How Britain committed billions to an electricity system whose tracks, junctions and power sources may not be ready in time
Britain’s energy programme now resembles a runaway train.
The destination was written into law. The timetable was dictated politically. Billions of pounds were committed. Network projects were accelerated. Land was identified, equipment ordered and communities told that enormous new lines, substations, solar farms and offshore connections were essential.
Only afterwards did the difficult questions begin to surface.
Can the lines actually be constructed across the selected land?
Are the substations on suitable ground?
Can the planning system process everything in time?
Is the specialist equipment available?
Can outages be coordinated without destabilising the existing network?
Will the offshore wind farms be financed and operating when the transmission infrastructure is completed?
Will all the adjoining lines be ready in the correct sequence?
And, most importantly:
What happens in winter when the wind is low, solar has disappeared with the setting sun and the transmission network is still incomplete?
Ed Miliband left the Department for Energy Security and Net Zero on 20 July 2026 to become Foreign Secretary. Miatta Fahnbulleh now heads DESNZ. But the accelerated Clean Power programme Miliband championed remains embedded in government policy, regulation, network investment and the connections system.
Miliband may have changed departments.The train he launched is still travelling at full speed.
The Climate Change Act laid the track towards a fixed destination
The root of the problem lies in the Climate Change Act 2008.
The Act established a legally binding emissions-reduction target and a system of rolling carbon budgets. In 2019, the statutory 2050 target was increased from an 80 per cent reduction to a 100 per cent reduction against the 1990 baseline , effectively net zero.
That created a legal ratchet.
Every government is now required to pursue continuing emissions reductions. Every major energy decision is assessed against carbon budgets. Electricity policy is no longer simply about affordability, security and engineering resilience; it must also conform to a predetermined emissions trajectory.
But the Climate Change Act did not require:
Clean Power by 2030;
45–47 GW of solar;
43–50 GW of offshore wind;
the destruction of productive farmland;
a particular network of pylons and substations;
or a rushed reconstruction of Britain’s electricity system.
The Act established the destination.
Ministers selected the speed, route and technology mix.That distinction matters because government cannot blame the legislation for every subsequent decision.
The 2030 deadline was a political acceleration, not an unavoidable technical consequence of the original Act.
Miliband pushed the throttle to the floor
The Clean Power 2030 Action Plan calls for:43–50 GW of offshore wind;27–29 GW of onshore wind;45–47 GW of solar;23–27 GW of battery capacity;4–6 GW of long-duration storage;and the rapid delivery of 80 network and enabling projects.
The Government estimates that the programme will require investment averaging around £40 billion every year between 2025 and 2030.
This is not a gradual alteration to Britain’s electricity system.
It is a simultaneous reconstruction of generation, transmission, storage, system operation and consumer behaviour.
New offshore wind farms must be financed, consented and constructed. Scottish power must be carried south. Hundreds of miles of new circuits must be completed. Existing lines must be uprated. New substations and converter stations must be commissioned. Batteries and other flexibility must materialise. Consumers and industry must alter when they use electricity.
Every part must move together.
The Government’s own plan admits that maintaining security will still require approximately 35 GW of unabated gas reserve capacity.
That figure destroys the illusion that wind, solar and batteries will independently guarantee winter security by 2030.
The system still needs almost an entire conventional gas fleet waiting behind the renewable system.Why?
Because wind and solar are sources of energy when the weather permits. They are not firm capacity that can be summoned whenever demand rises.
NESO agreed , but only under extraordinary conditions
The National Energy System Operator was asked to advise how Clean Power 2030 could be achieved.
NESO concluded that it was possible , but its conclusion came with conditions so demanding that they should have triggered a national reality check.
NESO said the right supply, demand, networks and flexibility would have to be delivered:“ simultaneously, in full and at maximum pace.
”It also said the challenge would require “prioritising pace over perfection.” Those are not reassuring statements.
They are warnings.
A programme that only works if dozens of interdependent components arrive simultaneously, in full and at unprecedented speed contains very little tolerance for failure.
A wind farm delay affects the utilisation of its connection.
A transmission delay increases curtailment.
A converter-station delay limits an offshore link.
A substation delay holds back several surrounding projects.
A missed outage window can move work into another year.
A shortage of transformers, switchgear, cable or specialist vessels can affect multiple schemes at once.
And winter does not wait for a project manager’s revised timetable.
The 50 per cent admission
Buried within NESO’s June 2026 technical report is perhaps the most important admission in the entire programme.
NESO defines a probable delivery date as: “This is the date an option has a 50% likelihood of being delivered by, taking account of delivery risks.” Those risks include supply-chain limitations, system access, planning and consenting. NESO describes this as providing a more realistic view of delivery.
