CCUS Clusters, Storage Geology and Business Models

Current CCUS Position

The procurement and contracting steps that have closed inside the last twelve to eighteen months set the chain mechanics. The East Coast Cluster on Teesside reached financial close on 10 December 2024 against a Transport and Storage Regulatory licence held by the Northern Endurance Partnership (NEP, a joint venture between BP, Equinor and TotalEnergies), with the Net Zero Teesside Power plant (a roughly 860 megawatt combined-cycle gas turbine with post-combustion capture, the anchor emitter on the Teesside leg) and the H2Teesside blue hydrogen production project taking final investment decision into 2025 and the first injection into the Endurance saline aquifer scheduled for late 2027 to early 2028.¹ HyNet North West reached financial close in parallel on the same December 2024 timetable, with the Eni-led Liverpool Bay Transport and Storage licence, the EET Hydrogen blue hydrogen project at Stanlow on the Mersey, and the Heidelberg Materials cement works at Padeswood in north Wales as the anchor capture sites; the Hamilton depleted gas field in Liverpool Bay is the storage destination.¹

Track 2 sits one step behind. Acorn at St Fergus in Aberdeenshire and Viking on the Humber were named in the Track 2 announcement of 17 July 2024 by the Secretary of State for Energy Security and Net Zero, and the cluster developers (Storegga and Shell for Acorn, Harbour Energy for Viking) are running front end engineering design through 2026 with a target for final investment decision in late 2026 and first injection in the 2028 to 2030 window.¹ The two Track 2 clusters together would add a further 18 to 20 megatonnes per year of nameplate capture and injection capacity by the early 2030s, on top of the roughly 8 to 10 megatonnes per year that the two Track 1 clusters will carry into the 2028 to 2029 commissioning year.

The statutory frame holding the procurement is the Energy Act 2023, which received Royal Assent on 26 October 2023.² Part 1 of the Act creates the four contract instruments and the economic licence that the four clusters operate against: the Industrial Carbon Capture (ICC) contract for the emitter, the Dispatchable Power Agreement (DPA) for the power-with-capture plant, the Hydrogen Production Business Model contract for the blue hydrogen producer, and the Transport and Storage Regulatory Licence (T and S Licence) for the cluster operator. The 20 billion pound, 20 year funding envelope announced in the March 2023 Strategic Vision underpins the strike-price headroom on each of those contracts; the Autumn 2024 Budget refresh on 30 October 2024 raised the envelope to 21.7 billion pounds over a 25 year horizon, front-loading roughly 3.9 billion pounds across the 2025 to 2029 spending review period so the Track 1 final investment decisions could close on the Government's revenue-support backing.¹

The data layer that lets a planner follow the cluster mechanics is moving in parallel. The North Sea Transition Authority maintains the Carbon Storage Licence register and the Storage Permit decisions for each offshore storage site, with public detail on the licensee, the reservoir, the planned injection rate and the monitoring obligations under the Energy Act 2008 Part 1 Chapter 3 as amended by the Energy Act 2023.¹ Ofgem administers the Transport and Storage economic regulation regime under a RIIO-style allowed-revenue framework adapted for first-of-a-kind cluster construction risk, with a Government Support Package (GSP) holding the construction-phase risk during the first three to five years and an allowed-revenue regime taking over once steady state operations begin. The Strategic Spatial Energy Plan that the Energy System Operator (NESO) is delivering in Q4 2026 includes the inter-cluster CO2 transport network as a candidate route for Track 3 sequencing, and the April 2026 Connections Reform Gate 2 outcomes have brought firm offers to several of the blue hydrogen and power-with-capture projects that anchor each cluster.³

The CCUS domain has a settled high-level architecture: four contracted instruments under Energy Act 2023 Part 1, a 21.7 billion pound funding envelope, two Track 1 clusters in construction and two Track 2 clusters in front end engineering design. The next load-bearing date is the Track 2 final investment decision window. Each layer is treated in turn.

