Where the Great Britain gas system stands in May 2026: the 7,600 kilometre National Transmission System, the daily flow pattern, the heat networks regulator going live, and the hydrogen blending pathway

Where the Great Britain gas system stands in May 2026

The Great Britain gas system in May 2026 sits inside a window of regulatory reform that has shifted the boundary of what Ofgem oversees. The headline change in the past four months is that Ofgem became the heat networks regulator on 27 January 2026 under the Heat Networks (Market Framework) (Amendment) Regulations 2026, SI 2026/7. The amendment regulations switched on the live regime that the parent Heat Networks (Market Framework) Regulations 2025 had set out the architecture for. From the commencement date, Ofgem regulates pricing, transparency, consumer protection and step-in arrangements across heat network operators in the same statutory family that holds gas and electricity supply. The reform brings around 14,000 networks and roughly 480,000 connected meters into a single regulator's view for the first time.⁴

The physical gas system continues to run on the architecture set out in the 1986 Gas Act, then opened to competition through the 1995 Gas Act and the Gas Safety (Management) Regulations 1996 (SI 1996/551). National Gas Transmission, the licence holder for the high-pressure transmission backbone, operates 7,600 kilometres of pipe across England, Wales and Scotland with twenty-three compressor stations along the route. The compressors restage pressure after distance losses, lift gas from the entry terminals into the steady 70 to 85 bar transmission band, and balance the inter-LDZ flows on the National Gas operational schedule.³ The Rough offshore storage facility reopened in October 2022 after a five-year pause; the salt-cavern fleet at Aldbrough, Hornsea and Hilltop continues to operate inside the within-day balancing market. Eight entry terminals carry the import mix: the Norwegian Langeled pipeline at Easington, the Belgian and Dutch interconnector flows at Bacton, the St Fergus terminals on the Scottish North Sea, the LNG tanks at Isle of Grain, Milford Haven (South Hook and Dragon) and the smaller Belgian flows at Bacton from the Belgian interconnector.

Demand for gas continues to track winter weather more tightly than any other system variable. In a representative cold winter week in 2026, daily demand on the National Transmission System runs to between 280 and 340 million cubic metres per day; in the warmest summer weeks it sits closer to 130 million cubic metres per day. The 1 March 2018 peak of 454 million cubic metres remains the standing record on the daily series, set during the cold spell that the Met Office named the Beast from the East. National Gas publishes the daily flow update at nationalgas.com under its operational transparency obligations; the figures resolve through the Local Distribution Zone (LDZ) splits that the four distribution networks operate against.³

The wholesale market continues to anchor on the National Balancing Point, the notional point at which gas changes hands between shippers under the Uniform Network Code. The NBP day-ahead price in May 2026 has been trading in a narrower band than the 2022 spike year, with the front-month curve carrying the demand-shift assumption of a continued slow contraction in domestic boiler load against a slow rise in green hydrogen demand. The within-day market handles the operational balance between scheduled flows and metered flows; Ofgem and National Gas publish the balancing-charge schedule annually under the UNC code arrangements.

The data layer for gas continues to lag the data layer for electricity, with the LDZ-level reporting still on monthly cadence rather than the half-hourly cadence that the BMRS now publishes for power. The Data (Use and Access) Act 2025, with core provisions in force from 5 February 2026, brings the gas smart meter dataset into the same access and privacy frame as the electricity dataset; the implication for the gas system is that household-level gas consumption analytics begin to follow the same cadence as the electricity equivalent.¹ The 283 gigawatts of generation and storage and 99 gigawatts of demand that the NESO Connections Reform Gate 2 process progressed in April 2026 include the hydrogen-ready dispatchable plant that the Clean Power 2030 commitment retains as a 5 percent unabated-gas resilience buffer for low-renewables weeks; the gas system therefore continues to underwrite the electricity system through to 2030, even as the share of household gas demand falls under the heat pump and heat network roll-out.⁵

So the gas system in May 2026 has a settled physical architecture (the NTS unchanged in geographic shape since the 1970s build, the eight entry terminals with the Norwegian and LNG mix replacing the falling UK Continental Shelf production), a fresh regulatory frame around heat networks (Ofgem live as regulator from 27 January 2026), and an active hydrogen-blending pathway that runs through the GS(M)R 1996 Schedule 3 quality envelope. The sections below walk each of these in turn.

