MARKET COMMENTARY

The start of the year put the energy industry under immediate pressure. Weather-related load shifts caused the markets to react nervously, while at the political level in Davos, the broad outlines of Europe's energy future took shape. Climate neutrality, industrial competitiveness and security of supply form a fragile triangle, with power increasingly becoming its supporting element. Electrification, including emission-neutral renewable energy production, is thus moving from a promise of transformation to a systemic necessity. But the more central power becomes, the more acute the question of its affordability becomes – and of political responsibility for stable framework conditions. Germany is adding a controversial instrument to these debates in the form of the industrial power price.

At the World Economic Forum (19-23 January 26), IEA Director Fatih Birol made a clear diagnosis: Europe's energy future is inconceivable without comprehensive electrification. Grids, transport, buildings and industry must be consistently converted to power if climate targets, security of supply and cost stability are to be achieved simultaneously. He is not entirely wrong: if, like Europe, one accepts the costs of climate change, the energy transition is clearly power-driven. Electrification opens up new markets, especially where digitalisation, flexibility and the right incentive regulation come together.

At the same time, Birol pointed out the structural weakness of the system: inadequate grid infrastructure. Approval barriers, delayed connections and bottlenecks in the integration of new plants are slowing down the transformation process and are ‘the main obstacle to electrification’. The European energy industry suffers less from a lack of generation concepts than from an infrastructural imbalance. The comparison of an efficient vehicle without roads sums up this contradiction.

Vattenfall CEO Anna Borg also clearly sees Europe's energy future in electrification. Lower power prices should be made possible not only through subsidies, but also through rising demand. Higher consumption levels could relativise grid expansion and system costs without necessarily leading to higher prices. At the same time, Vattenfall is focusing on new, smaller nuclear power technologies and expects cost degression through standardisation. However, a reliable, harmonised European regulatory framework remains a key element: a long-term ‘clear policy framework’ is the key aspect for investment security, which would not be guaranteed with different national regulations.

From a market design perspective, the merit order principle remains the most efficient mechanism for integrating renewable energies. However, the structural volatility of power prices results less from the power market itself than from its coupling to the European gas market and CO₂ costs. Since natural gas is predominantly imported, a key price driver lies outside European control. Regulatory interventions targeting power pricing therefore address symptoms rather than causes. Focusing on the gas-based part of pricing would be more consistent from a systemic perspective.

This problem is exacerbated by fragmented national industrial policy measures. Different support instruments within Europe trigger a subsidy competition that distorts power costs and weakens market integration. Against this backdrop, the German discussion about an industrial power price is logical. The European power market is highly developed in technical and institutional terms, but the distributional effects of the transformation are hitting power-intensive industries particularly hard.

This is precisely where the German industrial power price comes in. For up to 50% of the annual consumption of selected sectors, the difference between the market price and a target value of EUR 50/MWh can be reimbursed. The reference value is noteworthy. It is to be based on the futures market, specifically the year-ahead market. The structure aims to provide relief without displacing procurement.

This is understandable and has a significant advantage for the players involved: the premium for the following year is already known at the end of the year. For industry, this means that half of its annual energy requirements must also be procured on a year-ahead basis in order to be sure of achieving the target price. At the same time, this instrument increases the pressure on other Member States to consider comparable solutions and shifts the debate to the question of financing. Revenue skimming from producers, such as the energy crisis contribution, is politically obvious, but harbours investment risks. A more precise, systematically justified demarcation would be desirable in practical terms, but remains complex.

In the end, one sober observation remains: electrification is indeed an opportunity for Europe. But it will only work if power does not become a structural disadvantage. Europe's market design delivers efficiency and integration. However, it does not automatically deliver a sustainable distribution of transformation costs in global competition.

Market developments in January underscore this fragility. After a prolonged period of stability, gas and power markets reacted sensitively to weather changes, geopolitical risks and technical disruptions. Spot markets reflected seasonal shortages: low renewable generation, high demand and limited availability in neighbouring countries – particularly in France due to the shutdown of two nuclear power plants – led to high prices, especially during peak load hours. At EUR 141/MWh in Austria and EUR 109/MWh in Germany, it is highly likely that we have already seen the most expensive prices of the year. In the last week of January, renewable generation was 0.4 TWh below normal. Assuming that lignite-fired power plants are currently setting prices in Germany, this corresponds to additional consumption of ~125,000 tonnes of hard coal and additional CO₂ emissions of ~300,000 tonnes. And this, in turn, is also resulting in high spot power prices due to the current high CO₂ price level.

These effects were also amplified on the futures market by weather revisions and uncertainties in LNG supply chains. Colder temperatures increased gas-fired power generation, while CO₂ prices and marginal fossil fuel costs pushed up power prices. At the same time, the rapid consolidation at the end of the month showed that market mechanisms are fundamentally working. High LNG availability, flexible trading structures and cross-border capacities had a dampening effect on prices as soon as the fundamental assumptions changed. The CO₂ price had a serious impact here, with its speculative side contributing to the dip in power prices as long positions were reduced. Nevertheless, the environment remains sensitive: falling storage levels and weather-related risks are keeping volatility high. January has thus less established a new price level than revealed the vulnerability of the system.

Looking ahead to February, there are signs of a cautious easing. Milder temperature forecasts improved renewable feed-in and the return of French generation capacities point to falling spot prices. On the futures market, the tension between low gas prices and structurally rising CO₂ costs is likely to manifest itself in a sensitive sideways movement. Overall, the picture remains one of volatile equilibrium: short-term relief, but continued high sensitivity to weather, politics and global energy flows in the medium term.

Yours,

Felix Diwok

For the Inercomp team