the same wholesale price assumption.

The spread between the two years therefore reaches approximately 2.1 TWh, equivalent to around 40% of average annual generation from Bosnia and Herzegovina’s large hydro plants. Valued at €100/MWh, that translates into the estimated €210mn difference.

The actual financial consequences of poor hydrology can be greater than a simple valuation of lost production. When hydro output falls, utilities may have to replace relatively low-variable-cost generation with more expensive thermal production or imported electricity. That can weaken operating margins and cash flow at exactly the point when companies need additional investment in networks, generation and decarbonisation.

Conversely, strong hydrological years can materially improve trading positions, lower thermal dispatch requirements and create export opportunities.

The volatility underlines the strategic case for broadening Bosnia and Herzegovina’s generation portfolio. Additional wind and solar capacity could reduce the direct relationship between electricity availability and river flows, although growing variable renewable penetration would itself require greater flexibility.

Battery storage, flexible conventional generation and stronger regional interconnection would consequently become increasingly important alongside renewable development. The commercial issue is not simply increasing annual generation, but reducing the earnings volatility produced by a generation portfolio heavily exposed to one natural resource.

For Bosnia’s electricity companies, hydrology therefore remains both a production variable and a material financial risk factor, with annual movements capable of changing the sector’s power balance by terawatt-hours and its economic position by hundreds of millions of euros. 

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Hungary’s HUPX market recorded the highest price in the region at EUR 183.86/MWh, up EUR 45.9/MWh from Sunday. Slovenia followed at EUR 181.48/MWh, Austria at EUR 181.46/MWh, Croatia at EUR 180.63/MWh and Italy at EUR 179.30/MWh. Romania cleared at EUR 172.58/MWh, while Bulgaria reached EUR 169.90/MWh.

Further south, prices remained lower. Greece cleared at EUR 153.42/MWh, Albania at EUR 144.33/MWh, North Macedonia at EUR 151.23/MWh and Montenegro at EUR 168.22/MWh. Serbia remained the regional low at EUR 128.19/MWh.

The rally was broad-based across the region. Greek prices increased by EUR 48.4/MWh day on day, followed by North Macedonia with a EUR 48.3/MWh increase and Serbia with EUR 46.0/MWh. Hungary, Slovenia, Bulgaria and Croatia also recorded gains of between EUR 42.9/MWh and EUR 45.9/MWh.

The sharp increase reflected a substantially tighter regional physical balance following Sunday’s lower-load session. Combined electricity consumption across Hungary and southeast Europe rose to 30,974 MW, an increase of 4,206 MW from the previous day.

At the same time, the region shifted from a small net export position of 240 MW on Sunday to net imports of 1,107 MW for Monday delivery. Imports from the core European market through Austria and Slovakia increased to 1,405 MW, around 402 MW higher than a day earlier.

Renewable availability was mixed. Wind generation dropped sharply to 2,210 MW from 3,227 MW, removing more than 1 GW of relatively low-cost generation from the market. Hydro output also declined to 4,082 MW from 4,355 MW.

Solar generation increased by around 515 MW to 6,830 MW, but the additional photovoltaic output was insufficient to offset stronger demand and lower wind and hydro production. Coal-fired generation increased to 6,154 MW, while gas-fired output rose to 4,391 MW, pointing to greater reliance on thermal generation.

The tightening was particularly evident in Hungary’s day-ahead price curve. The HUPX base price rose to EUR 183.9/MWh from EUR 137.9/MWh on Sunday, while the peak contract jumped to EUR 181.4/MWh from EUR 101.6/MWh.

The minimum hourly price recorded an even stronger increase, reaching EUR 142.3/MWh compared with just EUR 27.3/MWh a day earlier. The maximum price rose more moderately to EUR 226.1/MWh from EUR 206.5/MWh.

This price structure suggests that Monday’s rally was driven less by an isolated evening scarcity event and more by broad upward repricing across the delivery day, including hours that had previously traded at much lower levels.

Northern SEE markets remained closely aligned with Hungary. Slovenia cleared at EUR 181.5/MWh, Croatia at EUR 180.6/MWh and Austria at EUR 181.5/MWh, while minimum prices across the markets were clustered around EUR 140-142/MWh.

The convergence points to a tightly coupled Hungary-Slovenia-Croatia-Austria price zone, while significantly wider spreads remained toward the southern Balkans. Hungary traded around EUR 11/MWh above Romania, EUR 14/MWh above Bulgaria, EUR 30/MWh above Greece and almost EUR 56/MWh above Serbia.

Serbia remained the region’s most significant price discount despite its strong day-on-day increase. SEEPEX settled at EUR 128.2/MWh, with a peak average of EUR 120.6/MWh, a minimum hourly price of EUR 62/MWh and a maximum of EUR 240/MWh.

The large Serbia-Hungary spread continues to indicate congestion and limited northbound transfer capability, rather than a fully integrated price response across the region.

Greece also remained structurally cheaper than the northern markets. HENEX averaged EUR 153.4/MWh, with a minimum hourly price of only EUR 28.4/MWh despite an off-peak average of EUR 183.1/MWh. Bulgaria, meanwhile, cleared considerably higher at EUR 169.9/MWh, with a minimum price of EUR 122.5/MWh.

Cross-border flows reflected the changing regional price structure. The HU+SEE region shifted to net imports of 1,107 MW, while exports toward Italy fell sharply to 281 MW from 1,364 MW on Sunday. Core imports from Austria and Slovakia increased to 1,405 MW.

The decline in exports toward Italy coincided with strong convergence between Italian and northern SEE prices. Italy’s national day-ahead price settled at EUR 179.3/MWh, only around EUR 4.6/MWh below Hungary, while the Italian peak price stood at around EUR 169.7/MWh.

Near-term fuel markets were comparatively stable and offered little explanation for the magnitude of the spot-market rally. CEGH gas was quoted at EUR 62.18/MWh, while EUA carbon allowances stood at around EUR 81.79/t.

Hungarian Week 34 power was assessed at EUR 156.50/MWh, Week 35 at EUR 160.50/MWh, September at EUR 161.50/MWh and Calendar 2026 at EUR 126.50/MWh. The HUPX day-ahead settlement therefore stood more than EUR 22/MWh above the September contract, highlighting that the current premium is concentrated in the short-term physical market rather than fully reflected further along the forward curve.

The regional market remains particularly sensitive to wind availability and weekday demand. Monday’s session combined a 4.2 GW increase in consumption with a drop of more than 1 GW in wind generation, while hydro output also weakened.

That combination pushed the HU+SEE system back into import dependence and lifted the broader northern SEE price structure.

The key market feature for the coming delivery sessions will be the widening divide between the EUR 180/MWh northern cluster around Hungary, Slovenia, Croatia and Austria and the substantially cheaper markets in Serbia, Albania, North Macedonia and Greece.

With HUPX’s daily minimum already above EUR 140/MWh, the market is showing signs of broad scarcity across the load curve, rather than a price pattern driven solely by the evening peak.

The post SEE spot power prices surge on August 17 as demand recovers and weaker wind tightens regional balance appeared first on Serbia SEE Energy Mining News.

Output had been reduced to around 80% following extreme temperatures and exceptionally weak river flows.

The reactor began gradually increasing production from the evening of 14 August.

Krško’s environmental permit requires the average daily temperature of the Sava downstream of the Brezice hydropower plant to remain below 28C. The plant is also permitted to raise river temperature by no more than 3C.

These limits became increasingly difficult to maintain during the recent heatwave.

While generation was reduced, Krško increased the use of cooling towers and other cooling equipment, cutting water withdrawals from the Sava from around 25 cubic metres/second to approximately 8.5 cubic metres/second.

The reactor does not use river water in direct contact with the nuclear system. Sava water is employed in the tertiary cooling circuit to remove heat from the condenser.

Plant output will continue to depend partly on river temperatures, water levels and weather conditions.

The operational restrictions have regional market significance because Krško provides electricity equivalent to around 20% of annual Slovenian consumption and 16% of Croatian demand.

Reduced production therefore raises the requirement for alternative generation or wholesale-market purchases, particularly in Croatia, where HEP has indicated that shortages can be covered through domestic generation and imported electricity.

Krško’s summer operating pattern increasingly demonstrates the interaction between nuclear availability and climate-related hydrological constraints — a factor likely to become more important in regional power pricing during future heatwaves. 

The post Slovenia: Krško raises reactor output to 90% as Sava temperatures ease appeared first on Serbia SEE Energy Mining News.

Output was around 0.5% below plan, compared with 505,827 MWh during the corresponding previous period, when production exceeded the same target by about 1.2%.

The plant nevertheless reported full technical availability. Both availability and capacity factors were stated at 100%, with no technical problems affecting operation.

Krško remains a critical source of baseload electricity for both Slovenia and Croatia. Its annual production corresponds to roughly 20% of Slovenian electricity consumption and around 16% of Croatian demand, giving relatively small changes in reactor availability an outsized impact on regional balances.

The modest shortfall against the monthly plan therefore did not indicate a mechanical reliability issue.

Attention around Krško has instead increasingly centred on environmental operating constraints during periods of extreme summer heat and low river flows, when cooling requirements can force generation reductions even when the reactor remains technically available.

That distinction is increasingly relevant in European nuclear markets as high summer temperatures expose thermal generation assets to hydrological and cooling-water constraints rather than conventional equipment outages. 

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The European Bank for Reconstruction and Development has committed up to EUR 120m, structured through an A loan of as much as EUR 57m and a B loan of up to EUR 63m.

The B-loan component includes a EUR 3.6m debt-service guarantee provided by Privredna Banka Zagreb and NLB.

Additional financing is being provided by the Black Sea Trade and Development Bank, OTP Bank and Exim Banca Romaneasca, taking potential total debt funding for the development to as much as EUR 229m.

Parau 2, located in Brasov county, is notable for combining three revenue elements: utility-scale photovoltaic production, merchant electricity exposure and battery flexibility.

Part of the project has long-term price protection. Around 125 MW secured support through Romania’s first Contract-for-Difference auction at a strike price of EUR 49.4/MWh for 15 years. Electricity from the remaining capacity will retain merchant-market exposure.

That hybrid structure reduces revenue volatility without removing upside from wholesale prices.

The 300 MWh battery system further differentiates the project from a conventional solar plant. It can shift generation from low-priced solar hours into stronger trading periods, provide balancing services and reduce the project’s exposure to declining midday capture prices as Romanian photovoltaic capacity expands.

Romania’s wider CfD programme is designed to support 5 GW of new solar and onshore wind capacity. The financing structure also benefits from InvestEU support, including a first-loss portfolio guarantee of up to EUR 115m associated with the EBRD lending framework.

Parau 2 illustrates the direction increasingly visible in European renewable finance: contracted revenues remain important for bankability, but storage and selective merchant exposure are being incorporated to improve flexibility and preserve market upside. 

The post Econergy secures financing for 342 MW Romanian solar-storage project appeared first on Serbia SEE Energy Mining News.

The project would be developed in Primorje-Gorski Kotar county and use the existing Tribalj reservoir, located at around 60 metres above sea level, as its lower reservoir. A new upper reservoir, Razromir, would be constructed in the Koreni valley on the slopes of Mount Medvedjak at roughly 800 metres elevation.

The large height difference between the two reservoirs would provide the hydraulic head required for pumped-storage operation. Electricity would be used to pump water uphill during periods of lower prices or surplus generation, with the stored water subsequently released through turbines when demand and wholesale prices rise.