The two Track 1 clusters: HyNet North West and the East Coast Cluster

Track 1 covers the two clusters that DESNZ named in the cluster sequencing decision of 4 October 2023, and that reached financial close on 10 December 2024 under the contract instruments set out in Energy Act 2023 Part 1. The two are HyNet North West, anchored on the Liverpool Bay industrial corridor across Cheshire and Merseyside, and the East Coast Cluster, anchored on Teesside and the Humber and operated by the Northern Endurance Partnership (NEP) joint venture of BP, Equinor and TotalEnergies. Each cluster combines a Transport and Storage licensee on a single economic licence, a set of anchor emitter sites holding Industrial Carbon Capture (ICC) contracts or Dispatchable Power Agreements (DPA), and a single offshore storage destination under a Storage Permit issued by the North Sea Transition Authority.¹

HyNet North West and the Liverpool Bay industrial corridor

HyNet North West runs from the Stanlow refinery and petrochemical complex on the south bank of the Mersey, through the Padeswood cement kiln in north Wales and the Encirc container-glass works at Elton on the south Mersey, north toward the Hamilton depleted gas field in Liverpool Bay. The Transport and Storage operator is Eni UK, with the existing Liverpool Bay gas-export pipeline being repurposed to carry dense-phase CO2 from the onshore manifold at Connah's Quay to the offshore platform at the Hamilton field. The anchor emitter on the blue-hydrogen leg is EET Hydrogen, an autothermal reformer at Stanlow producing roughly 350 megawatts of low-carbon hydrogen for nearby industrial offtakers; the anchor emitter on the industrial-capture leg is Heidelberg Materials at Padeswood, capturing roughly 0.8 megatonnes per year of CO2 from the cement-kiln calcination process. Hanson cement and Vertex Hydrogen sit in the second wave of HyNet capture sites under the Phase 2 build-out.

The East Coast Cluster, the Northern Endurance Partnership and the Endurance saline aquifer

The East Coast Cluster is the larger of the two Track 1 clusters by nameplate capture envelope. It splits geographically between Teesside (where Net Zero Teesside Power, a roughly 860 megawatt combined-cycle gas turbine with post-combustion capture under a Dispatchable Power Agreement, is the anchor; and where H2Teesside, a roughly 1.2 gigawatt blue hydrogen project led by BP, is the second anchor) and the Humber (where VPI Immingham, a combined heat and power plant; Phillips 66 Humber refinery; and Saltend Chemicals on the Yorkshire side, hosting a planned blue ammonia plant on the Equinor-led H2H Saltend project, are the anchors). The Northern Endurance Partnership operates the combined onshore and offshore Transport and Storage network, terminating at the Endurance saline aquifer roughly 145 kilometres offshore in the Southern North Sea. The Phase 1 build-out targets about 4 megatonnes per year of injection from the Teesside anchor by first commissioning in 2027 to 2028; the Phase 2 build-out adds the Humber emitters and a target of 23 megatonnes per year by the mid-2030s.¹

Both clusters share the same statutory anchor: Energy Act 2023 Part 1, with Royal Assent on 26 October 2023.² Chapter 1 of Part 1 created the carbon-capture revenue-support regime that funds the ICC and DPA contracts. Chapter 3 transferred the offshore Storage Permit regime wholly to the North Sea Transition Authority, amending the Energy Act 2008 sections 18 to 29. Chapter 4 created the Transport and Storage Revenue Support regime that funds the cluster operator under a RIIO-style economic licence administered by Ofgem. Chapter 5 mandates carbon-storage information and reservoir-sample sharing with NSTA. Chapter 6 created the Storage Termination regime that holds the post-closure stewardship liability with the operator for a defined number of years after injection ends, with the residual liability transferring to the Government under conditions set out in regulations.

The two Track 2 clusters: Acorn Scotland and Viking on the Humber

Track 2 covers Acorn Scotland and Viking. The Secretary of State for Energy Security and Net Zero confirmed the Track 2 selection on 17 July 2024, with negotiations on the Industrial Carbon Capture, Dispatchable Power Agreement and Transport and Storage Revenue Support contracts running through 2025 and 2026 toward a target final investment decision window of late 2026 and a first-injection window of 2028 to 2030.¹ The two Track 2 clusters together add the next 18 to 20 megatonnes per year of nameplate capture and injection capacity to the trajectory; they also bring a geographic balance to the cluster footprint, since Acorn is the only Scottish cluster and Viking sits on the south side of the Humber where Track 1's East Coast Cluster sits on the north side.