The National Transmission System: 7,600 kilometres of high-pressure pipe operated by National Gas Transmission

The National Transmission System is the high-pressure backbone that holds the Great Britain gas system together. National Gas Transmission holds the licence under the Gas Act 1986 and operates 7,600 kilometres of welded steel pipe across England, Wales and Scotland with twenty-three compressor stations along the route. The pipe diameter on the trunk lines is typically 900 millimetres (36 inches) and the operating pressure runs in a band between 70 and 85 bar gauge. The compressor stations restage pressure after the distance-related losses, with each station typically operating two or three Rolls-Royce or Solar Turbines RB211-class compressor sets driven by gas turbines fed off the transmission flow itself.³

The transmission backbone is regulated through the RIIO price control. The current price control RIIO-T3 for gas transmission runs from 1 April 2026 to 31 March 2031 following the Final Determinations published in December 2025; the predecessor RIIO-T2 ran from 1 April 2021 to 31 March 2026. The price control settles the allowed revenue, the capital expenditure envelope, the operational expenditure envelope, the output incentives (including emissions reduction and methane leakage), and the cost-recovery mechanism that translates the allowed revenue into the entry-exit charges that shippers pay at the terminals and offtakes.

The entry-exit charging methodology is the cost-recovery model that the Joint Office of Gas Transporters maintains under the Uniform Network Code. A shipper that books capacity at an entry terminal (St Fergus, Easington, Bacton, Milford Haven, Isle of Grain) pays the entry charge for that terminal; a shipper that books capacity at an exit point (a Local Distribution Zone offtake, an interconnector, or a connected industrial customer) pays the corresponding exit charge. The charging methodology is published annually; the auction calendar for entry and exit capacity follows the National Gas operational schedule.

The entry terminals carry the post-North-Sea import mix

UK Continental Shelf production fell to the lowest level since 1973 in 2024, with the Digest of UK Energy Statistics 2025 showing a 10 percent year-on-year contraction. The decline is structural: the easy onshore and shallow-water gas fields were developed in the 1960s and 1970s, the medium-depth fields in the 1980s and 1990s, and the deeper and smaller fields have been carrying the residual production curve down since the mid-2000s. The result is that the import mix now carries the bulk of the molecules flowing through the NTS in any representative week.

The eight active entry terminals in May 2026 are St Fergus (Aberdeen-shire, taking UKCS and Norwegian SAGE and FUKA pipelines), Barrow (Cumbria, taking South Morecambe UKCS production), Burton Point (Cheshire, taking Liverpool Bay UKCS production), Theddlethorpe (Lincolnshire, on a decommissioning trajectory), Easington (Yorkshire, taking the Norwegian Langeled pipeline and the Dutch BBL pipeline), Bacton (Norfolk, with the Interconnector UK to Belgium and the BBL to the Netherlands), Isle of Grain (Kent, regasifying LNG cargoes) and Milford Haven (Pembrokeshire, with the South Hook and Dragon LNG terminals operating side by side). Langeled at Easington is the single largest pipeline route into the country, capable of delivering up to 70 million cubic metres per day at peak.

The LNG terminals at Isle of Grain, South Hook and Dragon between them carry up to roughly 50 percent of total demand in cold snaps when cargoes are scheduled in. A 175,000 cubic metre LNG carrier discharges around 105 million cubic metres of regasified gas, equivalent to roughly a third of a typical winter daily demand for the whole country. Cargo scheduling sits in the commercial layer between the LNG terminal operator, the LNG shipper, and the loading terminal in Qatar, the United States, Trinidad or elsewhere; the operational interface to the NTS is the regasification rate the terminal posts under its capacity booking.