The investment would give HEP an asset capable of responding directly to increasingly volatile hourly electricity prices. Croatia and neighbouring SEE markets are adding substantial solar capacity, creating more frequent periods of midday oversupply and greater evening balancing requirements.

Pumped storage can capture that intraday spread while also providing balancing and system-support services. Unlike conventional hydropower, its operating strategy is driven primarily by market conditions rather than natural water inflows.

The project has now entered the environmental assessment process after HEP submitted documentation to the Croatian authorities. Permitting, reservoir construction requirements and the eventual investment cost will determine the pace at which the scheme can move towards execution.

For Croatia, the project would strengthen domestic flexibility at a time when regional power-market volatility and intermittent renewable production are increasing the value of dispatchable storage capacity. 

The post Croatia: HEP advances 160 MW Vinodol pumped-storage project appeared first on Serbia SEE Energy Mining News.

Battery capacity expanded from almost negligible levels to around 3 GWh during 2025, before accelerating to 8.6 GWh by May 2026. Financial support and streamlined permitting have helped turn Bulgaria into one of Europe’s most active utility-scale storage markets.

The scale of the build-out is particularly significant relative to new solar generation. Storage installed during 2025 could theoretically shift around 77% of Bulgaria’s additional daily solar output into hours without sunlight, ahead of comparable ratios of 76% in Chile and 60% in Australia.

The effect is already becoming visible after sunset. Solar paired with batteries covered around 24% of Bulgarian electricity demand between 19:00 and 21:00 during the first half of 2026, compared with virtually no solar contribution during those hours three years earlier. Across the wider 19:00-07:00 period, stored solar supplied roughly 10% of demand.

This matters increasingly for wholesale pricing. Bulgaria’s expanding photovoltaic fleet can create deep midday price discounts when production peaks, while demand and conventional generation requirements rise again in the evening. Batteries allow part of that low-value daytime electricity to be withdrawn from the market and resold later, increasing solar capture prices while reducing the severity of the evening ramp.

The development is occurring faster than in much of the EU. Member states installed around 27 GWh of batteries in 2025, theoretically enough to shift about 16% of incremental solar production, while European transmission operators expect storage capacity to increase roughly fourfold by 2030.

The economics continue to improve. Global battery installation costs fell from around $2,634/kWh in 2010 to $140/kWh in 2025, a decline of approximately 95%, while global annual battery additions are expected to rise from 307 GWh in 2025 to 459 GWh in 2026.

Bulgaria is therefore moving beyond simple solar capacity expansion towards a more flexible power system in which storage increasingly determines when renewable electricity reaches the market and at what value. 

The post Bulgaria battery boom starts reshaping solar price formation appeared first on Serbia SEE Energy Mining News.

Between August 10, 2026 and August 16, 2026, 70 articles were published.

Most-read in this period

Other developments in this period

The post Market News Roundup CW33 appeared first on Serbia SEE Energy Mining News.

Hungary averaged approximately EUR 145/MWh between 10 and 16 August, broadly in line with Croatia and Slovenia, while Romania averaged around EUR 143/MWh. The closely integrated central Southeast European markets remained approximately EUR 24–26/MWh above the broader European average.

Prices were lower in southern and eastern markets. Bulgaria averaged around EUR 129/MWh, Serbia EUR 126/MWh and Greece approximately EUR 102/MWh. Italy remained the region’s main high-price neighbouring market at around EUR 172/MWh, supporting continued export flows from Southeast Europe.

Despite the elevated regional price level, weekly averages declined significantly. Hungarian prices fell by around 7%, while Romania and Croatia dropped approximately 8%. Bulgaria declined by around 11%, Serbia by almost 19% and Greece by approximately 25%.

The headline averages, however, concealed much tighter conditions during the evening hours. The regional market is increasingly defined by a sharp separation between low-priced solar hours and expensive post-sunset electricity.

Strong photovoltaic generation pushed prices sharply lower around midday before the loss of solar output triggered steep evening ramps. In Hungary on Thursday, prices moved from approximately EUR 84/MWh during the solar-rich period to almost EUR 339/MWh in hour 21.

A similar pattern emerged on Friday. Hungarian prices fell to around EUR 30/MWh around midday before climbing above EUR 260/MWh during the evening.

Sunday produced an even wider intraday spread. Hungarian prices dropped to approximately EUR 27/MWh during the middle of the day before rising above EUR 206/MWh later in the session. Bulgaria moved from around EUR 16/MWh to more than EUR 205/MWh, while Serbia ranged from roughly EUR 10/MWh to above EUR 180/MWh.

Greece experienced some of the strongest solar-driven price compression, with several consecutive daytime hours trading close to zero, followed by evening prices above EUR 200/MWh.

The development is increasingly undermining traditional peakload indicators. In Hungary, peakload prices fell below off-peak averages on several days because conventional peak blocks captured solar-rich daytime hours, while off-peak periods included increasingly expensive evening intervals.

Nuclear and hydro constraints sustain the evening premium

Supply-side restrictions remained one of the main reasons for the region’s persistent premium.

Hungary continued to deal with reduced availability at the Paks nuclear power plant, which normally provides close to 2 GW of capacity and around half of domestic electricity production.

Several Paks units were affected by exceptionally low Danube water levels, although the gradual return of Unit 2 improved availability during the week. Hungary nevertheless remained heavily reliant on imports during periods of tighter supply, with imports approaching 2 GW on average early in the week.

Romania faced a similar situation at the Cernavodă nuclear power plant. Unit 1 had already been disconnected because of exceptionally low Danube levels, while operator Nuclearelectrica initiated a controlled shutdown of Unit 2 on 13 August.

The loss of both Cernavodă reactors removed approximately 1.4 GW of low-variable-cost nuclear capacity from the Romanian system. This increased reliance on coal, hydropower, renewable generation and imports, particularly during periods of elevated demand.

Hydrological conditions also remained weak in Serbia. Generation at Đerdap 1 was running at approximately 20% of normal levels, while Đerdap 2 was operating at around 30% amid exceptionally low Danube inflows. Serbian utility EPS consequently relied on market purchases to cover part of domestic demand.

The combination of reduced nuclear availability and weak hydro generation increased the value of flexible capacity across the region, particularly during the evening ramp after solar production disappeared.

Central Southeast Europe remains tightly coupled

Hungary, Romania, Croatia and Slovenia maintained strong price convergence throughout the week. On six of the seven days, the spread between the highest and lowest prices within the four-market cluster remained below approximately EUR 3/MWh.

The close coupling limited opportunities for sustained country-to-country spreads within the central SEE block, while larger differentials remained between the central markets and Greece, Bulgaria, Serbia and Italy.

Cross-border electricity flows continued to provide an important balancing mechanism. Hungary imported close to 2 GW during parts of the early week, although stronger renewable generation subsequently improved the wider regional balance.

By Wednesday, increased wind and solar generation had shifted the combined SEE system towards a small net-export position, although Hungary itself remained a significant importer.

Italy continued to attract electricity from the region because of its structurally higher price level. Exports towards Italy exceeded 1 GW during parts of the week, limiting the extent to which additional renewable generation could push down prices across Southeast Europe.

Meanwhile, gas and carbon prices maintained a relatively high thermal generation floor. Central European gas traded at approximately EUR 57–62/MWh, while EU carbon allowances remained around EUR 82–83/t.

These input costs imply short-run generation costs for modern gas-fired plants broadly consistent with central SEE baseload prices of around EUR 140–160/MWh. However, they do not explain evening prices above EUR 250–300/MWh.

Those spikes increasingly reflect scarcity of flexible generation, transmission constraints and the rapid withdrawal of solar capacity after sunset.

Forward prices continue to signal regional tightness

The Hungarian forward curve continued to price elevated regional power costs beyond the spot market. Week 34 traded around EUR 157/MWh late in the week, while September contracts were near EUR 161/MWh. Hungary therefore remained approximately EUR 25–27/MWh above comparable German contracts.

Early prices for Monday, 17 August, also pointed to a strong recovery following the weekend decline.

Hungarian day-ahead power rebounded to around EUR 184/MWh, while Slovenia and Croatia were both near EUR 181/MWh and Romania around EUR 173/MWh. Bulgaria rose to approximately EUR 170/MWh, while Greece reached around EUR 153/MWh.

The rebound indicates that week 33’s lower baseload averages were driven primarily by strong renewable generation and weaker weekend demand rather than a fundamental improvement in the regional supply balance.

For short-term Southeast European power trading, the widening difference between solar-rich hours and the evening period is becoming more important than the direction of baseload prices alone. Nuclear availability in Hungary and Romania, Danube hydrology, wind forecasts and cross-border transmission capacity remain key variables for the evening curve, while continued photovoltaic expansion is increasing downward pressure on daytime prices.

The changing price structure is also strengthening the economics of batteries and other flexible assets. Near-zero midday prices combined with evening settlements above EUR 200/MWh are creating increasingly attractive intraday spreads, even during weeks when headline baseload prices appear relatively stable.

As solar penetration rises and nuclear and hydro availability remain exposed to weather conditions, the value of flexibility is likely to become an increasingly important feature of Southeast Europe’s power markets.

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The European Commission’s Joint Research Centre has reported record-low August water levels on the Danube, Rhine, Loire and Po, while around 50% of the EU and the UK was experiencing some degree of drought and 9% had reached the most severe alert level. Forecasts continued to point towards warmer and drier conditions through August and into September.

This is no longer a conventional generation outage affecting a single plant or fuel. It is a correlated hydrological shock. Low water reduces hydroelectric generation while simultaneously limiting cooling-water availability for nuclear plants. Heatwaves then increase air-conditioning demand at precisely the time when hydro and nuclear availability is weakening. Stagnant high-pressure conditions can also reduce wind generation, leaving gas, coal, imports, batteries and demand response to cover the evening system.

Hydropower is directly dependent on river flows, hydraulic head and turbine efficiency. Run-of-river plants feel the impact almost immediately because lower discharge means less water passing through turbines and fewer megawatt-hours generated. Reservoir-based plants have greater flexibility, but operators must decide whether to use stored water during the summer or preserve it for evening peaks, emergency balancing and the winter season.

Nuclear plants face a different constraint. The reactor and nuclear fuel can remain fully operational, while the conventional part of the plant requires large volumes of cooling water to condense steam after it passes through the turbines. Low river levels can place water intakes and pump systems outside their normal operating range, while high river temperatures can restrict the amount of heated water that can be discharged back into the river.

The clearest example is Romania’s Cernavodă nuclear power plant. Unit 1 had already been shut down as Danube levels deteriorated, while Nuclearelectrica began the controlled shutdown of Unit 2 on the morning of 13 August because of the continuing decline in river levels. Each reactor has approximately 700 MW of installed capacity, meaning around 1.4 GW of Romanian baseload generation became unavailable. Both units remained in a safe shutdown condition, with no reported impact on personnel, the public or the environment.

Cernavodă normally provides approximately one-fifth of Romania’s electricity requirements, making the outage materially more significant than the loss of a small thermal unit. It increases import requirements, removes a major source of low-variable-cost generation and raises balancing exposure during evening demand peaks. Nuclearelectrica has also obtained force-majeure certificates covering electricity-delivery contracts because the severe Danube drought prevented the company from meeting all contracted supply obligations from its own generation.

The issue has therefore moved beyond plant operations into contractual, counterparty and earnings risk.

Hungary is experiencing a similar problem at the 2,000 MW Paks nuclear power plant, which normally supplies close to half of the country’s domestic electricity. Low Danube levels forced Units 1, 3 and 4 to shut down, while Unit 2 operated at half output for 11 days before gradually increasing production on 10 August. An official government update dated 13 August said Paks was operating at only around 500 MW, or 25% of installed capacity, while the Danube was again expected to decline.