Acorn Scotland and the St Fergus gas-terminal complex

Acorn is built around the St Fergus gas terminal complex in Aberdeenshire, where the FUKA, SAGE and Vesterled pipelines bring North Sea gas onshore. The Transport and Storage licensee is Storegga, leading a joint venture with Shell and Harbour Energy. The CO2 is captured at the Peterhead Power Station (an SSE Thermal CCGT-plus-capture project) and at the St Fergus gas-processing terminals themselves, conditioned onshore at St Fergus, and exported offshore through the depleted Goldeneye gas field in the Outer Moray Firth (operated by Shell to deplete in 2011). The strategic value of Acorn is twofold. First, it delivers geographical diversification of CCUS infrastructure away from the English east and west coasts. Second, the Feeder 10 pipeline from Grangemouth to St Fergus is under assessment for repurposing to carry industrial CO2 from the central-belt Scottish industrial cluster (Grangemouth refinery, Mossmorran chemical complex, Longannet decommissioned site) to the St Fergus terminal, opening a second anchor catchment for the cluster as it builds out.

Viking on the Humber and the LOGGS-area depleted gas fields

Viking, led by Harbour Energy with legacy ConocoPhillips assets, sits on the Lincolnshire side of the Humber and routes captured CO2 from VPI Immingham (a 1.2 gigawatt combined heat and power plant), the Phillips 66 Humber refinery and the regional Lincolnshire cement sites through a new onshore conditioning hub at Immingham and out to the Lincolnshire Offshore Gas Gathering System (LOGGS) area of the Southern North Sea, where the depleted Viking and adjacent Rotliegend Sandstone reservoirs hold the injected stream. The advantage of the LOGGS-area routing is the existing offshore infrastructure (the legacy gas-gathering manifold and platforms), which reduces the new-build subsea capital cost compared to a greenfield aquifer development. The disadvantage is that Track 2 final investment decision sits on the same calendar window as the Track 1 build-out, so the supply-chain pinch (subsea pipe-laying vessel days, capture-equipment fabrication slots) is one of the live programme risks for the cluster.

Read together, the four cluster footprints show that the geographic dispersion is strong (two on the Liverpool-Mersey side, one on Teesside, two on the Humber across both Track 1 East Coast Cluster and Track 2 Viking, and one on the Aberdeenshire coast), the reservoir dispersion is balanced (three depleted gas fields, one saline aquifer), and the anchor-emitter type dispersion is wide (refineries, cement kilns, combined-cycle power, combined heat and power, blue hydrogen production, gas processing). The cluster model deliberately groups dissimilar emitters around a single Transport and Storage operator so the offshore investment can amortise across a wider tonne-per-year envelope than any single emitter could underwrite alone.

The Transport and Storage business model and the economic licence under the Energy Act 2023 Part 1

The Transport and Storage business model is the financing innovation that makes the cluster approach to CCUS bankable in Great Britain. A first-of-a-kind cluster build sits in the awkward space between a utility-style regulated asset (long-dated, low cost of capital, allowed-revenue regulation) and an oil-and-gas-style project finance asset (shorter-dated, higher cost of capital, market-revenue exposure). Neither model on its own clears the threshold for an investable transaction. The Energy Act 2023 Part 1 Chapter 4 created the Transport and Storage Revenue Support regime to bridge the two: a RIIO-style allowed-revenue licence administered by Ofgem against a regulatory asset base, but with a Government Support Package during the construction-phase build years that holds the first-of-a-kind risk the private operator cannot price.²

The four contract instruments and the revenue chain

Four contract instruments sit underneath the cluster. The Industrial Carbon Capture (ICC) contract pays the emitter a pence-per-tonne strike for the captured volume, indexed to the costs of the capture, conditioning and connection equipment. The Dispatchable Power Agreement (DPA) pays the power-with-capture plant a capacity-style payment plus a strike against the merit-order wholesale dispatch, designed so the CCGT-with-capture clears the market against an unabated reference plant on a level emissions-adjusted basis. The Hydrogen Production Business Model (HPBM) contract pays the blue hydrogen producer a strike against a reference price benchmark for low-carbon hydrogen offtake. The Transport and Storage Revenue Support contract pays the T and S Licensee an allowed-revenue stream against the regulatory asset base of the onshore and offshore pipelines and the offshore storage well infrastructure. All four contracts are held by the Low Carbon Contracts Company Limited as counterparty, with the funding flowing back to consumers through a supplier-obligation pass-through to electricity and (for the Hydrogen Production Business Model) gas-shipper bills.

