A modern industrial hydrogen and chemical processing plant with distillation columns, storage vessels and pipework under a blue sky
A modern processing plant of the kind that produces hydrogen at industrial scale, with reforming columns, storage vessels and pipework. The colour label on the hydrogen describes the production route and the upstream emissions, not the molecule. Photo: Pexels

Hydrogen Pathways, Blending Limits and Business Models

Hydrogen is the same molecule whatever colour label is attached to it. The label describes the production route and upstream emissions. The practical questions are what energy source makes it, what it costs at the gate, whether the gas network can accept it inside the Wobbe Index limits, and which business model pays for production, transport or storage.

Scope: production pathways, blending limits, transport and storage business models and the demand cases that can justify hydrogen.

Sources and standards

Every regulatory and quantitative claim resolves to either a primary publication from DESNZ, Ofgem or NESO, a statutory instrument on legislation.gov.uk (the Energy Act 2023, the Gas Safety (Management) Regulations 1996, the Pipelines Safety Regulations 1996), an international standard (BS EN ISO 14687 purity grades, BS ISO 22734 electrolysers), or operational data from National Gas (linepack and Wobbe).

Current Hydrogen Position

Hydrogen sits in an awkward position. As a quantity of energy flowing through the system it is small: the total electrolytic capacity supported by the Hydrogen Allocation Round 1 contracts signed at the end of 2023 is around 125 megawatts of input power, and the shortlist envelope for Hydrogen Allocation Round 2 is 875 megawatts.1 A 10 gigawatt by 2030 ambition was set out in the British Energy Security Strategy of April 2022 and the 5 gigawatt electrolytic floor was carried into the Energy Act 2023, but the project pipeline that has actually reached contract is two orders of magnitude smaller than the gas system that hydrogen is sometimes asked to displace. As a question in policy terms hydrogen is larger than the megawatts suggest, because the strategic decision on whether hydrogen has a role in domestic heat (deferred from 2022 to 2026) is still pending and because the production, transport and storage business models created by Part 2 of the Energy Act 2023 were a substantial piece of new statute that have to clear their first allocation rounds before the framework is tested at scale.

The framework is settled. DESNZ has the policy lead and signs the production contracts through the Low Carbon Contracts Company; Ofgem regulates the transport and storage routes; the Health and Safety Executive holds the safety case for pipework, valves and combustion equipment; and the Energy Act 2023 Part 2 Chapter 1 carries the four enabling statutory provisions (the Hydrogen Production Business Model, the Hydrogen Transport Business Model, the Hydrogen Storage Business Model, and the Hydrogen Levy that funds them).1 The Low Carbon Hydrogen Standard sets the emissions test at twenty grams of carbon dioxide equivalent per megajoule of hydrogen on a well-to-gate basis, and that test is what decides whether a project qualifies for support. The Wobbe Index sets the combustion test that decides whether hydrogen can be blended into the National Transmission System or a downstream distribution network without changing every appliance behind it.

The cluster geography is set. The HyNet cluster around the Mersey, the East Coast Cluster centred on Teesside and the Humber, the Acorn cluster in Aberdeen, and the Viking cluster on the South Humber bank are the four locations where production, transport and storage can be procured together with the carbon capture that the blue route depends on. The first H100 Fife trial of a 100 percent green-hydrogen distribution network began supplying around 300 homes in Levenmouth on 31 October 2025, replacing natural gas through 8.4 kilometres of polyethylene pipe from a 5 megawatt electrolyser owned by SGN. The earlier village trials at Whitby and Redcar were withdrawn before commissioning, so H100 Fife is the only live evidence base from which the heating decision can be drawn.

The strategic plan that holds the sequence together is the Strategic Spatial Energy Plan, with first iteration due in Q4 2026 from NESO with DESNZ, and the Centralised Strategic Network Plan, whose methodology Ofgem approved in April 2026 with first delivery due by the end of 2028.2 3 Both treat hydrogen alongside electricity, gas, heat and carbon capture as one whole-system question; the days of hydrogen being planned on a separate page from the electricity grid are behind us. The Long Term Development Statement published its Stage 2 on 29 May 2026 under the third derogation letter of 13 May 2026, which moves the distribution-network model anyone can plan against onto a validated machine-readable footing.4 Connections Reform Gate 2 detailed results in April 2026 took 283 gigawatts of generation and storage and 99 gigawatts of demand to firm offers across the Phase 1 to 2030 and Phase 2 to 2035 cohorts; the renewable connections that the green hydrogen route depends on for additional electricity sit inside that pipeline.6

The current position is a settled framework, a contracted pipeline an order of magnitude smaller than the 2030 ambition, one live village trial, three industrial clusters at financial close, and the strategic heating decision still to come. The pathway sections below explain the choices the framework is paying for.

