In the age of AI data centres and electrification, the grid is the real bottleneck

The expansion of artificial intelligence (AI) workloads and large-scale data centres is materially changing global electricity demand. At the same time, transportation and industrial processes are becoming increasingly electrified.

Global electricity demand grew 4.3% in 2024, more than double the average annual rate of the previous decade, and the International Energy Agency (IEA) projects 4.1% annual growth through 2030. To meet the growing demand, generation capacity will have to increase dramatically. However, the electric grid itself has become a limiting factor.

Large-scale AI deployment is relatively new, but high-performance computing (HPC) infrastructure has existed for decades. Since the early 2000s, data centres built around CPU-based clusters have been widely used in academia, national laboratories, and industry for workloads such as scientific simulation, financial modelling, and large-scale data processing. These traditional HPC data centres were limited by air cooling and CPU-focused designs, which kept rack power levels relatively low and allowed facilities to scale gradually. Even today, most data centre racks draw under 8kW on average, with many operating at just 4–6kW and very few exceeding 30kW.

In contrast, AI data centres rely on GPU/accelerator racks with much higher power draw per server and per rack, often requiring liquid cooling and new electrical distribution architectures. Recent industry analysis highlights that AI training deployments can require approximately 100 – 200kW per rack, well beyond the historical ‘mainstream’ data centre envelope. At the facility scale, HPC sites have long operated in the tens of megawatts for flagship systems.

What’s different with AI is that new ‘AI-ready’ builds and campuses are being planned in the hundreds of megawatts per facility. A staggering 55% of upcoming data centres exceed 200MW in power capacity.

Another large driver of the increased global electricity demand stems from the electrification of the transportation sector. Only 500,000 EVs were sold worldwide in 2014. Ten years later, in 2024, the total number surpassed 17 million units, representing a compound annual growth rate of 42% over this decade, a rate akin to the introduction of the internet or smartphone rather than the historical automotive sector. The global electric car fleet has reached nearly 60 million vehicles, representing approximately 4% of the total passenger car fleet.

An ageing European electrical grid

Much of today’s transmission and distribution (T&D) infrastructure in Europe was built in the second half of the twentieth century. It may not have been designed for geographically distributed renewable generation, highly variable digital loads, or tens of millions of new electric vehicle charge points.

Electricity demand across the EU grew approximately 1.5% in 2024, a meaningful reversal of the near-zero average growth that had persisted since 2003 and is expected to continue steepening as industrial decarbonisation, data centre investment, and EV uptake compound through the remainder of this decade.

Globally, demand is projected to grow by roughly 25% by 2030 and nearly 80% by 2050, representing the largest expansion since the post-war electrification era.

The consequences are already visible in Europe. More than 1,650GW of solar and wind projects are waiting in global interconnection queues. A disproportionate share is concentrated in EU Member States and the UK.

New transmission infrastructure typically requires five to fifteen years to plan, permit, and construct in European regulatory environments. By contrast, AI data centres, renewable generation projects, and distributed EV charging networks can be deployed in a matter of months and draw down significant amounts of power. The loads are arriving faster than the wires.

Even as investment increases, supply chains remain strained. Transformer prices across Europe have more than doubled from pre-pandemic levels, lead times for high-voltage cables and power electronics have risen sharply, and shortages of skilled labour and specialised installation equipment continue to slow grid expansion.

For the data centre sector in particular, grid availability has become a primary site-selection risk across Europe. For renewable developers, curtailment in congested corridors is already eroding project returns in Germany and the UK. The investment case for the clean energy transition depends on solving this constraint, not in the 2030s, but now.

Why batteries are becoming a practical grid-capacity tool

Battery energy storage systems (BESS) are increasingly being deployed across Europe to address the structural timing gap between rapidly growing electrical loads and slow-moving grid infrastructure. Battery storage was the fastest-growing commercially deployed energy technology in 2023, with more than 42GW of new capacity added globally. Roughly two-thirds of this capacity was deployed at utility scale, and the total global installed base exceeded 190GWh by year-end.

