Southeast Europe’s power market entered the summer period with a set of signals that look less like a single shock and more like a structural disturbance pattern. The weekly data do not point to one isolated outage, fuel event or cross-border interruption. They point instead to a market in which price formation is becoming more fragmented, more hourly, more weather-dependent and less directly tied to the headline direction of gas.
The clearest anomaly was the break between gas and electricity. TTF weakened sharply during the week, falling to around €41.76/MWh, a decline of almost 15% week-on-week, yet several electricity markets still moved higher. Italy, Hungary, Croatia, Romania and Serbia all recorded higher day-ahead power prices even as the fuel input normally associated with marginal thermal generation moved lower. In a conventional gas-led pricing model, softer TTF should have reduced pressure on electricity prices. This time, the pass-through was partial and uneven. The market was being priced not by gas alone, but by physical scarcity in particular hours, weaker hydro, softer wind, stronger cooling demand and the cost of flexible generation during evening ramps.
Italy remained the strongest expression of that pressure. The Italian weekly average stood at about €127.69/MWh, far above the main Balkan and Central European-linked SEE markets. This was not a normal premium created only by fuel costs. It reflected a structurally tighter domestic balance, higher demand, weaker renewable and hydro availability, greater reliance on gas-fired output and increased import needs. Italy’s position matters because it is not only a national price signal. It is a regional anchor. When Italy stays expensive, it pulls value toward the Adriatic, Central Europe and the western edge of the Balkans, affecting spreads even in markets where domestic fundamentals are less tight.
Hungary showed another disturbance pattern. HUPX rose to around €109.16/MWh, even though Hungary reduced its net import position. A market that imports less but prices higher is not behaving according to a simple domestic balance model. It is showing the effect of regional marginal pricing, Central European coupling pressure and scarcity in critical hours. Hungary remains the bridge between SEE and Central Europe, and its price movement often reveals tension that is not immediately visible in national generation data. The Hungarian signal in Week 25 was therefore not just that prices were higher. It was that regional price transmission mattered more than the direction of physical import volume.
Serbia offered one of the most important regional signals. SEEPEX rose to around €85.73/MWh, up close to 10% week-on-week, while Serbia moved from net import to modest net export position. Hydro recovered strongly, thermal output eased and the country’s domestic balance improved. Yet the price still increased. That is a classic coupling disturbance pattern. Serbia was not short in the same way as Italy or Croatia, but it was still exposed to the scarcity price transmitted by neighbouring markets. The conclusion is that Serbia can improve its domestic physical position and still price higher when Hungary, Croatia, Romania and Italy create a firmer regional curve.
Croatia’s move looked more directly linked to domestic tightening. CROPEX climbed above €100/MWh, averaging around €102.36/MWh, as demand rose by nearly 10%, wind weakened and net imports increased by about 26%. Croatia is becoming a sensitive Adriatic indicator because its market reacts quickly to tourism-season load, weaker renewable output and import pressure. The Croatian system is not large enough to absorb these shifts without visible price movement, especially when Italy is trading at a premium and Central European prices are firm. This creates a recurring summer-risk pattern: relatively modest changes in demand and wind availability can move Croatia into a higher price band.
Romania showed a different form of stress. OPCOM rose to around €104.84/MWh, despite lower domestic demand. That would normally look counterintuitive, but the explanation lies in hydro and regional coupling. Romanian hydro output weakened, reducing domestic flexibility and forcing the market to price closer to the tighter regional curve. Romania’s move confirms that demand alone is no longer enough to explain SEE prices. Hydrology is becoming a market-moving variable, not only a generation statistic.
The opposite movement in Greece and Bulgaria sharpened the picture. Greece and Bulgaria corrected lower while several neighbouring markets moved higher. Greece averaged around €85.50/MWh, while Bulgaria traded around €87.58/MWh. Stronger solar output and export availability allowed both markets to resist the upward pressure seen in Italy, Hungary, Croatia and Romania. Bulgaria’s case was especially notable because demand rose sharply, yet prices still fell. That suggests solar and domestic generation adequacy were strong enough to offset load pressure, at least during daylight hours.
This split between Greece and Bulgaria on one side and Italy, Hungary, Croatia and Romania on the other shows that SEE is moving toward a more intraday-fragmented market structure. Solar is increasingly capable of suppressing daytime prices in markets with strong irradiance and export capacity. But solar does not remove evening scarcity. It can even sharpen it by increasing the ramp needed after sunset. The result is a market where average weekly prices hide growing hourly volatility. Daytime may look comfortable, while evening prices still reflect scarcity, hydro weakness and gas-fired flexibility.