The three Great Britain hydrogen production pathways compared on input, output, emissions, cost at the gate and suitability for gas-network blending

The pathway comparator below is drawn from the DESNZ Low Carbon Hydrogen Standard version three (December 2023) and the DESNZ Hydrogen Production Cost Update (December 2023), with the Wobbe Index column reading off BS EN 437 and the Gas Safety (Management) Regulations 1996 Schedule 3 as the primary source. Each column lists the input, the process, the output, the emissions in kilograms of carbon dioxide per kilogram of hydrogen, the levelised cost at the gate in pounds per kilogram, the Wobbe Index implication for blending into the National Transmission System, and whether the route passes the Low Carbon Hydrogen Standard threshold of twenty grams per megajoule.

The three hydrogen production pathways compared on input, process, output, emissions, cost at the gate, Wobbe Index implication and Low Carbon Hydrogen Standard test A horizontal layout of three coloured columns across the page representing the green, blue and pink production pathways. The green column on the left covers electrolysis from renewable electricity with about fifty one kilowatt hours per kilogram of hydrogen, near zero direct carbon emissions, a levelised cost at the gate of around four pounds eighty per kilogram, a Wobbe Index near forty eight megajoules per cubic metre which sits at the lower bound of the natural gas window, and a clear Low Carbon Hydrogen Standard pass. The blue column in the middle covers steam methane reforming or auto-thermal reforming with carbon capture at ninety to ninety five percent capture, one to three kilograms of carbon dioxide per kilogram of hydrogen depending on upstream methane leakage, a levelised cost at the gate around two pounds ten per kilogram and a typical pass on the standard, with the same low Wobbe Index because the molecule is identical. The pink column on the right covers electrolysis from nuclear electricity, near zero direct carbon emissions, a levelised cost in the four to six pounds per kilogram range and a pass on the standard in principle though no live commercial Great Britain production exists today. Three pathways to the same molecule; three very different upstream stories Green hydrogen Electrolysis from renewable electricity Input Water and renewable electricity About 51 kWh per kg at PEM efficiency Process PEM, AEM or alkaline electrolyser Stack splits H2O to H2 and O2 Emissions kg CO2 per kg H2 about 0 Direct; PPA scope Cost at the gate about 4.80 GBP per kg HAR1 weighted strike near 241 per MWh Wobbe Index for blending Pure H2 about 48 MJ per cubic metre At lower bound of NTS 47.20 to 51.41 window Low Carbon Hydrogen Standard PASS Blue hydrogen Steam methane reforming with CCUS Input Natural gas, steam and oxygen CCUS pipeline to permanent store Process SMR or ATR plus water-gas shift CO2 capture at 90 to 95 percent Emissions kg CO2 per kg H2 1 to 3 After capture; varies Cost at the gate about 2.10 GBP per kg DESNZ cost update Dec 2023, central Wobbe Index for blending Same molecule; about 48 MJ per cubic metre Identical limit to green for NTS blending Low Carbon Hydrogen Standard PASS (typical) Pink hydrogen Electrolysis from nuclear electricity Input Water and nuclear electricity Base-load power source; high load factor Process Same electrolyser families as green SOEC option uses reactor heat (HTSE) Emissions kg CO2 per kg H2 about 0 Direct; lifecycle low Cost at the gate about 4 to 6 GBP per kg Modelled; no commercial GB production Wobbe Index for blending Same molecule; about 48 MJ per cubic metre Identical limit; sourced from nuclear bus Low Carbon Hydrogen Standard PASS (in principle)

The three pathways produce identical hydrogen at the burner tip. What separates them is the carbon footprint of the electricity or feedstock that drives the conversion, and the cost of that input. Blue hydrogen is the cheapest at the gate today because the natural-gas feedstock is mature and the carbon-capture step has been engineered at refinery scale for forty years; green hydrogen carries the lowest residual emissions but pays the renewable-electricity price; pink hydrogen carries the same near-zero emissions as green at a similar or higher cost because the nuclear bus has its own capacity charge.

The three production pathways: green, blue and pink

The colour labels are shorthand for the production route. The Low Carbon Hydrogen Standard does not name the colours; it names a single emissions threshold of twenty grams of carbon dioxide equivalent per megajoule of hydrogen on a well-to-gate basis. A project is either above or below the threshold. Green hydrogen sits well below it because the input electricity is renewable, but only when the renewable additionality, the temporal matching and the geographic correlation tests are all satisfied. Blue hydrogen can sit below the threshold when the carbon-capture rate is high (ninety percent and above) and the upstream methane leakage is small; both numbers have to be verified. Pink hydrogen sits below the threshold by construction because the input electricity is nuclear, but the Great Britain pipeline has no commercial pink project at scale today, only Sizewell B research scope. Grey hydrogen (unabated steam methane reforming) sits at nine to twelve kilograms of carbon dioxide per kilogram of hydrogen and sits an order of magnitude above the standard; the standard exists to keep grey hydrogen out of the support framework.1

The three sections below take each route through its inputs, its kit, its emissions arithmetic and its cost at the gate. The diagram above is the comparator; the sections that follow are the long form.