50 per cent date does not mean a project has only a 50 per cent chance of ever being completed.
It means that, even after the known risks are considered, there remains an equal chance that it will arrive after that date.
That would be troubling enough.
But NESO goes further.Its technical report explains that the recommendations were based on deterministic earliest delivery dates supplied by the Transmission Owners.
Those are the theoretical dates at which projects could be delivered assuming delivery risks do not apply.
NESO also states that probabilistic dates were not required by the methodology and were therefore not supplied by every Transmission
Read that again.
The national investment recommendations were based on dates that assume away the very risks most likely to delay the programme:
supply-chain pressure;
access to the live electricity system;
planning;consenting;and construction delivery.
The more realistic P50 dates were incomplete.
And there is no publicly presented probability showing that every necessary component of an entire transmission corridor will be operational together.
That is the bombshell.
Britain is committing billions to an interconnected national programme without a complete, mandatory and integrated probability assessment showing that the full system can be delivered in sequence.
They designed the electrical destination first
The central failure can now be stated plainly:
They planned the electrical destination first and expected the land, engineering, consenting and construction programme to conform afterwards.
Strategic modelling identified where enormous quantities of electricity were expected to travel.
More wind would be generated in Scotland and the North Sea. Power would have to move south. Network boundaries would require greater transfer capacity. New circuits, converter stations and substations were inserted into the model.
The electrical picture looked coherent on the screen.
But high-level power-flow modelling cannot tell government whether:
a substation site has suitable geology;
a pylon foundation will sit safely in peat or unstable ground;
construction traffic can reach a remote location;
river, rail and road crossings are practical;
communities will accept the route;
protected habitats can be avoided;
specialist equipment can be manufactured in time;
or the necessary outages can be obtained on a live national network.
Those questions emerge through field investigations, detailed engineering, environmental assessment, procurement and construction planning.
Yet by the time many of those answers became available, political targets, regulatory dates and investment decisions were already in place.
NESO acknowledges that its analysis is ultimately informed by information supplied by the Transmission Owners. It also confirms that several projects already moving towards construction were not reassessed in its latest exercise.
This creates a dangerous baseline ratchet:
A project is selected using early assumptions.
It receives a political or regulatory delivery date.
Funding and procurement begin.
It becomes embedded in the future network baseline.
Later modelling assumes it exists.
Physical surveys force redesigns or delays.
The original strategic decision is rarely reopened.
The model begins to validate its own earlier assumptions.
Brinsworth–High Marnham:
a warning in South Yorkshire
The Brinsworth–Chesterfield–High Marnham reinforcement , known by its network code EDEU , shows how the process is operating.
EDEU is intended to upgrade approximately 65 kilometres of existing 275 kV overhead line to form a new 400 kV transmission spine between South Yorkshire and the East Midlands. Its regulatory delivery date remains 31 December 2029.
But the surrounding network develops much later and in stages.
The Brinsworth corridor connects northwards into Thorpe Marsh. Other routes extend towards Keadby, Drax, Eggborough and the wider northern system.
High Marnham is intended to become a major junction for further Humber and East Coast infrastructure.The line will not be useless in 2029. It can carry existing mixed generation and improve resilience.
The real question is whether it will deliver the full strategic benefit used to justify accelerated construction before all those adjoining and upstream reinforcements are complete.
Ofgem’s own EDEU consultation revealed that:
the forecast project cost had significantly increased since the original 2022 ASTI decision;
the early-construction request equalled 104 per cent of the original licence cost estimate, although it represented 25 per cent of the updated forecast cost;
required project works had changed;
additional land acquisition was needed;
and significant design changes had contributed to the increased forecast.
Ofgem also explained that early-construction funding exists precisely to permit activities before planning consents are obtained and the project is finalised. The requested expenditure included strategic land purchases, detailed design, ground investigations and early procurement of switchgear, transformers and conductors.
This is the process in plain sight.
The date comes first.
Money is then released to stop planning, design, land and procurement from making that date impossible.
Ofgem says the project could impose £220 million of constraint costs in 2030 if it is not delivered, based on NESO’s analysis.
Yet the public still deserves to see the full annual loading, directional-flow assumptions and project-specific benefit from 2029 through the later completion of the wider northern and East Coast network.
How much power is expected to enter at Brinsworth?
How much will enter High Marnham from the Humber?
How heavily will the corridor be used before the later Thorpe Marsh and Keadby works?
Where is the integrated critical path?
Those are not anti-grid questions.
They are elementary questions before imposing enormous costs and environmental consequences on communities.
The East Coast plan has already been substantially rewritten
The East Coast provides even stronger evidence.
The original Holistic Network Design envisaged one arrangement around Lincolnshire. That design did not survive contact with later system development.