For project developers and utilities, adoption is being driven primarily by deployment speed, modular system design, and declining costs. Over the past 15 years, lithium-ion battery costs have fallen by more than 90%, from approximately €750 (US$882.69) per kilowatt-hour to under €130/kWh. At the same time, global manufacturing capacity has expanded rapidly, supporting large-scale deployment.

The EU regulatory environment is also moving in storage’s favour: the revised Renewable Energy Directive (RED III) and the Net-Zero Industry Act both identify storage as a strategic clean energy technology, and several member states have introduced streamlined permitting for storage projects co-located with renewables, recognising that storage reduces the net impact on congested networks.

For European data centre developers, renewable project owners, and grid planners facing multi-year connection queues, the biggest advantage of battery systems is deployment speed and scalability. Where new transmission projects can take a decade or more to deliver in European regulatory environments, utility-scale battery systems are commonly deployed in six to eighteen months. Containerised systems installed behind-the-meter (BTM) can often be operational even faster, particularly on previously developed sites.

Speed and scalability are enabled by the modular architecture of modern battery systems. Capacity can be expanded incrementally without major changes to site infrastructure. This is a fundamentally different risk profile from transmission investment, which requires the full project commitment upfront and years of permitting before a single kilowatt-hour is stored. From a project-development standpoint, this allows storage to be deployed alongside new digital or renewable infrastructure and scaled as demand increases.

Using energy storage to defer grid demand rather than replace generation

For data centres, battery systems are increasingly used as a buffer between rapidly growing on-site demand and limited grid capacity.

When deployed BTM, battery systems can be charged gradually using existing grid connections and discharged during periods of high demand. In constrained regions, this load-shifting capability can reduce peak demand on local distribution networks and defer immediate infrastructure upgrades. Battery systems can also participate in time-of-use (ToU) and capacity-based pricing structures and, in some jurisdictions, export energy back to the grid when demand is high.

From a grid-planning perspective, this distinction matters. Battery storage does not replace generation capacity and does not eliminate the need for long-term grid expansion. Instead, storage provides a deployable mechanism to defer demand and manage congestion while transmission and distribution investments move forward.

A deployment tool for Europe’s near-term grid transition

Across Europe, the pace of digital infrastructure development, renewable energy buildout, and transportation electrification now exceeds the pace at which the grid can be expanded. For data centre developers, renewable project owners, and industrial customers, grid connection delays have become a primary development risk, not a secondary engineering consideration, and not a problem confined to any single market or member state.

In this environment, battery energy storage offers one of the few technologies that can be deployed on timelines comparable to new digital and renewable infrastructure, at a cost that has fallen dramatically and rapidly. Storage systems are a practical tool to manage peak demand, mitigate local congestion, unlock stranded renewable capacity, and defer infrastructure upgrades while long-term transmission investments move forward.

The assets most constrained by European grid timelines, solar and wind projects queued for connection, EV charging hubs awaiting network upgrade, data centres and industrial facilities seeking electrification pathways, can be made immediately viable by pairing with energy storage.

For grid planners, regulators, and policymakers across Europe, the constraint is no longer generation availability. It is the ability to deliver firm capacity to new loads on commercially viable timelines. Battery energy storage is not a substitute for the grid expansion that Europe urgently needs, but it may be an important near-term deployment tool that allows the clean energy transition to keep moving while the wires catch up. In a system that was not designed for the pace of today’s electrified, AI-driven economy, that capability is not a supplement. It is the bridge.

About the Author

Omri Tayyara, Ph.D, is the business manager for Energy Storage, Energy, and Power at product certification and standards development organisation CSA Group. An engineer by trade, Tayyara leads and supports initiatives spanning battery safety, energy storage systems, large-scale fire testing, and electrification technologies. His work includes developing custom research and development testing programmes, strengthening partnerships with manufacturers and developers, and building analytical frameworks that support evidence-driven decision-making. Omri Tayyara holds a doctorate in Mechanical Engineering from the University of Toronto.