Compressor stations and the operational pattern

The twenty-three compressor stations along the trunk route are the operational tool that holds the transmission pressure band against load shifts. Each station is typically configured for redundancy with N+1 compressor sets, so that one set can be taken out of service for planned maintenance without affecting throughput. The compressor sets are themselves driven by gas turbines fed off the transmission flow; the gas-turbine drive is the historically dominant choice because the fuel is already there in the line, but electric-motor drive has become a live option as the NESO connections queue has progressed sites near several compressor stations through Gate 2 to the firm-offer stage.⁵

National Gas Transmission publishes operational data on the nationalgas.com transmission operational data page under National Gas commercial reuse terms; the daily series includes the entry-terminal flows, the LDZ flows, the linepack carried at the start and end of each gas day (06:00 to 06:00), and the supply and demand outturns reconciled to the Energy Balancing Notification settled by Elexon's gas counterpart at Xoserve.³

The daily demand pattern, the winter peak, and linepack as the first hours of buffer

The daily demand pattern on the Great Britain gas system is driven primarily by space heating, which in turn is driven primarily by outdoor temperature. The 23 million domestic meters connected to mains gas (around 84 percent of GB households) collectively run a strong diurnal load shape (morning ramp, evening peak) layered on a seasonal envelope (winter weeks roughly two and a half to three times the summer-week daily total). Industrial and power-station demand contributes a flatter base load. Power-station demand has become more variable across the day as combined-cycle gas turbines have moved from running for energy to running for capacity, dispatched against the merit order behind the wind and solar variable layer that now provides more than half of annual electricity generation.

The daily flow pattern resolves through three components in the National Gas operational schedule: the entry flow (the gas physically arriving from the terminals), the exit flow (the gas physically leaving at the LDZ offtakes, the interconnector exits and the directly connected industrial customers), and the linepack change (the gas held in the pressurised NTS pipe stock, which rises when entry exceeds exit and falls when exit exceeds entry). The linepack is the first hours of buffer the system has when a demand surge hits faster than the entry terminals and storage withdrawal can respond.³

The standing record on the daily series is 1 March 2018, when the cold spell that the Met Office named the Beast from the East drove demand to 454 million cubic metres in a single gas day. National Gas Transmission issued its first Gas Deficit Warning since 2010 on that day. The system held its statutory pressure envelope because Norwegian Langeled flows at Easington ran at maximum throughout the cold spell, the Rough storage facility (then still in service) was drawn down on the maximum within-day rate, and the NTS linepack itself was drawn down from approximately 7 days of normal-load equivalent at the start of the cold snap to approximately 5 days of equivalent by its end. The buffer carried roughly the first two hours of the morning ramp when entry could not match demand instantaneously.

The Rough storage facility reopened in October 2022 after a five-year pause. Centrica Storage Limited, the operator, restored injection and withdrawal capability at the Rough field in the southern North Sea (East Riding), with the operational profile rebuilt to a partial-fill withdrawal rate. Rough is the largest single GB storage site by working volume; the salt-cavern sites at Aldbrough, Hornsea and Hilltop carry the within-day flexibility that the daily peak draws on faster than Rough can deliver. The storage section below sets out the operational profile of the whole fleet in May 2026.

The within-day balancing market

National Gas Transmission balances the within-day flows through the within-day commodity market that the Uniform Network Code arrangements set up. Shippers nominate their entry and exit flows at the start of the gas day, then trade incrementally through the day as actual flows resolve against forecast. National Gas itself takes balancing actions through the On-the-Day Commodity Market when the residual imbalance after shipper trading exceeds the operational tolerance; the cost of those actions resolves into the shipper-paid balancing charges under the UNC schedule.

The settlement frame for gas runs through Xoserve, the central data services provider for the four Gas Distribution Networks, and Elexon's gas counterpart for transmission flows. The gas day runs from 06:00 to 06:00 (the European Network Code on Gas Balancing harmonised gas day standard); the settlement period for individual nominations is hourly within that day. The slower settlement cadence than the electricity half-hourly equivalent reflects the slower physical response time of the gas system, which is set primarily by linepack inertia and the rotational inertia of the compressor sets, rather than by the inverter-controlled response time of the electricity system.

