Progressive Energy Backs Bacton Offshore Hydrogen Storage as North Sea Congestion Grows
A new feasibility study adds hydrogen storage to a North Sea seabed already contested by wind, oil and gas, and carbon capture projects.
The North Sea Transition Authority said on July 30, 2026 that carbon capture and storage received a significant boost from an assessment, supported by DNV, showing that reuse of existing offshore assets could reduce capital expenditure and shorten project timelines for emerging CCUS chains. The announcement landed just weeks after Progressive Energy released a study during the week of July 6, 2026 backing its proposal for offshore hydrogen storage connected to the Bacton gas terminal on the Norfolk coast — putting two competing visions for the same subsurface geology on a collision course.5,4
Bacton is one of the UK's principal gas import and processing hubs. The logic behind Progressive Energy's proposal is that existing pipeline infrastructure and offshore geology near the terminal could support large-scale hydrogen storage without the full greenfield capital cost of building from scratch. No project timeline or capital figure has been published, so the study remains a feasibility-stage endorsement rather than a committed investment decision.4
The NSTA's finding on asset reuse carries implications beyond CCUS. If subsurface infrastructure cases become cheaper to prosecute, offshore storage projects of all kinds look more viable against onshore alternatives. But the same improvement in the economic case for reuse also increases competition for the best available geology near established coastal terminals.5
Eni illustrates the point directly. The company expects to unlock roughly 300 million metric tons of CO2 storage capacity at the depleted Hewett gas field in the North Sea, a figure disclosed in a company statement on September 15, 2023, tied to the Bacton licence award. Hewett sits close to Bacton geographically, and depleted field structures of that type are precisely the geology that hydrogen storage assessments also target. Whether Eni's CO2 plans and any Progressive Energy hydrogen project can coexist or will compete for the same pore space is not addressed in the available material.1
That ambiguity sits inside a broader spatial problem. Research from the University of Aberdeen, published in June 2026, found that multiple offshore sectors — oil and gas, offshore wind, and carbon capture and storage — are already caught in unresolved conflicts, and that competition for sea room is putting the UK's energy transition at risk. Hydrogen storage adds another claimant to that list.2
The financing side of subsea storage has shown some movement. The CCUS joint venture of Eni and BlackRock's Global Infrastructure Partners closed more than EUR 500 million in financing in late May 2026 from a pool of 13 international lenders. That deal covered CO2 storage, not hydrogen, but it demonstrates that project-finance appetite for subsea storage assets can materialise when regulatory and revenue structures are sufficiently defined.1
The regulatory position for hydrogen storage in the UK is not settled. Without a clear storage remuneration mechanism, feasibility studies do not easily convert into final investment decisions. The UK hydrogen storage pipeline has accumulated more studies than construction starts.
The contrast with battery storage is stark. During the week of July 6, 2026, the Planning Inspectorate overturned a local refusal to grant Harmony Energy consent for a 99.9 MW battery energy storage system near Heath in Wakefield. ESB Scotland separately secured Scottish government consent for its 502 MW High Netherfauld BESS in South Lanarkshire. NatPower UK opened a consultation on a 1 GW BESS at the Port of Southampton. These are not hydrogen projects, but their pace of progression illustrates how differently the two storage technologies are moving through planning and consent processes.4
A study reported by Montel in June 2026 added one further pressure point: EU ETS allowance prices could surge if CCS and hydrogen technologies develop more slowly than optimistic decarbonisation models assume. UK Carbon Allowances stood at £58.27 per tonne CO2 as of August 3, 2026. A prolonged delay in physical storage infrastructure keeps decarbonisation dependent on carbon pricing rather than abatement capacity, which tightens the allowance market and raises costs for emitters who cannot wait for hydrogen or CCS solutions to materialise.3
Progressive Energy's Bacton study faces a sequence of hurdles before it moves beyond analysis: spatial planning consent in a congested North Sea, a revenue framework that makes storage economics bankable, and a resolution of how hydrogen storage interacts with the CO2 storage licences already awarded in the same area. The NSTA's push to accelerate CCUS through asset reuse could open a pathway — or it could mean the most attractive geology near Bacton is already allocated before the hydrogen case is fully made.5,2