Green hydrogen: electrolysis from renewable electricity

Green hydrogen is produced by passing renewable electricity through water in an electrolyser. The cell splits the water molecule into hydrogen at the cathode and oxygen at the anode. The three electrolyser families that dominate the Great Britain project pipeline are alkaline (about sixty to sixty five percent efficient on a Lower Heating Value basis, fifty to fifty five kilowatt hours per kilogram of hydrogen, mature low-cost stacks), proton exchange membrane (PEM, about sixty five to seventy percent efficient, around fifty one kilowatt hours per kilogram, fast ramp, the dominant choice in the Hydrogen Allocation Round 1 portfolio), and solid oxide electrolyser cells (SOEC, about eighty percent efficient when paired with industrial waste heat at seven hundred to eight hundred degrees Celsius, around forty kilowatt hours per kilogram, pre-commercial at scale).

A modern industrial process building with steel access stairways and gantries under a clear blue sky
A green hydrogen plant houses its electrolyser stacks inside a process building like this one. The carbon footprint of the hydrogen depends on the carbon intensity of the renewable electricity feeding the cells. Photo: Pexels

The carbon footprint of green hydrogen depends entirely on the carbon intensity of the input electricity. A grid-average kilowatt hour in Great Britain in 2025 carried around one hundred and twenty grams of carbon dioxide per kilowatt hour; at fifty one kilowatt hours per kilogram of hydrogen that would translate to six kilograms of carbon dioxide per kilogram of hydrogen, which is above the Low Carbon Hydrogen Standard threshold. The standard therefore requires the renewable electricity to be additional (a Power Purchase Agreement attached to a specific renewable asset, not displacement of existing renewable energy from another use), temporally matched (hourly matching from 2030, monthly transitional), and geographically correlated (same Great Britain bidding zone). When those three tests are satisfied the renewable input is treated as zero-carbon and the hydrogen passes the standard.1

The cost at the gate sits around four pounds eighty per kilogram on the central case of the DESNZ Hydrogen Production Cost Update of December 2023; the Hydrogen Allocation Round 1 weighted strike price of around two hundred and forty one pounds per megawatt hour of hydrogen output is the closest the framework has come to a settled Great Britain market price. The 10 gigawatt by 2030 ambition translates to roughly a 2 gigawatts per round cadence across Hydrogen Allocation Rounds 1 to 4; the first round delivered around 125 megawatts, the second round shortlisted an 875 megawatt capacity envelope.1 The trajectory needs the per-round cadence to step up by about one and a half orders of magnitude from the first round to the fourth round if the ambition is to be reached on time.

The electrolyser families have different operational signatures. Alkaline stacks ramp slowly (minutes to hours from cold) and are the right answer for a flat, high-utilisation duty cycle paired with a large dedicated wind farm or a steady offtaker. PEM stacks ramp in seconds, follow renewable variability cleanly, and are the right answer for an electrolyser sized against a windy seaboard with hour-by-hour matching to a renewable PPA. SOEC stacks are highest efficiency but operate at high temperature, take longest to start and stop, and are the right answer for a co-located industrial site that can supply waste heat at six hundred degrees and above continuously.

Cross-link: green hydrogen production sits on the renewable connections pipeline progressed under Connections Reform Gate 2 in April 2026, and the electrolyser load shows up on the electricity demand side with a duty cycle shaped by the renewable input profile.

Blue hydrogen: steam methane reforming with CCUS

Blue hydrogen converts natural gas to hydrogen at refinery scale using one of two reforming processes (Steam Methane Reforming, SMR, or Auto-Thermal Reforming, ATR), and captures the carbon dioxide co-product for permanent storage through the CCUS pipeline. The reforming step itself is mature; refineries have produced hydrogen this way for fifty years as a feedstock for hydro-treating and ammonia production. What is new in the blue route is the carbon-capture step. ATR runs hotter than SMR, integrates oxygen rather than air on the reformer, and produces a more concentrated carbon dioxide stream which is easier and cheaper to capture; ATR is the preferred process for new blue-hydrogen projects coupled to CCUS, including HyNet HPP1 at Stanlow.

Large-diameter steel gas pipework with separator vessels and yellow valve handwheels across an industrial plant
Blue hydrogen reforms natural gas to hydrogen through pipework and pressure vessels like these. The reforming step is mature, while the carbon capture that lowers the emissions is the newer part of the route. Photo: Pexels

The Low Carbon Hydrogen Standard pass for blue hydrogen depends on two numbers. The first is the carbon-capture rate on the production plant. A ninety to ninety five percent capture rate is the design point for new ATR projects coupled to CCUS; a capture rate below ninety percent pushes the residual emissions above the standard. The second is the upstream methane leakage on the natural-gas supply chain that feeds the reformer. Methane is around eighty four times more potent than carbon dioxide as a greenhouse gas on a twenty year horizon (around thirty times on a hundred year horizon), so a leakage rate of even half a percent on the upstream supply chain can dominate the residual emissions. The standard requires operator-supplied methane leakage data with third-party verification; a UK Continental Shelf gas supply with one tenth of a percent leakage will sit close to one kilogram of carbon dioxide equivalent per kilogram of hydrogen, while a supply chain with one percent leakage can sit above three kilograms.1