The Paks situation demonstrates that the critical issue is not simply the total volume of water flowing through the river. Plant operator MVM has explained that sufficient water could theoretically remain available for cooling, but the river level had fallen below the effective suction elevation of existing pumps. Operating units require roughly 100 cubic metres of water per second, while the four shut units require only around 2.5 cubic metres per second for residual cooling.

The plant was operating with the river approximately 28 centimetres below the previous 2018 record and more than one metre below the century-minimum level assumed when Paks was designed more than four decades ago.

Hungary has responded with an emergency river-engineering programme. The government approved a bed sill requiring approximately 145,000 cubic metres of rock, with two 80-metre barges prepared as an additional temporary measure. The intervention is expected to cost around HUF6.1 billion, while the government estimates that a complete shutdown of Paks could impose a burden of at least HUF50 billion per month.

The comparison illustrates the growing economics of climate adaptation. Relatively modest investment in water-intake resilience can protect generation assets whose replacement-power costs can be many times higher.

Further downstream, the same Danube shortage is cutting Serbian hydropower production. Elektroprivreda Srbije reported that Đerdap 1 was producing only around 20% of its usual output, with inflows falling to approximately 1,400 cubic metres per second. Đerdap 2 was operating at around 30%. Đerdap 1 has 1,140 MW of installed capacity and historically received average Danube inflows of around 5,370 cubic metres per second.

EPS expected Serbian electricity demand to approach 100 GWh per day during the heatwave and said around 10% of requirements were being procured from the market to compensate for missing hydroelectric generation. Thermal plants were carrying a larger share of domestic demand, while EPS sought to preserve reservoir stocks and coal inventories ahead of winter.

Serbia is therefore exposed on two fronts: directly through lower Đerdap production and indirectly through reduced nuclear availability in neighbouring Hungary and Romania. The loss of inexpensive regional generation limits the amount of electricity available for import precisely when Serbian demand is elevated.

The situation also challenges the traditional assumption that cross-border imports will automatically compensate for domestic weather-related outages. Interconnectors can transfer electricity, but they cannot create additional generation when several interconnected markets experience the same weather shock. Romania, Hungary and Serbia can all require additional imports during the same evening hours, bringing Austria, Slovakia, Croatia and Bulgaria into the same price-formation chain.

Transmission congestion then determines where the scarcity premium appears.

The wider European power system remains broadly adequate. ENTSO-E’s pre-summer assessment identified no major systemic adequacy threat across most of Europe, supported by expanding renewable generation, stronger cross-border coordination and growing battery capacity. Battery capacity had reached approximately 29 GW, while expected European hydro storage at the beginning of the season was already 18% below June 2025 levels. Summer electricity demand was forecast to rise by around 2.5% year on year.

The subsequent deterioration in river conditions highlights the difference between having sufficient capacity at the European level and having available capacity in the right region and at the right hour.

France provides an important counterexample. Water constraints do not make nuclear generation structurally unreliable. French electricity production reached 284.3 TWh in the first half of 2026, up 4.6%, while nuclear output increased by 7.9 TWh and average nuclear availability reached 73.9%.

Nevertheless, RTE has acknowledged that heatwaves and prolonged drought can temporarily restrict individual river-cooled reactors because of water-flow and discharge-temperature limits. At fleet level, these losses remain relatively small, but their impact on prices can become significant when they coincide with heat-driven demand and weak wind generation.

The market impact is becoming most visible in hourly price structures rather than monthly averages. The International Energy Agency expects EU electricity consumption to increase by around 2% in 2026, supported by electrification and higher cooling demand. Average EU spot prices in the second quarter were already more than 30% above the previous year, partly because of higher gas-generation costs.

Water-related restrictions on nuclear and hydropower are adding another scarcity factor to a market that is already operating with elevated fuel costs.

Hungary’s HUPX market illustrates the changing price structure. The baseload price for delivery on 15 August was approximately €137.94/MWh, while the conventional peak-load block averaged only €101.59/MWh. Intraday prices for 16 August were around €40–60/MWh during solar-rich midday periods before rising towards approximately €200/MWh during the evening.

Serbia displayed an even sharper pattern on 15 August, with the SEEPEX day-ahead price falling to €0.01/MWh around noon before reaching €182.90/MWh later in the evening.

Romania showed the same structural inversion. The OPCOM baseload block for 16 August stood at around RON717.86/MWh, while the daytime peak block was lower at RON624.92/MWh. The late-night block exceeded RON1,046/MWh. In July, Romania’s day-ahead market had already averaged approximately €120/MWh.

These figures describe an electricity system with surplus solar generation in the middle of the day and increasingly scarce firm electricity after sunset. The traditional assumption that peak hours are automatically the most expensive is becoming increasingly outdated in solar-heavy markets.

The IEA reported that the spread between midday lows and evening highs reached as much as $600/MWh in several European markets during the June heatwaves. Spain recorded negative wholesale prices during 17% of hours in the first half of 2026, compared with 10% during the same period of 2025.

Europe can therefore experience excess electricity and acute scarcity within the same day. Average baseload prices conceal much of the commercial value now moving towards batteries, pumped-storage facilities, flexible hydropower, demand response and fast-starting thermal plants.

Additional solar capacity will help meet daytime cooling demand, but solar alone cannot replace nuclear and hydro generation during the 19:00–23:00 period. Without storage, more photovoltaic capacity can deepen midday price compression while doing relatively little to solve the evening ramp.

Wind offers a different production profile, with lower correlation to solar output and greater potential to generate after sunset. However, wind investment must also account for the possibility that major heatwaves coincide with weak wind conditions across several markets.

The investment response should therefore combine generation, flexibility and water resilience rather than focus on a single technology. EPS has identified a 1 GW solar project, the proposed Niš gas plant, the Bistrica pumped-storage project and the longer-term Đerdap 3 development as components of Serbia’s security-of-supply strategy.

Hungary is accelerating investment in wind, storage and transmission, while Romania’s nuclear programme will increasingly need to incorporate cooling-water resilience into plans for the refurbishment of Cernavodă Unit 1 and the development of additional nuclear capacity.

A potential Southeast European resilience programme for 2027–2032 could require approximately €4–7 billion, although these figures represent analytical ranges rather than announced project budgets. Around €300–800 million could be allocated to deeper nuclear and thermal intakes, pumping systems, cooling optimisation, dredging and river-control infrastructure.

Another €800 million–€1.5 billion could support hydroelectric rehabilitation, reservoir digitalisation and projects designed to increase generation efficiency per cubic metre of water. Approximately €1–2 billion could support 2–4 GWh of battery storage and industrial demand-response infrastructure, with the remainder directed towards pumped storage, transmission reinforcement and strategically important interconnectors.

Battery projects will increasingly depend on their ability to monetise volatility rather than simply provide backup capacity. For a two-hour battery located in a volatile Central or Southeast European market, an illustrative model based on investment costs of €250,000–€400,000 per MWh, 250–300 annual equivalent cycles, a captured spread of €90–130/MWh and additional balancing revenues could produce a nominal equity IRR of approximately 12–16%.

Returns could rise towards 15–20% if evening scarcity remains persistent or capacity payments are introduced. Conversely, a normalisation of spreads towards €50–70/MWh could push returns back towards high-single-digit levels. A 12–18-month grid-connection delay could reduce equity IRR by roughly 2–5 percentage points while increasing effective project costs through interest during construction, equipment escalation and delayed revenues.

Hydropower requires a different investment approach. A reservoir plant may generate fewer annual megawatt-hours during dry periods but can increase the value of each unit of electricity by concentrating production during high-price evening hours. Its value increasingly comes from flexibility, balancing services, black-start capability and avoided scarcity purchases, rather than baseload generation alone.

Run-of-river projects have considerably less flexibility and should therefore be valued using more conservative climate-adjusted production assumptions.

Nuclear projects also require a more explicit hydrological risk premium. Plant valuations, availability guarantees and long-term PPAs should consider intake depth, river-bed erosion, minimum-flow forecasts, water-temperature restrictions and alternative cooling arrangements. Historical capacity factors based on twentieth-century river conditions are no longer sufficient for robust debt sizing or contracted-output guarantees.

The immediate outlook remains dependent on rainfall across the Alps, Central Europe and the Danube basin. Significant precipitation could allow nuclear units to restart and increase hydropower generation, while lower temperatures would reduce cooling demand. However, depleted soils, low river flows and reduced reservoir levels do not recover immediately.

Even after the current operational emergency ends, utilities will enter the autumn with greater sensitivity to reservoir preservation, nuclear availability and replacement-power costs.

Europe’s electricity market is therefore assigning an increasingly visible premium to water that can be converted into a reliable megawatt-hour after sunset. The most valuable assets are no longer necessarily those capable of producing the greatest annual volume, but those that can remain available during the narrow evening window when heat, low river flows and declining solar generation converge.

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The disruption highlights the increasingly interconnected nature of hydro, nuclear and thermal-generation risks. Cernavodă’s two CANDU reactors do not depend on reservoir inflows for fuel, but their operation remains sensitive to river flow and temperature conditions. Danube discharge has fallen from a seasonal norm of more than 4,000 cubic metres per second to around 1,600 cubic metres per second, with earlier forecasts pointing to a further decline towards 1,500 cubic metres per second.

Romania had already declared an energy-sector state of alert for August. With both nuclear units unavailable, authorities have postponed the retirement or temporary withdrawal of coal-fired capacity, encouraged consumers to reduce evening demand and increased reliance on imports from Bulgaria, Hungary, Serbia and Ukraine. Dacia and Ford have reportedly suspended automotive production until 19 August, reducing industrial consumption during the most critical period.

The Romanian system can compensate for the missing nuclear output as long as regional interconnectors and neighbouring markets retain sufficient spare capacity. The country has aggregate technical import capacity of around 3.3 GW, although commercially available capacity is lower and varies by hour. A combination of extreme heat, weak Balkan hydrology or additional outages in Bulgaria and Hungary could rapidly reduce that buffer.

Moldova is particularly vulnerable to the regional imbalance. Romanian imports can cover a substantial share of Moldovan demand, but higher balancing requirements in Romania could force Moldova to rely more heavily on costlier supplies from Ukraine or western interconnected markets.

The outage is also changing the earnings outlook for Hidroelectrica, Nuclearelectrica, OMV Petrom and Complexul Energetic Oltenia. Nuclear generation normally provides Romania with stable baseload electricity at low marginal cost. Its temporary removal increases the value of gas-fired and coal generation, while weak hydrological conditions limit Hidroelectrica’s ability to fully benefit from higher prices. OMV Petrom’s Brazi gas-fired plant gains additional dispatch value, while coal-fired assets regain a temporary security-of-supply role despite their high carbon intensity.

Quarter-hourly coupling creates a €1-to-€199/MWh regional price curve

The day-ahead market for delivery on 15 August showed strong price convergence between Hungary and Romania, while Bulgaria remained relatively closely aligned after adjusting for its one-hour time difference.

Hungary’s HUPX market recorded an average price of approximately €115.10/MWh, with prices falling to €1/MWh at 13:15–13:30 and reaching a maximum of €199.10/MWh at 19:45–20:00. Romania’s OPCOM market averaged around €115.20/MWh, with the same €1/MWh floor and €199.10/MWh peak, although both occurred one hour later in local time.