The Government Support Package and the steady-state allowed-revenue regime

The Government Support Package wraps the construction phase. It comprises a Discretionary Reward and Penalty regime (DRP) against defined construction milestones, a Volume Underwriting mechanism that protects against under-utilisation during the first years of operation (when the emitter ramp profile is being established), and a Termination Compensation backstop that pays the licensee a defined value if the Government withdraws the licence outside the agreed regulatory framework. Once the cluster enters steady state operation (typically 3 to 5 years after first commissioning, when the emitter base has reached its committed throughput), the GSP tapers and the Ofgem allowed-revenue regime takes full effect. The allowed revenue is calculated against the regulatory asset base on a real-terms basis at a regulated cost of capital, with operating expenditure recovered against a totex allowance and incentive payments tied to availability, throughput and monitoring performance.²

The Special Administration Regime and the post-closure stewardship

Two further mechanisms hold the long-dated risk on the cluster. The Special Administration Regime (SAR), set out in the Energy Act 2023 Part 1, applies as a fall-back if the T and S Licensee enters insolvency or otherwise cannot continue to operate. Under SAR a court-appointed Special Administrator runs the licensee through to a transfer of the assets to a successor operator, holding service continuity for the connected emitters during the transition. The Storage Termination Regulations under Chapter 6 hold the post-closure stewardship liability with the operator for a defined number of years after injection ends, with the residual liability transferring to the Crown under conditions set out in regulations once the post-closure monitoring period is complete. The Decommissioning Regulations under Chapter 7 mirror the oil-and-gas decommissioning regime for the offshore CCUS infrastructure on the United Kingdom Continental Shelf.

The offshore storage geology: depleted gas fields and saline aquifers in the Bunter Sandstone

Two geological reservoir types carry the injected CO2 across the four clusters. Depleted offshore gas fields hold the Hamilton storage destination (Track 1, HyNet), the Goldeneye storage destination (Track 2, Acorn) and the Viking storage destinations (Track 2, Viking). Saline aquifers hold the Endurance storage destination (Track 1, East Coast Cluster). Each geology has a distinct sequence of advantages and constraints, and the cluster operators chose between them on a project-by-project basis based on capacity, proximity, reservoir characterisation cost and existing infrastructure availability.

Depleted gas fields and the cap-rock argument

A depleted offshore gas field has held natural gas under high pressure for tens of millions of years before its production life began. The cap rock above the reservoir (typically a low-permeability mudstone or salt layer) is therefore a proven seal: it has demonstrated, on geological timescales, that it can hold a buoyant gas-phase fluid in place. When the field is depleted (its gas-bearing pore volume drawn down to a low residual pressure), it offers a known reservoir geometry, known porosity and permeability, a network of wells already drilled and characterised, and an offshore platform and pipeline infrastructure that can be repurposed for CO2 import and injection. The Hamilton field operated by Eni UK in Liverpool Bay, the Goldeneye field operated by Shell in the Outer Moray Firth, and the cluster of Rotliegend Sandstone fields in the Lincolnshire Offshore Gas Gathering System area all sit in this category. The cost advantage of repurposing an existing offshore asset can be substantial relative to a greenfield aquifer development; the constraint is capacity, since a depleted reservoir holds a known and bounded pore volume.