The cost at the gate sits around two pounds ten per kilogram on the central case of the DESNZ Hydrogen Production Cost Update of December 2023, which is the cheapest of the three pathways at today's natural-gas prices because the reforming step is at refinery scale and the carbon-capture step pays a separate Transport and Storage charge that is allocated to the CCUS account rather than the hydrogen account. The four Great Britain blue-hydrogen projects in the pipeline (HyNet HPP1 at Stanlow, the East Coast Cluster bp H2Teesside, the Acorn cluster St Fergus, and the Viking cluster Immingham) all sit inside one of the four Track 1 or Track 2 CCUS clusters. A blue-hydrogen project not in a cluster has no transport-and-storage offtake for the captured carbon dioxide, and therefore cannot operate.

The economic case for blue hydrogen in Great Britain rests on the assumption that the captured carbon dioxide will be priced separately from the hydrogen. The producer pays a Transport and Storage charge to the CCUS network operator at a tariff set under the Transport and Storage Regulatory Model; the producer recovers the cost through the Low Carbon Hydrogen Agreement strike price; the consumer pays through the Hydrogen Levy on gas shippers. The architecture treats blue hydrogen and CCUS as two regulated industries with a contractual interface between them, rather than one bundled project; that separation is what allows the same CCUS infrastructure to serve industrial decarbonisation, power-sector decarbonisation under the Dispatchable Power Agreement and blue-hydrogen production from a single transport-and-storage backbone.

Cross-link: the carbon-capture step that makes blue hydrogen low-carbon is described in detail on the CCUS page, which covers the Track 1 and Track 2 cluster geography, the Transport and Storage Regulatory Model, and the residual emissions reporting framework.

Pink hydrogen: electrolysis from nuclear

Pink hydrogen uses the same electrolyser kit as green hydrogen, with the input electricity sourced from a nuclear reactor rather than a renewable asset. The carbon footprint of the input is close to zero on a lifecycle basis (around five to twelve grams of carbon dioxide per kilowatt hour on EDF and EPRI numbers), so pink hydrogen passes the Low Carbon Hydrogen Standard by construction. The renewable additionality test that complicates the green route does not apply to pink hydrogen, because the input electricity is dispatched from a single named asset on a take-or-pay basis. The temporal matching test is automatically satisfied because nuclear runs at a high load factor close to the electrolyser's twenty four hour duty cycle.

The economic case for pink hydrogen rests on two ideas. The first is that a nuclear reactor running at base load can dedicate part of its output to an electrolyser, generating hydrogen rather than selling all of its electricity onto the wholesale market; in periods of high renewable output and low wholesale prices, the hydrogen revenue can be higher than the electricity revenue. The second is that an SOEC electrolyser paired with the reactor's thermal output (a High Temperature Steam Electrolysis route, HTSE) can hit eighty percent efficiency on a Lower Heating Value basis, well above the alkaline and PEM families, because the high-temperature reactor heat provides part of the energy of dissociation directly. Pink hydrogen on HTSE is the highest-efficiency electrolytic route on paper.

There is no commercial pink hydrogen production in Great Britain today. The Wylfa site contract for three Rolls-Royce small modular reactors signed in April 2026 has hydrogen production as one of several potential offtake routes alongside electricity and process heat, with final investment decision expected in 2029 and in-service mid-2030s.7 EDF's research scope at Sizewell B includes electrolyser coupling but at a research scale only. The pink pathway is a planning option, not a near-term contracted route.

The reason the pink pathway is in the planning picture at all is the inter-system balancing argument. A renewable-heavy electricity system that meets a high decarbonisation target needs a firm low-carbon source of dispatchable energy for cold, still weeks. A nuclear-coupled electrolyser can store the surplus energy of windy weeks as hydrogen, dispatch the hydrogen as gas during still weeks, and ride out the lull on the molecule rather than on the electron. That argument is what keeps small modular reactors with hydrogen offtake in the Centralised Strategic Network Plan modelling alongside electrolytic hydrogen from wind.

Cross-link: the Great Britain nuclear fleet, the Wylfa SMR site contract, and the dispatchable base-load profile that pink hydrogen would draw from are covered on the nuclear page.

The Wobbe Index and the limit on gas-network blending

Hydrogen is a different fuel from natural gas. It burns with a higher flame speed, a different stoichiometric air requirement, and a much lower volumetric energy content. A burner designed for natural gas tuned to give a certain heat-release rate will give a different heat-release rate on hydrogen for the same valve opening; tuned incorrectly, it can flash back into the burner, leave the flame visible only as ultraviolet, or simply not produce enough heat to run a boiler. The single number that tells a gas-network operator whether a fuel will burn correctly through a given burner is the Wobbe Index.

