Charles Hardcastle, Partner, Head of Energy & Marine, Carter Jonas
The Great Grid Upgrade is indispensable, but connection certainty has become a scarce commodity, and investors and developers are increasingly forced to plan for uncertainty.
The complexity of re-mapping of Britain’s energy system is inevitable. Previously, power flowed out from large stations. Now, with generation increasingly coming from Scotland and the coast, demand growth is uneven and involves two-way flows, storage and new high-intensity loads.
The problem is that investors do not fund principles, they fund programmes with reliable dates. In the last few months, the industry has been reminded that there is a difference between an upgrade strategy and an investable delivery plan.
Following its publication of an Update on delays to connection dates for some TMO4+ Protected Projects, Ofgem admitted frustration that of 340 transmission projects with protected dates, 210 were expected to have their connection date and or connection point changed. Likewise for anyone trying to commit or attract capital, it was disappointing that projects believed to have a degree of certainty were in fact far from certain.
Our team works in the context of consents, land rights and programme delivery and we regularly see the impact of grid delays. A connection date is not just a technical milestone, but the point at which debt can be drawn, construction risk priced, revenue assumptions clarified and supply chain commitments made. Uncertainty in the timing changes not only the programme but the risk profile too.
It is easy to underestimate the true costs of a six-month delay. Retaining development teams, and renegotiating land and procurement options can be expensive but what makes the situation more difficult is that the queue itself is changing. Before the reform reset, according to NESO, the pipeline of projects seeking connections was over 700 GW, far beyond what was envisaged.
An inability to connect power has significant consequences. The Greater London Authority’s West London Electrical Capacity Constraints paper warned in 2022 that major new applicants to the distribution network, including housing and commercial schemes, could face waits of several years for connections. The Old Oak and Park Royal Development Corporation went further in its Q4 2022/23 Performance and Finance Report, listing electricity capacity issues in west London as a risk that stalls delivery of new housing.
Oxfordshire has provided similarly direct testimony. Written evidence to a parliamentary committee said over 7,000 homes in Bicester had been paused while awaiting grid connection reinforcement. Furthermore, in a House of Commons debate in December, it was claimed that up to 9,000 homes north-west Bicester were stalled due to a lack of grid capacity.
Then there is strategic demand. Ofgem’s demand connections update shows contracted offers in the demand queue rising from 41 GW in November 2024 to 125 GW by June 2025.
For many, the option of waiting does not exist because capital and supply chains do not pause. The only practical response is to plan on the basis of connection uncertainty and design the project so it can survive that risk. There are investment strategies that can mitigate the impact of delay, as I have seen in practice in the work of experienced advisory teams.
One is to treat the grid as a scenario set: model a base case, a delayed case and a reconfigured case, then build decision points into the programme so that early spending buys options rather than locks in irreversible commitments.
Secondly, it can be possible to stage capital in line with deliverability evidence. Enablement works, land assembly, surveys and consents can move ahead while larger spend is held behind pending the clearance of hurdles such as a confirmed connection offer, secured route or defined reinforcement solution.
There is also the possibility of designing for modularity and flexibility, perhaps accepting a smaller connection earlier and expand later and working in flexible connections, storage and demand management.
Sometimes the answer is co-location and private wire. In others, behind-the-meter generation paired with storage can keep a site operational.
Finally, I advise aligning consenting strategy with delivery risk. Planning consents expire if not implemented. That risk needs managing from the start through phasing, conditions strategy and a clear plan for what constitutes meaningful commencement if a scheme needs to preserve a permission while the grid position is resolved.
The need for the Great Grid Upgrade is indisputable because the alternative is curtailment, higher system costs and investment drifting to jurisdictions that can offer firmer delivery. But confidence will only return through greater transparency, discipline in sequencing where possible and a more joined-up view of future demand.
This article appeared in the May 2026 issue of Energy Manager magazine. Subscribe here.