Saline aquifers and the Bunter Sandstone formation

A saline aquifer is a porous and permeable sandstone formation that has never held hydrocarbon, but instead carries brine (sodium-chloride-rich pore water of marine origin). The advantage of the saline aquifer is capacity: a single regional aquifer can hold an order of magnitude more pore volume than a single depleted gas field, with the Bunter Sandstone Formation in the Southern North Sea alone assessed at several billion tonnes of theoretical storage capacity. The constraint is characterisation: the cap-rock integrity needs to be established by appraisal drilling rather than inferred from a production history; the structural closure that traps the buoyant CO2 plume needs three-dimensional seismic mapping; and the well infrastructure has to be drilled and equipped from scratch. The Endurance saline aquifer in the Bunter Sandstone, operated by the Northern Endurance Partnership about 145 kilometres offshore east of Teesside, is the lead Great Britain example. The Phase 1 development targets about 450 megatonnes of storage capacity; the regional Bunter Sandstone holds an order of magnitude more across other appraisal blocks that further sequencing rounds may bring forward.

The reservoir engineering: dense-phase injection, plume migration and well-bore integrity

The injected CO2 sits in the reservoir as a dense-phase fluid (above the critical pressure of 73.8 bar and the critical temperature of 31.1 degrees Celsius, so behaving as a high-density supercritical fluid rather than a gas or a liquid). At the depths typical of the Great Britain offshore reservoirs (about 1,000 to 2,500 metres below the seabed), the in-situ pressure and temperature put the CO2 well into the supercritical envelope. The buoyancy of the dense-phase plume relative to the displaced brine drives an upward migration to the cap rock, where the structural closure traps it. The monitoring obligation under the Storage Permit covers three concentric layers: reservoir-level seismic monitoring (four-dimensional seismic surveys at a defined cadence to track plume extent), well-bore integrity monitoring (distributed temperature and acoustic sensing on the injection wells), and surface monitoring (atmospheric and seabed sampling for any potential leakage indicator). The Monitoring, Reporting and Verification (MRV) requirements run from first injection through the post-closure stewardship period.

Industrial decarbonisation use cases: cement, chemicals, refineries, blue hydrogen

The capture side of the cluster chain serves a specific set of industrial sectors that have no economically competitive electrification path to net zero. Cement, lime, chemicals, refineries and combined heat and power plants in industrial clusters all produce concentrated streams of CO2 from either a calcination process (cement and lime), a combustion process (refineries, CHP) or a steam-methane reforming or autothermal reforming process (blue hydrogen production). For each of these the alternative to capture-and-storage is either a transformation of the underlying chemistry (which is not yet at scale for cement clinker or refinery hydrocracker hydrogen) or an offset purchase (which does not reduce the emission at source). Industrial decarbonisation is therefore the load-bearing decarbonisation case that the cluster model is designed to serve.

Cement and lime: the calcination CO2 that nothing else can decarbonise

Roughly 60 percent of the CO2 from a cement kiln is process emission from the calcination of calcium carbonate (limestone) to calcium oxide and CO2; the remaining 40 percent is fuel emission from the kiln combustion. The process emission is unavoidable in the chemistry of Portland cement production, so even a switch to fully zero-carbon kiln fuel (hydrogen, biomass, electrified heat) leaves the calcination CO2 in place. Capture is the only decarbonisation option for that residual. Heidelberg Materials at Padeswood in north Wales (the HyNet cluster anchor for cement capture) and Hanson cement (HyNet Phase 2) are the lead Great Britain examples. The capture cost band on cement and lime sits at the upper end of the industrial range, at about 80 to 160 pounds per tonne of CO2 captured at the kiln gate, because the flue-gas concentration is typically lower than at a refinery and the capture equipment retrofit competes against the kiln's existing process layout for space and integration.

Chemicals, refineries and combined heat and power

Refineries (such as the EET Stanlow refinery on the Mersey, the Phillips 66 Humber refinery, and the INEOS Grangemouth refinery in Scotland) produce CO2 from process furnaces, hydrogen production for hydrocracking, and combustion plant. Chemicals plants (Saltend Chemicals on the Humber, Vertex Hydrogen on the Mersey, the Mossmorran complex in Fife) produce concentrated streams from ammonia synthesis, ethylene cracking and steam-methane reforming. Combined heat and power plants serving industrial estates (VPI Immingham, Drax CCGTs) produce flue-gas CO2 from natural-gas combustion. For each sector the capture cost band sits in the 70 to 110 pounds per tonne range at the gate, lower than the cement band because the flue-gas streams are more concentrated and the integration footprint is more flexible.