The Wobbe Index, W, is defined as the gross calorific value of the fuel gas divided by the square root of its specific gravity relative to air:

W = CVgross / √(SGfuel / SGair)

The Wobbe Index has units of energy per volume (megajoules per cubic metre at standard temperature and pressure, MJ per m3). Two fuels with the same Wobbe Index will deliver the same heat-release rate through the same burner at the same supply pressure, even if their individual calorific values and specific gravities are different. Two fuels with different Wobbe Indices will deliver different heat-release rates; the burner is then either over-firing or under-firing, and the appliance is operating outside its design envelope.

The Great Britain natural gas system runs to a Wobbe Index window set by the Gas Safety (Management) Regulations 1996. Schedule 3 specifies a Wobbe Index between 47.20 and 51.41 MJ per m3 at the inlet to the National Transmission System and at the National Transmission System offtake to a downstream distribution network. The window is narrow because the appliance population behind the network was designed and tested against it; every domestic gas boiler, every industrial burner, every gas turbine connected to the network expects fuel within the window. A fuel outside the window cannot be put into the network without compromising safety or appliance performance.5

Pure hydrogen sits at a Wobbe Index of around 48 MJ per m3 on a gross calorific value basis. That number is inside the Gas Safety (Management) Regulations window. The arithmetic looks promising at first glance: a pure hydrogen feed would just clear the lower bound of the natural gas window. The catch is that the gross calorific value of hydrogen is much lower than natural gas (around 12 MJ per m3 versus 39 MJ per m3), and its specific gravity is much lower too (0.07 versus 0.6); both numbers move together in a way that keeps the Wobbe Index close to the natural-gas value but produces a fuel that flows three times the volume for the same heat content. The pipes have to carry more cubic metres per second; the burners have to swallow more cubic metres per second; the metering has to count more cubic metres per kilowatt hour. Every downstream component is sized for a much smaller volume flow at the same heat.

Worked example: Wobbe Index of a 20 percent hydrogen blend into the National Transmission System

Take a representative National Transmission System natural gas (Wobbe Index 49.5 MJ per m3, gross calorific value 39.0 MJ per m3, specific gravity 0.62) and blend in 20 percent hydrogen by volume. What is the resulting Wobbe Index, and does it sit inside the Gas Safety (Management) Regulations window?

The blended mixture's properties are weighted averages by volume. Gross calorific value of the blend (subscript b):

CVb = 0.80 · 39.0 + 0.20 · 12.0 = 31.2 + 2.4 = 33.6 MJ per m3

Specific gravity of the blend:

SGb = 0.80 · 0.62 + 0.20 · 0.07 = 0.496 + 0.014 = 0.510

Wobbe Index of the blend:

Wb = 33.6 / √0.510 = 33.6 / 0.714 = 47.06 MJ per m3

The blend sits at 47.06 MJ per m3, just below the 47.20 lower bound of the Gas Safety (Management) Regulations window. A 20 percent blend on a typical National Transmission System gas would breach the window by 0.14 MJ per m3, a 0.3 percent shortfall. The HyDeploy pilot programme used distribution-network gas with a different starting Wobbe Index that kept a 20 percent blend inside the equivalent distribution-side limits, but the National Transmission System case is tighter than the distribution case and a regulatory change to the lower bound would be needed to operate a 20 percent blend on the transmission system continuously.

Blending up to 20 percent under the HyDeploy pilots

The current statutory cap on hydrogen content in the National Transmission System is 0.1 mole percent under Schedule 3 of the Gas Safety (Management) Regulations 1996. That cap was set against an appliance population designed for natural gas with hydrogen present only as a trace impurity; the cap exists to keep the trace impurity from drifting upward into a range that the appliance population was not tested against. Lifting the cap requires either an amendment to the regulations or a derogation granted on a specific safety case. Neither is a small piece of work.

The HyDeploy programme ran two distribution-network trials between 2020 and 2023 that demonstrated up to 20 percent hydrogen by volume in a low-pressure distribution system. The first trial blended hydrogen into the closed gas network at Keele University (about 100 properties on a private wire of the same nominal pressure as a public distribution network). The second trial scaled to a public distribution network on the Winlaton estate near Gateshead (around 670 homes). Both trials operated under Health and Safety Executive exemptions that allowed the 20 percent blend in a bounded geography for a bounded period, and both produced evidence that domestic gas appliances on a natural-gas distribution network can run safely on a 20 percent hydrogen blend without modification. The headline finding from HyDeploy was that no boiler, cooker or fire required intervention to operate inside the 20 percent envelope; the burner adjustment that would have been needed below ten percent was not material between zero and twenty percent.

