Rising uncertainty surrounding future electricity demand could affect Europe’s energy transition and power infrastructure investment plans. Governments and system operators have projected that power demand in major European countries could increase by as much as 7 percent per year to 2030 after two decades of relative stagnation. In McKinsey’s Global Energy Perspective 2024 report, the Continued Momentum scenario projects growth to be only slightly above 2 percent CAGR.1 Further McKinsey analysis has found that up to 40 percent of this modeled growth may not, in fact, materialize. The possible impact of this reduced demand outlook might be profound if higher system costs drive up the price of electricity and potentially accelerate deindustrialization in the region.
Factors, including elevated power prices, energy efficiency gains, and structural economic changes linked to deindustrialization, may all moderate the expected electricity demand growth. Mario Draghi’s recent report on the future of European competitiveness warns that the region faces a slow economic decline linked to deindustrialization.2 Our analysis indicates that elevated power prices—which are currently 60 to 90 euros per megawatt hour (EUR/MWh) across Europe versus historical averages of 30 to 50 EUR/MWh—could increase industrial production costs and result in lower-than-expected power demand from the industrial sector (see sidebar “Our analysis”). While reduced industrial demand is the primary contributing factor and focus of this article, shifts in overall industrial activity are, of course, a function of many interconnected factors, including macroeconomic conditions or demographic shifts.
Following the major industrial shutdowns of 2022–23, several big industrial players have more recently announced plans to move production to lower-cost locations.3 Meanwhile, the uptake of other important electricity demand drivers, such as electric vehicles (EVs) and heat pumps, has slowed in the last three years, adding further questions about how European power demand could evolve in the years to 2030.4
In this article, we examine the expected trajectory of electricity demand in Europe through 2030, the factors that may prevent this from fully materializing, and the broader implications for the region. We also touch on potential solutions such as revised market design, infrastructure build-out, demand-side response, and electrification incentives.
Why electricity demand is expected to grow
Power demand has long been expected to grow in Europe as increasing population and rising GDP drive higher overall energy consumption (despite efficiency gains). The current boom in AI could create a further demand surge, with data centers possibly accounting for as much as 5 percent of total European power consumption by 2030.
Meanwhile, the energy transition has also spurred new transmission and distribution (T&D) investments to accommodate growing demand and the deployment of increasingly dispersed renewable energy sources (see sidebar “The evolving energy transition: McKinsey’s latest analysis”).
The European Union’s commitment to achieving net zero by 2050 has led to increasingly ambitious policies concerning emissions, renewables, EVs, and heat pumps, all of which point to growing power demand. For example, the REPowerEU initiative aims to have at least 30 million newly installed heat pumps by 2030, up from 22 million in 2023, and the Renewable Energy Directive (RED III) has raised the 2030 target for renewable energy’s share of final consumption to 42.5 percent.5
Other factors that could cause demand to grow include longer-term policies looking beyond 2030, regulations such as “Fit for 55,” the decreasing costs of electrification technology, and GDP recovery.6 Taken together, these growth-signaling factors have led governments and system operators across major economies to forecast a 1 to 7 percent annual increase in electricity demand until 2030 (Exhibit 1).
Factors putting demand growth at risk
According to our latest analysis, however, these growth expectations may not be attainable. In fact, electricity consumption in Europe has already slowed. Following steady growth of 1.4 percent per annum through the 2000s, peaking in 2008, demand growth has remained relatively muted. Since 2021, demand has dropped consistently at around 3 percent per annum, failing to meet expectations for a post-COVID-19 “bounce back” (Exhibit 2).
Historically, electricity demand was closely correlated with economic growth in most European economies—over 2 percent GDP growth per annum between 2000 and 2008, a correlation of around 0.96 between electricity demand growth and GDP for that period.7 But after the financial crisis and growth peak in 2008, GDP and electricity demand have delinked in these countries (with a correlation of approximately –0.53).
There are various underlying reasons for the decline in demand growth in recent years:
- The COVID-19 pandemic and the invasion of Ukraine both impacted Europe’s power demand profile. The conflict in Ukraine triggered a gas shortage, with the resulting higher gas prices peaking at a yearly average of around $41 per metric million British thermal unit (MMBTU) in 2022—up from a yearly average of $6/MMBTU in 2017 to 2019.8 This, along with operational challenges at reduced-output nuclear plants in France and low hydroelectric production, caused many industrial companies to shut down across sectors such as steel, aluminum, and chemicals.9 This deindustrialization trend has had a significant impact on power demand and is one of the key reasons why growth remains below historical levels.