Blue hydrogen and the cross-link to the hydrogen production pathway

Blue hydrogen production (steam-methane reforming or autothermal reforming of natural gas, paired with capture of the process CO2 stream from the reformer) is the largest single anchor for two of the four clusters: HyNet (EET Hydrogen at Stanlow, about 350 megawatts of low-carbon hydrogen production) and East Coast Cluster (H2Teesside, about 1.2 gigawatts; H2H Saltend, about 600 megawatts on the Humber side). The capture rate on a modern autothermal reformer is typically 95 to 99 percent because the CO2 is delivered as a concentrated stream from the reformer shift reaction rather than as a dilute flue-gas stream. The capture cost band on blue hydrogen sits at the lower end of the industrial range, at about 50 to 80 pounds per tonne of CO2 captured, because the reformer is designed around the capture-ready process layout from the outset. The cross-vector implication is that blue hydrogen acts as a hub for the cluster: it consumes natural gas at scale (a load on the National Transmission System), it produces low-carbon hydrogen for industrial offtakers within the cluster (a substitute for grey hydrogen), and it produces a concentrated CO2 stream for the Transport and Storage operator (a feedstock for the offshore injection). The Hydrogen Production Business Model contract under Energy Act 2023 Part 1 Chapter 2 is the funding instrument; the wider hydrogen production pathway is laid out elsewhere in this workspace.

Reading the four cluster footprints against the industrial sector list shows the deliberate design of the cluster model. Each cluster aggregates a wide enough set of anchor emitters that the Transport and Storage operator's investment can amortise across a diverse tonne-per-year envelope, with no single anchor able to bring down the whole cluster economics if a delivery slips. Cement at Padeswood, refinery at Stanlow, blue hydrogen at Stanlow, glass at Elton and CHP at the Mersey industrial estates together hold the HyNet envelope. CCGT-with-capture at Teesside, blue hydrogen at Teesside, refinery at Humber, ammonia at Saltend and CHP at Immingham together hold the East Coast Cluster envelope. The connections-side anchor for several of the larger emitter projects came in via the April 2026 NESO Connections Reform Gate 2 outcomes, which brought 283 gigawatts of generation and storage and 99 gigawatts of demand to firm offers across the two delivery phases.³

The 20 billion pound, 20 year funding envelope under the 2023 Strategic Vision

The headline funding commitment that holds the cluster procurement together is the 20 billion pound, 20 year envelope set out in the March 2023 Strategic Vision for CCUS, published by the Department for Energy Security and Net Zero (DESNZ) under the then Secretary of State Grant Shapps. The envelope was committed across the four contract instruments under Energy Act 2023 Part 1 (the ICC, the DPA, the Hydrogen Production Business Model and the Transport and Storage Revenue Support) for the period running from the first Track 1 final investment decision in 2024 to the back end of the 2040s. The headline number set the size of the strike-price headroom and the construction-phase Government Support Package that the Track 1 and Track 2 negotiations were drawn against.¹

The Autumn 2024 Budget refresh to 21.7 billion pounds over 25 years

The Chancellor of the Exchequer, Rachel Reeves, refreshed the envelope on 4 October 2024 to a 21.7 billion pound commitment over a 25 year horizon, with the Autumn Budget of 30 October 2024 confirming the figure and front-loading approximately 3.9 billion pounds across the 2025 to 2029 spending review period. The refresh did three things in practice. It enabled the Track 1 final investment decisions to close on the December 2024 timetable that the cluster developers had been working against. It signalled continued cross-party commitment to the cluster approach through the 2025 to 2030 build-out phase. And it raised the per-year headroom for further sequencing rounds (Track 3 and beyond) by extending the funding tail from 2043 to 2048.

The supplier-obligation route to consumer bills

The funding flows through the Low Carbon Contracts Company Limited (LCCC) as the contract counterparty, then back to consumers through a supplier-obligation pass-through on electricity bills (for the Dispatchable Power Agreement and the Transport and Storage Revenue Support) and on gas-shipper bills (for the Hydrogen Production Business Model under the Hydrogen Levy regime created by Energy Act 2023 Part 1 Chapter 2). The Industrial Carbon Capture contract is funded from general taxation rather than a supplier-obligation route. The split reflects the underlying logic that the captured CO2 from a power-with-capture plant or a blue hydrogen producer is intrinsically tied to the electricity or gas system, and so the supplier-obligation route makes the funding chain visible on the bill, while the captured CO2 from a cement kiln or a chemicals plant is a process-emission decarbonisation that the wider economy benefits from and so the general-taxation route is the appropriate funding source.