The storage fleet: Rough, the salt caverns at Aldbrough, Hornsea and Hilltop, and the LNG tank stock

Great Britain has a smaller standing gas storage stock than its near neighbours on the European continent. Germany, the Netherlands and France each carry storage equivalent to approximately 20 to 25 percent of annual demand; Great Britain carried less than 1 percent before Rough reopened, and carries between 2 and 3 percent in May 2026 with Rough back in service at a partial-fill operating profile. The structural reason is geographic: the United Kingdom Continental Shelf provided a quasi-storage equivalent through its on-demand production curve until the early 2010s, so the commercial case for building dedicated underground storage on land never matched the Continental case. The result is a fleet that combines one large offshore depleted-reservoir facility (Rough), a small number of onshore salt caverns sized for fast within-day flexibility, and the LNG tank stock at the three regasification terminals that doubles as a strategic reserve when cargoes are scheduled in.

The Rough field is a depleted gas reservoir 18 miles off the East Yorkshire coast, originally a production site that Centrica Storage Limited (then BG Storage) repurposed as a storage facility in 1985. The original working volume sat at around 3,300 million cubic metres with a maximum withdrawal of around 45 million cubic metres per day. The facility went into a maintenance closure in 2017 because the offshore platform reached the end of its original design life and the well-pressure profile required reassessment for continued operation. Centrica Storage Limited restored partial operation in October 2022 after the 2021 to 2022 wholesale price spike made the commercial case for the restoration capex investable; the reopened site is currently operating against a partial-fill profile rather than the full working volume of the original design.

The salt-cavern fleet (Aldbrough, Hornsea, Hilltop, Stublach, Holford) sits in the Cheshire and East Yorkshire salt deposits. Each cavern is created by solution mining: fresh water is injected into a deep salt layer, the salt dissolves, the brine is withdrawn, and the resulting void is then used to store gas under pressure. The salt-cavern format is well suited to fast injection and withdrawal because the void retains mechanical integrity under cycling pressure (the salt itself plastically deforms to seal small fractures), and the cavern can therefore be cycled multiple times per year against the within-day balancing market rather than once per season against the seasonal envelope.

The LNG tank stock at the three regasification terminals carries a different operational role. The tanks are sized for the storage of liquefied gas at minus 162 Celsius prior to regasification; they buffer the timing mismatch between cargo arrivals (every few days) and the continuous send-out into the NTS. In a cold spell when no cargo is expected for several days, the tank stock can be drawn down to keep send-out running; the operator then schedules a cargo arrival to refill the tanks. The LNG tank stock therefore doubles as strategic reserve when cargoes are pre-positioned ahead of forecast cold weather.

The wholesale market: the National Balancing Point, day-ahead pricing, and the within-day reference

The Great Britain wholesale gas market anchors on the National Balancing Point, the notional point at which gas changes hands between shippers under the Uniform Network Code. NBP is a virtual hub: every shipper that has booked NTS capacity at an entry terminal owns gas at NBP, and every shipper that has booked NTS capacity at an exit point delivers gas at NBP. The hub is therefore commodity-fungible, in the sense that a molecule injected at Bacton and a molecule injected at Milford Haven sit at the same point in the wholesale price register. The Joint Office of Gas Transporters operates the UNC arrangements that the NBP sits inside; the Intercontinental Exchange and Trayport carry the bulk of the bilateral trading; the European Energy Exchange runs the physical-delivery futures that resolve to NBP delivery.

Three price tenors are the daily reference: the day-ahead, the within-day, and the front-month. The day-ahead price clears on the afternoon of day D-1 for delivery during gas day D; the within-day price clears continuously through the gas day for delivery before the close of the same day; the front-month future clears for delivery during the named calendar month, with rolling tenor as time progresses. The day-ahead is the standing reference for the spot wholesale level; the within-day is the operational reference for shipper balancing; the front-month sits at the boundary between spot and forward and carries the demand-shift assumptions for the coming weeks.

The 2021 to 2022 NBP spike took the front-month from around 50 pence per therm in summer 2021 to a standing peak of 540 pence per therm in March 2022. The trigger was a sequence of structural and operational factors: a colder than average winter 2020-2021 had left European storage at the lowest level for the time of year since 2013, the post-COVID recovery had pulled Asian LNG demand back above pre-pandemic levels, the Nord Stream 1 pipeline maintenance schedule had restricted Russian pipeline supply through autumn 2021, and the Russian invasion of Ukraine in February 2022 then removed the credible expectation that pipeline supply from Russia would resume on the historic cadence. The spike resolved over the course of 2022 and 2023 as LNG cargoes redirected from Asia to Europe, European storage refilled ahead of winter 2022-2023, and demand contracted across the industrial and household sectors.

