Southeast Europe’s electricity market entered the summer season with developments pointing to a structural shift rather than a short-term disruption. Market data show a growing gap between traditional pricing drivers and observed outcomes. Electricity prices are increasingly influenced by weather conditions, renewable generation patterns, hydrology, cross-border flows and the availability of flexible generation during critical hours.
TTF gas down while regional power prices rise
One of the clearest moves was the divergence between natural gas and electricity prices. During the week, TTF gas fell to about €41.76/MWh, while several regional power markets recorded higher electricity prices. Italy, Hungary, Croatia, Romania and Serbia all saw increases despite the decline in the fuel most often linked to marginal thermal generation. Hydro shortages, weaker wind output, higher cooling demand and evening flexibility value were cited as factors affecting pricing.
Italy posted the strongest price signal in the region. Average day-ahead prices reached approximately €127.69/MWh. The higher level reflected stronger demand alongside lower renewable and hydro availability, greater reliance on gas-fired generation and increased import requirements. Italy’s role as a regional pricing anchor was highlighted for its impact on price formation across the Adriatic and Southeast European area.
In Hungary, electricity prices rose to around €109.16/MWh even as the country reduced its net import position. The change was linked to regional market coupling and cross-border price transmission. Hungary’s location between Central Europe and Southeast Europe was described as a key indicator of broader conditions. The rise in Hungarian prices suggested that scarcity signals transmitted through interconnected markets could outweigh domestic supply-demand balances.
SEEPEX, CROPEX and OPCOM show different drivers
Serbia’s market behaviour contrasted with improvements in its domestic balance. Average prices on SEEPEX increased to roughly €85.73/MWh. Hydro generation strengthened, thermal generation eased and Serbia moved from net importing to a modest net export position. Despite these changes, Serbia remained exposed to regional pricing pressures transmitted from neighbouring markets.
Croatia’s price movement aligned more closely with domestic fundamentals. CROPEX prices rose above €100/MWh, averaging about €102.36/MWh. The increase coincided with a significant rise in electricity demand, weaker wind generation and expanded import needs. Croatia was also described as an indicator for Adriatic conditions where seasonal tourism demand, renewable variability and import dependence can raise prices when Italy holds a premium.
Romania saw upward pressure even with lower demand levels. Average prices on OPCOM climbed to around €104.84/MWh. Weaker hydro generation was identified as the main driver by reducing system flexibility and increasing exposure to regional market conditions. Hydrology was highlighted as a critical determinant of electricity pricing across Southeast Europe.
Greece and Bulgaria fall; solar output shapes daytime values
Greece and Bulgaria moved in the opposite direction from Italy, Hungary, Croatia and Romania. Average prices declined to approximately €85.50/MWh in Greece and €87.58/MWh in Bulgaria. Strong solar generation and favourable export conditions were cited as supporting lower prices despite upward pressure elsewhere in the region.
Bulgaria’s decline stood out because prices fell even as demand increased. This was used to underscore solar’s growing influence during daylight hours. The divergence between Greece and Bulgaria versus other markets was linked to increasing fragmentation within Southeast Europe’s electricity market.
The effect of solar output was described as capable of suppressing daytime prices in markets with favourable irradiation and export capacity. At the same time, solar does not remove evening scarcity pressures, which can increase the importance of flexible generation after sunset. This contributes to sharper price swings between daylight and evening hours.
Türkiye posts a much lower price level
Türkiye remained the region’s most significant outlier on price levels. Average electricity prices were about €16.66/MWh, far below those recorded across EU-linked Southeast European markets. The gap was attributed to structural differences including market design, interconnection capacity and regulatory integration.
The low-price environment was noted to create theoretical export opportunities, although physical and commercial constraints were said to limit convergence with EU-linked markets.
Demand up; renewables expand; thermal flexibility increases
The generation mix supported the view that changes were structural rather than temporary. Electricity demand increased to roughly 16.34 TWh, while renewable generation also expanded during the period discussed. Solar output strengthened but weaker wind generation reduced some of the gains.
Hydro production declined, removing an important source of system flexibility. Meanwhile thermal generation increased significantly, particularly from gas-fired power plants. Additional gas generation was described as required not because gas prices were high but because flexible capacity was needed to maintain balance during critical periods.
The market structure described pricing as increasingly dependent on dispatchable availability rather than fuel costs alone. Factors included hydro conditions, renewable production patterns, cross-border transmission capacity and system responsiveness to rapid supply-demand changes.
Cross-border flows remain uneven across countries
Cross-border trading patterns added further complexity to regional pricing behaviour. While regional net imports declined overall, countries such as Italy and Croatia increased their import requirements during the period referenced by the data set.
This was presented as evidence that conditions were not uniform across all zones in Southeast Europe. Different market areas faced different circumstances, producing a fragmented pricing landscape where some systems stayed relatively balanced while others moved into tighter conditions.
Market indicators shift for traders, consumers and developers
For energy traders, indicators were described as becoming more market-specific rather than driven by one common variable across countries. Italy’s import requirements were highlighted as a measure of regional pricing pressure.
The Hungary–Serbia link was referenced for how Central European dynamics transmit into the Balkans through coupled markets . Croatian demand growth together with import dependence was tied to Adriatic summer stress, while Romanian hydro output continued to influence wider regional price formation.
Solar exports from Greece and Bulgaria were described as signals for daytime softness linked to renewable-driven price suppression . For industrial consumers, lower gas prices were noted not to guarantee lower electricity costs when procurement relies only on fuel expectations or average baseload levels.
The risk profile for consumers with high evening demand or limited operational flexibility was described as increasing alongside spot-market exposure needs . Renewable developers were also said to face rising capture-price risk under pressured daytime values for solar projects.
Wind production patterns were described as distinct from solar output profiles for evaluation purposes . Hydropower was characterised as essential for system flexibility but vulnerable to weather conditions, while energy storage was described as moving toward a critical component for shifting output into higher-value periods and supporting reliability .
Lenders focus on hourly modelling amid volatility
Lenders and investors were described as needing more detailed modelling than evaluations based only on average electricity prices can provide . Financial models now require detailed hourly price forecasts along with capture-price assessments.
The same modelling approach was said to include balancing-cost analysis, curtailment scenarios and grid-connection considerations . Deliverability, flexibility and operational certainty were described as becoming at least as important as generation output itself .
Week 25 reflects ongoing fragmentation across SEE markets
The period referred to as Week 25 was presented as less like an isolated event than an indicator of evolving sector structure in Southeast Europe . Italy’s persistent premium was paired with Hungary’s coupling effects alongside Serbia’s higher pricing despite improved fundamentals.
Croatia’s import sensitivity and Romania’s hydro exposure were listed alongside Greece and Bulgaria’s solar-driven resilience . Türkiye’s deep discount relative to EU-linked markets completed the set of contrasts cited for Week 25 behaviour .
