For decades, access to electricity was largely an assumption in industrial site selection.
Land mattered. Labour mattered. Logistics, taxes, suppliers, customers, planning permission all mattered.
Electricity? You connected to the grid.
That assumption is starting to break.
A company can secure the site, approve the capital, line up customers and still discover that its factory, data centre, logistics depot or charging hub cannot operate on the timetable it planned because sufficient electrical capacity is not available.
And that takes us somewhere much bigger than energy policy.
If access to power determines where investment can happen, grid policy starts to become industrial policy.
The scale of the emerging constraint is extraordinary. The International Energy Agency’s Electricity 2026 report estimates that more than 2,500 GW of renewable generation, energy storage and large-load projects are stalled in grid connection queues worldwide. Annual grid investment, currently around $400 billion, needs to increase by roughly 50% by 2030 to meet forecast electricity demand.
There is an important caveat here: a connection queue is not the same thing as a pipeline of projects certain to be built. Many projects are speculative or will eventually be withdrawn.
But that does not make the bottleneck imaginary.
It tells us something else instead: electricity infrastructure is increasingly becoming a constraint on both sides of the market – on companies trying to generate clean electricity and on companies trying to consume much more of it.
Grid capacity is becoming economic capacity.
The timing mismatch is becoming structural
The problem starts with speed.
Renewable generation can now be deployed comparatively quickly. The same is true of many of the new technologies consuming electricity.
According to the IEA, solar and wind projects can typically take one to five years to develop. EV charging infrastructure can take one to two. Data centres may take one to three.
Major grid infrastructure can take five to fifteen years.
Think about that mismatch.
We can build the asset demanding the electricity faster than we can build the infrastructure supplying it.
We can also build the asset generating the electricity faster than we can build the infrastructure carrying it away.
The grid gets squeezed in the middle.
AI is making one part of that problem particularly visible. The IEA now expects global data-centre electricity consumption to rise from around 485 TWh in 2025 to 950 TWh by 2030, with AI-focused facilities growing considerably faster than the data-centre sector overall.
But AI is only one source of new demand.
Transport is electrifying. Heat is electrifying. Parts of heavy industry are electrifying. Battery manufacturing, semiconductor production and other advanced industrial processes can require significant and highly concentrated power loads.
Electricity is moving from being one input into the economy to becoming a much larger part of its energy foundation.
And infrastructure built for yesterday’s demand patterns is being asked to support tomorrow’s.
Generation without delivery creates stranded value
This was the idea at the centre of my recent Climate Confident conversation with Niklas Persson, CEO of Grid Integration at Hitachi Energy.
Niklas’s point was deceptively simple: building more renewable generation without expanding and modernising the grid eventually means some of that electricity cannot be used.
It gets curtailed.
Australia offers a useful illustration.
The Australian Energy Market Operator reported that grid-scale solar in the National Electricity Market experienced average network-driven curtailment of 4.5% in 2024, while several individual solar farms saw curtailment above 25%. The worst congestion was concentrated in areas where networks originally built mainly to supply local electricity demand were now being asked to export substantial volumes of renewable generation.
That is an engineering problem.
It is also an economics problem.
Imagine doubling production at a factory while leaving the road outside unchanged, then discovering that trucks cannot move the additional output to customers.
Nobody would call that a manufacturing success.
They would call it a logistics failure.
Electricity has its own equivalent of production, routing, storage, capacity constraints, congestion and last-mile delivery.
The grid is the logistics system of the electrified economy.
More generation matters enormously. But production is only valuable when it can reach demand.
Power availability is becoming a site-selection issue
This is where grid infrastructure lands squarely in the boardroom.
The European Commission says grid connection queues now exist in at least 16 EU countries, with around 120 GW of mature renewable projects, including 1.5 million household installations, at risk of failing to receive timely grid access by 2030.
Across the US, Berkeley Lab recorded 2,061 GW of generation and storage capacity seeking transmission connection at the end of 2025.
Again, that number needs context. Berkeley Lab found that historically only a minority of queued capacity ultimately becomes operational, while 75% of capacity entering queues between 2000 and 2020 had been withdrawn by the end of 2025.
Yet another number is arguably more telling: for projects that actually reached commercial operation in 2025, the median journey through the connection process in regions with available data was more than five years.
For executives making capital decisions, that matters.
Imagine two regions competing for the same advanced manufacturing plant. Labour costs are comparable. Logistics are good. Incentives are attractive.
One can guarantee the required clean electrical capacity in two years.
The other says six.
Suddenly the substation belongs in the site-selection model alongside the motorway, port and workforce.
The same calculation applies to fleet depots, logistics hubs, semiconductor plants, battery factories and data centres.
Power availability becomes time-to-market.
And time-to-market becomes competitive advantage.
Build ahead of demand, or arrive behind it
That creates a difficult question for governments and regulators.
How much electricity infrastructure should be built before demand is certain?
Transmission assets are expensive and long-lived. Consumers ultimately carry much of their cost. Building infrastructure that goes badly underused is hardly good policy.
But waiting until every megawatt of future demand is contractually certain creates a different risk: the infrastructure may arrive years after the economic opportunity.
Europe is already moving towards what regulators call anticipatory investment – planning some network development against credible future demand rather than merely responding to connection applications already in the queue.