Bulgaria recorded a lower average of approximately €102.90/MWh. Prices also fell to €1/MWh during the afternoon, while the maximum reached €177.70/MWh. The lower Bulgarian price profile reflects stronger domestic nuclear availability, coal generation and the country’s rapidly expanding battery-storage fleet.

The shape of the curve is more important than the daily average. In Hungary, prices declined from above €150/MWh in the morning to almost zero around midday, before recovering above €175/MWh during the evening and approaching €200/MWh after sunset. Romania followed a remarkably similar pattern despite the Cernavodă outage.

The convergence demonstrates the effectiveness of cross-border market coupling during much of the session, but it does not mean that the underlying systems were equally balanced. Romania’s generation deficit was partially transferred into regional imports, while Hungarian and Bulgarian solar surpluses helped establish the common midday price. During the evening ramp, rising demand and the rapid withdrawal of photovoltaic generation produced a shared scarcity signal.

Intraday and balancing markets remain considerably more exposed than the day-ahead auction indicates. Unexpected changes in wind output, additional thermal deratings or reductions in import capacity can force system operators to procure electricity at prices significantly above day-ahead levels. Romania’s dependence on scheduled imports also leaves less cross-border headroom for correcting forecast errors.

For traders, the opportunity is therefore shifting away from a simple Romania-Hungary baseload spread. More attractive strategies increasingly involve quarter-hourly solar-to-evening shape trades, intraday adjustments around nuclear-return expectations and cross-border capacity optionality when coupled markets begin to separate.

Solar generation is increasing volume while reducing midday value

The €1/MWh midday clearing price in Hungary, Romania and Bulgaria demonstrates that the region’s solar build-out has reached a scale capable of depressing prices simultaneously across several interconnected markets, even during a major nuclear outage.

Hungary’s solar fleet has expanded beyond the point at which domestic afternoon demand can absorb all available generation without greater reliance on exports, curtailment or storage. Romania is moving in the same direction, while Bulgaria’s growing utility-scale and commercial photovoltaic capacity is creating increasingly pronounced summer price troughs.

The development presents a growing challenge for unhedged solar projects. Plants can produce their highest physical output during the very quarter-hours in which wholesale prices are at their lowest. As a result, capture prices can decline even when average baseload prices remain above €100/MWh.

This increases the importance of fixed-price or floor-price PPAs, route-to-market agreements with active intraday optimisation and co-located storage. It also changes how curtailment and imbalance risks are allocated between generators and buyers. PPAs based solely on annual contracted volumes can hide significant exposure to zero-price periods, negative-price provisions and replacement-energy costs after sunset.

Industrial consumers, meanwhile, have an opportunity to benefit from the same volatility. Energy-intensive companies capable of shifting production towards midday can access wholesale electricity at prices close to zero, although network charges, taxes, supplier margins and balancing costs remain. Electrolysers, pumping facilities, refrigeration, water-treatment plants and flexible industrial processes are particularly well positioned to exploit these price patterns.

Evening prices also demonstrate that solar generation is not reducing the value of electricity across the entire day. Instead, it is widening the gap between solar hours and firm supply. Wind projects retain a different revenue profile because their generation is less concentrated around the midday solar trough and can continue after sunset.

Bulgaria’s battery expansion begins to reshape regional scarcity

Bulgaria’s lower average price and less pronounced evening peak highlight the growing system value of battery storage. The country has commissioned a significant battery fleet through its RESTORE support programme, including Enery’s 150 MW/600 MWh Nova Zagora BESS, developed with Sungrow and Sunotec.

A four-hour battery of this size can absorb surplus photovoltaic generation during low-price periods and release up to 150 MW during the evening ramp. A single project cannot determine the national price curve, but a growing portfolio of similar systems can reduce balancing requirements, limit price spikes and preserve export capacity when neighbouring markets are short.

The economics are visible in the day-ahead curve. The difference between a €1/MWh minimum and evening prices around €165/MWh implies a gross spread of almost €164/MWh. A four-hour battery capturing a realised spread of €120–€160/MWh could theoretically generate approximately €72,000–€96,000 of gross daily arbitrage revenue per 150 MW of discharge capacity, before accounting for round-trip losses, degradation, market fees and imbalance costs.

Such returns will not remain constant. As storage capacity increases, batteries will compete against one another, pushing midday prices higher and evening prices lower. The long-term revenue stack will therefore need to include intraday optimisation, balancing energy, frequency services and other capacity-related products where available.

The next wave of Bulgarian investment is increasingly focused on hybridisation. OMV Petrom and Enery’s Gabare project in the Byala Slatina region combines approximately 415 MWp of solar capacity with 600 MWh of storage. The partners estimate total investment at around €300 million, including approximately €100 million for the battery component, with first generation expected in 2028. OMV Petrom has agreed to purchase half of the solar output under a PPA.

Gabare’s commercial model depends less on selling all photovoltaic production immediately and more on converting a variable generation profile into a more predictable product. The battery can reduce exposure to low and negative prices, shift deliveries towards higher-value hours and limit balancing costs, although 600 MWh remains relatively modest compared with the potential daily output of a 415 MWp solar plant.

Romania’s storage pipeline moves towards bank financing

Romania’s nuclear disruption strengthens the investment case for battery storage while also highlighting the limitations of relying on projects that remain in development.

The country is preparing a €150 million support programme for standalone storage, with market estimates suggesting that it could enable approximately 3–4 GWh of capacity depending on grant intensity and eligible costs. The strongest projects are likely to be those capable of combining public support with merchant revenues rather than relying on subsidies to compensate for weak grid locations or inadequate trading strategies.

Private lenders have already demonstrated a willingness to finance storage at a much larger scale. Enery’s Ogrezeni hybrid project in Giurgiu County combines 761 MWp of solar, 534 MW of grid-connected photovoltaic capacity and more than 1 GWh of BESS. The company secured a €460 million syndicated green financing led by UniCredit and supported by Intesa Sanpaolo, ING, Banca Transilvania, National Bank of Greece, Exim Banca Românească and Alpha Bank. An accordion facility of up to €79 million allows for additional battery expansion.

The financing structure demonstrates that regional storage is becoming increasingly project-financeable when integrated into a large renewable portfolio, backed by an experienced sponsor and supported by multiple facilities covering term debt, VAT, working capital and contingencies. Standalone merchant batteries without contracted revenues or bankable optimisation agreements continue to face greater leverage constraints.

MORE’s Stâlpu 2 project, currently in trial operation, provides a smaller operational example. The facility combines 63 MW of solar with a 10 MW/21 MWh battery and is expected to generate approximately 76 GWh annually. MORE’s participation in nine regional power exchanges enables it to optimise the asset within a broader trading portfolio rather than treating storage simply as an extension of the solar plant.

That operating model is becoming a competitive advantage. Utilities and traders with access to multiple markets can combine physical generation, storage, cross-border capacity and customer portfolios. Standalone developers must acquire these capabilities through route-to-market agreements, transferring part of the potential storage margin to aggregators.

Danube weakness reduces Serbian hydro output and complicates coal logistics

The same hydrological conditions affecting Cernavodă are also reducing generation from Serbia’s largest hydropower complex. Đerdap 1, jointly operated across the Serbian-Romanian section of the Danube, has recently produced approximately 5,000 MWh per day, around one-third of its normal daily generation. The Serbian side forms part of a combined complex with roughly 1,140 MW of installed capacity.

EPS reported that generation during May and June was the weakest for those months since Đerdap 1 entered service in 1970. The loss of low-cost hydro generation increases dependence on the Nikola Tesla and Kostolac lignite plants, imports and other reservoir generation within the EPS portfolio.

Low river levels are also affecting thermal generation and fuel logistics. Cooling-water constraints have reduced flexibility at Kostolac, while barges and tankers operating on the Danube have reportedly carried only 30–40% of normal cargo volumes. At one point, July fuel imports were approximately 25% of the monthly target.

The financial impact is asymmetric. Hydro shortfalls remove EPS’s cheapest and most flexible generation precisely when regional evening prices are strengthening. Coal plants can replace part of the missing energy, but at higher operating, maintenance and carbon-adjusted costs. Imports protect physical security while exposing EPS to HUPX- and OPCOM-linked prices approaching €200/MWh during evening peaks.

This increases the strategic value of Serbia’s planned 1 GW solar and storage programme, being developed by EPS with Hyundai Engineering and UGT Renewables. The project covers six locations and is expected to include approximately 1.2 GWp of photovoltaic modules, 1 GW of connection capacity and at least 200 MW/400 MWh of battery storage.

K-SURE has indicated support for up to €900 million of financing within an estimated investment of approximately €1.1 billion. The financing structure is linked to Korean equipment exports and Swedish export-credit reinsurance. However, the proposed battery provides only two hours of full-discharge duration and represents a relatively small share of the solar portfolio’s installed capacity. It can support ramp management and balancing but cannot compensate for prolonged hydro or nuclear outages.

The financing model will therefore need to account for multi-day low-hydro conditions, solar curtailment, EPS counterparty strength and potential grid-connection delays. A 12–18-month transmission delay could postpone energy revenues while interest during construction and battery warranty periods continue, potentially reducing a projected 10–12% equity return to high-single-digit levels unless EPC and connection agreements allocate delay risks effectively.

East Mediterranean gas gains a route to European markets

One of the most significant gas developments is emerging from Cyprus, where Eni and TotalEnergies are targeting the first European deliveries from the Cronos field during the first half of 2028. The field is estimated to contain around 3 trillion cubic feet of natural gas.

The proposed US$2 billion development would connect Cronos with Egypt’s offshore Zohr infrastructure before sending the gas to the Damietta LNG terminal for export to European buyers. Using existing Egyptian processing and liquefaction infrastructure avoids the cost and delays associated with constructing a new LNG plant in Cyprus.

Most of the production is expected to be directed towards Europe, while around 20% could supply Egypt’s domestic market. The arrangement links Cypriot upstream resources with Egyptian infrastructure and European LNG demand, creating an eastern Mediterranean supply chain without requiring a direct pipeline connection to Greece.

The project also complements the regional Vertical Gas Corridor, through which Greece, Bulgaria, Romania, Hungary, Slovakia, Ukraine, Moldova, Serbia and North Macedonia are seeking to move LNG and Caspian gas northwards. Serbia’s Srbijagas has reserved approximately 300 million cubic metres annually for 10 years at the Alexandroupolis LNG terminal.

The investment case will depend on liquefaction availability, shipping costs, European gas prices and political stability in the eastern Mediterranean. Cronos is relatively small compared with total European gas consumption, but its strategic importance lies in diversifying supply through infrastructure outside the Russian transit system.

Grid resilience gains measurable commercial value

The current regional stress combines several risks that are often modelled separately in energy projects: low hydro inflows, nuclear cooling restrictions, coal-plant deratings, reduced river transport, high cooling demand and volatile solar generation. In reality, these risks are increasingly correlated because they are driven by the same heat and drought conditions.

The market impact is already measurable. Romania and Hungary moved from around €1/MWh at midday to €199.10/MWh during the evening, while Bulgaria’s expanding storage fleet helped contain part of the equivalent price ramp. Interconnection prevented Romania’s generation deficit from developing into a physical supply shortage, but it also transmitted the scarcity premium across neighbouring markets.

The changing price curve is reshaping the hierarchy of investable assets. Unshaped solar faces increasing capture-price erosion. Wind retains greater system value when it generates outside the main solar hours. Batteries benefit from volatility but require sophisticated dispatch strategies and multiple revenue streams. Gas plants and flexible coal capacity retain security-of-supply value but remain exposed to fuel and carbon costs.