The May 2026 wholesale picture sits in a calmer band. The day-ahead has been trading in a 60 to 110 pence per therm range across the winter just ended; the front-month curve carries the assumption of continued slow contraction in household gas demand against a stable industrial and power-generation backstop. The supply-demand balance is held by a mix of Norwegian pipeline flows (the standing largest single source), LNG send-out at the three regasification terminals (cargo-scheduled), the residual UKCS production (declining year on year), and the Belgian and Dutch interconnector flows (responsive to the European Title Transfer Facility and Zeebrugge Hub differentials). The interconnector flows are bidirectional: in tight European weeks the Bacton flows export from GB to Belgium and the Netherlands; in tight GB weeks the same flows import into GB on the same physical assets.

The On-the-Day Commodity Market and balancing

National Gas Transmission acts as the residual balancer for the within-day system. Shippers that find themselves long or short on their nominated entry-exit position can trade out of the imbalance through bilateral counterparties on Trayport, or through the On-the-Day Commodity Market that National Gas operates under the UNC code arrangements. The OCM accepts bids and offers at fifteen-minute resolution; National Gas takes balancing actions on the OCM when the residual aggregated shipper imbalance exceeds the operational tolerance against the system-wide linepack target.

The cost of National Gas balancing actions resolves into the within-day commodity price and the daily cash-out price that each imbalanced shipper pays. The cash-out arrangements are designed to incentivise shipper-led trading toward balance ahead of National Gas residual action; the marginal cost of National Gas action sits above the market clearing price by a margin set under the UNC. The arrangements were designed by the Ofgem Project Discovery review in the late 2000s and have been refined through a succession of UNC modifications since.

The four Gas Distribution Networks and the 23 million household meters

Below the NTS, four Gas Distribution Networks (GDNs) operate the lower-pressure tiers that carry gas from each Local Distribution Zone offtake to the meter. Each GDN holds a separate distribution licence under the Gas Act 1986 and operates against the same RIIO-GD3 price control that runs from 1 April 2026 to 31 March 2031. The four GDNs are Cadent Gas (the largest, covering East of England, North West, West Midlands, London and North London), Northern Gas Networks (covering Northern England and the North East), SGN (Scotland, Southern, Wales and South West), and Wales and Western Utilities (Wales and the South West, with overlap into the West Country). The GDNs collectively serve 23 million domestic and 1.5 million industrial and commercial meters across thirteen Local Distribution Zones.

The distribution networks operate on a four-tier pressure cascade. The highest tier is local transmission pipe at 7 to 38 bar, carrying gas from the NTS offtake into the major distribution feeders. The medium-pressure tier at 2 to 7 bar feeds the urban network. The low-pressure tier at 75 millibar to 2 bar feeds the street mains. The service tier at 21 millibar feeds the household meter. Each step down is achieved by a pressure-reduction skid (PRS) which throttles the upstream pressure through a control valve to the downstream operating band, with a slam-shut valve as the secondary safety device against over-pressure on the downstream side.

The Iron Mains Risk Reduction Programme

The largest standing operational programme on the GDN networks is the Iron Mains Risk Reduction Programme (IMRRP), which is the long-running replacement of cast-iron and ductile-iron mains with polyethylene equivalents. The cast-iron mains were laid between the 1850s and the 1970s in the UK town-gas era and the early natural-gas era; the iron material is mechanically rigid, prone to fracture under ground movement, and corrodes preferentially at joints. Polyethylene mains are flexible, mechanically tolerant of ground movement and chemically inert; they also produce significantly lower methane leakage at the joint. The Health and Safety Executive set the IMRRP target in the 2000s to replace all iron mains within 30 metres of buildings on a phased programme; the RIIO-GD3 price control continues the programme through to 2031 with annual progress reporting to the HSE.

The methane leakage reduction from the Iron Mains Programme is one of the most significant single emissions reduction interventions in the GB gas system. Cast-iron mains leak roughly an order of magnitude more methane per kilometre of pipe than the equivalent polyethylene replacement; methane has a global-warming potential roughly 80 times that of carbon dioxide over a 20-year time horizon. Independent estimates put the cumulative emissions reduction from the IMRRP at roughly the equivalent of taking a million cars off the road, on a 20-year warming-equivalent basis.