The scale is substantial. The European Commission estimates that around €730 billion of distribution investment and €477 billion of transmission investment could be required by 2040.
That does not mean writing blank cheques for grid operators.
Quite the opposite.
It means becoming better at forecasting where electricity demand and generation are likely to emerge, sharing the utilisation risk sensibly, improving spatial planning, coordinating infrastructure programmes and taking decisions early enough for the physical system to arrive when the economy needs it.
Niklas captured the other side of that risk wonderfully in our lightning round.
I asked him for the most expensive grid mistake.
His answer was two words:
“Not building.”
That is deliberately provocative. Overbuilding has costs.
But so does being late.
The second is simply harder to see because it appears as the factory that chooses another country, the charging depot delayed, the renewable project curtailed, or the investment that never reaches a final board paper.
Energy sovereignty may require electrical interdependence
There is another strategic contradiction hiding here.
Europe understandably wants greater energy security after seeing the consequences of excessive dependence on imported Russian fossil fuels.
But a more secure electrified system does not necessarily mean every country attempting to become an electrical island.
Quite possibly the opposite.
Denmark is a useful example. When wind generation exceeds domestic demand, interconnection allows electricity to move into neighbouring systems. Nordic hydropower can conserve water while wind is plentiful elsewhere. When Danish wind production falls, electricity can move back in.
Interconnection allows different weather patterns, generating technologies, storage resources and consumption profiles to complement one another.
It means countries do not each have to build an electricity system capable of independently surviving every conceivable peak.
That is not dependence in the old fossil-energy sense of relying heavily on one pipeline and one supplier.
It is a network of options.
And options are valuable in resilient systems.
HVDC is changing electricity’s geography
High-voltage direct current transmission pushes that logic further.
The engineering is sophisticated; the strategic idea is straightforward.
HVDC makes it practical to move very large quantities of electricity efficiently across long distances and through subsea cables. As a result, renewable resources no longer need to sit conveniently beside the consumers using them.
That changes electricity’s economic geography.
ELMED is one example.
The 600 MW electricity interconnector being developed between Tunisia and Italy will run more than 200 kilometres between Tunisia’s Cap Bon region and Sicily, creating the first direct electricity connection between the two countries.
Projects like this could eventually allow North African renewable resources to play a larger role in European electricity supply.
But they also require care.
Europe should not recreate an extractive energy relationship in which generating regions provide resources while capturing little of the economic value. Domestic electricity requirements, local jobs, skills, revenues, industrial development and infrastructure ownership all matter.
Done well, however, interconnection creates value in both directions.
Tunisia gains infrastructure, investment and access to a larger electricity market. Europe gains another source of power and additional system flexibility. Both gain another pathway for moving electricity when system conditions change.
The strategic asset is not simply the cable.
It is the optionality the cable creates.
We don’t have to wait for every new transmission line
There is a danger, though, in reducing the grid challenge to “build more wires”.
We certainly need more infrastructure.
But we also need to extract more value from infrastructure already built.
This may be one of the most commercially important findings in the IEA’s latest analysis.
It estimates that a combination of more flexible connection agreements, dynamic line ratings, advanced power-flow controls, reconductoring, voltage upgrades and related reforms could release enough capacity to connect 1,200-1,600 GW of advanced-stage projects currently caught in queues worldwide.
That is a huge number.
It reframes the problem.
Some of the grid constraint is physical infrastructure.
Some is how we operate that infrastructure.
Some is regulation.
Some is queue management.
Some is the assumption that every user must receive unrestricted access at every moment rather than accepting flexible connections in return for faster access.
Batteries, demand response, local generation and smarter siting add further flexibility.
So the choice is not “build grids” versus “optimise grids”.
We need both.
Electricity strategy belongs earlier in capital strategy
For senior business leaders, the practical conclusion is fairly stark.
Electricity can no longer be an engineering workstream added late in a major capital project.
For energy-intensive investments, management teams should understand available grid capacity, realistic connection dates, reinforcement requirements, power quality, potential curtailment or flexibility conditions, and the cost of alternative locations before committing heavily to a site.
That also means asking different questions.
Could storage reduce peak connection requirements?
Could a flexible connection bring the project online earlier?
Would locating closer to generation or existing network capacity materially alter project economics?
Could on-site generation cover part of the load?
What happens to the business case if the grid connection slips by three years?
Those are no longer niche energy questions.
They are investment questions.
The renewable generation revolution is well advanced. Solar, wind and batteries continue scaling because their economics increasingly work.
Now the infrastructure linking supply and demand has to catch up.
Niklas gave perhaps the best summary near the end of our conversation. Clean electricity only counts, he said, “when it can be brought to the consumers.”
Generation is not delivery.
And in an economy becoming steadily more dependent on electrons, delivery infrastructure determines where growth can occur.
That is why the grid can no longer remain invisible to boards, policymakers or investors.
The next battle for industrial competitiveness may not be won by the country offering the largest subsidy.
It may be won by the one that can say, with confidence:
We have the power. And we can connect you on time.
I explored the implications in much greater depth with Niklas Persson in the latest episode of Climate Confident, including interconnectors, HVDC, permitting, resilience and the difficult question of who gets priority when grid capacity is scarce.
Listen to Generation Is Not Delivery: The Grid Problem Behind Decarbonisation
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