MARKET COMMENTARY

The heat is putting pressure on both us ad the power market. What may look at first glance like a simple weather pattern is in fact a daily price shock: particularly high cooling demand is coinciding with low wind feed-in and, in the evening, barely noticeable PV generation. Last week was significantly more expensive in power than the previous week, and the evening price spikes are a clear expression of the transformation we are currently undergoing.

The highest individual quarter-hourly prices of the year in Austria and Germany occurred last week. On 24 June at 20:45, the price reached 645 EUR/MWh in Austria and 747 EUR/MWh in Germany. Germany was therefore significantly more expensive than Austria at the peak. The Austrian premium, which in the winter half-year had still ranged between 12,6 and 31,3 EUR/MWh, moved back into negative territory in June for the first time since August 2025 and currently stands at -1,8 EUR/MWh. The reasons are multi-layered: weak wind utilisation, hardly any negative prices, and a situation in which Austria frequently supplies the marginal unit for its neighbours during the most expensive hours. Pumped storage is currently in use in many hours from around 18:00 onwards.

The scarcity is particularly striking in the case of Hungary. On 29 June at 21:00, the price there stood at 785 EUR/MWh. At the same moment, Austria was at 281 EUR/MWh, or 36% of the Hungarian level, while Germany was at 319 EUR/MWh, or 41%. This shows how steep the supply curve can become in scarcity phases, and how even a small additional change in load can have a significant price impact.

The heat is not only affecting demand, but also supply. Low water levels are reducing run-of-river generation, while high river temperatures are causing cooling-water restrictions for thermal power plants and nuclear power stations. The extremely high evening prices are therefore the result of several simultaneous bottlenecks, all linked to the heat. This makes the contrast with midday all the more striking, when prices are often close to zero. PV feed-in in Austria at the end of the first half-year is around 16% above the previous year’s level in terms of weekly peak values, and almost 30% higher in terms of average daily peaks. However, the annual high was not reached during the current midsummer period, but in spring: in the week starting 27 April, PV feed-in reached almost 5.600 MW. Current June values are around 9 to 10% below that level, reflecting the reduced module output caused by summer heat.

In principle, wind and PV complement each other well on a seasonal basis. Stable high-pressure systems like the current one, however, lead to low wind power output. With further renewables expansion and if the rest of the system remains as it is, the spread between the midday low and the evening peak will not become smaller, but larger. The average daily standard deviation of prices follows a pronounced seasonal pattern: in winter it was around 18 to 26 EUR/MWh, rose sharply in spring and reached around 76 EUR/MWh in June. Last week, it stood at 97 EUR/MWh in Austria, 109 EUR/MWh in Germany and 121 EUR/MWh in Hungary. This is a clear signal for the next stage of the energy transition.

Many small consumption loads still follow comfort patterns rather than price signals. Cooling is switched on when people come home, not when electricity is available in abundance. Air conditioning, hot water preparation, charging infrastructure and heat pumps are all relevant loads in aggregate. This is exactly where aggregators come in: players that bundle distributed flexibility and make it marketable. Broad implementation, however, is still waiting for national implementation. The simpler lever lies in industrial flexibility and could already be realised to a large extent today with small regulatory adjustments. Anyone who reacts to price signals moves the market. Battery storage is also continuing to develop; with current price spreads, use cases outside balancing energy have become commercially viable. Sector coupling is therefore not just a buzzword, but a prerequisite for a cost-efficient system. Mobility and heat are being integrated into the power system. The most difficult part of the energy transition is probably already behind us: the serial production of the necessary technologies and the associated cost degression. What is needed now is regulatory development and greater awareness of load adjustments during price peaks.

While spot prices are shooting up to system- and market-driven highs, forward prices developed moderately to slightly lower overall over the course of the month. The main driver was, of course, the long-awaited agreement between Iran and the United States. The front month closed at 97,71 EUR/MWh, almost unchanged from the previous week. At the beginning of July, however, it rose sharply again after weather forecasts predicted another heatwave for the first half of the month. Lower temperatures than in the previous week are expected for the current week, but weather models point to values around 5 °C above the long-term average again next week. At the same time, wind feed-in in the current week is expected to average 3,5 GW, well below normal levels, thereby supporting the spot market. In the short term, the picture therefore remains bullish, while longer-term products continue to await developments in the Iran conflict.

In gas, the downward movement continued in the final week of June, albeit more moderately than before. The Cal-27 contract at the TTF fell by 3,1% week on week and now stands at 33,85 EUR/MWh. With an apparent easing of geopolitical tensions and the resumption of shipping traffic through the Strait of Hormuz - 27 LNG vessel transits so far in June, already three times as many as in May - the TTF front month temporarily fell below the 40 EUR/MWh mark on Thursday, 25 June. Towards the end of the week, however, an attack on a container ship near the Strait of Hormuz led to a slight renewed price increase.

LNG imports into Europe also continued to decline. Last week, average arrivals amounted to 3,3 TWh per day, a further 18,5% lower than in the previous week. Across June so far, Europe is around 19% below the previous year’s level. This is affecting injection rates into European gas storage facilities: they are currently 47% full, 10% below the previous year’s level. If injection rates remain at their current level, storage levels would reach around 70% at the beginning of November. To meet the EU storage target of 90%, competition with Asia for LNG spot cargoes will therefore intensify, increasing the risk of higher prices in the third quarter.

As the heatwave eases this week, gas demand in power generation is likely to decline somewhat again. For price development on the forward market, geopolitics remains decisive. In the short term, the market picture is therefore bullish, driven by weather and wind, while in the long term it is more balanced at its core. The coming weeks will show how strongly the expected cooling affects spot and gas prices without putting European storage injections at risk.

Best regards,

Matthias Kisslinger
For the Inercomp team