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The European electricity market has entered an unprecedented period of change. Electricity prices hit a new high: the base-load price of electricity a week ago has risen to more than 200 euros per megawatt hour (MWh)1 1. Platts European Power Daily, S&P Global, spglobal.com. In some European countries-about four times the historical average. This increase is mainly due to the soaring prices of natural gas and carbon, which currently exceed 100 Euros per MWh2 2. TTF (Title Transfer Facility). And 60 euros per metric ton. This development has affected the cost of electricity produced by natural gas power plants, which set prices extensively in the European market.
At the same time, due to the uncertainty in the production of renewable assets and the tight balance between supply and demand in the European power system, price fluctuations are reaching new heights. Navigating the next normality will be the main challenge for utilities, traders and large power consumers, which highlights the importance of developing flexible power asset portfolios and managing risks.
In this article, we explore five trends that will shape the European power industry in the next decade, and provide some insights on how utilities and large consumers might respond.
The European electricity market is undergoing major changes. Five trends underpin these developments.
Electricity demand in Europe is expected to grow steadily, with a compound annual growth rate of approximately 2% by 2035. The main factors behind the surge will be the electrification of transportation and the increase in the production of green hydrogen through electrolysis, which requires renewable energy (Figure 1).
Due to the introduction of electrified infrastructure and national emission regulations (for example, if cities ban internal combustion engines and adopt fiscal measures to prevent the use of non-electric vehicles), transportation power demand will grow at a compound annual growth rate of 14%. By 2035, the electricity demand for green hydrogen production will grow at a compound annual growth rate of about 40%, absorbing 230 terawatt hours (TWh) of renewable energy output-equivalent to nearly one-third of Germany's total consumption. Demand in the industrial, commercial and residential sectors will only grow moderately, as efficiency measures will mainly offset the electrification of industrial processes and residential equipment.
It is expected that from 2021 to 2035, more than 650 gigawatts (GW) of intermittent renewable energy, including wind and solar energy, will be developed. Intermittent renewable energy will account for about 60% of Europe's total installed capacity in 2035, and this proportion is about 35 percent in 2021 (Figure 2). However, it is still uncertain whether the speed of the introduction of renewable energy is sufficient:
As the use of coal is being phased out and nuclear power plants are being decommissioned, it is expected that dispatchable or controllable power generation assets will drop significantly. This issue highlights the power system's dependence on weather-dependent renewable energy and natural gas. Unfavorable wind and solar conditions or a slowdown in the development of renewable energy sources may lead to power shortages. Given the sensitivity of heating demand and the demand for dispatchable power generation, natural gas prices may also fluctuate more. In particular, European coal and lignite production capacity will drop sharply—about 70% from 2021 to 2035. Western and Nordic countries are taking the lead in reducing these capacities.
At the same time, some EU countries have not updated their existing nuclear power assets and rarely made new investments. From 2021 to 2035, nuclear power installed capacity is expected to drop by 23% (Figure 3). Germany, Belgium and Spain have announced that they will close all nuclear power plants in 2022, 2025 and 2035, respectively. France has begun to shut down its oldest nuclear power plant while building a new generation reactor of 1,650 MW. The UK is developing a new 3,200 MW nuclear power project, but delays and costs may hinder further development of nuclear power capacity there.
In order to ensure the stability of the grid, the power sector must compensate for the decline in dispatchable assets.
In order to ensure the stability of the grid, the power sector must compensate for the decline in dispatchable assets. With the decline in coal and nuclear power generation, we expect new power plants such as natural gas power plants and batteries to partially balance the grid. It is expected that more than 14 gigawatts of natural gas will be put into use, mainly from 2021 to 2030, and batteries will exceed 80 gigawatts, mainly from 2030 to 2035. However, some investments depend on the national capacity mechanism to avoid stranded assets by risk investors. The capacity mechanism will also depend on compatibility with EU regulations and EU Fit for 55 packaging. In general, natural gas is expected to remain an important source of dispatchable electricity, especially during periods of long-term downturn in renewable energy production.
The drop in battery storage costs may encourage the introduction of batteries to alleviate the shortage of dispatchable capacity. But the speed may be slower than expected, because European countries did not start the industry through storage instructions like some states in the United States. Nevertheless, people still have doubts about the potential to reduce costs. Uncertainties include the recent rise in battery material costs and questions about the speed of the launch of grid-scale battery "super factories".
We expect that the European power market will be more integrated, including significant coupling of power hubs. By 2030, the annual cross-border flow is about 200 TWh, and Germany is expected to become the center of the European power system. The country is now a net exporter of electricity and is expected to become a net importer of electricity by the mid-2020s. By 2030, interconnection capacity may increase by about 50% (Exhibits 4 and 5), which will further strengthen Germany's position as the most liquid electricity market in Europe. The country is an important strategic area for European utilities and traders aiming to manage market risks in their power investment portfolios.
As we have seen from the surge in electricity prices this year, it is expected that the basic trends in the European power system will cause the electricity pricing environment to become more turbulent. Europe is entering a period of extreme volatility, with daily and hourly prices hitting new highs. According to McKinsey’s EU electricity model, in Germany, the price of more than 3,000 hours per year may exceed 100 Euros or less than 10 Euros by 2030, while today there are only a few hundred hours. Such volatility may stimulate new behaviors of market participants-for example, they bid on electricity supply or hedge the level of future demand.
One way for participants to better understand the dynamics of the electricity market (including volatility) is the value ranking cost curve, which illustrates the pricing mechanism of the electricity market. Five elements are particularly important for predicting future trends in electricity prices and price fluctuations (Exhibit 6):
The European power market is entering uncharted territory. When utilities and large power purchasers face this uncertainty, strategic risk management becomes a survival issue. In the UK, with the soaring price of natural gas, recent defaults by electricity and natural gas retailers indicate a high risk. Here are some steps players can take to resolve uncertainty:
The European power market is entering an unprecedented stage. Market participants who wish to become industry leaders must urgently invest in first-class risk and portfolio management.
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