Nuclear generation continues to offer low-cost baseload power, but the Cernavodă outage demonstrates that water availability is becoming an increasingly important operational risk for thermal generation, including nuclear.

The Danube has therefore become more than a transport or hydropower resource. It is simultaneously a generation asset, a nuclear cooling source, a constraint on thermal plants and a critical fuel-transport corridor. Its exceptionally low levels are exposing the value of flexibility across Southeast Europe and demonstrating how tightly interconnected the region’s electricity and gas systems have become.

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GRITA 2 would complement the existing 500 MW interconnector, which has been operating since 2002. The new link could significantly increase Greece’s ability to export renewable electricity during periods of surplus, import power during supply shortages and strengthen its role as a gateway between the Balkans and Western European electricity markets. For Italy, the project would provide access to a more diversified generation portfolio while reinforcing the wider Mediterranean electricity corridor.

However, the economic value of the new connection will depend on more than its headline capacity. Price differences between the Greek and Italian markets, availability during critical periods and the ability of domestic networks to transport electricity to and from the interconnector will all determine its utilisation. Cross-border capacity has limited value if internal congestion prevents electricity from reaching the border. The €1.9 billion investment will therefore need to be supported by coordinated onshore grid reinforcement and efficient capacity allocation.

The Western Balkans face a different challenge. The region has extensive physical interconnection, but commercial integration remains incomplete. Industry analysis citing Energy Community estimates suggests that as much as 70% of electricity flows through the region may represent transit between EU countries. Serbia alone is connected to eight neighbouring electricity systems, yet Western Balkan day-ahead markets are still not fully integrated into the EU Single Day-Ahead Coupling framework.

Market coupling allows electricity and cross-border transmission capacity to be allocated through a single calculation, directing electricity toward higher-priced markets until network constraints are reached. Without such mechanisms, traders must secure transmission rights and electricity separately, increasing transaction risks and limiting market liquidity. The result is a region with substantial physical electricity flows but without the full economic benefits of integrated trading.

Regulatory alignment also remains uneven across the Western Balkans. A 2025 assessment placed Serbia at 63% alignment with Energy Community requirements, followed by Montenegro and North Macedonia at 53%, Albania at 50%, Kosovo at 46% and Bosnia and Herzegovina at just 26%. Bosnia and Herzegovina still requires an effective state-level framework and organised electricity market, while other countries continue to work on balancing arrangements, unbundling and market-coupling reforms.

Carbon policy is adding further pressure for reform. From 2026, the EU’s Carbon Border Adjustment Mechanism (CBAM) applies to electricity imports, increasing the importance of aligning Western Balkan power markets with EU climate and electricity-market rules. Estimates suggest that up to 60% of electricity imported into the EU from Bosnia and Herzegovina, Montenegro, North Macedonia and Serbia can originate from coal generation. Introducing domestic carbon pricing could retain revenues within the region and help finance the energy transition, but it would also expose ageing lignite plants to their full economic costs.

GRITA 2 illustrates what deep physical integration could look like, while the Western Balkans demonstrate why transmission infrastructure alone is not enough. Southeast Europe needs functioning power exchanges, common market-coupling algorithms, transparent carbon pricing and coordinated cross-border capacity calculation.

Physical interconnectors move electricity; market integration determines the value of those flows. The region’s next stage of integration will therefore depend not only on building more cables, but on creating the regulatory and commercial structures capable of turning those connections into lower costs, greater security of supply and stronger incentives for cleaner generation.

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The regulator examined the extreme summer conditions of 2024, when average peak electricity prices in the affected Southeast European markets reached around €350/MWh. The most significant pressure emerged after sunset, when solar generation declined rapidly while electricity demand remained elevated. The region lacked sufficient flexible resources to replace the lost solar output, while limited import capacity—including restrictions linked to planned network maintenance—prevented cheaper Central European electricity from fully relieving the shortage.

ACER estimates that 147 of the most severe price spikes could have been avoided if the EU requirement to make at least 70% of relevant transmission capacity available for cross-zonal trade had been met. This does not mean every transmission line must operate at 70% of its physical thermal capacity at all times, as the regulatory methodology accounts for reliability margins and contingencies. However, it highlights how domestic congestion and insufficiently coordinated operational decisions can leave too little transmission capacity available to the integrated electricity market.

The affected Southeast European markets include Slovenia, Croatia, Hungary, Romania, Bulgaria and Greece, while Austria and Slovakia provide the relevant Central European comparison. Electricity flows across this corridor are influenced by outages and network constraints that can occur far from the national border where transmission capacity is allocated. Flow-based market coupling and stronger regional coordination are therefore increasingly important because bilateral capacity figures cannot fully capture the behaviour of a highly interconnected and meshed electricity network.

ACER is calling for improved outage planning, greater use of curative remedial actions, faster delivery of high-impact network investments and full implementation of flow-based market coupling. It also supports greater use of grid-enhancing technologies, including dynamic line rating, which can increase available transmission capacity by more than 50% on certain constrained network elements under favourable conditions.

However, stronger interconnection alone will not solve the region’s evening supply problem. If several Southeast European countries experience the same post-sunset decline in solar generation, neighbouring markets may all attempt to import electricity simultaneously. Storage, demand response, flexible hydropower and fast-start generation therefore remain essential components of a resilient regional system. Cross-border trading can reduce the cost of scarcity by pooling available resources, but it cannot create surplus electricity when the entire region faces a simultaneous shortage.

The commercial implications are substantial. Persistent price separation creates opportunities for battery storage and electricity traders, but increases costs for energy-intensive industrial consumers and weakens the expectation that renewable expansion will automatically translate into cheaper electricity. It also changes the relative value of generation and flexibility assets. A megawatt of flexible capacity located near a congested border or within a constrained market can potentially be more valuable than an equivalent megawatt located in an unconstrained area.

ACER’s findings therefore shift the policy debate away from simply building more transmission lines. Southeast Europe needs to use existing infrastructure more efficiently, coordinate network outages more effectively and apply common market rules consistently. Operational reforms and additional flexibility could provide some of the fastest reductions in price volatility while larger interconnectors and grid investments are being developed.

The region’s electricity-price problem is increasingly a market-design and flexibility challenge as much as a generation challenge. Closing that gap will require Southeast Europe to treat its electricity system as an integrated regional market rather than a collection of national grids.

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The investment response is already becoming significant. SeeNext’s 2026 regional assessment found that the five largest Southeast European electricity markets have earmarked multi-billion-euro investments in grid infrastructure, with Greece leading at approximately €7.8 billion. Romania and Bulgaria are implementing the €208 million CARMEN smart-grid programme, while utilities across the region are seeking financing for substations, smart meters, digitalisation and network automation.

The spending reflects a fundamental change in how electricity flows through the system. Traditional grids were designed to transport power from a relatively small number of thermal, nuclear and hydropower plants toward consumers. Today, thousands of solar installations feed electricity into lower-voltage networks, large renewable projects are often located far from demand centres, and batteries can switch between consumption and generation within minutes. Grid operators are therefore managing increasingly complex two-way flows with infrastructure designed for a much simpler power system.

Connection queues are one of the clearest symptoms of this mismatch. Developers can reserve grid capacity years before reaching financial close, potentially blocking viable projects behind speculative applications. Transparent development milestones, financial guarantees and use-it-or-lose-it rules could help clear these queues while ensuring that smaller investors are not unfairly excluded. Publishing available network capacity could also encourage developers to choose locations where reinforcement requirements and connection costs are lower.

Technology can provide another part of the solution. ACER estimates that dynamic line rating could increase available capacity on relevant Southeast European network elements by more than 50% under certain conditions. Instead of relying on conservative static limits, the technology uses real-time weather and equipment data to determine how much electricity transmission lines can safely carry. Advanced conductors, phase-shifting transformers and coordinated remedial actions can similarly unlock additional capacity before major new transmission corridors are completed.

These measures will not eliminate the need for conventional grid expansion. New interconnectors, substations and internal transmission lines remain essential to accommodate the region’s growing electricity demand and renewable capacity. However, construction can take years because of route selection, permitting, public opposition and long equipment lead times. Grid-enhancing technologies can act as a bridge, while also improving the utilisation of expensive infrastructure once new projects are completed.

Regulation will need to evolve alongside the physical network. Grid companies require predictable returns for anticipatory investment, allowing them to build infrastructure ahead of confirmed demand. At the same time, consumers need protection against unnecessary investment and underused assets. Regulatory frameworks should increasingly reward connections delivered, congestion reduced, losses lowered and flexibility procured, rather than simply measuring the amount of capital invested.

The consequences extend beyond the electricity sector. Industrial investors are increasingly evaluating locations based on grid availability and access to reliable, low-carbon electricity. A congested network can delay data centres, electric furnaces, heat pumps and hydrogen projects even when sufficient generation capacity exists elsewhere. Grid infrastructure is therefore becoming an increasingly important industrial-policy tool.

Southeast Europe’s renewable transition will not ultimately be determined by which country announces the largest generation pipeline. It will be determined by which markets can connect credible projects, operate networks closer to their real physical limits and coordinate investment across borders.

Generation capital is available. The grid is increasingly becoming the factor that determines whether that capital is transformed into productive energy infrastructure.

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The project brings together Bulgaria’s Electricity System Operator, Romania’s transmission system operator Transelectrica and Romanian distribution company Delgaz Grid. Bulgaria’s share of the investment exceeds €59 million, including approximately €29 million in funding from the Connecting Europe Facility. Implementation is scheduled to continue through 2032.

CARMEN is not simply another cross-border interconnector. Instead, it represents a coordinated package of substation reconstruction, automation, telecommunications and control-system upgrades aimed at increasing the usable capacity and visibility of the existing electricity network. In Bulgaria, the work includes substations such as Dobrudzha, Varna, Gorna Oryahovitsa, Mizia and Balkan. More than 1,100 kilometres of optical telecommunications infrastructure are also planned along overhead lines, including the 400 kV Druzhba and Saedinenie interconnectors with Romania.

That distinction is increasingly important because Southeast Europe’s grid challenges cannot be addressed solely by constructing additional transmission lines. Renewable generation is geographically dispersed and can change rapidly depending on weather conditions. Real-time data, automated controls and coordinated remedial actions are becoming essential for using existing infrastructure safely and efficiently. In some cases, digitalisation can unlock additional network capacity faster and at lower cost than conventional grid expansion.

CARMEN’s geographical focus is also strategic. Northeastern Bulgaria and southeastern Romania have significant wind and solar potential, while the wider north-south electricity corridor connects renewable-rich areas with major demand centres and neighbouring markets. Increasing the controllability and visibility of the network could help reduce renewable curtailment, strengthen cross-border electricity trading and support future green-hydrogen development.

The project also illustrates the growing operational connection between transmission and distribution networks. Rooftop solar, batteries, electric vehicles and flexible industrial consumers are largely connected at the distribution level, but their combined behaviour increasingly influences national balancing and cross-border electricity flows. Delgaz Grid’s involvement reflects the reality that a smart transmission system cannot operate efficiently without an intelligent distribution layer.

The wider investment environment reinforces this trend. In July 2026, the EBRD separately provided Delgaz Grid with a RON 300 million loan, equivalent to around €57 million, to support its 2026–2030 electricity-network investment programme, including modernisation, digitalisation and smart-meter deployment. The financing is separate from CARMEN’s €208 million budget, but both projects contribute to the same broader transformation of the regional electricity system.

Implementation will nevertheless present challenges. Digital infrastructure requires interoperable systems, strong cybersecurity, skilled personnel and disciplined procurement. Installing sensors has limited value if operators cannot exchange the resulting data or incorporate it into real-time capacity calculations. Cross-border projects also face the risk of asynchronous implementation, where one country completes its infrastructure before the corresponding systems in the neighbouring country are ready.

