In mid-June, regional electricity demand rose as summer load built, while average day-ahead prices softened across most South East European markets. In Week 24, demand reached about 15.85 TWh, up 4.6% week on week. Variable renewable generation increased to 3.64 TWh, up 16.6%. Solar output was 2.23 TWh and wind reached about 1.40 TWh.
The same period showed a different price response than under prior market conditions. Stronger wind and solar output capped the stack as summer demand increased. That shift altered day-ahead price formation across the region.
Week 24 day-ahead price moves across SEE markets
Serbia recorded one of the steepest weekly declines, with average day-ahead prices down 21.5% to around €78.22/MWh. Bulgaria fell 7.2% to €93.58/MWh, while Croatia declined 7.3% to €92.02/MWh. Romania eased 4.7% to €97.38/MWh, and Hungary slipped 4.3% to €98.71/MWh.
Italy remained structurally higher despite a weekly fall of 3.8%, to about €123.17/MWh. Greece was the exception, rising 2.6% to €91.53/MWh. Türkiye stood apart with an average day-ahead price of only €22.85/MWh, supported by strong domestic renewable and thermal supply.
Renewables, hydro and thermal output in the Week 24 mix
The generation pattern in Week 24 reflected the changing drivers behind prices in South East Europe. Wind and solar output rose as hydropower declined by 7.5%, to around 3.70 TWh. Hydro remains a flexible low-carbon resource for storage, balancing capacity and reserve support.
The week also included higher thermal generation, up 8.7% to about 4.52 TWh. Coal and lignite output increased by 24.4%, reaching around 2.14 TWh, while gas-fired generation fell by 2.4% to roughly 2.38 TWh. The combination indicated that renewables reduced average power prices without removing the need for dispatchable back-up.
Bulgaria and Romania expand battery capacity linked to renewables
Bulgaria’s Week 24 price decline to €93.58/MWh coincided with stronger renewable generation and higher net exports. The country is also increasing battery storage capacity, including a commissioned system of 602 MWh. The project is associated with Solarpro and CATL.
Bulgaria also has a proposed expansion at the Tenevo renewable hub of 246 MW / 512.5 MWh. The developments position Bulgaria as a solar-plus-storage market with export optionality rather than only a solar-growth destination.
Romania is expanding storage as well, with Aukera commissioning the first phase of its Gura battery project at 150 MW. The total target is 250 MW / 500 MWh. Romania’s location at the intersection of Hungary, Bulgaria, Serbia, Moldova, Ukraine and the Black Sea corridor increases the regional relevance of storage operations.
Türkiye’s low-price profile and Italy’s higher-price role
Türkiye’s demand increased by 3.8%, reaching 6.74 TWh, while its low day-ahead average remained driven by supply conditions rather than weak load. Variable renewables rose alongside strong domestic generation during Week 24.
The Italian day-ahead price remained above most Balkan and Central European markets even after falling to about €123.17/MWh. Italian consumption rose to around 5.12 TWh, while net imports increased to about 1.08 TWh. This supported continued spread trading when interconnector capacity is available.
The grid constraint affects project economics and flexibility needs
The physical grid is described as a key determinant of market outcomes because announced renewable capacity may outpace available grid flexibility. Transmission bottlenecks, distribution constraints, connection queues, delayed substations, slow permitting and limited balancing-market maturity can affect project economics.
A solar plant that appears profitable on an annual average-price basis can become less attractive when curtailment risk, negative midday prices, grid delays and limited intraday access are considered . The bankable profile increasingly depends on whether projects are grid-integrated, forecastable and dispatchable or paired with flexibility resources .
Hydrology risk across SEE and Montenegro’s small-system exposure
A hydrological cycle influences multiple countries including Albania, Bosnia and Herzegovina, Montenegro, Croatia, Serbia, Romania and parts of Bulgaria depending on local conditions. In wet years hydro can suppress prices, support exports and reduce thermal dispatch; in dry years it can increase import exposure and raise coal dispatch needs.
The financial sensitivity of smaller systems is illustrated by Montenegro’s experience following an outage at TPP Pljevlja involving EPCG electricity purchases . EPCG’s credit obligations rose sharply in 2025 while the system remained exposed to coal-plant availability, imports, hydrology and tariff politics.
Montenegro is also developing a virtual power plant platform for distributed energy resources based on more than 10,000 prosumers. Rooftop solar under the Solari programmes totals around .
Evolving policy risks: Serbia oil security, Bosnia gas law and CBAM-linked pressure
NIS is central to oil security in Serbia because it covers refining backbone functions along with distribution system roles and geopolitical exposure . Temporary sanctions relief and efforts related to Russian ownership are described as factors affecting corporate governance variables for the market context.
Bosnia and Herzegovina is dealing with institutional uncertainty including the Federation’s draft gas law aimed at addressing fragmented gas governance . Better regulation, crisis-supply rules and independent oversight are described as prerequisites for serious gas-market development.
The broader power sector in Bosnia remains exposed to coal dependence, hydro variability, ageing infrastructure, political fragmentation and EU carbon-policy pressure . Under CBAM-linked expectations, coal-heavy systems face gradual competitiveness pressure for electricity-intensive exporters unless clean power procurement arrangements improve through PPAs, certificates, metering and embedded-emissions documentation.
Coprocessing plans in North Macedonia amid coal transition sequencing
A transition case in North Macedonia includes preparatory work for the REK Bitola 1 cogeneration project supported by a grant of about $$2.$4mn$ . The work is described as small in capital terms but important for direction.