The funding envelope shows that the headline number gave the Track 1 negotiations the ceiling they needed to close on the December 2024 timetable, and the Autumn 2024 refresh raised the ceiling far enough that the Track 2 final investment decisions in late 2026 have headroom in the envelope as well. The remaining question is whether the trajectory through the 2030s holds the additional clusters and the additional capacity that the 20 to 30 megatonnes per year target needs by the back end of the decade. The trajectory toward Track 3 sequencing is the next load-bearing decision; the Strategic Spatial Energy Plan delivery in Q4 2026 is the first publication that will sequence the candidate inter-cluster routes and the candidate further storage destinations.

Cross-vector implications for hydrogen and the National Transmission System

The CCUS chain does not sit in isolation. Two cross-vector implications follow from the cluster footprint and the contract architecture, and each one is covered in detail elsewhere in this workspace.

The blue hydrogen pathway and the hydrogen pillar

Blue hydrogen production sits as the largest single anchor on two of the four clusters and as a meaningful anchor on the other two. The Hydrogen Production Business Model contract under Energy Act 2023 Part 1 Chapter 2 is the funding instrument; the EET Hydrogen project at Stanlow on the Mersey, the H2Teesside project on Teesside, the H2H Saltend project on the Humber and the Peterhead Hydrogen project at St Fergus are the lead Great Britain blue hydrogen anchors. Each project is paired with a Transport and Storage Licensee that takes the captured CO2 to the offshore storage destination, and each project is funded under a contract counterparty (Low Carbon Contracts Company Limited) that mirrors the Dispatchable Power Agreement structure for power-with-capture. The wider hydrogen production pathway (including green hydrogen production from electrolysis under the Hydrogen Allocation Round programme, the FutureGrid and H100 Fife distribution-grid blending evidence base, the storage and pipeline questions for hydrogen delivery, and the 2026 strategic decision on hydrogen for heating) is laid out in detail at Hydrogen.²

The National Transmission System implications and the gas pillar

Blue hydrogen production at scale consumes natural gas at scale, and the four cluster anchor sites are connected into the National Transmission System (NTS) operated by National Gas Transmission. The Stanlow cluster on the Mersey draws from the Point of Ayr offtake and the Cheshire compressor stations. The Teesside cluster draws from the Teesside offtake on the NTS spine. The Humber cluster draws from the Easington terminal on the Norwegian Langeled pipeline and from the Humber-side offtakes on the NTS. The St Fergus cluster draws gas at the terminal itself, where the FUKA, SAGE and Vesterled pipelines bring North Sea gas onshore. The combined incremental gas-demand load from the Track 1 and Track 2 blue hydrogen projects, once all four clusters are running, is in the range of 5 to 9 billion cubic metres per year, against a current annual NTS throughput of about 70 to 75 billion cubic metres on a 2024 baseline. The NTS spine has the headroom to carry the load, but the question of how the increment competes against the falling domestic-heating gas demand, the rising blending-pathway demand and the constrained import flexibility through the eight entry terminals is one of the sequencing issues that the Strategic Spatial Energy Plan is working through. The NTS layout, the entry-terminal mix, the daily flow pattern and the wholesale-market mechanics of the National Balancing Point are laid out in detail at Gas.³

The connections-side anchor for the power-with-capture plants

The CCGT-with-capture plants that anchor several of the cluster Dispatchable Power Agreement contracts (Net Zero Teesside Power on the East Coast Cluster, Peterhead Power on Acorn, with further power-with-capture projects in the Track 2 negotiation set) connect into the transmission network at the 132 kilovolt and 275 kilovolt boundary tiers operated by the transmission owners. The grid connection step is the slowest item on the project critical path for each of the power-with-capture anchors, and the April 2026 NESO Connections Reform Gate 2 outcomes brought firm offers to several of the anchor projects across the two delivery phases. The wider connections pattern sits inside the network pillar of this workspace.³