The strategic decision of December 2023 was supportive of up to 20 percent blending in the distribution networks subject to a full safety case, and the September 2025 Ofgem Uniform Network Code Derogation D0001 created the governance arrangement that would let blended gas be measured, settled and accounted for separately from natural gas. Neither of those steps lifted the 0.1 mole percent statutory cap; both prepared the ground for the cap to be lifted later. As at May 2026 the cap is still in force on the National Transmission System, and the HyDeploy 20 percent envelope is available only inside a project-specific safety case on a bounded distribution-network geography. The H100 Fife trial that went live on 31 October 2025 supplies 100 percent hydrogen on a dedicated polyethylene network, not blended hydrogen, so it sits outside the HyDeploy envelope entirely; it is a different demonstration question (whether a 100 percent hydrogen distribution network can be operated end to end, including appliance conversion) rather than a blending question.

The cross-link to the gas system is that the National Transmission System is a 7,600 kilometre high-pressure backbone that has to keep its Wobbe Index window across continuously varying input compositions. Hydrogen injection at one location propagates downstream through the network with a residence time of hours to days depending on flow patterns and linepack; the operator has to forecast where the hydrogen ends up, what blend ratio each offtake sees, and whether every downstream Wobbe Index remains inside the regulation window. Operating a National Transmission System with even small hydrogen percentages requires the same forecast-and-control discipline as operating the electricity system frequency response.5

The three Energy Act 2023 business models for hydrogen

The Energy Act 2023 received Royal Assent on 26 October 2023. Part 2 Chapter 1 of the Act created the statutory framework for revenue support to hydrogen producers, hydrogen transport infrastructure and hydrogen storage infrastructure. Three separate business models sit inside the Chapter, each with its own counterparty, its own contract length and its own funding route.1

SectionsSubjectMechanism
Sections 61 to 62Hydrogen transport revenue supportTransport business model contracts; Ofgem-regulated; cost-plus-return tariff structure on a regulated asset base
Sections 63 to 64Hydrogen storage revenue supportStorage business model contracts; Ofgem-regulated; floor-and-ceiling cap and collar on net revenue
Section 65Hydrogen production counterpartyDesignates the Low Carbon Contracts Company as the contractual counterparty for production support
Sections 66 to 67Low Carbon Hydrogen Agreement15-year strike-price contract between the producer and the Low Carbon Contracts Company on a Contract for Difference structure
Sections 69 to 72Hydrogen LevyFunding mechanism for the three business models; Gas Shipper Obligation chosen in January 2025 as the levy route
Sections 73 to 77Definitions and supplementary"Low carbon hydrogen", "qualifying offtake", "hydrogen production revenue support contract"

The three business models are sequenced in time. The production business model came first because the producers need a 15-year strike-price contract to take a final investment decision; it cleared its first allocation round in December 2023 and the second round is in shortlist as at April 2025 with awards expected in early 2026. The transport business model came second because the pipework cannot be built ahead of the production it carries; it is on a regulated-asset-base structure designed for the four cluster geographies. The storage business model came third because storage is needed at the inter-seasonal and strategic timescales rather than the intraday timescale of production-to-offtake; it is on a cap-and-collar structure that protects the operator from arbitrage shortfall in low-price years and shares upside with the consumer in high-price years.

The Hydrogen Production Business Model and the Low Carbon Hydrogen Agreement

The Hydrogen Production Business Model is the headline support mechanism. It pays a producer a strike price per megawatt hour of low-carbon hydrogen output for fifteen years under a Low Carbon Hydrogen Agreement signed with the Low Carbon Contracts Company. The structure mirrors the Contract for Difference used for renewable electricity: the producer is paid the difference between the strike price and a reference market price for hydrogen, with the difference clearing both ways (top-up when the market is below strike, payback when the market is above). The fifteen year contract length matches the typical economic life of an electrolyser stack at first replacement.

The strike price is set through a competitive allocation round administered by the Department for Energy Security and Net Zero. Hydrogen Allocation Round 1 results were announced on 14 December 2023 with eleven electrolytic projects awarded against a 250 megawatt capacity envelope, totalling around 125 megawatts of contracted capacity and a weighted strike price of around 241 pounds per megawatt hour of hydrogen output. Hydrogen Allocation Round 2 was launched on 19 December 2023 with an 875 megawatt envelope; the shortlist of 27 projects was published on 7 April 2025; final awards are expected in early 2026.1 Hydrogen Allocation Round 3 is in design as at May 2026 with a launch expected in the second half of 2026.

The Low Carbon Hydrogen Standard is the eligibility gate for the Low Carbon Hydrogen Agreement. Version three of the standard (December 2023) is the operative version. It sets the well-to-gate emissions threshold at 20 grams of carbon dioxide equivalent per megajoule of hydrogen on a Lower Heating Value basis, requires the renewable input electricity to be additional, requires temporal matching at hourly granularity from 2030 (monthly transitional), requires geographic correlation within the Great Britain bidding zone, and requires operator-supplied methane leakage data with verification for blue-route projects. A project that does not meet the standard cannot sign a Low Carbon Hydrogen Agreement and cannot receive production payments.