If successfully implemented, CARMEN could demonstrate that the value of a modern electricity grid is not measured only by the number of kilometres of new transmission lines. Better information, automation and control can allow existing infrastructure to accommodate more renewable electricity, manage contingencies and facilitate cross-border trade.

For Southeast Europe, where permitting and constructing major new transmission infrastructure can take many years, improving the performance of the network already in place could prove just as important as building new lines.

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Romania’s Nuclearelectrica shareholders approved a conditional final investment decision for the Doicești SMR project in February 2026. The proposal would replace a former 600 MW coal-fired power station with six NuScale modules rated at 77 MW each, providing a total capacity of 462 MW. Project communications estimate that the development could create around 4,000 jobs across development, construction, manufacturing and operations, including approximately 200 permanent positions.

The main uncertainty remains cost and financing. Published estimates have ranged from around €4.9 billion to $6–7 billion. Romania has discussed potential support of up to $3 billion from the US Export-Import Bank and another $1 billion from the US International Development Finance Corporation. However, the final commitments, drawdown conditions and capital structure still need to be resolved. Nuclearelectrica said in May 2026 that work was continuing on financing, licensing, cost optimisation and establishing a commercially viable electricity price. Importantly, moving into the next development phase does not represent an unconditional construction commitment at a fixed cost.

Bulgaria’s proposed Kozloduy Units 7 and 8 would use Westinghouse AP1000 technology and provide approximately 2,300 MW of combined capacity. Citi has been appointed exclusive coordinator and export-credit arranger for the project, describing the mandate as its largest nuclear-financing assignment in Central and Eastern Europe. The overall financing requirement has not been disclosed. Unit 7 is currently targeted for 2033, with Unit 8 expected to follow.

Slovenia’s JEK 2 represents an even larger undertaking relative to the size of its domestic market. Public cost estimates have ranged from approximately €9.6 billion to €15.4 billion, depending on reactor capacity and underlying assumptions. A proposed referendum was cancelled in 2024 amid legal and transparency concerns, but technical and project preparation has continued. Because the existing Krško nuclear plant is jointly owned by Slovenia and Croatia, any expansion or replacement project carries important cross-border commercial and political implications.

The three projects share a common strategic rationale: preserving firm, low-carbon electricity as coal capacity is phased out and solar and wind generation expand. Nuclear power can reduce dependence on gas imports, support industrial electricity demand and provide stable generation that complements variable renewable sources. At the same time, the projects face similar challenges, particularly construction delays, cost overruns and the need for state-backed financing or revenue support.

For Southeast European electricity markets, the central question is whether such projects can be financed through commercial revenues alone. In practice, first-of-a-kind nuclear developments are unlikely to rely entirely on merchant electricity prices. Governments may therefore need to consider contracts for difference, state guarantees, regulated-asset models, export-credit financing or direct public ownership. Each approach allocates risks differently among taxpayers, consumers, developers and lenders.

That makes financial transparency and risk allocation just as important as reactor technology. Governments and investors need clear information on expected electricity prices, construction costs, financing conditions and potential downside exposure before committing billions of euros over several decades.

Southeast Europe is therefore not simply deciding which nuclear technologies to build. It is deciding which financial and construction risks it is prepared to carry for the long term. Doicești could help establish an SMR supply chain in the region, Kozloduy could strengthen Bulgaria’s position as a major source of firm electricity, while JEK 2 could deepen the long-standing Slovenia-Croatia energy partnership.

Ultimately, the projects most likely to succeed will not necessarily be those with the largest capacity targets. Credible financing, disciplined project governance and transparent risk allocation will be the decisive factors in turning Southeast Europe’s renewed nuclear ambitions into operating power plants.

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Unit 1 entered commercial operation in 1996 and typically supplies around 10% of Romania’s electricity. Extending its operating life would preserve a major source of low-carbon, dispatchable generation at a time when coal capacity is being phased out and renewable output is becoming increasingly variable. It would also help maintain the technical expertise, workforce and supply chains associated with Romania’s CANDU nuclear fleet.

The EIB financing represents an important part of the investment, but not the project’s full cost. Refurbishment requires the replacement or upgrading of major reactor systems, extensive safety improvements and preparations for a second operating cycle. Such work involves a complex and carefully planned outage, meaning that cost control, scheduling and project execution will be critical, even though refurbishment generally carries less construction risk than developing an entirely new nuclear site.

The strategic rationale for extending Unit 1 is strong. Romania’s two Cernavodă reactors normally account for around one-fifth of national electricity generation. Their stable output complements rapidly expanding wind and solar capacity while reducing the country’s exposure to imported fossil fuels. Nuclear life extension can therefore support both decarbonisation and energy security without requiring Romania to wait for a new generation of nuclear projects to materialise.

However, the Danube emergency of August 2026 exposed an important vulnerability. Record-low water levels forced one Cernavodă reactor offline and threatened the cooling supply of the remaining unit. Authorities responded by removing a rock obstruction, dredging the riverbed and constructing a temporary dike from rock-filled barges. The measures increased the local water level by around four centimetres and extended the remaining unit’s operation by at least nine days.

The incident broadens the definition of nuclear resilience. Reactor safety and fuel security remain fundamental, but future nuclear investment must also account for heat and water stress. Cooling-system design, water intakes, river-basin forecasting and operating limits will increasingly need to reflect more extreme hydrological conditions. A plant can be a major source of low-carbon electricity while still being exposed to climate-related risks.

The regional implications are significant. A prolonged outage at Cernavodă can tighten electricity supply not only in Romania but also across interconnected Southeast European markets, particularly when drought is simultaneously reducing hydropower generation. This correlation strengthens the case for batteries, demand response and stronger interconnections alongside nuclear refurbishment. Firm generation remains essential, but no single technology can be considered completely firm under every climate scenario.

For other nuclear markets in Southeast Europe, Romania’s experience offers an important benchmark. Bulgaria, Slovenia and Croatia all face strategic decisions concerning the extension of existing nuclear capacity or the development of replacement projects. Refurbishment can generally be faster and less capital-intensive than new nuclear construction, but its benefits depend on regulators confirming that both technical and climate-related vulnerabilities are adequately addressed.

Cernavodă Unit 1 is therefore more than an ageing reactor receiving new equipment. It represents a test of whether Southeast Europe can preserve its existing low-carbon generation base while adapting critical infrastructure to a more challenging operating environment. The €800 million EIB commitment demonstrates confidence in the project, while the Danube crisis has raised the bar for the resilience that the refurbished reactor will need to deliver.

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The concept behind pumped storage is straightforward. When electricity is abundant and prices are low, water is pumped into an upper reservoir. When demand and prices increase, the stored water is released through turbines to generate electricity. Although a pumped-storage plant consumes more electricity than it produces over a complete cycle, it effectively converts low-cost electricity into dispatchable peak power while providing reserves, inertia and other essential grid services.

Bistrica’s strategic importance is increasing as Southeast Europe’s hourly electricity price profile changes. Rapid solar deployment is pushing prices lower during periods of strong midday generation, while evening prices can rise sharply once the sun sets. Batteries are highly effective for fast, short-duration balancing, but large pumped-storage facilities can store considerably more energy and operate for several decades. The two technologies are therefore complementary rather than competing solutions.

Serbia has approved the spatial plan for Bistrica and has explored potential Japanese participation, with the goal of bringing the project into operation early in the next decade. However, its economics require careful scrutiny. An estimated €1.2 billion investment is not the same as a secured financing package, while major hydropower construction projects face significant geological, environmental and construction risks. Electricity arbitrage alone may not generate sufficient revenues to justify such a capital-intensive asset. Capacity payments, ancillary-service revenues or another mechanism that compensates the plant for its wider system value may therefore be required.

Existing hydropower infrastructure can offer a lower-risk route to increasing flexibility. Romania’s Hidroelectrica signed a €188 million contract in May 2026 to refurbish the 335 MW Râul Mare Retezat hydropower plant. Modernisation can extend asset life, improve efficiency and reliability, and recover flexible generation without the need to build an entirely new dam. Serbia is also preparing the long-delayed reconstruction of the four-plant Vlasinske cascade with support from the EBRD and the European Union.

This points to two distinct hydropower investment markets in Southeast Europe. The first is refurbishment: relatively well-defined projects that restore lost performance and adapt ageing infrastructure to an increasingly variable electricity system. The second is new pumped storage: larger and more complex developments whose long-term value will depend heavily on electricity-market design, financing conditions and the future role of flexibility services.

Environmental and social considerations remain equally important. New reservoirs can alter river ecosystems, inundate land and require the relocation of communities. Albania’s proposed Skavica hydropower project illustrates these challenges. Public cost estimates have increased from earlier figures of €308–510 million to more than €1 billion in some assessments, while financing remains uncertain and opposition has focused on potential displacement and the loss of part of the Black Drin’s remaining free-flowing river section. The Western Balkans Investment Framework describes a 132 MW project capable of producing around 450 GWh annually, although the project’s design and status remain contested.

The strongest hydropower strategy for Southeast Europe is therefore selective rather than indiscriminate. Existing high-value assets should be refurbished where the benefits are clear, pumped storage should be developed where its contribution to system flexibility justifies the cost, and new dam proposals should not automatically be considered sustainable simply because they produce renewable electricity.

As solar and wind take a larger share of the region’s generation mix, the value of hydropower may increasingly lie in flexibility and storage rather than annual energy production alone. Capturing that value, however, will require transparent assessments of financial returns, system benefits, environmental impacts and social costs.

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May and June were reportedly the plant’s weakest production months since its opening in 1970. By early August, inflows were expected to approach 1,500 cubic metres per second, close to the biological minimum. At the same time, low water levels restricted barge loading to just 30–40% of capacity and complicated cooling operations at Serbia’s Kostolac coal complex. A single climatic event was therefore simultaneously reducing renewable generation, disrupting fuel transport and putting additional pressure on thermal power plants.

The episode highlights a growing weakness in how Southeast Europe has traditionally valued hydropower. Large plants have long been viewed as dependable domestic resources capable of reducing fuel imports and providing flexible generation. They remain important for both functions, but historical production is becoming a less reliable indicator of future output. Hotter summers, lower river flows and increasingly variable precipitation can reduce hydropower generation precisely when electricity demand for cooling is at its highest and solar production declines in the evening.

This does not make hydropower less valuable. Instead, it makes flexibility, reservoir management and climate adaptation more important. Reservoir-based plants can respond quickly to changes in demand, while run-of-river facilities remain directly exposed to available water volumes. Operators will increasingly need better seasonal forecasting, coordinated management across borders and operating rules that treat ecological flows as binding system constraints rather than optional environmental considerations.

The Danube is a shared energy artery for the region. Lower output at Đerdap increases Serbia’s need for electricity imports, with potential consequences for prices and power flows in Romania, Bulgaria, Hungary and the wider Western Balkans. At the same time, low river levels threatened cooling-water supplies at Romania’s Cernavodă nuclear plant and reduced output at Hungary’s Paks facility. The 2026 episode demonstrates that even a diversified generation mix can face correlated climate risks when multiple technologies depend on the same river basin.

Investment priorities should therefore adapt to the new reality. Turbine refurbishment can increase the amount of electricity generated from each unit of water, while digital controls can improve dispatch and operational efficiency. Batteries can help preserve hydro reservoirs during prolonged shortages by managing intra-day fluctuations in supply and demand. Additional cross-border interconnection can also spread local shocks across a wider electricity market. None of these measures can create water, but each can reduce the economic impact of water scarcity.

