Five trends shaping European power networks

European power markets have entered a period of unprecedented change, driven by five key trends. In this article, we outline how they will shape the European power sector in the decade to come and offer some perspectives on how utilities and large consumers might respond.

Trend 1: sustained growth in power demand

Electricity demand is expected to increase steadily in Europe, at a CAGR of about 2% until 2035. The main factors behind the surge will be the electrification of transport and a ramp-up in the production of green hydrogen through electrolysis, requiring renewable power.

Transport power demand will grow by 14% CAGR as a result of the rollout of the electrification infrastructure and national regulations on emissions (for example, if cities ban internal-combustion engines and impose fiscal measures to discourage the use of nonelectric vehicles). The power requirements of green-hydrogen production will expand by about 40 percent CAGR, absorbing 230TWh of renewables output by 2035 across Europe - the equivalent of nearly a third of Germany’s total consumption. 

Trend 2: a future energy system dominated by intermittent production

The expectation is that more than 650GW of intermittent renewable power, including wind and solar, will be developed from 2021 to 2035. Intermittent renewables will account for about 60% of total installed capacity in Europe in 2035, compared with about 35% in 2021. However, it remains uncertain whether the pace at which renewables are rolled out will be sufficient:

• Project permissions have been delayed in a number of European countries. As a result, the gap between the time projects are proposed and commissioned is up to seven years
   
• The modernisation of the grid faces significant challenges as the production of renewable power drives nodal imbalances, requiring utilities to invest in new transmission and distribution assets
   
• Restrictions have been placed on the development of renewables assets in a growing number of countries - for example, limitations on onshore wind development as a result of concerns about biodiversity or noise and visual pollution.

Trend 3: the phase out of coal and nuclear assets

A large drop in dispatchable, or controllable, generation assets is expected because the use of coal is being phased out and nuclear plants are being decommissioned. This issue highlights the power system’s reliance on weather-dependent renewables and on natural gas.

Adverse wind and solar conditions or a slower pace of development for renewables could lead to power shortages. Gas prices may also fluctuate more, given the demand sensitivity of heating and the need for dispatchable power generation. In particular, European coal and lignite capacity will drop drastically - by about 70% from 2021 to 2035. Western and Northern European countries are taking the lead in these cutbacks.

Meanwhile, a number of EU countries are not renewing their existing nuclear-power assets and are making few new investments. Nuclear capacity is expected to decline by 23% from 2021 to 2035. Germany, Belgium, and Spain have announced that they will close all their nuclear plants by 2022, 2025, and 2035, respectively.

France has started closing its oldest nuclear plant while building a 1,650MW new-generation reactor. The United Kingdom is developing a new 3,200MW nuclear project, though delays and costs may hinder the further development of nuclear capacity there.

Trend 4: the critical role of gas and batteries to bridge dispatchable-power capacity needs

To ensure the grid’s stability, the power sector must compensate for the drop in dispatchable assets. We expect new ones, such as natural-gas power plants and batteries, to partly balance the grid as coal and nuclear generation decline.

More than 14GW of natural gas are expected to come on line, mostly from 2021 to 2030, and more than 80GW in batteries, primarily from 2030 to 2035. Yet a number of investments are contingent on national capacity mechanisms to avoid the risks of stranded assets for investors. Capacity mechanisms will also depend on compatibility with EU regulations and the EU’s Fit for 55 package. Overall, natural gas is expected to remain a critical source of dispatchable power, especially in periods with prolonged low renewables output.

Declining battery-storage costs may encourage the rollout of batteries to alleviate the shortfall in dispatchable capacity. But the pace may be slower than anticipated, since European countries have not kick-started the industry with storage mandates like those in some US states. Still, doubts remain about the potential for cost reductions. The uncertainties include recent inflation in the cost of battery materials and questions about the pace of the rollout of 'giga-factories' for grid-scale batteries.

Trend 5: the rise of an integrated European power market with Germany at its core

We expect a more integrated European power market including significant coupling of power hubs. With cross-border flows of about 200TWh a year in 2030, Germany is expected to be at the centre of the European power system. The country, now a net power exporter, is expected to become a net power importer by the mid 2020s. Interconnection capacity could grow about 50 percent by 2030, and this should further reinforce Germany’s position as Europe’s most liquid power market. The country represents a key strategic region for European utilities and traders aiming to manage market risks in their power portfolios.

How can market players respond?

Together, these trends are expected to lead to a much more volatile power-pricing environment, as we already see from this year’s power-price surge. Europe is entering a period of extreme volatility, with daily and hourly prices hitting new highs. When utilities and large power buyers face that kind of uncertainty, strategic risk management becomes a matter of survival. Here are some steps players can take to address the uncertainties:

• Investing in best-in-class risk-management models
  These would cover market-price risks along with the nonlinear volume or shape risks of day-ahead and intraday power markets. For example, players could make more use of advanced stochastic profit-at-risk or cash-flow-at-risk models, such as running them in quasi-real time to best inform hedging strategies. Ad-hoc stress tests will also be critical to run on a periodic basis.
   
• Pursuing flexibility in portfolios
  To reduce exposure to price surges in wholesale power markets, players could source more flexibility both on the demand and supply sides of portfolios, including, for example, demand-side response aggregation and investments in gas-peaker assets, grid-scale batteries, and virtual power plants (VPP).
   
• Developing an active presence in the most liquid European power hubs
  Germany is expected to remain the most liquid market and an ideal place to optimize hedging strategies across Europe—for example, by employing proxy hedges and cross-border hedges in the event of strong market coupling and limited liquidity in other markets.
   
• Using power purchase agreements with partial or full fixed-price arrangements
  Companies could use this strategy to hedge long-term power purchases or sales, thus reducing exposures to volatile power prices.

The European power market is entering an unprecedented phase. Market participants that hope to be industry leaders must urgently invest in best-in-class risk and portfolio management.

Fabian Stockhausen is a consultant in McKinsey’s Düsseldorf office, Eivind Samseth is a solution manager in the Oslo office, Xavier Veillard is a partner in the Paris office and Alexander Weiss is senior partner in the Berlin office