The Low Carbon Contracts Company is the statutory counterparty designated under Section 65 of the Energy Act 2023. The same counterparty signs the renewable Contracts for Difference, the Dispatchable Power Agreements for CCUS-coupled gas generation, and the Hydrogen Production Business Model contracts; it has a balance sheet large enough to bridge the multi-year payment streams and is funded through the supplier obligation on electricity bills (for the renewable Contracts for Difference) and through the Hydrogen Levy on gas shippers (for the hydrogen contracts) from January 2025 onwards under Sections 69 to 72.

The Hydrogen Levy on gas shippers is the funding route that lets the production business model scale without drawing on general taxation. A gas shipper that delivers a therm of natural gas to the National Transmission System pays a levy proportional to the volume; the receipts flow through the Low Carbon Contracts Company to the producers under the strike-price contracts. The architecture aligns the cost of hydrogen support with the consumer base that the hydrogen will eventually serve (heat and industrial offtake), rather than the electricity bill that funds the renewable Contracts for Difference. That choice has its own consumer-bill consequences which the heating decision will revisit.

The Hydrogen Transport Business Model

The Hydrogen Transport Business Model under Sections 61 and 62 of the Energy Act 2023 funds the pipework, valves, compressors and metering that move hydrogen from a producer to an offtaker. It does not fund the offtaker (an ammonia plant, a refinery, a glass furnace, a gas turbine) and it does not fund the producer (covered by the production business model above); it funds the infrastructure in between. Without the transport business model the producer cannot reach the offtaker because hydrogen at industrial scale is hard to road-haul; the molecule is too small to fit comfortably in a road-tanker pressure vessel without expensive cryogenics or extreme compression.

The structure is a regulated-asset-base tariff. The transport company recovers its cost of building and operating the pipeline plus an Ofgem-determined cost of capital over a regulatory period (commonly five years), with the recovery spread across the volume of hydrogen carried under a tariff agreed in advance. The model is closely analogous to the regulated-asset-base structure used for electricity transmission and distribution, the National Transmission System for natural gas, and the carbon-capture Transport and Storage Regulatory Model. The familiarity of the structure is an advantage in licence drafting and in regulatory precedent.

The first hydrogen transport networks under the model will sit inside the four CCUS clusters. The HyNet North West cluster has a regional pipeline plan that lifts hydrogen from electrolysers on the Mersey to industrial offtakers across the Manchester, Cheshire and North Wales geography. The East Coast Cluster has a Teesside-Humber backbone plan. The Acorn cluster runs from St Fergus inland to the Grangemouth and Aberdeen industrial belt. The Viking cluster connects Immingham to the South Humber. The cluster pipelines sit alongside the carbon-dioxide pipelines for the CCUS route, sharing rights of way and engineering contractors but operating as separate networks with separate tariffs.

The cross-link to the gas system is a regulatory question rather than an engineering one. The National Transmission System and the regional distribution networks are designed for natural gas; the safety case work to extend either to hydrogen blending or to a hydrogen-dedicated mode is a substantial multi-year programme led by the Health and Safety Executive in coordination with National Gas and the regional distribution operators. The HyDeploy 20 percent blending evidence base, the H100 Fife 100 percent demonstration, and the Ofgem Uniform Network Code Derogation D0001 of September 2025 are the live pieces of that programme as at May 2026. The Hydrogen Transport Business Model funds new hydrogen-dedicated pipework rather than the conversion of existing natural-gas pipework; the conversion case sits inside the heating decision rather than the transport business model.5

The transport business model also covers the metering arrangement. A hydrogen pipeline operating to industrial offtakers needs Coriolis or ultrasonic metering at every offtake point, with a calibration discipline that matches the financial value of the flow; the metering accuracy that is acceptable for an industrial offtake (around 1 percent of flow) is not the same as the metering accuracy required for a settled fiscal sale (closer to 0.2 percent). The model sets the metering standards that apply at each tariff boundary and the audit trail that has to be maintained by the network operator.

The Hydrogen Storage Business Model

The Hydrogen Storage Business Model under Sections 63 and 64 of the Energy Act 2023 funds large-volume hydrogen storage, principally in salt caverns and in depleted gas reservoirs. The role of storage in a hydrogen system is twofold. The first role is intraday and weekly balancing of production against offtake; a green-hydrogen electrolyser running on a wind input produces hydrogen at the wind shape, while an industrial offtaker needs hydrogen at a flat or scheduled shape. The storage absorbs the difference. The second role is inter-seasonal and strategic; a hydrogen-heated system would have demand peaked in January and February against electrolyser output peaked in spring and summer, and the inter-seasonal gap can only be bridged by large-volume storage.

