Great Britain’s available gas supplies, in aggregate, are greater than peak demand over the next ten years. But the diversity of the future gas supply mix makes it “both unpredictable and uncertain”, according to National Grid Gas (NGG), the system operator for the high-pressure National Transmission System (NTS).
The increasing diversity of gas flows that have to be managed in the NTS, alongside managing the ageing system, were highlighted in NGG’s annual Gas Ten Year Statement (GTYS), which assesses needs and trends for the system over the coming decade.

Ageing network
The NTS comprises 7,630 km of pipeline, 24 compressor sites with 68 operational compressor units, 20 control valves and 530 above-ground installations.
NGG says the network is ageing. It was built rapidly between the late 1960s and 1990, and “With a typical asset design life of 40 years, a significant proportion of our network is now
beyond its original life expectancy.” It means “careful management of these ageing assets
is required”.
An indication of the work required is expenditure under NGG’s monetised risk-based approach to manage the assets. The RIIO-2 Final Determination, for the period 2021-2026, allows for investment of over £700 million on asset health (subject to Uncertainty
Mechanisms) – 40% greater than the annual asset health investment in RIIO-1 and driven by an increased volume of work to maintain current levels of network risk on the ageing asset base.
The system also needs new investment as gas imports change. NGG has already reduced its capability to move gas from the declining St Fergus terminal in Scotland (but also added capability to move gas into Scotland). More imports now arrive as LNG to terminals in the southeast and South Wales but the compressors that move gas from LNG import terminals have to be upgraded to meet pollution limits set under the Industrial Emissions Directive.

New users
NGG has always had to be flexible around users because it is obliged to make capacity available to shippers up to and including the gas flow day. “This creates a situation where we are unable to take long-term auctions as the definitive signal from shippers about their intentions to flow gas,” it said.
Whereas historically NTS users were large entry and exit connections or storage, now NGG is connecting customers with smaller projects. These are “fundamentally different to
traditional NTS customers”, it says, as they are fast to market and the associated costs for
a connection represents a significant portion of their total project budget. This emerging customer base includes those developing biomethane and hydrogen.
Over 100 companies have registered with a new ‘Gas Connections Portal’ that allows them to generate cost estimates and apply for a gas connection.
NGG says “The impact on existing network capability of investments to deliver net zero, such as repurposing feeders for carbon capture use and storage (CCUS) or hydrogen, will be assessed as part of any project proposals.”
With more varied gas sources NGG also did a project to explore whether it could offer a gas quality blending service at NTS entry terminals, but concluded that “it would not be feasible to offer this as an enduring service arrangement at NTS entry terminals but remain open to consider short-duration requests.”

The long term mix of gas in the network and the likely pattern of use could take very different forms and NGG uses NGESO’s Future Energy Scenarios alongside its Ten-Year Statement to consider needs in different supply zones across the country.
Overall, peak demand projections are falling, because less gas is being used for power generation. But gas flow changes are significant. For example because of the limited capability to transport gas from south to north, the decline in entry flows “will make it difficult for us to meet our exit commitments in Scotland”, NGG said. It has no compression capability to move supplies from Teesside or Barrow towards the areas of high demand in that zone. In that region, it says, “in 2031/32 we still expect the maximum flow through the terminal to be consistent to today, but there are now a number of scenarios with very low or zero flow. A number of these are beyond our current levels of capability and would lead to constraints on the system without intervention.”
In contrast, in South Wales the number of periods where supply is above capability will increase by 2031, as North Sea supplies continue to decline and more LNG is moved through the region’s terminals. In the Southeast, simultaneous imports from the Isle of Grain terminals and the UK interconnector may be above capacity. “Historically coincidental high entry flows from LNG and the interconnectors has been an unlikely scenario. But as UKCS supplies decline and we become increasingly reliant on imports, this risk of high flows from both terminals increases,” NGG says.
In other discussions about operability of the network NGG has noted that alongside the long term decline it has seen more variation in demand within the day, which has required more active management.

Compressor fleet
NGG has been working to address the impact of the IED’s pollution limits on its ageing compressors for a number of years. The issue has been made more complex because the compressors are used more often across the year as gas use has become more volatile, reducing the opportunities for planned maintenance.
NGG has proposed that during the next five years two new compressor units would be
installed at Wormington and two more at King’s Lynn. In the following five years (RIIO-3) it proposes three new units at St Fergus and a third unit at Peterborough. NGG says, “Construction of new compressor stations may require development consent if a new high-voltage electricity connection is needed and, subject to local planning requirements, may require similar timescales to pipeline projects.”
Overall, of 52 compressors that will be operational when IED takes effect on 1 January 2030, 13 new compressors will have been installed and 36 compressors will have been
decommissioned.

Further reading
Towards 2032: switching gas customers to 100% hydrogen. How might it be done?
Towards 2032: NGESO details electricity system reinforcement needs