The Beast from the East 2018 and the operational lessons

The cold spell that the Met Office named the Beast from the East ran from 22 February to 4 March 2018 and pushed Great Britain gas demand to the standing record of 454 million cubic metres on 1 March 2018. The operational response was a coordinated draw across multiple buffers: Norwegian Langeled flows at Easington went to maximum on the morning of 28 February; the Rough storage facility (then in service) was drawn down at the maximum within-day rate; the salt-cavern sites at Aldbrough, Hornsea and Hilltop went into peak withdrawal; LNG send-out from Isle of Grain and Milford Haven rose against the pre-positioned tank stock; the NTS linepack itself was drawn down from approximately 7 days of normal-load equivalent at the start of the cold snap to approximately 5 days by the end. The system held the pressure envelope throughout, and no customer was disconnected.

The first Gas Deficit Warning since 2010 was issued by National Grid (the predecessor licensee) on 1 March 2018. A Gas Deficit Warning is the operational signal under the UNC code arrangements that the residual imbalance after all shipper-led actions and all storage and import responses is approaching the system's operational tolerance, and that shippers are required to take additional balancing actions to restore the position. The warning was lifted on 2 March 2018 once the cold spell broke and Norwegian flows and storage withdrawal restored the balance.

The heat networks regulator going live on 27 January 2026 under SI 2026/7

The most significant regulatory change to the gas sector boundary in the past four months is the commencement of the Heat Networks (Market Framework) (Amendment) Regulations 2026, statutory instrument SI 2026/7. The amendment regulations switched on the operational regime that the parent Heat Networks (Market Framework) Regulations 2025 had set out the architecture for. From 27 January 2026, Ofgem became the heat networks regulator in Great Britain, with the same enforcement powers over heat network pricing, transparency, consumer protection and step-in arrangements that the regulator already exercises over gas and electricity supply. The new regime covers approximately 14,000 heat networks and around 480,000 connected meters at commencement, with the population expected to grow rapidly as the heat decarbonisation programme proceeds.⁴

A heat network is a centralised heat-generation plant (typically a combined heat and power unit, a heat pump, an industrial heat-recovery system or a biomass boiler) that distributes hot water through insulated pipes to a population of connected buildings. The connected buildings each carry a heat interface unit at the building boundary which transfers the heat from the network water to the building's internal heating circuit. The heat is metered at the heat interface unit, and the consumer pays for the metered heat under a supply contract with the network operator. The model has been common across Northern European cities (Copenhagen, Stockholm, Helsinki, Vienna, Berlin) for decades; in Great Britain the model is concentrated in new-build developments, university campuses, hospital estates and high-density urban regeneration sites.

The regulatory case for bringing heat networks into Ofgem's perimeter rests on a structural feature of the model: a heat network consumer cannot easily switch supplier the way a gas or electricity consumer can. The pipework is physical, the heat interface unit is dedicated, and the consumer typically has no alternative supplier within the same building. The consumer protection situation before commencement was therefore weaker than for the equivalent gas or electricity consumer; the new regime brings consumer protection (price transparency, complaints handling, step-in arrangements when the operator exits or defaults) into the same statutory family as the rest of the regulated utility sector.

The interaction with the gas system is twofold. First, many existing heat networks are gas-fired (a combined heat and power gas turbine or reciprocating engine that produces electricity for export and recovers the engine waste heat into the network water); the regulator regime now extends Ofgem's price oversight to the gas-firing cost that flows through into the consumer heat tariff. Second, the heat network pathway is one of the two principal household decarbonisation routes alongside individual heat pumps; the new regime sets the consumer-protection floor that the heat network roll-out will operate against as more boilers retire from the housing stock.

The Heat Networks Zoning programme, run by the Department for Energy Security and Net Zero, is the planning mechanism that designates urban areas where heat networks become the default route for new buildings and for retrofit at end of life of existing gas boilers. The zoning pathway delivers the connection rights set out in the new regulations: a building inside a designated zone has standardised connection terms with the local heat network operator, similar in shape to the standardised connection terms that a building has with the local gas distribution network. The first wave of designated zones is expected through late 2026 and into 2027.