Two large industrial storage tanks joined by an elevated steel walkway and access stairs against a clear blue sky
Large-volume storage lets a hydrogen system balance variable production against steady demand. Above-ground tanks handle the intraday and weekly swings, while salt caverns hold the inter-seasonal volumes. Photo: Pexels

The natural geology for hydrogen storage in Great Britain is the Cheshire and East Yorkshire salt deposits. A solution-mined salt cavern is a near-spherical void in solid rock salt with volumes of hundreds of thousands of cubic metres at depths of around 500 to 1,500 metres. Salt is impermeable to hydrogen, the cavern walls are self-healing under stress, and the storage pressures (typically 50 to 200 bar) are well inside the salt's strength envelope. The Centrica Rough field in the southern North Sea is a depleted gas reservoir already converted partly back to gas storage; conversion to hydrogen storage is a regulatory and economic question rather than a geological one.

The structure of the storage business model is a cap-and-collar on net revenue rather than a regulated-asset-base tariff. The cap-and-collar is needed because storage revenue depends on the arbitrage between low-price periods (when hydrogen is injected) and high-price periods (when hydrogen is withdrawn); in years with a flat hydrogen price the arbitrage revenue is too thin to recover the cost of capital, while in years with high arbitrage spreads the revenue can outrun the cost of capital comfortably. The cap-and-collar protects the operator in low-spread years (the floor) and shares the upside with the consumer in high-spread years (the ceiling). The structure mirrors the cap-and-floor mechanism used for the Great Britain to European Union electricity interconnectors at the same regulator.1

The first storage projects under the model are expected at the HyNet cluster (the Stublach salt cavern complex in Cheshire) and at the East Coast Cluster (the Aldbrough salt cavern field in East Yorkshire). Both projects are at planning and consenting stages as at May 2026, with first storage decisions expected in 2027 once the production business model has had two further allocation rounds to confirm the volume of hydrogen that needs to be stored.

The interaction between the storage business model and the gas system is direct. Several of the candidate salt caverns are already in use for natural-gas storage and could be converted to hydrogen with a moderate engineering programme; the conversion preserves the rights of way, the wellhead infrastructure and the surface plant, and replaces the cushion gas with hydrogen-compatible inert gas. The decision on whether to convert an existing cavern from natural gas to hydrogen depends on the storage business model's strike price against the natural-gas storage market, which is set by the seasonal spread on the National Transmission System. The two markets are linked through the same physical asset base.

Primary sources

The most load-bearing sources for hydrogen are listed below.

  1. DESNZ; the Department for Energy Security and Net Zero is the policy lead for the Hydrogen Strategy, the Low Carbon Hydrogen Standard, the Hydrogen Allocation Rounds, and the three Energy Act 2023 business models. https://www.gov.uk/government/organisations/department-for-energy-security-and-net-zero
  2. Strategic Spatial Energy Plan (SSEP); NESO with DESNZ; methodology May 2025; first iteration Q4 2026; final SSEP Autumn 2027. Treats hydrogen alongside electricity, gas, heat and CCUS as one whole-system question. https://www.neso.energy/what-we-do/strategic-planning/strategic-spatial-energy-planning-ssep
  3. Centralised Strategic Network Plan (CSNP); NESO with Ofgem; methodology approved April 2026; first CSNP delivery by end-2028. https://www.neso.energy/what-we-do/strategic-planning/centralised-strategic-network-plan-csnp
  4. LTDS CIM Stage 2 and 3 Extension (Derogation) Letter, dated 13 May 2026. Stage 2 publication 29 May 2026; Stage 3 30 November 2026. https://www.ofgem.gov.uk/sites/default/files/2026-05/LTDS-CIM-Stage-2-and-3-Extension-Derogation-Letter.pdf
  5. National Gas; the National Transmission System operator. Publishes daily linepack, demand and Wobbe Index data; the Gas Safety (Management) Regulations 1996 Schedule 3 window sits on this operational data. https://www.nationalgas.com/data-and-operations/transmission-operational-data
  6. NESO Connections Reform Gate 2 detailed results; April 2026. 283 GW generation and storage and 99 GW demand progressed; Phase 1 to 2030; Phase 2 to 2035. https://www.neso.energy/document/374936/download
  7. Wylfa SMR site contract; DESNZ; April 2026. Three Rolls-Royce SMRs at Wylfa; final investment decision expected 2029; in-service mid-2030s. https://questions-statements.parliament.uk/written-statements/detail/2025-11-13/hcws1056

The Gas Safety (Management) Regulations 1996 (SI 1996/551) Schedule 3 sets the National Transmission System Wobbe Index window at 47.20 to 51.41 MJ per cubic metre and the hydrogen content cap at 0.1 mole percent. The Energy Act 2023 (c.52) Part 2 Chapter 1 carries the four enabling provisions for the three business models and the Hydrogen Levy. BS EN ISO 14687 sets the hydrogen purity grades (Grade A for industrial, Grade D for fuel-cell vehicles). BS ISO 22734 sets the electrolyser equipment standard.