Türkiye remained the most extreme outlier. Its weekly average of around €16.66/MWh was far below Italy, Hungary, Croatia, Romania, Serbia, Greece and Bulgaria. Such a discount is not just a price difference; it is a structural signal. In a fully converged regional market, a spread of that scale would be arbitraged down through exports. The fact that it remains so large implies binding interconnection limits, different market architecture and incomplete integration with the EU-linked SEE price zone. Türkiye’s low price is visible, but much of its value is trapped behind commercial and physical constraints.
The generation mix confirms that the disturbance is structural rather than isolated. SEE demand rose to around 16.34 TWh, while variable renewables increased to about 3.78 TWh. Solar was stronger, but wind weakened. Hydro fell to roughly 3.57 TWh, removing part of the flexibility that normally cushions the region. At the same time, thermal generation increased to around 5.31 TWh, with gas-fired output rising sharply. The market needed gas not because gas was expensive, but because flexible generation was required. That is an important distinction. Fuel cost was lower, but flexibility demand was higher.
This is the new SEE pricing pattern. The marginal value is no longer set only by the cost of fuel. It is set by the availability of dispatchable power in the right hours, the strength of hydro, the shape of solar output, the reliability of wind, the ability to move electricity across borders and the willingness of buyers to pay for firmness. In that environment, gas can fall and power can still rise. A country can export and still see higher prices. Demand can fall and prices can still increase. These are not contradictions. They are symptoms of a more complex regional market.
Cross-border flows add another layer. Regional net imports fell, but Italy and Croatia imported more. That means SEE was not uniformly short. Some areas were export-capable while others were tightening. This is a zonal disturbance pattern rather than a general supply crisis. Greece, Bulgaria and Serbia had more favourable export or balance positions, while Italy and Croatia remained import-exposed and premium-priced. The result was fragmentation: the regional average looked manageable, but individual price zones showed clear stress.
For traders, the actionable signals are now more specific. Italy’s import volume is a leading indicator of regional premium pricing. The Hungary–Serbia spread shows whether Central European tightness is transmitting into the Balkans. Croatia’s demand and import ratio reveals Adriatic summer stress. Romanian hydro output is a key driver of OPCOM and wider regional coupling. Bulgaria and Greece solar exports show whether daylight supply can soften the market. Türkiye’s discount measures how much value remains trapped by interconnection and market design. Evening peak prices versus baseload averages are becoming the most important indicator of flexibility scarcity.
For industrial buyers, the lesson is uncomfortable. Lower gas does not guarantee lower power. Procurement strategies based only on baseload averages or fuel-indexed expectations are becoming weaker. Buyers with high evening consumption, low operational flexibility or exposure to regional spot prices need more active hedging of peak-hour risk. The most exposed consumers are those that cannot shift demand into lower-price daytime hours and cannot secure firm bilateral supply.
For renewable developers, the same weekly data carry a different warning. Solar is gaining influence, but capture-price risk is rising. Wind cannot be modelled by analogy with solar because its output pattern, balancing risk and system value are different. Hydro remains a flexibility anchor but is weather-dependent. Storage is no longer a theoretical add-on; it is becoming a practical response to the gap between low-value solar hours and high-value evening scarcity. Projects that can shape, firm and document electricity will be more valuable than projects that only add megawatts.
For lenders, the disturbance signals should feed directly into financial models. Average price assumptions are no longer enough. Debt sizing needs hourly curves, capture-price analysis, curtailment cases, balancing-cost assumptions and grid-delay sensitivities. A project with a strong resource but weak grid position may be less bankable than a lower-yield asset with firm connection rights and better dispatch certainty. The market is beginning to price not only electricity, but also flexibility, documentation and deliverability.
Week 25 therefore looks less like an abnormal event and more like a preview of the summer market structure. SEE is becoming a region where gas, power, renewables and cross-border flows no longer move in a simple line. Italy’s premium, Hungary’s coupling pressure, Serbia’s price rise despite export balance, Croatia’s import sensitivity, Romania’s hydro exposure, Greece and Bulgaria’s solar-led correction, and Türkiye’s deep discount all point to the same conclusion: the region is entering a phase where disturbance is not occasional noise, but part of the market architecture itself.