Ofgem records that evolving system needs, increased demand, environmental factors and potential consenting challenges forced Transmission Owners to develop an alternative design.
The connection point for Eastern Green Links 3 and 4 moved from the proposed Lincolnshire Connection Node to a new Walpole substation in Norfolk.
The original South Humber–South Lincolnshire proposal became a much larger Grimsby–Walpole scheme involving approximately 140 kilometres of 400 kV overhead line and several substations.
That was not a minor route refinement.
It changed:the destination;the geography;the communities affected;the number of substations;the project interfaces;the cost;and the delivery programme.
The Transmission Owners’ risk analysis produced P50 dates in 2034. Ofgem ultimately adopted revised target arrangements materially later than the original 2030 ambition. It also accepted that EGL3 and EGL4 would need to be commissioned sequentially because simultaneous commissioning would create too much system-stability risk.
The strategic model originally saw two powerful new links transporting Scottish electricity south.
Detailed development later revealed that the landing point had to move, the onshore network had to be redesigned and the links could not safely be commissioned together.
That is the central thesis demonstrated in one project cluster:
The electrical destination was selected before the physical and operational route was sufficiently mature.
Scotland is slipping because the ground does not obey a computer model
Scotland is critical because much of the future electricity expected to feed the East Coast system is supposed to originate there.
But the Scottish network must first collect that power and move it towards the subsea links and English border.That requires enormous new onshore infrastructure across difficult landscapes.
The Beauly–Peterhead project originally included a major new 400 kV substation at Coachford. After detailed ground investigations identified technical challenges, SSEN removed the Coachford substation from the project scope.
substation that had appeared in plans, consultations and system architecture was removed because the selected ground could not support the intended scheme as expected.
Elsewhere, SSEN has confirmed that ground investigations undertaken after its 2023 consultation showed that the preferred route for the Blarghour connection could not be delivered as planned, forcing new route options and another consultation.
On the major Spittal–Loch Buidhe–Beauly 400 kV project, intrusive ground investigations began in August 2024 and are continuing throughout 2026. The work includes boreholes, trial pits and testing needed to understand conditions beneath prospective infrastructure.
Ground investigation during project development is normal.
What is not normal is treating politically essential completion dates as highly reliable while the investigations capable of changing alignments, foundations, access and cost remain incomplete.
The Scottish landscape is not an empty sheet.
Peat, rock, groundwater, roads, protected habitats, weather and community opposition do not rearrange themselves to fit a Whitehall deadline.
The winter problem remains exactly where it was
Even if every transmission project were delivered on time, Britain would still face the physical limits of weather-dependent generation.Solar cannot generate after sunset.
Britain’s winter demand peaks commonly occur during dark morning and evening periods. Adding tens of gigawatts of solar may increase annual output and provide useful summer and daytime electricity, but it does not create firm capacity for a cold January evening.
Wind is better aligned with winter than solar on average, but average output is not the same as guaranteed output.
A secure system must survive the difficult hours and days, not merely produce enough energy across an entire year.
NESO’s own Clean Power analysis says approximately 35 GW of unabated gas must remain on standby during prolonged periods of high demand and low renewable output, and that this requirement continues into the early 2030s. This is effectively an official admission that the renewable system cannot guarantee winter adequacy on its own.
Batteries can provide valuable rapid response, shift some energy across the day and support system stability.But capacity measured in gigawatts is not the same as stored energy measured in gigawatt-hours. A battery capable of supplying power for two or four hours is not a national reserve for a low-wind period lasting several days.
Interconnectors are useful, but Britain cannot assume that continental Europe will always have surplus electricity during a cold, still weather system affecting several countries simultaneously.
The real Clean Power architecture is therefore:Wind and solar for much of the annual energy; gas, imports, storage and managed demand for security when the weather fails.That is a far less comforting proposition than the public slogan.
Is the solar invasion a stopgap?
But the inference is becoming increasingly difficult to ignore.Offshore wind takes years to finance, consent, manufacture, install and connect.Major transmission lines can take even longer.Solar farms can often be developed more quickly. They can be placed near planned substations and existing distribution infrastructure. They add nameplate renewable capacity rapidly and help ministers claim progress towards the 2030 target.
The Government is aiming for 45–47 GW of solar by 2030, with policy documents suggesting the system might accommodate still more.
But solar cannot replace delayed Scottish wind.It cannot replace unfinished East Coast transmission.It cannot supply a dark winter evening.It cannot provide several days of stored energy.
And when numerous solar schemes cluster around the same regional network, they may create large simultaneous summer daytime exports while contributing very little at the time of the winter peak.
Solar may therefore be functioning as a political capacity bridge , something that can be installed quickly while the much harder offshore and transmission programme slips.That does not make every solar panel useless.It means the country risks confusing rapid installation with genuine system security.