New hydropower projects should also be stress-tested against future hydrological conditions rather than relying primarily on twentieth-century averages. Expected generation, debt-service capacity and environmental impacts can all change if drought years become more frequent. A project that appears inexpensive on a cost-per-megawatt basis may ultimately prove expensive per delivered megawatt-hour if water availability has been overstated.

The key lesson from Southeast Europe’s 2026 experience is therefore not that hydropower has failed. It is that water can no longer be treated as a constant. The region’s hydropower fleet remains one of its most valuable sources of renewable flexibility, but its future contribution will increasingly depend on climate-resilient operation, modernised equipment and stronger integration with battery storage and cross-border electricity markets.

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Day-ahead electricity prices declined across most of Southeast Europe for delivery on 14 August 2026, reflecting a significant increase in forecast solar generation while regional consumption remained broadly unchanged. Despite lower baseload prices, hourly profiles continued to show evening tightness and exceptionally wide intraday spreads.

Hungary’s HUPX baseload price fell by €19.90 to €143.76/MWh. Romania declined by €20.60 to €142.91/MWh, Slovenia by €21.50 to €144.19/MWh and Croatia by €20.90 to €143.95/MWh.

These four markets remained closely coupled, with only €1.28/MWh separating the highest and lowest prices. Austria, at €143.25/MWh, also remained close to the regional cluster.

Serbia recorded the largest absolute decline, falling €22.50 to €134.72/MWh. Bulgaria settled at €125.33/MWh after a €13 decline, while Albania dropped €11.30 to €135.33/MWh.

Greece remained the region’s cheapest market at €96.98/MWh, despite increasing by €1.20 on the day. The Greek price was €46.78/MWh below HUPX. At the opposite end, Montenegro rose €9.50 to €151.51/MWh, while Italy remained the most expensive major market at €174.55/MWh.

Solar reshapes the market

Regional electricity consumption was forecast at 31,835 MW, just 54 MW above the previous day. Supply conditions changed more significantly, with forecast solar generation increasing by 1,916 MW, while wind output declined by 531 MW. Combined solar and wind availability therefore increased by approximately 1,385 MW.

The increase in solar generation pushed midday prices sharply lower. In Hungary, the hourly minimum reached €29.60/MWh at H12, compared with a daily maximum of €261.70/MWh at H21. This created an intraday spread of €232.10/MWh.

HUPX’s reported peak average was only €111.40/MWh, substantially below the €176.10/MWh off-peak average. The unusual relationship reflects weak solar-heavy daytime prices and significantly stronger evening pricing as the system moves into the evening ramp.

The pattern was even more pronounced in Greece. HEnEx reached zero at H12, with the peak-block average falling to €46.50/MWh. Prices subsequently recovered to a maximum of €161.40/MWh at H20.

Italy’s price profile remained considerably firmer. The national price stayed above €130/MWh even at the daily minimum and reached €254.70/MWh at H21. The persistent Italian premium continued to create an economic incentive for Southeast European exports towards Italy.

Regional exports increase

The SEE and Hungarian system was a net exporter of approximately 471 MW on average, an increase of 281 MW from the previous day. Flows towards Italy reached around 1,261 MW, consistent with Italy trading €30.79/MWh above Hungary.

At the same time, imports from Austria and Slovakia into Hungary and Slovenia averaged 894 MW, down by 151 MW.

Greek consumption declined by 458 MW as temperatures fell by 1.6°C, reinforcing the country’s surplus and low-price position. Greece has also become a more prominent regional exporter, supported by growing renewable generation and lower domestic demand during favorable weather conditions.

Prompt forwards weaken

The bearish day-ahead movement extended into Hungarian prompt power contracts. Week 34 fell by €4 to €156.50/MWh, Week 35 declined by €3.50 to €157/MWh and September lost €1.50 to settle at €161/MWh.

Hungarian forward prices nevertheless maintained a substantial premium over Germany. The HU-DE spread stood at €25.50/MWh for Week 34, €27.50/MWh for Week 35 and €26.50/MWh for September, although all three prompt spreads narrowed during the session.

Gas and carbon markets provided a mixed signal. CEGH gas declined by €1.20 to €60.73/MWh, while EU allowances increased by €0.80 to €82.74 per tonne. September gas rose by €1.50 to €61.50/MWh. The combination of lower prompt power prices and firmer near-term gas prices could put pressure on thermal generation margins outside the most expensive evening hours.

Nuclear availability remains the principal upside risk

The immediate market signal remains bearish during solar-heavy hours, but significant supply risks continue to limit the downside.

Both units at Romania’s Cernavodă nuclear power plant were unavailable, removing approximately 1,360 MW of capacity that normally supplies close to one-fifth of Romanian electricity consumption. Romania has requested regional support and is seeking to retain almost 900 MW of coal-fired capacity beyond its planned retirement date.

Low Danube water levels also pose a risk to Hungary’s Paks nuclear plant. Emergency construction work has begun to protect cooling-water availability, highlighting the vulnerability of nuclear generation to persistent drought conditions.

For traders, the strongest signal is therefore not simply lower baseload prices, but greater hourly volatility. Solar generation is depressing midday prices, while evening scarcity continues to produce sharp spikes. Italian export demand, nuclear availability and Danube conditions will remain the main factors capable of tightening the market and reversing the current bearish prompt trend.

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Hungary reached almost €265/MWh, Romania surged to €310/MWh and Bulgaria approached €199/MWh. The divergence suggests that available cross-border transmission capacity was insufficient to fully equalise evening scarcity prices, highlighting the limitations of regional coupling during periods of tight supply.

Romania’s emergency measures also weaken the assumption that purchased transmission capacity automatically guarantees physical delivery. During an adequacy event, transmission system operators can restrict commercial exchanges in order to protect system security, creating additional risks for cross-border market participants.

The Montenegro–Italy corridor has a different value profile. Recent daily auction prices in the export direction averaged approximately €8.59/MWh, supported by Italy’s persistent price premium over Adriatic markets. However, Montenegro’s own dry-summer electricity deficit can limit export availability even when Italian prices remain significantly higher.

The submarine interconnector can therefore serve two opposing functions: supporting Montenegro with imports during periods of domestic scarcity while providing access to the Italian market when EPCG has surplus hydropower or wind generation. Its economic value consequently lies in optionality rather than a permanently fixed direction of flow.

Intraday coupling reliability has also become an increasingly important factor in power-price formation. Repeated cancellations and partial decoupling of European intraday auctions during early August reduced traders’ ability to correct cross-border positions. This becomes particularly significant when fifteen-minute prices can move from zero to €300/MWh within a few hours.

A portfolio relying on forecast solar generation but lacking a dependable intraday trading route can therefore face balancing costs that significantly exceed the revenue captured through the original day-ahead transaction. Storage can reduce physical imbalance exposure, but it cannot fully compensate for an unavailable or illiquid market interface.

The broader implication is that regional market integration does not eliminate price risk. As renewable penetration increases and intraday price spreads widen, transmission availability, market coupling reliability and flexibility resources will become increasingly important determinants of the actual value of cross-border electricity trading.

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However, the absence of negative prices does not eliminate the underlying market challenge. Strong solar generation continues to depress daytime electricity values, while gas-fired power plants increasingly determine the marginal price during the morning and evening periods.

Greece can export electricity northwards through Bulgaria and North Macedonia when solar generation is strong and domestic prices are relatively low. As photovoltaic output declines later in the day and Greek gas generation becomes more expensive, those flows can reverse. The value and direction of cross-border transmission can therefore change significantly within a single day.

Curtailment is also becoming an increasingly important variable for renewable project economics. A solar plant can maintain its expected technical annual yield while its commercially saleable output declines because the power system cannot absorb all available generation during saturated hours.

For project financing, this makes it essential to distinguish between weather-related production losses, grid-driven curtailment and price-driven economic shutdown. These factors have different impacts on revenues and should not be treated as equivalent risks.

Conventional solar PPAs based on fixed annual volumes can also create additional imbalance and delivery exposure when curtailment, low prices or grid instructions prevent the contracted output from being delivered. As a result, new contracts are increasingly incorporating hourly shaping, storage integration, floor-price mechanisms and explicit allocation of curtailment risk.

Greece’s market is therefore moving beyond a simple solar expansion model. As photovoltaic penetration increases, the commercial value of generation will increasingly depend not only on how much electricity a project produces, but when it produces and how flexibly that output can be delivered.

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Electricity production reached approximately 26.9 TWh between 1 January and 9 August, representing a 7.8% increase year on year. Consumption also rose, increasing by 6.8% to around 25.0 TWh, leaving Bulgaria with a cumulative electricity surplus of approximately 1.86 TWh.

Hydropower generation increased significantly to around 3.4 TWh, compared with 1.81 TWh during the same period in 2025. Transmission-connected renewable generation also increased by more than 16%, reaching approximately 2.94 TWh.

Despite the country’s growing generation surplus, the price curve shows that hourly scarcity remains a significant market feature. IBEX prices fell to just €11/MWh during the strongest solar-production period before climbing to almost €199/MWh during the evening ramp.

This widening intraday spread is creating an increasingly attractive market for battery energy storage. Sunotec’s two operating storage systems at Brusartsi and Byala Slatina have a combined capacity of 200 MW/505 MWh, with market access and optimisation provided by Slovenian trader GEN-I.

The systems can discharge at high power for approximately two and a half hours, allowing them to target the most expensive part of the evening ramp. GEN-I’s planned expansion across another nine Bulgarian projects, totalling 195 MW/782 MWh, would increase average storage duration towards four hours and provide greater coverage during longer periods of scarcity.

Bulgaria’s rapid solar expansion is therefore creating two increasingly distinct electricity markets. Solar developers are competing to sell power into increasingly depressed midday prices, while batteries and flexible thermal generators are competing to capture value from the evening recovery.

For new photovoltaic projects, the implication is increasingly clear: without storage, flexible offtake arrangements or a carefully structured PPA, captured solar prices may fall materially below the IBEX baseload average. The country’s annual generation surplus does not remove this risk; instead, it is reshaping when electricity has value.

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The intervention is expected to extend the reactor’s operation by approximately nine to ten days, rather than the previously anticipated five to six days. While this provides additional time, it does not change the underlying hydrological situation. Danube flows have fallen to roughly one-third of their normal August level and could remain depressed beyond mid-August.

A shutdown of the second reactor would remove another 680 MW of dependable baseload capacity, leaving the entire 1.36 GW Cernavodă nuclear fleet unavailable. Romania would then become significantly more dependent on gas-fired generation, coal, electricity imports and demand-side measures, particularly during the evening peak.

The government has already authorised staged reductions in industrial consumption and could impose export restrictions if the country’s adequacy position deteriorates. This introduces an additional physical-delivery risk for cross-border electricity trading. Market participants holding commercial transmission capacity from Romania cannot assume that exports will remain available if emergency system-security measures are activated.

The risk also extends to neighbouring markets. Moldova remains heavily dependent on Romanian electricity supplies, while Hungary is structurally short and regularly imports more than 2 GW. Serbia can provide exports during selected hours, but its own hydrological position is weak and coal availability remains operationally sensitive.

Bulgaria currently represents the strongest alternative regional supplier, supported by Kozloduy nuclear generation, lignite-fired capacity, hydropower and a year-to-date electricity surplus. However, its ability to compensate for Romania’s lost nuclear generation is limited. Bulgaria cannot simultaneously replace Cernavodă output, meet its own evening demand and supply every neighbouring market at unconstrained volumes.