- The drop in power demand is also driven by considerable energy efficiency gains, structural economic changes—such as offshoring and the transition to a more services-oriented economy—and milder winters over the past couple of years that have reduced the demand for space heating.10 While advancements in energy efficiency and reduced heating demand are a positive trend overall, they further build on the case made in this article that current projections for electric demand growth may not materialize as expected.
These factors have affected European countries differently. Major economies such as France, Germany, and Spain experienced the steepest declines in demand, mostly due to decreasing industrial output. Electricity consumption in the region’s smaller eastern and northern economies responded more moderately to gas price increases, mainly because of their generally lower industrial demand and dependency on gas.11
Global Energy Perspective 2024
Uncertainty spans multiple sectors
To explore electricity demand predictions in more detail, we examined the power demand forecast in McKinsey’s Global Energy Perspective 2024 (Continued Momentum scenario), identifying key areas where demand growth is at risk.12 While approximately 460 terawatt-hours (TWh) of additional demand is forecast by 2030, our analysis suggests that around 40 percent (180 TWh) of this might not materialize. Besides lower demand from industry, other key demand drivers, such as EVs and heat pumps, have grown at a slower pace than expected, too (Exhibit 3).13
The uncertain outlook spans several sectors, including buildings, transport, industry, green hydrogen, and data centers (Exhibit 4). Sectors most affected by high prices would likely include those where the total cost of ownership (TCO) is a significant factor when electrifying, such as EVs and residential heating, as well as high-investment or technically challenging areas, such as high-temperature industrial processes.
Buildings: According to our analysis, annual heat pump sales in Europe decreased by 3 percent in 2023 to 2.9 million units, partly due to ongoing delays in supportive policy and partly driven by evolving business cases. More recently, several European heat pump manufacturers have reported sales declining by 47 percent in the first half of 2024, with full-year estimates reaching only 1.5 million heat pumps. This has led to permanent and temporary layoffs in the sector.14 Given the direct tie between heat pumps and power demand, if the current rate of heat pump adoption continues, about 17 TWh of expected electricity demand could be at risk, putting electricity demand for heating 50 percent lower than expected in 2030.
Transport: The growth in demand for battery electric vehicles (BEVs) and plug-in hybrids has decelerated over the past three years, dropping from a 42 percent year-on-year increase in 2021 to 21 percent in 2023. The picture looked even worse for the first half of 2024—only a 1 percent increase in sales compared to the first half of 2023. High material costs, slow infrastructure development, and supply chain challenges could limit the total number of EVs to 36 million by 2030. The slowdown is partly due to reduced support schemes, though the introduction of more affordable models may revive momentum. If sales in Europe maintain their current pace, however, 45 percent of the anticipated EV-related power demand may not materialize, putting 58 TWh of road transport demand at risk by 2030.
Industry: As reported in the press, industrial activity remains subdued, with high production costs and ongoing plant closures expected to extend into the fourth quarter of 2024.15 Deindustrialization may continue as key players in vehicle manufacturing, steel, and chemical industries announce reductions in European production.16 Several companies have announced planned plant closures in recent years, citing unfavorable economic conditions in Europe.17 High energy prices and regulatory developments could drive further declines, potentially leading to a 10 percent reduction in steel and chemicals output by 2030. Of the sector’s expected growth, more than half—66 TWh—could be at risk due to declining industrial output and slower electrification.
Green hydrogen: Growth in power demand from green hydrogen is particularly uncertain, largely because of the limited confirmed offtake resulting from the high cost expectations for hydrogen. As a result, there have been delays in electrolyzer development, with many announced projects not reaching a final investment decision (FID).18 Only 1.4 million tons per annum (Mtpa) of the low-carbon hydrogen pipeline has reached FID, compared to the 1.8 Mtpa forecast for 2030. This could result in a 20 percent lower electricity demand than expected for hydrogen production. In contrast, to meet 2030 targets, clean hydrogen (blue and green) production needs to increase approximately 25-fold in Europe over the next five years.19
Data centers: Due to increasing workloads (such as enterprise apps and data storage), innovations in hardware, and data residency laws in the European Union, electricity demand from data centers is rising. However, it may be tempered by uncertainties related to AI-driven load increases, connection issues to already constrained grids, and new EU regulations. If the trends driving demand growth do not accelerate, 21 TWh could be at risk and could lead to overinvestment in potentially oversized assets.