This is beginning to resemble HS2
The comparison with HS2 is no longer exaggerated.
The two programmes are technically different, but the governance pattern is disturbingly familiar:
a politically attractive destination;
an ambitious timetable;
immature design assumptions;
early expenditure creating lock-in;
changing scope;
rising costs;
delayed benefits;
and increasing difficulty admitting that the original plan was unrealistic.
The National Audit Office reported in June 2026 that the estimated cost of completing the remaining HS2 programme had risen to between £87.7 billion and £102.7 billion, around double the 2020 estimate for Phase One. The scheme is smaller than originally planned while costing more and taking longer. By March 2026, £46.8 billion had already been spent, including expenditure associated with the cancelled Phase Two.
HS2’s physical incompleteness is visible.
The electricity programme’s incompleteness may be harder to see.
A substation can be energised.
A solar farm can export.
A cable can be connected.
A new circuit can carry some electricity.
Yet the whole system may still fail to provide the volume, direction, reliability or constraint savings used to justify the individual parts.
The public could therefore be paying simultaneously for:
renewable support;
new pylons and substations;
curtailed generation;
balancing interventions;
backup gas;
storage;
imports;
and infrastructure operating below its intended strategic capacity.
That would be an energy version of HS2—but hidden across network charges, balancing costs, contracts and electricity bills.
Who is responsible?
Responsibility must be assigned accurately.
The Climate Change Act
It created the binding emissions destination and the legal carbon-budget ratchet.
DESNZ and ministers
They selected the Clean Power 2030 acceleration, technology mix and scale of deployment.
Ed Miliband
As Energy Secretary from July 2024 to July 2026, he became the political face and driving force of the accelerated programme now moving through planning, regulation and construction.
It advised that the programme was achievable, despite saying that everything had to arrive simultaneously, in full and at maximum pace.
Transmission Owners
They supplied the reinforcement proposals, costs and delivery information used in the modelling.
Ofgem
It created and administered funding and incentive arrangements that allow strategic land acquisition, procurement and early works to proceed before final planning consent and complete cost assessment.
This is not one organisation’s mistake.
It is a chain of institutional responsibility.
The law created the pressure.
Ministers imposed the speed.
NESO modelled the required electrical destination.
Transmission companies designed the projects.
Ofgem released the money.
And the physical world is now revealing what the desktop plan failed to settle.
What must happen now
Britain needs an immediate independent critical-path audit of the complete electricity transition.
Not another glossy strategy.
Not another model showing where power might flow in an ideal future year.
A physical delivery audit.
It should require:
A mandatory P50 and P80 date for every major project
The public should see the dates associated with a 50 per cent and an 80 per cent probability of delivery , not merely the theoretical earliest date.
Corridor-level probability assessments
It is not enough to assess individual projects separately. Government must publish the probability that every necessary component of an entire Scotland–East Coast–Midlands corridor will be operational together.
Annual utilisation forecasts
For every major line, government should publish expected loading, direction of flow and benefit for each year following completion.
A winter firm-capacity test
Every future electricity pathway should demonstrate how demand will be met through a prolonged cold, low-wind period without relying on optimistic imports or consumer behaviour.
Reassessment of baseline projects
A scheme should not escape scrutiny simply because it was selected under an earlier plan and has already accumulated expenditure.
Full disclosure of contingency plans
What happens when an offshore wind farm is delayed?
What happens when a substation site fails?
What happens when a converter cannot be delivered?
What happens when adjoining projects miss their outage windows?
What replaces the expected electricity?
Who pays?
Until those questions are answered, communities should not be told that every pylon, solar development and substation is an unquestionable necessity.
The train has a destination—but the tracks are unfinished
This is not an argument against maintaining and modernising Britain’s electricity network.
It is an argument against rebuilding it backwards.
A responsible programme would have reconciled:generation;winter demand;firm capacity;network design;route feasibility;geology;planning;land;supply chain;system access;construction;and contingency
before committing the nation to an artificial political deadline.
Instead, Britain fixed the emissions destination, imposed the 2030 timetable and began committing money before the physical route had reached comparable maturity.
The result is an electricity programme whose own operator says success depends on everything arriving simultaneously and at maximum pace—while its more realistic project dates represent only a 50 per cent likelihood of completion by those dates.
That is not prudent national infrastructure planning.
It is a wager.
A wager made with our countryside, our electricity bills, our industrial future and our winter energy security.
Miliband’s train may have left the station.
But the evidence increasingly suggests that the tracks ahead were never completed.And Britain is rapidly approaching the point where political ambition meets physical reality.
Shane Oxer. Campaigner for fairer and affordable energy
SAY NO TO THE DESTRUCTION OF OUR LAND 
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