The hydrogen blending pathway under GS(M)R Schedule 3

The hydrogen blending pathway runs through the Gas Safety (Management) Regulations 1996 (SI 1996/551), the statutory instrument that holds the gas-quality envelope for everything flowing in the public network. Schedule 3 of the regulations sets the quality parameters: the Wobbe number (an interchangeability measure that combines calorific value and relative density), the calorific value itself, the sulphur content, the oxygen content, the hydrogen content, and other parameters that together define a molecule that an appliance burner is designed to handle. The Schedule 3 envelope was originally tuned to natural gas as delivered from the North Sea, with the appliance population calibrated to that envelope through the 1967 to 1977 conversion programme that replaced 40 million appliances when the GB system moved from town gas to natural gas.

The 2023 amendment to GS(M)R (SI 2023/284) reduced the lower Wobbe limit from 47.20 to 46.50 megajoules per cubic metre from 6 April 2025, and brought biomethane explicitly into the regulatory scope. The reduction in the lower Wobbe limit was the regulatory step that allowed a wider range of biomethane production sources (anaerobic digestion, sewage gas, landfill gas) to inject into the network without bespoke certification, and was the precursor regulatory step to the hydrogen blending pathway that is the live policy question for the sector in 2026.

The hydrogen content limit in GS(M)R Schedule 3 currently sits at 0.1 percent molar (one part in a thousand) under the original 1996 envelope. A blending pathway that would permit up to 20 percent hydrogen by volume into the public network requires either an amendment to Schedule 3 or a safety case argued under the regulations themselves. The strategic policy decision of December 2023 from the Department for Energy Security and Net Zero was supportive of up to 20 percent blending, subject to the safety case being demonstrated; the operational evidence base has been built through the FutureGrid programme run by National Gas Transmission and the HyDeploy and H100 trial programmes run by the GDNs.

The technical question that the safety case has to settle is interchangeability. An appliance burner is calibrated for a specific Wobbe number range; hydrogen has a Wobbe number that sits below the bottom of the current Schedule 3 envelope. Blending hydrogen into the supply therefore lowers the effective Wobbe of the delivered mixture; below a certain blend ratio the mixture remains inside the original envelope (because the calorific-value contribution from hydrogen is offset by the density contribution), and the appliance population can continue to operate without re-calibration. The 20 percent blend ratio is the threshold at which the resulting mixture is consistently inside the envelope across the appliance population that the conversion programme calibrated against.

The cross-cutting question that sits behind the blending pathway is the carbon impact. A 20 percent blend by volume corresponds to roughly a 7 percent reduction in carbon emissions per cubic metre of delivered gas (because hydrogen carries roughly a third of the volumetric energy density of methane, the energy share of the blend is around 7 percent rather than 20 percent). The blend reduces emissions modestly per unit of delivered heat, but the absolute emissions reduction is small set against the equivalent emissions reduction from heat pump or heat network connection. The strategic case for blending therefore rests on the value of providing a hydrogen production market at scale (an enabler for the hydrogen-ready dispatchable plant that the Clean Power 2030 commitment retains as the 5 percent unabated-gas resilience buffer), rather than on the household decarbonisation contribution in its own right.⁵

The interaction with the data layer matters too. The Data (Use and Access) Act 2025, with core provisions in force from 5 February 2026, brings the gas smart meter dataset into the same access and privacy frame as the electricity dataset. The implication for hydrogen blending is that an appliance population that begins to receive a blended supply can be monitored at the household-level cadence that the smart meter network supports; the regulatory case for proceeding with a blend can therefore be reinforced by the operational outturn data as it accrues.¹

For the long-form treatment of the hydrogen pathway in May 2026, the workspace separates out a dedicated page at /gb-energy-workspace/hydrogen. That page covers the green, blue and pink production routes, the FutureGrid evidence base, the H100 Fife pilot, the Wobbe interchangeability tests, the appliance population studies, the regional cluster decisions (HyNet, East Coast, Track 1 and Track 2 CCUS), and the connection of the hydrogen pathway to the wider Clean Power 2030 and net-zero programmes.