The situation highlights the growing importance of regional flexibility and cross-border security margins as low hydropower availability, nuclear constraints and extreme weather conditions increasingly overlap across Southeast Europe.

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The eclipse will occur relatively late in the day, when solar generation is already declining. As a result, the overall loss of energy will be smaller than it would have been around midday. However, the event could sharpen the rate of solar output decline at a critical period when power systems are already increasing thermal generation to cover the evening ramp.

For Central Europe and the Balkans, the impact is primarily indirect but commercially significant. Lower domestic solar output in Italy and France could reduce the amount of electricity available for exports towards Slovenia, Croatia and the wider Adriatic region. Germany is also providing less surplus generation, with wind output falling to around 4.7 GW, approximately 60% below seasonal levels.

France’s day-ahead electricity price rose to €142.50/MWh, while Germany reached €138.50/MWh, as high temperatures constrained nuclear availability and weaker wind reduced renewable generation. French nuclear limitations could affect as much as 7.3 GW, equivalent to around 12% of the country’s reactor fleet.

In Britain, the system operator issued a margin notice for the eclipse-period evening, initially identifying a supply shortfall of more than 1.7 GW before revising the estimate to approximately 1.2 GW. British evening electricity prices subsequently moved above £211/MWh. Although the UK is outside the Southeast European trading system, the warning highlights the broader European competition for flexible generation during the same hours.

European system operators have been preparing for the eclipse for months, making the event less dangerous than an unexpected outage of comparable size. The main trading risk instead comes from the interaction between the eclipse and forecast uncertainty. Higher cooling demand, an additional nuclear outage, weaker-than-expected wind generation or delayed battery availability could turn an anticipated solar decline into a significantly more expensive balancing event.

For Southeast Europe, the eclipse therefore represents another potential source of evening price volatility, particularly as the region increasingly depends on cross-border flows and flexible generation to manage the gap between midday renewable surpluses and evening demand.

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OPCOM prices fell below €20/MWh before noon, reached zero across multiple fifteen-minute intervals and remained close to zero for several hours. After 17:00, prices began rising rapidly, exceeding €150/MWh during the evening and reaching €310/MWh shortly before 21:00.

Romania can therefore face renewable oversupply and power adequacy challenges on the same delivery day. The country has rapidly expanded solar capacity through both utility-scale projects and a growing prosumer fleet. However, this generation is highly concentrated in daylight hours and has limited flexibility to respond to market conditions.

At the same time, one of Cernavodă’s two 680 MW nuclear reactors is unavailable, while the remaining unit continues to face cooling-water risks. Hydropower output has also been weakened by record-low Danube flows and poor reservoir conditions. As solar generation declines in the evening, Romania may therefore need to rely on gas, coal, imports, storage or demand-side flexibility to cover the resulting shortfall.

Domestic demand was recently expected to reach around 7,300 MW, compared with available internal generation of approximately 4,000–4,300 MW during the tightest periods. While this does not represent a permanent hourly deficit, it illustrates how quickly Romania’s market can shift from zero prices to €300/MWh within a single day.

The situation creates an unusually clear opportunity for battery energy storage. A two-hour battery charging during the zero-price period and discharging around the evening peak could theoretically capture a spread approaching €300/MWh. Actual revenues would be lower after accounting for round-trip efficiency losses, degradation, grid charges, imbalance exposure and market-access costs, but the underlying arbitrage opportunity remains significant.

However, such spreads are unlikely to remain unchanged as Romania adds more storage capacity. Authorities are preparing commercial approvals for 324 MW of new capacity, including 176 MW of storage and 148 MW of photovoltaic and wind projects. A further 990 MW is reportedly moving through documentation and validation.

In the near term, additional storage will provide much-needed flexibility to the Romanian power system. Over the longer term, however, batteries will increasingly compete for the same low-price charging periods and evening discharge opportunities. Projects relying exclusively on day-ahead arbitrage may therefore face revenue compression, making balancing services, ancillary markets and congestion-related revenues increasingly important for long-term investment returns.

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Hungary’s HUPX market cleared at an average of approximately €123.20/MWh. The lowest fifteen-minute price fell to €36.50/MWh before prices climbed to €264.90/MWh, resulting in a daily spread of more than €228/MWh.

Bulgaria recorded a lower average on IBEX, at around €104/MWh, with prices ranging from €11/MWh to approximately €198.90/MWh. Greece averaged roughly €116.50/MWh, while HEnEx prices fluctuated between €25/MWh and €174.20/MWh.

Romania recorded the region’s most extreme price curve. OPCOM saw a prolonged period of zero or near-zero prices from around 12:30 until after 15:30, despite limited nuclear and hydropower availability. Prices subsequently surged to €310/MWh at 20:45–21:00, pushing the daily spread above €300/MWh.

The results marked a significant change from delivery on 11 August, when Hungary, Romania, Serbia, Croatia, Slovenia and Albania largely converged around €150/MWh. Serbia cleared at €149.94/MWh, Hungary at €151.44/MWh, Romania at €149.54/MWh and Montenegro at €155.59/MWh.

The lower averages recorded on 12 August should not be interpreted as evidence of a fundamentally better-supplied regional market. Instead, they reflect deeper photovoltaic price cannibalisation during midday hours. Firm electricity remains expensive, while the daily baseload increasingly combines several hours of almost valueless solar generation with a concentrated period of thermal and flexibility scarcity during the evening peak.

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The Hungarian day-ahead baseload price increased by €18.80/MWh to €163.69/MWh, while Romania followed at €163.54/MWh, leaving a narrow spread of just €0.15/MWh. Slovenia and Croatia also traded close to those levels, reaching €165.65/MWh and €164.83/MWh, respectively.

Serbia recorded the largest daily increase in the region, with the SEEPEX price rising by €43.60/MWh to €157.20/MWh. Bulgaria advanced by €12.70/MWh to €138.29/MWh, while Germany and Austria reached €147.07/MWh and €161.55/MWh, respectively.

Italy remained the most expensive market in the report, with its national price rising to €183.80/MWh, a premium of €20.11/MWh over Hungary.

Southern markets moved in the opposite direction. Greece recorded an €8.70/MWh decline to €95.81/MWh, widening its discount to Hungary to €67.89/MWh. North Macedonia fell to €128.53/MWh, Albania to €146.65/MWh, while Montenegro was broadly stable at €141.97/MWh.

Hungary highlights growing evening price risk

The Hungarian market showed a particularly wide intraday price range. The HUPX price fell to a daily low of €83.50/MWh at hour 14, when solar generation was strongest, before climbing to €338.90/MWh at hour 21.

The resulting €255.40/MWh daily spread highlights the increasing importance of hourly price risk in a market with rapidly growing renewable generation. Hungary’s peak-period average was €140.80/MWh, while the off-peak average reached €186.60/MWh, reflecting the impact of expensive evening hours.

The €338.90/MWh peak was recorded simultaneously in Germany, Romania and Slovenia, pointing to strong market coupling and a broad tightening of supply conditions after solar output declined.

The contrast with midday prices was significant. Strong renewable generation continued to put downward pressure on prices during solar hours, but the subsequent evening ramp rapidly reversed that effect.

Higher demand offsets stronger renewable output

Forecast electricity consumption across Hungary and Southeast Europe increased by 563 MW to an average of 33,186 MW, despite cooler regional temperatures.

Romania and Bulgaria accounted for most of the increase, with their combined demand rising by 592 MW. Hungarian consumption declined by 40 MW to 4,461 MW, while Greek demand fell by 53 MW to 7,216 MW.

Renewable generation forecasts also improved. Regional solar output was expected to increase by 1,302 MW to 8,558 MW, while wind generation rose by 77 MW to 4,888 MW.

The simultaneous increase in renewable availability and electricity prices suggests that the market was not experiencing a straightforward shortage of daily energy. Instead, the timing of generation, the steep evening ramp and cross-border transmission conditions appear to have been the main drivers of price formation.

The region’s reported net-import position stood at -229 MW, improving by 128 MW from the previous day. Imports from Austria and Slovakia increased by 62 MW to 1,018 MW, providing additional supply to Central and Eastern European markets but failing to prevent the evening price spike.

Hungarian forward prices remain elevated

Hungarian power forwards showed mixed movements at the front of the curve but strengthened across monthly and annual contracts.

The Week 34 contract declined by €0.50/MWh to €160.50/MWh, while Week 35 gained €0.50/MWh to the same level. September 2026 increased by €2.50/MWh to €162.50/MWh, while the calendar contract rose by €2/MWh to €127/MWh.

Hungarian electricity continued to trade at a significant premium to Germany. The HU-DE spread stood at €31/MWh for Week 34, €33.50/MWh for Week 35 and €27.50/MWh for September. The calendar spread was €21/MWh.

The persistence of these spreads suggests that Hungary’s premium is not limited to the day-ahead market. Forward prices continue to reflect expectations of tighter regional balances and greater reliance on imports.

Fuel markets provided additional upward pressure. Austrian CEGH gas rose by €1.20/MWh to €61.90/MWh, increasing the variable cost of gas-fired generation. The EUA carbon price declined by €0.50 to €81.99/t, providing only limited relief, while September coal increased slightly to $122.50/t.

Outlook

The near-term outlook for Southeast European power markets remains bullish but highly dependent on hourly fundamentals. Strong solar generation is likely to continue suppressing prices around midday, while evening prices remain vulnerable to sharp increases as photovoltaic output falls and thermal generation or imports are required to cover demand.

The widening gap between midday and evening prices is making hourly positioning increasingly important. Baseload prices can conceal substantial exposure to the evening ramp, particularly in Hungary, Romania, Slovenia and Croatia.

Regional spreads are also providing important trading signals. Hungary and Romania remain closely coupled, while Greece continues to trade at a substantial discount and Italy maintains a significant premium.

Changes in cross-border transmission availability, thermal generation, renewable forecasts and evening demand could therefore produce substantial movements in both outright electricity prices and regional spreads.

The post Southeast Europe power prices surge as evening scarcity offsets stronger renewables appeared first on Serbia SEE Energy Mining News.

GEN Energija had sold most of Krško’s expected 2026 electricity production in advance. With the nuclear plant generating below planned levels, the company must now purchase replacement electricity to meet those contractual obligations. Wholesale prices have averaged around EUR 180/MWh, while evening prices have climbed significantly higher as regional supply conditions tighten.

The production shortfall is also increasing reliance on the Brestanica gas-fired power plant, which is normally used primarily as a system reserve. Higher electricity prices have nevertheless made its operation commercially viable despite elevated gas and carbon costs, with evening market prices recently reaching EUR 300–400/MWh.

As a result, Brestanica has already exceeded its expected full-year generation target well before the end of 2026. The plant produced 25.75 GWh by 5 August, around 3% more than its planned generation for the entire year.

The situation highlights the financial exposure created when a large baseload plant operates below expectations after its output has already been sold forward. GEN Energija is effectively facing the difference between the price at which Krško’s electricity was contracted and the considerably higher cost of securing replacement power on the wholesale market.

At the same time, increased operation of Brestanica is providing additional domestic generation during periods of tight regional supply, but at a significantly higher marginal cost than nuclear production.

The combination of lower nuclear output, costly replacement purchases and increased gas-fired generation is therefore putting additional pressure on GEN Energija’s finances at a time when Southeast European electricity prices remain elevated, particularly during evening peak periods.

The post Slovenia: Krško output shortfall costs GEN Energija at least EUR 300,000 per day appeared first on Serbia SEE Energy Mining News.