The possible implications of slower demand growth and how industry could adapt
Lower-than-expected electricity demand growth in Europe could significantly impact overall system costs—and, ultimately, the path of the energy transition and Europe’s broader economic conditions. To mitigate these risks, it will be important for stakeholders across the energy value chain to monitor trends and adjust their strategies proactively in five key areas:
- Power generation assets: Planned total generation capacity and its composition will likely need to evolve in response to slower demand growth. Here, different scenarios are possible, including one in which Europe doubles down on sustainability and government targets and decides to invest further in energy transition generation assets and systems. However, overall system costs may rise as a result, posing fundamental challenges to affordability and resulting in supply and cost challenges impacting the future of European industry. To illustrate, roughly a 10 percent reduction in power demand could shift up to €300 billion of investment in generation assets between 2025 and 2030 (30 percent of the expected total) to different sources. Even in that scenario, however, the required annual investments in the next five years would still be over 15 percent higher than they were in the last decade.
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Grid build-outs: Investments in T&D infrastructure may need to adapt to the future demand growth and the implications that develop regarding generation assets. For example, a reduction in power demand could translate to a shift in the size and shape of investment in T&D in the near-term 2025–30 period, although fundamentally, the total investment in the path to net zero is still likely to remain the same. We note that the required annual investments in the next five years would still be over 50 percent higher than they were in the past decade (and, in some geographies, still represent a two to five times scale-up of the build-out). System operators and local grids will need to adapt while still providing an essential utility.
This may imply a change in focus, moving away from local build-outs and ever greater, more frequent, and larger interconnection and grid automation—all of which will have implications for grid fees. Innovative approaches like digitalization, microgrids, and energy storage could be explored to ensure cost-effective deployment.
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Consumer impact and pricing: Lower electricity demand could lead to reduced wholesale power prices. While the lower landed costs of electricity may benefit consumers, they could possibly weaken the business case of power generation assets. If recouping the capital extended to connect those assets falls to wholesale prices only, customers could pick up the tab through higher power prices.
In Germany, for example, household grid fees could increase from about 13 cents per kilowatt-hour (ct/kWh) in 2023 to about 18 ct/kWh in 2030 if demand aligns with government targets.20 However, if a significant amount of this growth does not materialize, prices could increase to as much as 25 ct/kWh (of a total household power price of 51 ct/kWh), threatening affordability. A similar impact is expected for industrial rates, with implications for competitiveness.
- New market frameworks: The potential slowdown in demand growth could prompt renewed focus on new market frameworks to manage demand more effectively instead of merely increasing supply. Solutions could involve promoting energy efficiency, enhancing demand-side management, and investing in smart grids and energy storage. Overall, T&D system operators would be well advised to increase collaboration and better align investments to actual demand, leveraging long-term agreements to ensure value creation.
- Potential positive impact on emissions: Of course, lower electricity demand could lead to a reduction in emissions in Europe, especially if it reduces the reliance on generation from fossil fuels, such as coal and gas. This could make it easier for countries to meet their climate targets, offering significant environmental benefits. However, this positive outlook is tempered by the realization that if lower industry emissions are linked to acquiring alternative or lower-cost energy, this could come from sources with higher emissions intensity than those in Europe, further depleting the global carbon allowance.
Despite expectations of continued growth in European electricity demand toward 2030, the current outlook suggests this could be as much as 40 percent lower than anticipated. Balancing sustainability goals with energy affordability and economic growth will require coordinated action between key players in the region.
Mitigating the impact of reduced power demand will require utilities, T&D companies, governments, and investors to realign their strategies with regularly updated demand forecasts. Enhanced grid flexibility will also be essential to maintain a stable and sustainable energy system. This need for increased agility will place strategic and organizational demands on both companies and regulators, ideally resulting in more robust systems for the future.
Above all, affected European players can closely monitor sector developments and key indicators, such as power retail prices, and start readying themselves now for a future that may not turn out quite as planned.
