October had no single price driver – it had a whole cluster of them: low river flows, expensive gas and an unresolved conflict in the Middle East. The US midterm elections on 3 November brought an additional unknown into focus: How would Donald Trump proceed with Iran after the vote? A negotiated settlement could unwind risk premiums; a continued stalemate in the Strait of Hormuz could cement them. The market went into November without an answer.
The price difference between the Austrian and German power spot markets remains a central issue for Austria’s energy sector. Austria has been a separate bidding zone since October 2018, and since then prices can at times diverge considerably. Over the past seven years, the annual average difference ranged from 2.35 EUR/MWh (2024) to 25.95 EUR/MWh (2022). Only in 2022 did the annual figure exceed 10 EUR/MWh. In 2026, the high volatility is evident once again: on 3 October, Austria was more than 16 EUR/MWh cheaper than Germany; by 10 October, it was already 156 EUR/MWh more expensive. Year to date, the Austrian premium stands at 14.94 EUR/MWh; 18.6 EUR/MWh is expected for the full year.
The most important factor is Austrian run-of-river generation. Amplifying factors are the ratio of marginal costs between coal- and gas-fired power plants (fuel switch), wind and photovoltaic feed-in, demand and the available cross-border capacity. While the physical interconnections have not changed in recent years, renewable generation – and run-of-river hydropower in particular – fluctuates considerably. A comparison of 2024 and 2026 illustrates this: record run-of-river output and the lowest bidding-zone spread were followed in 2026 by the driest year since records began in the late 19th century. From the start of the year to 11 October, run-of-river generation averaged 3.8 GW in 2024, but only 2.2 GW in 2026. That is a drop of 42 %, or 1.6 GW.
In principle, Austria can offset the hydropower shortfall with imports. Power from Germany is often cheaper than domestic generation. Imports, however, have their limits: what matters is not only the physically available interconnection capacity, but also the capacity actually made available for market coupling. Once that is exhausted, Austrian gas-fired power plants have to step in. Their marginal costs can be well above the German import price – and the difference then becomes visible in the Austrian spot price.
The price gaps also follow seasonal and daily patterns. They are usually larger in winter than in summer, because run-of-river plants produce less while demand rises at the same time. Over the course of the day, the largest differences occur on average at 4 pm, followed by 3 pm and 5 pm. The smallest gaps are seen between 8 and 10 am and between 8 and 10 pm. These are precisely the hours in which Austrian pumped-storage plants generate power: they increase domestic generation, reduce the need for imports and thus limit the spread.
High price differences weigh on all Austrian consumers, but particularly on manufacturers competing with German companies. Nothing can be done about rainfall in the short term. That makes two things all the more important: additional wind and PV plants that provide low-cost generation, and more available cross-border capacity. A major grid expansion project is the “Germany line” (Deutschlandleitung), under construction since 2023: the new 380 kV connection is to link Bavaria with the St. Peter am Hart substation and replace the existing 220 kV line. Its phased commissioning is planned for April to December 2027. This will raise the capacity from 800 MW to 6,000 MW. For comparison: according to E-Control, Austria’s total physical cross-border capacity currently stands at around 10,000 to 11,000 MW.
The high bidding-zone spreads of 2026 are therefore likely to remain a statistical outlier. A normalisation of hydrology could bring relief in 2027, and from 2028 the Germany line should create additional headroom. The precondition, however, is that downstream bottlenecks – particularly on Germany’s internal north–south transmission corridors – also ease and that the additional physical capacity actually becomes tradable. The line alone will neither eliminate hydrological scarcity nor remove every grid constraint, but it does broaden the scope for cross-border power trading.
The tension was not confined to Austria. In the second week of October, spot prices in Germany and Austria reached their highest level in four years. In monthly average terms, October 2026 was the most expensive European spot month since December 2022: Germany averaged 169 EUR/MWh, higher than in October 2022 (152 EUR/MWh), while Hungary reached 244.5 EUR/MWh and Romania 239.2 EUR/MWh. In France, the spot price rose by 189 % compared with October 2025. High gas prices, weak nuclear availability and low run-of-river generation all coincided.
The rise continued on the forward market. The Austrian baseload front-year contract (Cal-2027) gained 8.0 % between 19 and 26 October and, at 174.27 EUR/MWh on 26 October, traded well above its German counterpart (157.98 EUR/MWh). A lack of geopolitical progress and the approaching winter kept risk premiums high; milder temperatures brought only brief relief.
Gas remained the key cost driver. The TTF front month reached 87 EUR/MWh in the second week of October and CEGH 89 EUR/MWh – in each case the highest level since 2022. Attacks on LNG tankers in the Middle East and Asian buyers stocking up for winter intensified competition for LNG. Low storage levels, rising heating demand and unplanned outages at Norwegian gas fields added to the pressure. Market participants considered prices of around 100 EUR/MWh later in the winter a possible scenario.
On 2 November, power and gas front-year contracts corrected by around 7 %. Milder weather forecasts, Trump’s announcement that he would give negotiations more time, and a possible agreement on Russian gas supplies via Ukraine took pressure off the market. As of the turn of the month, the midterms, peace negotiations and the weather are the key price drivers. Higher heating demand and high gas prices are likely to outweigh the hoped-for return of nuclear power plants. Despite possible pullbacks, the overall conditions therefore point to persistently high prices and a volatile market.
Matthias Kisslinger
For the Inercomp team