The approach reflects repurposing legacy thermal infrastructure rather than assuming old coal assets can be switched off before replacement capacity and heat systems are ready . Across SEE, coal transition planning is framed as involving conversions and flexibility projects alongside district-heating links and gas-readiness questions . Hydrogen optionality, workforce issues and grid constraints are also cited as part of that sequence .
TFF volatility persists while gas output falls in Week 24; oil adds fiscal exposure
TFF prices remained volatile around storage refill dynamics, LNG competition and geopolitical risk during the period described . In Week 24, gas-fired output in SEE fell even though TTF stayed elevated . Gas remains critical for winter adequacy, industrial heat, district heating and peaking capacity in addition to its role in coal replacement politics.
The risk highlighted is not that gas disappears from power pricing but that investors may treat short-term decoupling as structural insulation . Oil exposure includes Middle East risk affecting refinery security along with fuel-tax politics and crude-price volatility feeding into inflation signals such as transport costs and energy-company margins . Fuel-price changes are linked to household budgets logistics costs tourism competitiveness and government revenues within regulated or politically sensitive systems where external shocks can become fiscal questions before market-clearing issues .
EUA policy instruments reshape asset valuation; industrial contracts require hourly evidence logic
The EU policy frame referenced includes CBAM emissions pricing state-aid rules grid codes renewable auctions electricity-market integration and guarantees of origin shaping how SEE assets are valued . Lignite plants may still be needed for security of supply but financing conditions tied to export-linked value are described as deteriorating . Solar revenue quality depends on capture prices curtailment levels and storage pairing requirements under evolving rules . Hydropower strategic value rises when flexibility becomes scarce while battery bankability increases when ancillary services congestion relief capacity value balancing needs and intraday spreads are included .
The next investment focus described involves batteries pumped storage grid upgrades dispatch centres digital forecasting automated trading aggregation platforms and flexible industrial demand capturing value across volatile hours . Industrial offtakers including aluminium steel cement fertiliser chemicals mining and data-centre investors are described as needing credible electricity arrangements beyond headline price levels . CBAM requires attention to carbon content traceability which creates opportunities for renewable PPAs only where documentation supports buyer bank verifier requirements including hourly matching balancing arrangements certificates metering evidence systems . A PPA tied only to intermittent power without balancing logic may not satisfy those requirements according to the description .
Lender underwriting shifts toward curtailment risk grid access spreads; wind differs from solar; storage spans durations
Lender underwriting models are described as changing through assessment of curtailment sensitivity grid-connection risk merchant-price cannibalisation balancing exposure cross-border spreads negative-price scenarios storage optionality and regulatory delay . A solar project with strong land position but weak grid access may be less bankable than a smaller hybrid project with storage paired with a credible connection timetable according to the description . Wind projects with higher capacity factor along with better evening output may offer stronger system value than oversized solar exposed to midday price compression . Pumped storage may appear capital-intensive but strategic value rises where duration and flexibility are constrained .
The description distinguishes wind from solar by noting that solar strongest output coincides with periods expected for future price compression while wind produces across more varied hours often carrying higher capacity factors in suitable locations . For SEE winter adequacy alongside hydro variability remaining important good wind projects may become more valuable than solar projects with similar nominal capacity subject to permitting environmental sensitivity grid connection turbine logistics and bankable resource assessment requirements . Storage is described as not a single market because short-duration batteries can monetise intraday spreads ancillary services and solar shifting while longer-duration options including pumped hydro address multi-hour or seasonal stress needs . Virtual power plants can aggregate distributed rooftop solar small batteries industrial loads and flexible consumption while hydro reservoirs can act as natural system batteries when managed commercially . Some markets face midday solar congestion others winter import dependence hydro drought or interconnector scarcity requiring multiple tools rather than one solution set .
A more detailed trading model emerges amid fragmented regional spreads; policy-infrastructure lag remains a risk factor
The trading opportunity is described as becoming more sophisticated beyond watching baseload prices or fuel spreads alone because traders need shape models weather intelligence hydrology forecasts interconnector auction strategies imbalance-cost analytics real-time renewable forecasts regulatory monitoring credit-risk controls . Value is described as coming from differences between hours zones products Italy’s premium Türkiye’s low-price position Bulgaria’s storage growth Romania’s battery buildout Serbia’s balancing needs Montenegro’s distributed solar aggregation and Bosnia’s hydro-coal exposure creating a more fragmented but tradable map within SEE . The main risk identified is policy or infrastructure lagging market developments such that renewable capacity can be announced faster than grids absorb it or batteries financed faster than ancillary-service markets reward them according to the description . Industrial PPAs can be signed faster than hourly evidence systems verify them while tariff reform delays until utilities accumulate debt are also cited as gaps affecting where value changes hands .
Balkan characteristics persist within a move toward European-style market structures; timing scarcity replaces megawatt scarcity
The region is described as moving toward a more European power-market structure but retaining Balkan characteristics including hydro volatility coal legacy political tariffs weak listed utilities limited liquidity grid bottlenecks fast solar growth strategic interconnectors and growing exposure to EU carbon rules . The combination is described as producing sharp price signals sudden investment windows congestion rents curtailment disputes balancing shortages alongside periodic political intervention within the period referenced . The opportunity is framed around rebuilding systems while they remain under stress because each new battery substation pumped-storage study interconnector upgrade PPA structure VPP platform or forecasting system changes commercial maps across SEE according to the description .
